The new Edwardsport coal gasification power plant, after initial issues related to startup and a very cold 2013-2014 winter, has performed well lately and is dispatching power into the Midcontinent ISO marketplace.
That is among the coal-related points made in July 31 fuel cost testimony that the Duke Energy Indiana unit of Duke Energy (NYSE: DUK) filed with the Indiana Utility Regulatory Commission.
John Swez, employed by Duke Energy Carolinas LLC as Director, Generation Dispatch and Operations, supplied some of that testimony. He noted that in June 2013, the Edwardsport IGCC began commercial operation. “The station has performed as expected during this time, although significant challenges did arise this winter, in part, as a result of the extreme winter weather,” Swez wrote. “Production at Edwardsport IGCC has rebounded sharply since this time, with the station having its highest amount of monthly generation to date in May 2014 and continues to operate as expected.”
During the early operations of the plant, the station is being offered into the MISO market with a commitment status of must-run with the minimum and maximum output dictated by the specific schedule and unit availability. During these times, the output of the station is coded as testing. The company’s offer to MISO essentially results with the MISO dispatch following the output of the units during this time rather than MISO determining the level of output of the unit. However, during times when syngas is not available, no testing is planned on natural gas, and the station is available on natural gas operation, the unit is offered to MISO as an economic resource and can be committed and dispatched at MISO’s discretion. During these situations, the output of the station would not be coded as testing, Swez pointed out.
Another issue touched on by Swez is the use of a coal price decrement, which basically means that Duke figures the cost of not burning coal, like coal inventory costs, into its MISO bids, allowing the coal units to dispatch more readily. Starting in late February 2012, the company started applying a decrement to the dispatch costs of Gibson 1-5, Wabash River 2-6, and Cayuga 1-2 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.
Swez pointed out that 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,” he said. “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.”
On Jan. 22, 2014, the coal price decrement dropped to zero and has remained at zero through July 2014. Thus, starting on this date, there is no difference between the non-decremented dispatch price and the as-offered price of a generating unit. The company continues to perform the coal price decrement calculation twice a month. If the results show that a decrement is economic in the future, one will be added at that time.
Utility buys 13.1 million tons of coal in latest 12-month period
Also supplying July 31 testimony was Brett Phipps, the Director, Fuel Procurement at Duke Energy Progress, a utility affiliate of Duke Energy Indiana. Phipps said that the Gibson, Wabash River, Cayuga and Edwardsport IGCC stations are supplied by long-term coal agreements. Gallagher Station will be supplied by spot purchases throughout 2014 depending on how much the Gallagher station units operate.
For the twelve-month period ended May 31, 2014, the company purchased a total of approximately 13.1 million tons of coal (under both long and short-term contract commitments) at an approximate average cost of $2.79/MMBtu. The delivered cost of coal purchased under long-term commitments averaged $2.79/MMBtu and made up 96.03% of total coal receipts. The delivered cost of coal purchased under short-term commitments averaged $2.62/MMBtu.
“Published prices for U.S. coal markets have not changed significantly since the last fuel proceeding,” Phipps pointed out. “The following are 2014 price indications for the different coal producing regions: High-sulfur Illinois basin coal prices are in the high $30’s to low $40’s per ton; Central Appalachia coal prices range from the high $50’s to mid $60’s; Northern Appalachia coal prices range from the high $50’s to low $60’s; and Powder River Basin coal prices are approximately $12 per ton. Currently coal demand has increased in response to higher natural gas prices. Even though utilities stockpiles have declined slightly with the recent below normal weather and increased demand, published prices for U. S. coal markets market prices have remained relatively flat, driven primarily by the widely-held view that the coal markets continued to be over supplied in addition to annual production increases in the Illinois Basin and Northern Appalachian regions.”
Coal markets are likely to be relatively stable in the near term, said Phipps, though there is the potential for market volatility due to a number of factors, including: recent U.S. Environmental Protection Agency 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; softening demand in global markets for both steam and metallurgical coal, while coal exports continue to be of interest to U.S. coal producers; increased production in the Illinois Basin and Northern Appalachian regions; increased volatility in gas prices, and continued increase in gas supply combined with installation of new combined cycle (CC) generation by utilities, especially in the South, which may also lower overall coal demand; increasingly stringent safety regulations for mining operations, which result in higher costs and lower productivity; and volatile power prices.
Duke Energy Indiana trucking coal to Cayuga to address rail issues
As a result of the extreme weather in the beginning of 2014 and the ongoing increase in coal generation as well as other commodities and services, the railroads have been in very high demand with limited resources to serve the increased demand, Phipps testified. “For example the Company has not been receiving all of the scheduled shipments it requests each month to the Cayuga station due to the increased demand for rail service across the entire rail system. As a result inventory declined well below target levels and was forecasted to decline further if the Company did not find an alternative to support Cayuga’s forecasted coal burns. In response, beginning in June 2014, the Company has started trucking coal from the Wabash River station to the Cayuga station in order to increase inventory levels and supplement the rail performance.”
As noted in April 30 fuel testimony filed at the commission, Duke Energy Indiana’s coal inventories as of March 31, 2014, were approximately 3,300,000 tons (or 54 days of coal supply at a full load burn rate per day) across the system. As of June 30, 2014, coal inventories had fallen to approximately 3,200,000 tons (or 51 days of coal supply) as a result of higher demand for coal generation due to higher natural gas and power prices. But Duke Energy Indiana expects coal inventories to increase over the next quarter because of existing contractual commitments.
The company continues to evaluate a host of options in order to effectively manage the growing coal inventories. It has extended an existing storage agreement with one supplier to store coal at the supplier’s mine facilities for up to one additional year. The company has also agreed to defer up to 475,000 tons of coal for delivery in 2014 to 2015 with one supplier.
As inventory levels dictate, the company explores options to defer contract coal or re-sell surplus coal into the market. However, due to continued weak coal market conditions, re-sell opportunities are limited.
Duke Energy Indiana exercised its right to reopen the price under its Bear Run contract in accordance with the terms of the contract, by giving notice in April 2013. In addition, Duke Energy Indiana has also exercised its right to reopen the contract price of another long term agreement in accordance with the terms of the contract by giving notice in April 2014, said Phipps.
The parties have reached an impasse in the Bear Run talks, which requires resolution through arbitration. A new price has not yet been established in the other long-term agreement.
A major factor affecting coal burn, as Phipps indicated, is the state of often volatile natural gas pricing at any given time. The current spot price for natural gas is about $4/MMBtu. For the period March-May 2014 the price the company paid for delivered natural gas at its gas burning stations was between $4.28/MMBtu on May 23 to $18.51 on March 3.
In comparison, during the previous period of December 2013-February 2014, prolonged below normal temperatures and pipeline restrictions added to the price and volatility of natural gas prices. The price Duke paid for delivered natural gas at its gas burning stations during this period was in a range of delivered daily gas prices between a low of $3.90/MMBtu on Dec. 3, 2013, to a high of $23.00/MMBtu on Jan. 27, 2014.