Duke Energy Progress coal buys up lately, but may fall again

Duke Energy Progress bought 7.1 million tons of coal in the March 2014-February 2015 period, up from 6.5 million tons in the year-ago period, said Swati V. Daji, the Senior Vice President of Fuels & Systems Optimization for Duke Energy Corp. (NYSE: DUK).

Daji supplied May 7 annual fuel cost testimony to the South Carolina Public Service Commission that describes Duke Energy Progress’ (DEP) fossil fuel purchasing practices, provides fossil fuel costs for the period March 1, 2014, through Feb. 28, 2015 (called the “review period”), and describes changes forthcoming for the period July 1, 2015, through June 30, 2016 (the “billing period”).

“The Company’s average delivered coal cost per ton decreased less than 1.0% from $90.31 per ton from the prior review period to $89.58 per ton in the review period,” Daji said. “The average transportation costs decreased approximately 6%, from $31.83 per ton in the prior review period to $29.92 per ton in the review period. The decrease in transportation costs reflects the incorporation of additional lower cost barge movements, where feasible, and reduced rail transportation costs due to lower fuel surcharges caused by the significant drop in fuel oil prices.

“Coal markets continue to be in a state of flux due to a number of factors, including: (1) U.S. Environmental Protection Agency (‘EPA’) regulations for power plants that result in utilities retiring or modifying plants, which reduces total domestic steam coal demand, and can result in some plants shifting coal sources to different basins; (2) low natural gas prices and increased volatility due to continued increases in gas supply combined with the installation of new combined cycle (‘CC’) generation by utilities, especially in the Southeast, which reduces overall coal demand; (3) softening demand in global markets for both steam and metallurgical coal, but coal exports continue to be of interest to U.S. coal producers; (4) increasingly stringent safety regulations for mining operations, which result in higher costs and lower productivity; and (5) the deterioration of the financial health of coal suppliers due to reduced demand and market pricing in combination with increasing production costs.

“Due to the increasing competitiveness for low cost electricity between natural gas and coal, the Company anticipates that DEP’s coal generation will fluctuate with prevailing market conditions. The actual coal burn for the review period was 7.1 million tons, which is more than 15% higher than the 6.2 million tons originally anticipated in the prospective period of the currently billed rate. The projected coal burn reflected in the rate proposed for the billing period is 6.1 million tons, however the Company’ projected coal burn may be impacted by changes in natural gas prices, volatile power prices, and demand. Although inventory levels were below target at the end of the review period, DEP’s inventory levels are currently above target and future inventory levels may remain above target levels at the end of 2015.

“Combining coal and transportation costs, the Company projects average delivered coal costs of approximately $79.49 per ton for the billing period. This represents a decrease from the review period actual cost. This projected cost, however, is subject to change based on (1) changes in oil prices, which impact transportation rates; (2) potential additional costs associated with suppliers’ compliance with legal and statutory changes, the effects of which can be passed on through coal contracts; (3) performance of contract deliveries by suppliers and railroads which may not occur despite the Company’s strong contract compliance monitoring process; (4) the amount of non-Central Appalachian coal the Company is able to consume; and (5) exposure to market prices and associated impacts to open coal positions.”

Joseph A. Miller Jr., the Vice President of Central Engineering and Services for Duke Energy Business Services LLC, testified that Duke Energy Progess has 3,334 MW of coal-fired generation represent three generating stations and a total of seven units. These units are equipped with emission control equipment, including selective catalytic reduction (SCR) for removing NOx, flue gas desulfurization (FGD) for removing SO2, and low-NOx burners. “This inventory of coal-fired assets with emission control equipment employed enhances DEP’s ability to maintain current environmental compliance and concurrently utilize coal with increased sulfur content – providing flexibility for DEP to procure the best cost options for coal supply,” Miller added.

“For the review period, DEP’s total system generation was 66,027,051 megawatt-hours (‘MWHs’), of which 36,453,751 MWHs, or approximately 55%, was provided by the fossil/hydro fleet,” Miller pointed out. “The breakdown includes 29% contribution from gas facilities, 25% contribution from coal-fired stations, and approximately 1% contribution from hydro facilities.”

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.