Duke Energy Progress coal burn falls sharply from expected level in latest test year

For Duke Energy Progress, the average delivered coal cost per ton decreased approximately 0.6% from $89.28 per ton in the prior test period (April 2013-March 2014) to $88.77 per ton in the latest test period (April 2014-March 2015).

This includes average transportation costs decreases of approximately 4.7%, from $30.78 per ton in the prior test period to $29.34 per ton in the latest test 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.

Swati V. Daji, the Senior Vice President, Fuels & Systems Optimization for Duke Energy (NYSE: DUK), described the Duke Energy Progress coal buying in a June 17 filing at the North Carolina Utilities Commission as part of a fuel cost review case.

The purpose of the testimony is to describe DEP’s fossil fuel purchasing practices, provide fossil fuel costs for the period April 2014-March 2015 (the “test period”), and describe changes forthcoming for the period December 2015-November 2016 (the “billing period”).

Daji wrote: “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, DEP anticipates that its coal generation will fluctuate with prevailing market conditions. The actual coal burn for the test period was 6.7 million tons, which is 24.0% lower than the 8.9 million tons originally anticipated in the currently billed rate. Although the projected coal burn reflected in the rate proposed for the billing period is 6.6 million tons, the Company’s projected coal burn may be impacted by changes in natural gas prices, volatile power prices, and demand. DEP coal inventory levels were on target at a 40-day supply at the end of the test period. Future inventory levels are dependent on actual versus projected coal burns and actual coal deliveries based on performance of the railroads.

“Combining coal and transportation costs, the Company projects average delivered coal costs of approximately $76.81 per ton for the billing period. This represents a decrease of 13.5% from the test 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.”

Gas usage at the utility continues to climb

Daji added: “The Company consumed approximately 137 billion cubic feet (“Bcf”) of natural gas in the test period, compared to approximately 121 Bcf in the prior test period. This increase in natural gas consumption was primarily the result of the full year of operations of DEP’s Sutton CC that went into commercial service in late 2013. For the billing period, DEP’s current forecasted natural gas consumption is approximately 129 Bcf. As noted above, the Company’s natural gas consumption forecast for the billing period is in the range that occurred in the test period. Over time, the Company’s forecast for the billing period may change due to dynamic factors such as changes in natural gas prices, fuel price relationships, load and unit availability.

“The Company’s average cost of gas purchased for the test period was $6.03 per Million British Thermal Units (“MMBtu”), as compared to $6.18 per MMBtu during the prior test period. These costs include gas supply, transportation, storage and financial hedging. 

“The development of shale gas has created a fundamental shift in the nation’s natural gas market. Shale gas is natural gas that is trapped within shale formations, and which can provide an abundant source of petroleum and natural gas. Within recent years, improvements in production technologies have allowed greater access to the natural gas trapped in these formations, and has resulted in increased reserves that can produce natural gas supply more quickly and economically. Given continued production increases, forward natural gas prices continue to remain at lower levels.

“Short of the real-time volatility due to extreme colder weather, DEP believes new production from shale gas has contributed to substantial increases in the supply of U.S. marketed natural gas. This increase has currently outstripped demand growth. The Company expects the shale gas production percentage of total natural gas domestic production to continue to increase over time. The current forward prices for natural gas reflect this continued increase in competitively priced supply with an average forecasted Henry Hub price of approximately $3.16 per MMBtu through the billing period.”

The utility’s coal capacity is at three power plants

Also supplying June 17 testimony was Joseph A. Miller Jr., Vice President of Central Engineering and Services for Duke Energy Business Services LLC. He noted that the company’s fossil/hydro generation portfolio consists of 9,176 MW of generating capacity, made up as follows:


  • Coal-fired – 3,334 MW
  • Combustion Turbines – 2,995 MW
  • Combined Cycle Turbines – 2,620 MW
  • Hydro – 227 MW

The 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) equipment for removing NOx, flue gas desulfurization (FGD) equipment 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.

The company has a total of 36 simple cycle combustion turbine (CT) units, the larger 14 of which provide 2,201 MW, or 73.5% of capacity. These 14 units are located at the Asheville, Darlington, Richmond County, and Wayne County facilities, and are equipped with water injection and/or low NOx burners for NOx control. The 2,620 MW shown as “Combined Cycle Turbines” (CC) represent four power blocks. The Lee Energy Complex CC power block (Lee CC) has a configuration of three CTs and one steam turbine. The two Richmond County power blocks located at the Smith Energy Complex consist of two CTs and one steam turbine each. The Sutton Combined Cycle at Sutton Energy Complex (Sutton CC) consists of two CTs and one steam turbine. Within these four CC power blocks, all nine CTs are equipped with low NOx burners, SCR equipment, and carbon monoxide volatile organic compound catalysts. The steam turbines do not combust fuel and, therefore, do not require NOx controls.

There were no retirements or new generation brought on line during the test period. In February 2014, DEP announced that it has entered discussions with North Carolina Eastern Municipal Power Agency (NCEMPA) regarding the potential purchase of NCEMPA’s portions of the coal-fired Roxboro Unit 4 and Mayo Unit 1. This purchase, which is expected to close by Dec. 31, 2015, would bring DEP’s ownership to 100% and add 208 MW to DEP’s coal-fired portfolio.

For the test period, DEP’s total system generation was 66,092,310 MW hours (MWHs), of which 36,041,852 MWHs, or approximately 55%, was provided by the fossil/hydro fleet. 

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.