Duke Energy Progress coal burn tumbles as gas takes its place

Due to increasingly lower power prices, the retirement of Duke Energy Progress (DEP) coal stations, and the addition of natural gas-fueled combined cycles, coal burn projections for 2013 and forward are forecasted to be lower than historical volumes.

That is according to May 9 testimony from Alexander (Sasha) Weintraub, Vice President, Fuels & Systems Optimization for parent Duke Energy (NYSE: DUK). DEP is the former Progress Energy Carolinas that Duke took over in mid 2012. The testimony was filed at the South Carolina Public Service Commission in a fuel review case.

The actual coal burn for DEP’s stations in 2012 was just over 9.7 million tons, about 30% less than the average coal burn over the prior five-year period of over 12.4 million tons, Weintraub noted. Based on the low coal burns in 2012, as well as the downward projection for coal burns in 2013 as compared to the amount of coal under contract for delivery in 2013, the company expects coal inventories to be above target levels during 2013. If the company experiences mild weather and  continued low purchased power prices, there likely will be even further upward pressure on coal inventories, Weintraub added.

The purpose of this testimony was to describe DEP’s fossil fuel purchasing practices, provide fossil fuel costs for the period March 2012-February 2013 (the “review period”), and describe changes forthcoming for the period July 2013-June 2014 (“billing period”). Weintraub also provided an update from a procurement and operations perspective on the Joint Dispatch Agreement (JDA) that Duke Energy is using to deliver savings to its North and South Carolina customers, as well as fuel savings that DEP has realized to date on behalf of its customers as a result of the merger, which put Duke Energy Carolinas and Progress Energy Carolinas (now DEP) under one roof.

DEP’s average delivered coal cost per ton decreased less than 1.0% from $91.11 per ton from the prior review period to $90.74 per ton in the latest review period. The average transportation costs decreased approximately 2.5%, from $28.08 per ton in the prior review period to $27.38 per ton in the latest review period.

Weintraub: coal markets still in a major state of ‘flux’

“Coal markets continue to be in a state of flux due to a number of factors, including  (1) 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; (2) continuing growth in global demand for both steam and metallurgical coal, which makes coal exports increasingly attractive to U.S. coal producers; (3)  continued low gas prices combined with installation of new combined cycle generation by utilities, especially in the Southeast, which also lowers overall coal  demand; and (4) increasingly stringent safety regulations for mining operations,  which result in higher costs and lower productivity,” Weintraub noted.

Combining coal and transportation costs, the company projects average delivered coal costs of approximately $92.60 per ton for the billing period. This represents a 2.0% increase compared to the review period actual cost. This cost, however, is subject to change based on:

  • changes in oil prices, which impact transportation rates;
  • potential additional costs associated with suppliers’ compliance with legal and statutory changes, the effects of which can be passed on through coal contracts;
  • performance of contract deliveries by suppliers and railroads which may not occur despite the company’s strong contract compliance monitoring process;
  • cost of potential contract volume deferrals in light of declining coal burn projections and high coal inventories; and
  • the amount of non-Central Appalachian coal the company is able to consume.

DEP expects to address forward coal requirements later this year with any potential competitively bid purchases, if made, taking into account projected coal burns, as well as coal inventory levels. The company currently is considering alternatives to help mitigate inventory levels including negotiating contract shipment deferrals/buy-outs, and evaluating re-sale market opportunities. Due to lower coal demand for most of the U.S., however, either of these options would likely be difficult to achieve without paying additional costs to the supplier or incurring sales at potential losses, Weintraub added.

In the meantime, the company’s natural gas consumption is expected to only continue to increase. The company consumed about 89 billion cubic feet (Bcf) of natural gas in the review period, compared to about 69 Bcf in the prior review period. This increase was driven by the downward trend in gas prices as well as the operation of the second combined cycle power block at the Richmond facilities. For the billing period, DEP’s current forecasted natural gas consumption is approximately 152 Bcf. This forecast is based on current natural gas prices which are expected to remain low.

Coal unit retirements, new gas capacity figure into the fuel mix

Joseph Miller Jr., General Manager of Strategic Engineering for Duke Energy Business Services LLC, said in companion testimony that the company’s fossil/hydro generation portfolio consists of 9,365 MW of generating capacity, made up as follows:

  • Coal-fired – 4,095 MW;
  • Hydro – 225 MW;
  • Combustion Turbines- 3,041 MW; and
  • Combined Cycle Turbines – 2,004 MW.

The coal-fired fleet consists of four stations and a total of ten units. These units are equipped with emission control equipment, including selective catalytic or selective non-catalytic reduction (SCR or SNCR) for removing NOx and flue gas desulfurization (FGD or “scrubber”) equipment for removing SO2. In addition, nine coal-fired units are equipped with low NOx burners. This emissions control equipment allows DEP to utilize coal with increased sulfur content – providing flexibility to procure the best cost options for coal supply, Miller noted.

The company has a total of 36 simple cycle combustion turbine (CT) units, of which 14 are considered the larger group, providing about 2,241 MW of capacity. These 14 units are located at Asheville, Darlington, Richmond County and Wayne County. Within the fleet of 36, a total of 14 units have NOx control equipment. There is 2,004 MW of Combined Cycle Turbines (CC) that represent three power blocks. The Lee Energy Complex has a configuration of three CTs and one steam turbine, and Richmond County has two power blocks consisting of two CTs and one steam turbine. Within these power blocks, the seven CTs are equipped with low NOx burners, SCR equipment, and carbon monoxide volatile organic compound catalysts.

Changes recently within the power portfolio include the addition of a combined-cycle facility providing 920 MW of capacity at the Lee Energy Complex (Lee CC), which went in-service on Dec. 31, 2012, and is located in Goldsboro, N.C. Also within the review period, DEP retired coal-fired units 5 and 6 at Cape Fear, Units 1-3 at Lee and Unit 1 at Robinson. These coal retirements in September and October 2012 reduced capacity by 875 MW. The CT fleet was reduced by a total of 144 MW with the October 2012 and March 2013 retirement of units at Cape Fear and Lee.

Another combined-cycle facility is under construction in New Hanover County, N.C. The Sutton CC will provide an additional 625 MW of capacity and is scheduled to be in service by December 2013. Also at the Sutton facility, coal-fired Units 1-3 are scheduled for retirement by the end of 2013.

Over the review period, the average heat rate for the coal fleet was 10,856 Btu/kWh, Miller reported. The most active units at Asheville, Mayo, Roxboro, and Sutton achieved a heat rate of 10,844 Btu/kWh and the most efficient two units were Roxboro Units 1 and 2, achieving heat rates of 9,551 and 10,204 respectively. The Roxboro units provided the majority (62.5%) of coal-fired generation for DEP during the period.

DEP’s coal-fired units achieved results of 91.05% equivalent availability factor and 46.65% capacity factor over the review period. During the 2012 peak summer season, the fleet achieved results of 97.04% equivalent availability factor and 62.32% capacity factor.

The company’s most active CTs located at Asheville, Darlington, Richmond County, Lee, and Wayne County were available as needed in this time period, with a 98.75% starting reliability. The Richmond CC facility reported a capacity factor of 73.02% for the review period. The Lee CC facility began commercial operation in December 2012 and has performed well as a baseload unit in its first two months of operation, achieving a capacity factor of 80.18%, Miller wrote.

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.