Duke Energy Carolinas currently operates three coal-fired units at the Lee Steam Station – Units 1 and 2 at 100 MW (net) each, and Unit 3 170 MW (net) – that will be shut down (Units 1 and 2) or switched to gas (Unit 3) in 2015.
That is according to Aug. 4 fuel case opening testimony filed at the South Carolina Public Service Commission from Joseph Miller Jr., the interim Vice President of Central Engineering and Services for Duke Energy Business Services LLC. Duke Energy Carolinas (DEC) is a subsidiary of Duke Energy (NYSE: DUK). The fuel case is due for hearing on Aug. 27.
Lee is DEC’s only coal-fired plant in South Carolina and is scheduled to be retired from active service by April 2015, largely due to environmental regulations and economic reasons. The company plans to retire Units 1 and 2, and convert Unit 3 to natural gas to serve DEC’s native load by the summer peak of 2015. The Lee units were originally designed and operated as gas-fired boilers, but were converted during the 1970s to operate on coal. Once converted back to natural gas, Lee Unit 3 will maintain its capacity rating of 170 MW, Miller noted.
Other Aug. 4 testimony came from Alexander (Sasha) Weintraub, the Vice President, Fuels & Systems Optimization for Duke Energy. The purpose of his testimony is to describe DEC’s fossil fuel purchasing practices, provide fossil fuel costs for the period June 2013-May 2014 (called the “review period”), and describe changes forthcoming in the period of October 2014-September 2015 (the “billing period”).
DEC’s average delivered coal cost per ton decreased 1.08% from $99.27per ton in the prior review period to $98.20 per ton in the review period. The average transportation costs increased approximately 7%, from $30.27 per ton in the prior review period to $32.49 per ton in the review period.
“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) softening demand in global markets for both steam and metallurgical coal, but coal exports continue to be of interest 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.
Coal competing better with gas, so coal burn expected to increase
Due to the increasing competitiveness for low cost electricity between natural gas and coal, it is anticipated that DEC’s coal generation will fluctuate with prevailing market conditions. With the increase in natural gas prices in response to extreme weather last winter, the actual coal burn for DEC’s stations for the review period was just over 12 million tons, which is more than 9% higher than the 11 million tons originally anticipated in the currently billed rate. The coal burn for the billing period is projected to be approximately 12.8 million tons, which is a 6% increase compared to the actual burn for the review period.
“DEC’s billing period projections for coal generation, however, may be impacted due to changes in natural gas prices, volatile power prices, and demand,” Weintraub wrote. “In addition, 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, DEC projects average delivered coal costs of approximately $94.19 per ton for the billing period. This represents a 4% decrease compared to the review period. 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 DEC’s strong contract compliance monitoring process; the amount of non-Central Appalachian coal DEC is able to consume; and the market prices for DEC’s open coal positions at the time of purchase.
DEC’s primary source of coal supply is no longer Central Appalachia, Weintraub added. That region is basically southern West Virginia, eastern Kentucky and southwestern Virginia. Historically, fuel switching to a different coal basin has been difficult for DEC because coal quality characteristics vary greatly between coal basins, and the design of DEC’s plants was meant to optimize the use of Central Appalachia coals. Where the impacts of burning other coals require mitigation, DEC has undertaken engineering and economic studies to determine whether the cost is justified by the savings obtained through burning that coal. DEC can not only source coal supply from non-Central Appalachian regions, DEC can also leverage this fact to purchase Central Appalachian coals at a lower price.
Additionally, as a result of a merger earlier this decade with Progress Energy, DEC can achieve fuel savings by sharing best practices between DEC and Duke Energy Progress (DEP) for coal blending at their respective coal-fired plants.
Over the past seven years, DEP has made a substantial investment to improve the fuel flexibility of its scrubbed coal units. These investments, which have included improvements to the coal-fired boilers, as well as the balance-of-plant components, have expanded the types of coal that DEP can reliably burn at these units. DEC has been able to learn via the merger from the DEP practices of consuming non-traditional coals at the DEP coal units without impacting reliability or operations.
Natural gas consumption expected to fall a bit – for now
The company consumed approximately 59 billion cubic feet (Bcf) of natural gas in the review period, compared to approximately 52 Bcf in the prior review period. For the billing period, DEC’s forecasted natural gas consumption is approximately 42 Bcf. This forecast is based on natural gas prices that are forecasted to remain low.
The development of shale gas has created a fundamental shift in the nation’s natural gas market, Weintraub noted. Given continued production increases, natural gas prices continue to remain at relatively low levels.
The company’s average price of gas purchased for the review period was $5.22/MMBtu, compared to $3.91/MMBtu in the prior review period. The higher average price of gas purchased for the review period versus the prior review period was driven by increased gas demand due to multiple cold weather events across the Midwest, Mid Atlantic, Northeast and Southeast during the first quarter of 2014.
Although real-time volatility during an extreme cold weather event can impact gas supply, 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. DEC expects the shale gas production percentage of total natural gas domestic production to continue to increase over time. The forward prices for natural gas reflect this continued increase in competitively priced supply, with an average forward Henry Hub price of $3.96/MMBtu through the proposed fuel rates period.