Duke Energy Progress is predicting a roughly 300,000-ton uptick in coal burn in the December 2016-November 2017 period, to 5.1 million tons, compared to a very poor burn figure for a prior year.
Duke Energy Progress, a unit of Duke Energy (NYSE: DUK), applied June 22 at the North Carolina Utilities Commission in its latest annual fuel cost review case. One of the officials supplying testimony was Swati V. Daji, Senior Vice President, Fuels & Systems Optimization for Duke Energy.
The testimony covers fossil fuel costs for the period April 2015-March 2016 (called the “test period”) versus April 2014-March 2015 (the “prior test period”), and also describes changes forthcoming for the period December 2016-November 2017 (the “billing period”).
The company’s average delivered cost of coal for the test period was $80.74 per ton, compared to $88.77 per ton in the prior test period, representing a decrease of 9%. This includes an average transportation cost of $24.02 per ton in the test period, compared to $29.34 per ton in the prior test period, representing a decrease of approximately 18%. The company’s average price of gas purchased for the test period was $4.10 MMBtu, compared to $6.03 MMBtu in the prior test period, representing a decrease of 32%.
The decrease in coal 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. The cost of gas includes gas supply, transportation, storage and financial hedging, and the decrease in gas costs is primarily reflective of the historically low price of gas during the test period.
DEP’s coal burn for the test period was 4.8 million tons, compared to a coal burn of 6.7 million tons in the prior test period, representing a decrease of 29%. The company’s natural gas burn for the test period was 176 MMBtu, compared to a gas burn of 140 MMBtu in the prior test period, representing an increase of 26%. The decline in coal burns, and the increase in gas burns, was primarily attributable to declining gas prices combined with milder than forecasted weather during the 2015-2016 winter season.
Daji wrote about coal markets in general: “Coal markets continue to be in a state of flux due to a number of factors, including: (1) proposed and imposed U.S. Environmental Protection Agency (‘EPA’) regulations for power plants that have resulted in utilities retiring or modifying plants, which lowers total domestic steam coal demand, and can result in plants shifting coal sources to different basins; (2) abundant natural gas supply and storage resulting in lower natural gas prices combined with the installation of new combined cycle (‘CC’) generation by utilities, especially in the Southeast, which has also lowered overall coal demand; (3) continued softening demand in global markets for both steam and metallurgical coal; (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.
“At the same time, the nation’s natural gas supply has grown significantly and has outstripped demand. Over the longer term planning horizon, overall growth in gas supply is expected to continue. Currently observable forward market prices are at near historically low price levels as producers continue to look for efficiencies to further enhance economics and lower production costs. In addition to the increase in natural gas supply, new pipeline infrastructure continues to be added to provide for opportunities to move the growing supply to various markets.
“DEP’s current coal burn projection for the billing period is 5.1 million tons compared to 4.8 million tons consumed during the test period. DEP’s billing period projections for coal generation may be impacted due to changes from, but not limited to, the following factors: delivered natural gas prices versus the average delivered cost of coal, volatile power prices, and electric demand. Inventory level were above target 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, DEP projects average delivered coal costs of approximately $76.11 per ton for the billing period compared to $80.74 per ton in the test period. This cost, however, is subject to change based on, but not limited to, the following factors: (1) exposure to market prices and their impact on open coal positions; (2) the amount of non-Central Appalachian coal DEP is able to consume; (3) performance of contract deliveries by suppliers and railroads, which may not occur despite DEP’s strong contract compliance monitoring process; (4) changes in transportation rates; and (5) potential additional costs associated with suppliers’ compliance with legal and statutory changes, the efforts of which can be passed on through coal contracts.
“DEP’s current natural gas burn projection for the billing period is approximately 151 MMBtu, which is a decrease from the 176 MMBtu consumed during the test period. The current average forward Henry Hub price for the billing period is $2.71 per MMBtu, compared to $2.44 per MMBtu in the test period, resulting in the Company’s decreased natural gas consumption projection. Although the price of natural gas is currently projected to increase slightly, gas markets remain in a near historically low price environment which will affect actual burns.”
Coal still has a major share of the company’s capacity
Other June 22 testimony came from Joseph A. Miller Jr., the 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 9,378 MW of generating capacity, made up as:
- Coal-fired – 3,544 MW;
- Combustion Turbines – 2,943 MW;
- Combined Cycle Turbines – 2,620 MW;
- Hydro – 227 MW; and
- Solar – 44 MW.
The 3,544 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 NOx control, 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 coal units, their capacity and their dispatch designations are:
- Asheville Unit 1, 191 MW, cycling;
- Asheville Unit 2, 187 MW, cycling;
- Roxboro Unit 1, 379 MW, cycling;
- Mayo Unit 1, 735 MW, intermediate;
- Roxboro Unit 3, 694 MW, intermediate;
- Roxboro Unit 4, 703 MW, intermediate; and
- Roxboro Unit 2, 672 MW, baseload.
DEP has a total of 35 simple cycle combustion turbine (CT) units, the larger 14 of which provide 2,201 MW, or 75% 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 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 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 company’s hydro fleet consists of 15 units providing approximately 227 MW of capacity. The company’s solar fleet consists of three sites providing 44 MW of capacity.
Changes within the company’s portfolio since the 2015 fuel and fuel-related cost recovery proceeding include the addition of 208 MW of capacity from the purchase of the North Carolina Eastern Municipal Power Agency‘s (NCEMPA’s) portions of the coal-fired Roxboro Unit 4 and Mayo Unit 1, bringing DEP’s ownership to 100% of both units. The company has also added three solar sites (Warsaw, Fayetteville, and Camp Lejeune) with a total of 101 MW of nameplate capacity, providing 44 MW of utility equivalent capacity, and retired Darlington CT Unit 11 in November 2015, reducing capacity by 52 MW.
For the test period, DEP’s total system generation was 63,238,795 MW hours (MWHs), of which 34,943,002 MWHs, or approximately 55%, was provided by the fossil/hydro fleet. The breakdown includes 36% contribution from gas facilities, 18% contribution from coal-fired stations, approximately 1% contribution from hydro facilities, and less than 0.1% from solar facilities.