On July 26, the North Carolina Utilities Commission approved a March 9 application from Duke Energy Carolinas LLC for approval of fuel and fuel-related cost adjustments, with fuel testimony coming from Duke official Swati V. Daji.
The test period for purposes of this proceeding is the 12 months ended Dec. 31, 2015. The billing period is September 2016-August 2017.
Said the July 26 order: “According to witness Daji, the Company’s average delivered coal cost per ton for the test period was $89.72 per ton, compared to $91.72 per ton in the prior test period, representing a decrease of 2%. This includes an average transportation cost of $27.66 per ton in the test period, compared to $32.11 per ton in the prior test period, representing a decrease of approximately 14%.
“Witness Daji stated that 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 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 installation of new 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 on-going financial viability of many of the Company’s coal suppliers.
“She also testified, however, that at the same time, the nation’s natural gas supply has grown significantly and has outstripped demand. Over the longer term planning horizon, overall gas supply is forecasted to continue to grow, and currently observable forward market prices are at 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.
“Witness Daji stated that DEC’s coal burn for the test period was 9.8 million tons, compared to a coal burn of 12.0 million tons in the prior test period, representing a decline of 18%. Additionally, the 9.8 million tons burned in the test period represents a 23% decline compared to the average annual coal burn over the prior five-year period of over 12.7 million tons. The decline in coal burns in the test period is attributable to declining natural gas prices combined with milder than forecasted weather in the latter half of the test period.
“Witness Daji stated that DEC’s current coal burn projection for the billing period is 11.9 million tons compared to 9.8 million tons consumed during the test period. DEC’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.
“DEC’s inventory levels were above target at the end of 2015, and future actual inventory levels may be above target levels at the end of 2016 as well. Combining coal and transportation costs, DEC projects average delivered coal costs of approximately $68.75 per ton for the billing period compared to $89.72 per ton in the test period. Witness Daji testified that 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 DEC is able to consume; (3) performance of contract deliveries by suppliers and railroads which may not occur despite DEC’s strong contract 12 compliance monitoring process; (4) changes in transportation rates; and (5) potential additional costs associated with suppliers’ compliance with legal and statutory changes, the effects of which can be passed on through coal contracts.
“Witness Daji also testified that the Company has implemented natural gas procurement practices that include periodic Request for Proposals (RFPs) and short-term market engagement activities to procure and actively manage a reliable, flexible, diverse, and competitively priced natural gas supply that supports DEC’s Buck and Dan River CC facilities and the Company’s combustion turbine (CT) facilities. The Company procures long-term firm transportation to support its natural gas needs at its generating facilities. In addition, as needed, DEC may procure shorter-term firm pipeline capacity through the capacity release market, as well as delivered market supply options that provide the needed natural gas supply to its generating facilities.
“According to Witness Daji, through the Asset Management and Delivered Supply Agreement (AMA) between DEC and [Duke Energy Progress], which was implemented on January 1, 2013, DEC serves as the designated Asset Manager that procures and manages the combined gas supply needs for both utilities, and performs the necessary scheduling and balancing on the pipelines. DEC does not have an agreement for storage capacity, nor does it maintain an inventory of natural gas. DEP, however, does have a storage agreement which was released to DEC as part of the AMA.
“As the Asset Manager, DEC procures all the needed supply for the combined Carolinas gas needs, and as part of the AMA, has access to the released storage agreement. On any given day, DEC may utilize the storage to balance and support the Carolinas gas needs.
“Witness Daji further testified that the Company’s natural gas consumption is expected to continue to increase. The Company’s natural gas burn for the test period was 76.8 billion cubic feet (Bcf), compared to a gas burn of 55.7 Bcf in the prior test period, representing an increase of 38%. DEC’s current natural gas burn projection for the billing period is approximately 84 Bcf, which is an increase from the 76.8 Bcf consumed during the test period. The current average forward Henry Hub price for the billing period is $2.69 per MMBtu, compared to $3.97 per MMBtu in the test period. Currently, spot and forward market prices for natural gas remain at historically low levels which have resulted in the Company’s increased natural gas consumption projections.”