Progress Energy Carolina‘s delivered cost of coal for the year ended Feb. 29 increased by about $10 per ton (12%), as compared to the prior review period, to $91.11 per ton, in part because it bought more coal from outside of nearby Central Appalachia.
This increase in delivered coal price versus the prior review period was equally attributable to the cost of coal and to the cost of coal transportation, said Bruce Barkley, Manager-Fuel Forecasting and Regulatory Support for Progress Energy Carolinas (PEC). Testimony from Barkley was filed with the South Carolina Public Service Commission on May 9 as part of an annual fuel cost review case. PEC is a unit of Progress Energy (NYSE: PGN).
Transportation costs increased in the most recent review period due to: higher oil costs for locomotives which were passed along by PEC’s traditional suppliers; and PEC purchasing coal from the Illinois Basin (ILB) and Northern Appalachia (NAPP), which are farther from PEC’s generating plants than is the traditional source of supply from Central Appalachia (CAPP). Coal from these more distant sources is currently less expensive than CAPP coal, Barkley noted.
Coal costs increased as compared to the review period ended Feb. 28, 2011, primarily as a result of contract expirations. PEC consumed 9.3 million tons of coal during the one-year review period ended Feb. 29 and purchased 10.2 million tons. Coal in inventory jumped, from 1.5 million tons on Feb. 28, 2011, to 2.5 million tons as of Feb. 29 of this year.
During the current review period ended Feb. 29, coal market prices in the CAPP region declined from about $70 per ton to about $55 per ton. ILB prices declined from around $53 per ton to about $40 per ton. This was primarily due to a mild winter, significant declines in the price of natural gas, mixed domestic economic indicators and less demand for coal exports. The reduced demand for coal resulting from these factors led to high levels of coal inventory by the end of the review period, Barkley noted.
Coal industry hit with regulations from many different directions
The U.S. coal industry currently faces uncertainty due to numerous federal regulatory initiatives, including the Cross-State Air Pollution Rule, Mercury and Air Toxics Standards, carbon emissions and coal ash rules that impact coal-fired power plants, plus mine safety and water quality initiatives that hit coal mines directly, he wrote. “While these initiatives are in various stages of judiciary review and development by the U.S. Environmental Protection Agency, utilities are preparing to reduce emissions. This uncertainty and increasing regulation has resulted in the announcement of coal-fired electric generating plant closures and retrofits that will likely reduce future coal demand and shift the location of supply sources.”
Producers within the CAPP region continue to be affected by declining coal reserves which increases mining costs. The development of new coal supplies is negatively impacted by the difficulty of obtaining permits from the federal government due to water quality concerns associated with surface mining. “As a result of this challenging environment, several major coal producers within the CAPP region have announced planned production cuts,” Barkley said. “These trends threaten the existence of certain coal mining companies and promote additional consolidation within the industry.”
The current market price has little influence on the delivered cost of coal at PEC for the review period because almost all of the coal was received under contracts that were signed prior to the market decline that began in the fall of 2011. The contracts in effect during the prior review period had a lower average cost than those in effect during the current review period.
Coal prices due to go up – maybe
Asked about PEC’s expectations for coal market conditions during the forecasted period ending June 30, 2013, and beyond, Barkley wrote: “[T]he market price of coal is expected to increase during the remainder of 2012 and throughout 2013. The timing of such increase is subject to a myriad of factors that are difficult to predict including weather, the health of both U.S. and international economies, natural gas prices, judicial review of EPA proposals and the upcoming presidential election. PEC’s cost per ton of coal consumed during the forecasted period is expected to remain relatively consistent with cost incurred during the review period, primarily due to PEC’s policy of utilizing coal contracts generally ranging from one to three years in duration. As contracts expire, they will be replaced by contracts at current market values. Over time, the market price of coal is expected to increase and to exhibit volatility as it has done historically.”
Morgan Stanley Research has estimated that thermal coal production within CAPP will decline from about 200 million tons in 2002 to around 100 million tons in 2012 and then to approximately 25 million tons by 2020, Barkley wrote. More abundant NAPP and ILB coals can fill some of that gap. “These coals present transportation and plant performance challenges for many companies such as PEC who have historically relied on a low to moderate sulfur coal from the CAPP region,” Barkley said about ILB and NAPP coals. “As a result of the projected price relationship and the declining supply within CAPP, PEC is actively expanding its usage of coals from these regions.”
During the review period, PEC procured about 3 million tons of coal (30% of total) from non-traditional supply locations or that possessed characteristics that were not typical of PEC’s historical coal supply. Characteristics of these coals include lower heat content, higher sulfur content, higher ash content and a lower melting point, known as ash softening temperature, than PEC’s traditional CAPP supply.
The process for evaluating non-traditional coals involves several steps including computer based modeling, short-term demonstrations and controlled tests lasting for a month or more. To date, PEC has invested approximately $68m to facilitate the handling and consumption of these coals. Expenditures were primarily directed to combustion improvements and mitigating the formation and collection of residue within boilers caused by the lower ash softening temperatures and higher ash content of these coals, and mitigation of chemical compounds produced by the combustion of higher sulfur coals that can cause boiler corrosion. Also, coal handling improvements were made in order to mitigate issues resulting from the increased fineness of some of the coals, Barkley wrote.
Coals from the ILB and NAPP as well as lower quality coals from CAPP were purchased at prices that were lower than PEC’s traditional supply. Further, the price per ton for coal from NAPP and ILB are forecasted to remain less expensive than CAPP coal. PEC has secured a significant amount of coal from these regions to be delivered during the forecasted period and will continue to do so if the economics remain favorable. “Further, PEC’s preparation for and selection of these coals created regional market competition that would not have existed otherwise,” Barkley noted.
PEC finds new routes to transport far-flung coals
Coal traditionally moves to PEC by rail using either the CSX Transportation or the Norfolk Southern railways. PEC takes a limited amount of coal by truck at the Asheville plant and has received foreign coal by barge at the Sutton plant located near Wilmington, N.C. Receipt points for coal delivered by rail are generally in the CAPP region, but can include coal delivered to the port at Charleston, S.C. Buys of coals from NAPP and ILB required new modes of transportation for PEC. PEC’s strategy for transporting these coals is to deliver them using river barges to locations in West Virginia and then use rail from those locations to PEC’s plants.
Natural gas market prices remained at low levels, at an average cost of about $3.70/mmBtu during the review period. Toward the end of the review period, natural gas prices fell below $2.50/mmBtu, which had not occurred since 2002. A major contributor to these low prices was the very mild winter, with U.S. degree days more than 15% below normal. Despite the low market prices and weak demand, natural gas production increased by 8% in 2011, the largest annual increase in history.
The market price of natural gas is projected at about $3/mmBtu during the forecasted period. Inventory levels are expected to remain high at least until the 2012-2013 winter heating season.