Wisconsin Electric Power has been re-selling coal out of inventory to iron-ore processors and this program is a prudent method of disposing of the utility’s unwanted coal, said WEPCO’s Mary Wolter.
The Wisconsin Public Service Commission is currently reviewing WEPCO’s joint application with Wisconsin Gas LLC, which both d/b/a We Energies, to conduct a biennial review of costs and rates for test year 2013. We Energies is part of Wisconsin Energy (NYSE: WEC).
Rebuttal testimony from Wolter, who is WEPCO’s Manager-Fuel Cost Planning, was filed Sept. 20 at the commission in response to the direct testimony of PSCW staff witness James Wagner and the Citizens Utility Board witness Richard Hahn with regards to monitored fuel costs for the 2013 test year and coal sales revenues.
One issue covered by Wolter is cost accounting related to re-sales of coal to Tilden Mining and Empire Iron Mining Partnership (collectively the “Mines”). “The Company has been increasing natural gas combined cycle generation and reducing generation at its coal plants in 2012 in reaction to shifts in market price trends for natural gas and coal and lower than forecasted sales growth and overall generation,” Wolter noted. “In order to accommodate reduced coal burns and minimize their impact on coal inventory costs, some contract buydowns were negotiated and purchases of coal have been deferred from 2012 until 2013.”
A detailed analysis of the costs and benefits of the coal contract buydowns in 2012 was filed with the Federal Energy Regulatory Commission. FERC approval of the contract buydown payments and accounting was received on Aug. 15.
“The Mines, who also have some fuel flexibility, have a contract requiring an annual nomination of purchases of coal from the Company subject to an 80% minimum purchase requirement,” Wolter explained. “The current nomination extends through March, 2013. Because the nomination extends into 2013, some of those purchases have been from WEPCO’s coal under contract from 2012 and some could potentially be from coal under contract in 2013. The 2012 coal is approximately $8/ton more expensive than the 2013 coal.”
Because of the price difference, the PSC staff was concerned that if the Mines shifted their purchases from 2012 until 2013 the coal market price difference could be shifted to other customers. They made a $1.7m adjustment to the Wisconsin fuel costs in this proceeding as a placeholder pending assurance from WEPCO that Wisconsin customers are not subsidizing coal sales to the Mines’ in the ratemaking process. “Based upon my review of the facts, I do not believe that a subsidy exists,” Wolter wrote.
This is longtime contract coal from Peabody and Cloud Peak
The coal in question was originally purchased under long-term contracts (circa 2008) to meet the needs of WEPCO’s native load in Michigan and Wisconsin. Sales of coal to third parties were not factored into the contractual purchase quantities, leaving the costs of all of the coal inventories properly attributable to the ratepayers, Wolter noted. To the extent there are excess coal inventories that can be sold to third parties, WEPCO performing a valuable service to the ratepayers by selling that excess, Wolter added.
By way of background, Wolter noted that coal for the Presque Isle plant comes from two mines, the North Antelope Rochelle Mine (NARM) in Wyoming of Peabody Energy (NYSE: BTU) and the Spring Creek mine in Montana of Cloud Peak Energy (NYSE: CLD). The Oak Creek plant also uses coal from NARM.
The utility’s purchase contracts for the NARM coal for Oak Creek and Presque Isle were executed in 2008 for the years 2010-2012 based upon the forecasted generation needs of those plants. The volumes under contract for NARM and Spring Creek coal were not predicated on selling any coal to third parties. The agreement with the Mines calls for a coal price based upon a blend of 55% NARM and 45% Spring Creek coal.
Buying this coal from WEPCO helps the Mines keep overall costs down. “Purchasing from coal suppliers in small quantities would increase their commodity purchase prices and coal dock and transportation costs,” Wolter noted.
If its own coal burns have been or are expected to be higher than originally predicted, WEPCO picks up additional spot market purchases to fulfill the third party sales nomination, preserving the inventory quantities on-hand for use in its own utility generation, Wolter pointed out. “In such a period of high coal demand, we might presume that coal prices would be rising so the Company would want to keep its inventories for its own customers.”
Wagner’s $1.7m adjustment is based upon an estimated $8 per ton decrease in the market price of coal times 215,000 tons. Because the adjustment is thought to capture the inventory effect of WEPCO deferring the purchase of 250,000 tons of coal from the 2012 contract year to 2013, Wagner’s use of 215,000 tons in his calculation is apparently meant to represent the portion attributable to the Wisconsin jurisdiction, Wolter said.