New EPA rules endanger Duke Energy Indiana coal usage

As a result of emerging environmental regulations such as the Cross-State Air Pollution Rule, which is due to take effect Jan. 1, 2012, Duke Energy Indiana currently projects much higher fuel costs and lower coal consumption levels for calendar year 2012 at its aging Wabash River plant.

Elliott Batson Jr., the Vice President, Regulated Fuels at Duke Energy Business Services LLC, a subsidiary of Duke Energy Corp. (NYSE:DUK) , outlined the latest fuel considerations for Duke Energy Indiana in a Nov. 4 fuels filing at the Indiana Utility Regulatory Commission.

Due to the impending compliance requirements for CSAPR, Duke has competitively sourced supplies of lower sulfur coal for Wabash River, Batson said. Duke Energy Indiana continues the testing of lower sulfur fuels at Wabash River, with the intent of drawing down inventories of mid-sulfur coal at that station in the fourth quarter of 2011 and replacing that coal with a lower sulfur coal for compliance with CSAPR effective Jan. 1, 2012.

In addition, the company projects an overall increase in coal costs as of Jan. 1,2012, due to the expiration of one long-term coal contract with an unnamed supplier at the end of 2011 and the market re-pricing of a second, long-term coal contract effective Jan. 1,2012. “These two contracts have provided value to the customer over the past several years through pricing provisions that have been consistently below the published market pricing for such coals,” Batson noted.

The Gibson, Wabash River and Cayuga power plants are supplied by long-term coal agreements for more than 90% of their annual requirements. Gallagher is supplied under a short term contract of one year or less and can be supplemented by spot purchases when demand for electricity is high and Gallagher consumes more coal than projected.

For the twelve-month period ended Aug. 31, Duke Energy Indiana purchased about 13.15 million tons of coal under both long- and short-term contract commitments at an approximate average cost of $2.36/mmBTU. The delivered cost of coal purchased under long-term commitments averaged $2.35/mmBTU and made up greater than 97% of total coal receipts. The delivered cost of coal purchased under short-term deals averaged $2.56/mmBTU.

Central Appalachia is a primary coal-producing region for low-sulfur coal, but that coal supply continues to decline due to: EPA efforts to limit the issuance of Clean Water Act permits for new surface mines and above-ground operations, tougher U.S. Mine Safety and Health Administration inspections that constrain deep mine productivity; and coal producers shifting investment resources to either more profitable metallurgical coal production or to coal production in other basins, Batson said.

Competition grows for Illinois Basin coal

Due to the Central Appalachian production concerns and market dynamics, as well as increased competition from natural gas generation, many Eastern and Southeastern utilities have shown increased interest in and demand for Illinois Basin coal, which has long been a primary coal for Duke Energy Indiana.  The utility has particularly relied on in-state Indiana coal supplies and suppliers.

“Several eastern and southeastern utilities that typically consume Central Appalachian or Northern Appalachian coals are currently evaluating the use of or have already made a switch to the use of Illinois Basin coals,” Batson said. “In addition, the global export market has begun to show a keen interest in Illinois Basin coals. Together, these developments are encouraging new mine development in the Illinois Basin.”

Recently published data indicates that increasingly larger shares of coal produced in the Illinois Basin is going to locations other than states in the basin itself, which are Illinois, Indiana or Kentucky. For example, from 2007 through the first half of 2011, the portion of Illinois Basin coal shipped to states outside of the three-state region that comprises the Illinois Basin increased from 26% to 30%, while the portion going to industrial applications and the export market more than doubled, from 9% to 19%. The story for coal produced in Indiana is similar, with coal shipping to other states more than doubling, from 8% to 17%, while that share going to industrial applications and to the export market increased from 9% to 14%.

Published market spot prices for high-sulfur Illinois Basin coal have remained relatively flat for the past quarter, with prices trending between $46 and $48 per ton, Batson said. ”Conversely, spot pricing for the other major coal basins, including the Western Coal basins, has trended higher in the past quarter. Central Appalachian and Northern Appalachia spot prices have risen to greater than $80 and $77 per ton, respectively. Powder River basin coal prices have risen from approximately $13 per ton in June 2011 to approximately $15 per ton in early October.”

The utility continues to maintain the Gallagher coal inventories slightly below target levels in anticipation of the potential retirement of two units there in early 2012, Batson noted.

Two Gallagher units to get shut or converted

John Swez, the Director, Regulated Portfolio Optimization at Duke Energy Business Services, said in companion Nov. 4 testimony that a clean-air consent decree worked out a few years ago with the U.S. EPA may force the shutdown of those two Gallagher units. The impacted units under the decree are Wabash River units 2, 3 and 5, and Gallagher units 1 and 3. Under the consent decree, these units are being operated under pre-project New Source Review baseline levels to limit annual emissions. This restriction did not impact the units’ generation in 2010 and is not impacting the units’ generation in 2011, Swez noted.

To reflect the correct variable cost for Gallagher units 2 and 4, which got recent dry sorbent injection scrubbing equipment added to control SO2 emissions, as of Dec. 1, 2010, the impact of dry sorbent injection costs was added to the dispatch price for these units, resulting in a slight increase to the dispatch cost.

CSAPR created four new interstate trading markets, with Indiana a member of three. These three markets are for Annual NOx, Seasonal NOx, and Group 1 S02 allowances. “The allocation levels associated with this rule will require significant reduction in emissions and the market prices associated with the allowances are likely to be considerably higher than emission allowance prices seen in recent years,” said Swez. “The EPA’s initial price estimates for 2012 allowances were approximately $1,000 for Group 1 S02, $500 for Annual NOx, and $1,300 for Seasonal NOx. Market prices have been extremely volatile since the rule was announced and are likely to remain so for the near future. Preliminary model runs show significant reductions in capacity factor are possible at non-scrubbed generating units. These results are preliminary, however, and significant changes in forecasted capacity factors can occur by changing data inputs.”

Duke Energy Indiana is seeking permission from the commission to buy part of a gas-fired merchant power plant of Duke Energy Vermillion II LLC, which would replace power lost from the potential shutdown of the coal-fired Gallagher units 1 and 3. Under the consent decree in the NSR lawsuit, the company must make a final decision by Jan. 1, 2012, on whether Gallagher units 1 and 3 will be converted to natural gas or retired. If it is approved to buy a portion of the Vermillion plant and the decision is made to retire the units, they must be retired by the end of January 2012. Gallagher units 1 and 3 are both rated for 140 MW each. The total summer rated capacity of the Vermillion units is 568 MW, with the company wanting to buy 62.5%, or 355 MW of additional summer capacity.