Duke Energy Indiana’s coal-fired Gallagher plant will be supplied by spot purchases, if any, throughout the rest of 2012 because higher per-unit fuel costs, low forward power prices and the retirement of two units at the end of January mean the remaining Gallagher units will operate infrequently.
Elliott Batson Jr., Vice President, Regulated Fuels at Duke Energy Business Services LLC, a service company subsidiary of Duke Energy (NYSE: DUK), and a non-utility affiliate of Duke Energy Indiana, described the coal situation in April 30 fuel adjustment clause testimony filed at the Indiana Utility Regulatory Commission.
The Gibson, Wabash River, Cayuga plants, and, most-recently the Edwardsport IGCC plant, are supplied by long-term contracts for more than 90% of their annual requirements. For the twelve-month period ended Feb. 29, the company bought about 12.4 million tons of coal (under both long- and short-term commitments) at an average cost of $2.55/mmBtu. The delivered cost of coal purchased under long-term commitments averaged $2.54/mmBtu and made up greater than 98% of total coal receipts. The delivered cost of coal purchased under short-term commitments averaged $2.65/mmBtu.
The vast majority of spot coal purchased during the twelve-month period was for Gallagher. The delivered spot price for Gallagher is higher than Duke Energy Indiana’s long-term contract coal due to the fact that Gallagher is subject to New Source Review (NSR) compliance requirements and must burn coals with a much lower sulfur content and a higher price tag.
“Published market prices for all coal basins have decreased significantly over the last six months,” Batson noted. “High-sulfur Illinois basin coal prices are trending down from the upper $40’s during late Summer of 2011 to the upper $30’s per ton for prompt delivery and low $40’s for 2013 delivery. Central Appalachia coal prices have decreased from approximately $80 per ton during late Summer of 2011 to the mid $50’s per ton for prompt delivery. The Northern Appalachia and Powder River coal basin market prices have decreased significantly as well. The biggest drivers for these pricing changes are sharply falling natural gas prices and extremely mild weather this past winter that have led to significant reductions in coal generation.”
According to recent reports, the national coal burn for December 2011 through February 2012 was more than 23% below average, Batson said. Overall utility inventories grew by as much as 22 million tons in the United States over these same three winter months (as compared to a typical average decrease of 15 million tons). According to the same reports, coal inventories at U.S. power plants as of the end of February are more than 45 million tons above normal.
“Looking forward, we continue to see volatility in the coal markets, with such driving forces being: (a) the decline of the Central Appalachian steam coal supplies, (b) the growth of Illinois Basin coal production, (c) uncertainties around the export market, (d) low natural gas prices, (e) declining power prices, and (f) uncertainties associated with compliance requirements for the Cross-State Air Pollution Rule [CSAPR] and other environmental regulations,” Batson wrote. “Several suppliers have conveyed plans to reduce 2012 coal production in light of lower U.S. coal demand, including recent announcements by Alpha Natural Resources, Patriot Coal and CONSOL Energy; this will further impact coal market conditions. History has shown that small imbalances in coal supply and demand can cause large changes in coal market prices.”
Coal burn drops 45% in December 2011-February 2012 period
Due to increasingly lower power prices and reduced demand for coal generation, Duke Energy Indiana’s coal burn projections for 2012 have been adjusted downward. For example, coal burn for Duke Energy Indiana stations in December 2011 through February 2012 were about 45% less than the coal burn compared to the same months over the prior five years. If natural and power prices continue to be depressed, there likely will be further downward pressure on Duke Energy Indiana’s coal generation.
Duke Energy Indiana’s coal inventories as of Feb. 15 had grown to about 3.8 million tons (over 60 days of coal supply at a full load burn rate per day) across the system, including more than 450,000 tons in storage at the Gibson Station remote pile. From Dec. 1, 2011, through Feb. 15, 2012, coal inventories increased by about 800,000 tons, a period of time in which historically inventories have decreased. As of April 11, coal inventories were around 3.6 million tons (the equivalent of 58 days of coal supply).
The reduction in inventory is due to increased coal burns since the implementation of a coal price decrement on Feb. 24, as well as reduced coal shipments over this time period. However, based on the company’s latest forecast for coal generation, Duke Energy Indiana expects coal inventories to increase through the remainder of 2012 and into 2013. A decrement is basically a way for Duke Energy Indiana to subtract the money it loses when a plant doesn’t run from its bid price for that power into the Midwest ISO regional power market, making that generation more competitive.
The company has entered into an agreement with an Indiana supplier for low-sulfur coal to be delivered in 2012 to comply with CSAPR. Upon the stay of CSAPR by a federal court last December, the company evaluated its options related to this relatively small volume of coal. Currently, Duke Energy Indiana has placed some of the low-sulfur coal in storage at a river terminal for possible resale, and the rest has been shipped to Gibson for consumption. “We continue to evaluate the best options for future deliveries, including ongoing negotiations with the coal supplier about cancellation of future 2012 deliveries,” Batson added.
Duke Energy Indiana has met with each of its long-term suppliers in Indiana to discuss deferral, cancellation and other commercial and operational options to decrease the shipments for 2012. In addition, it has completed a survey to determine the maximum storage capabilities at all of its stations. Duke Energy Indiana shaped and compacted the existing Gibson remote pile adjacent to Gibson station for receipt of additional coal for storage. It also has explored options to increase the storage capabilities at both on-site and off-site facilities, including a possible second Gibson remote pile. The company has also been exploring the option to resell surplus coal into the market. Finally, the company is considering its options to buy out of the existing contracts or to pursue other legal options.
Vermillion gas capacity replacing shut Gallagher coal units
John Swez, who works at Duke Energy Business Services as Director, Regulated Portfolio Optimization, described in his own April 30 testimony the impacts of closing two Gallagher coal units due to a New Source Review settlement worked out some time ago with the U.S. Environmental Protection Agency.
“Under the Consent Decree reached in the NSR lawsuit, the Company was required to make a final decision by January 1, 2012, concerning whether Gallagher units 1 and 3 would be converted to gas or retired,” he wrote. “As a result of the Company receiving approval for the purchase of a portion of the Vermillion Plant, the decision was made to retire the units. Accordingly, Gallagher units 1 and 3 were retired on January 31, 2012. Gallagher Unit 1 and Unit 3 fuel oil and coal systems have been partially demolished and are permanently blanked off at the coal bunkers and fuel oil pumps. Coal feed tubes, feeders, mill discharge piping, and torches have been removed. In addition, the fuel oil supply has been closed off at the pumps.”
Gallagher units 1 and 3 were both rated for 140 MW each for a total capacity of 280 MW. The total summer rated capacity of the Vermillion II LLC gas-fired units is 568 MW (71 MW/unit) of which the company acquired 62.5%, or 355 MW of additional summer capacity. The additional capacity from acquiring Vermillion II LLC is slightly larger than the lost capacity from retirement of Gallagher units 1 and 3. Vermillion CT’s 1-8 began successfully participating in MISO’s markets as Duke Energy Indiana generating units, jointly owned with Wabash Valley Power Association, on Jan. 12.
Swez also offered an update on the price decrement program mentioned by Batson. “Starting in late February 2012, a price decrement was applied to the dispatch costs of Gibson 1-5, Wabash River 2-6, and Cayuga 1 generating units to correctly reflect the economics of additional costs associated with avoiding or reducing surplus coal inventories,” he said. “To the extent units are dispatched with the price decrement in place that otherwise would not be dispatched, coal coming to the station is consumed, other potential costs are avoided, and customers ultimately benefit because options with a higher cost are not incurred. With the price decrement in place, the Company has seen a significant increase in generation output from these units. In short, the price decrement is working as designed.”