Duke Energy Indiana has no luck beating down stubborn coal piles

Duke Energy Indiana has had no luck lately burning down stubborn coal inventories, with inventories standing at 3.225 million tons (53 days of supply) as of July 25, and at basically that exact same level as of Oct. 3.

“Duke Energy Indiana still expects coal inventories to increase through the remainder of 2012 and into 2013 because of existing contractual commitments,” said Elliott Batson Jr., Manager, Coal Procurement by Duke Energy Business Services LLC, a service company subsidiary of Duke Energy (NYSE: DUK). The utility on Nov. 1 filed testimony from Batson and others at the Indiana Utility Regulatory Commission in support of its latest fuel adjustment clause case.

Batson noted that the Gibson, Wabash River, Cayuga and Edwardsport IGCC plants are supplied by long-term coal agreements. Gallagher will be supplied by contract and/or spot purchases throughout the remainder of 2012 depending on how much the Gallagher units operate.

For the twelve-month period ended Aug. 31, the company purchased a total of about 11.8 million tons of coal (under both long- and short-term commitments) at an average cost of $2.66/mmBtu. The delivered cost of coal purchased under long-term commitments averaged $2.66/mmBtu and made up 99% of total coal receipts. The delivered cost of coal purchased under short-term commitments averaged $2.63/mmBtu.

“Published market prices for U.S. coal markets have not changed significantly since the last fuel proceeding,” Batson reported. “High-sulfur Illinois basin coal prices remain in the upper $30s per ton for prompt delivery and for 2013 delivery. Central Appalachia coal prices remain in the mid $60s for prompt and 2013 delivery. The northern Appalachia and Powder River coal basin market prices continue to be depressed from Summer 2011 prices. The biggest drivers for these flat coal market prices are low natural gas prices and published reports of surplus amounts of coal inventories in stockpile at most U.S. power plants.”

In the near term, the company sees: the continued decline in U.S. steam coal supplies; a slumping global coal market; low natural gas prices (leading to displacement of coal-fired generation; healthy utility coal inventories; and volatile power prices. “Coal markets are likely to be relatively stable in the near term; however, looking forward, we see potential for market volatility as market uncertainties continue and coal suppliers continue to cut production and bring supply into balance with demand,” Batson wrote.

The company continues to evaluate a host of options in order to manage coal inventories. It has entered into a short-term storage agreement with one supplier to store coal at the supplier’s mine facilities and began storing coal at this location during September. The company has also shaped and compacted the Gibson Remote Pile adjacent to Gibson station for receipt of additional coal for storage and continues to actively explore options to resell surplus coal into the market, Batson reported. “However, due to continued weak coal market conditions, resell opportunities will continue to be extremely difficult in the near term,” he added.

Price decrement program begun in February has boosted coal usage

John Swez, employed by Duke Energy Business Services as Director, Fuels & Systems Optimization, described in companion Oct. 31 testimony the impacts of being in the Midwest ISO on the company’s generation, including its coal-fired plants. He noted that the company frequently designates the commitment status of its most economic coal-fired units and the economic coal-fired units with long start up times as “must-run.”

“If a generation owner wants to limit the number of times a generating unit will move through a mill point (the point at which a mill has to be turned on to bring coal to a boiler), the owner can self-schedule the unit to operate above that mill point by updating the real-time generating unit offer for the unit,” Swez added. “MISO, utilizing all self-scheduled generator information as offered, will then perform an incremental dispatch to meet the remaining demand requirements taking into consideration reliability concerns. All of these activities described above are generally referred to as self-scheduling. It should be noted that there is no ‘one size fits all’ approach in submitting a generating unit’s day-ahead or real-time energy offer to MISO. In making the decision regarding an individual unit’s offer status, the Company considers various factors such as forecasted locational marginal prices (‘LMP’), unit generation production cost, MISO cost impact (revenue sufficiency guarantee make-whole payments, real-time price volatility make whole payment amount, real-time revenue sufficiency guarantee first pass distribution, etc.), and the capability and economic impact from cycling the generating unit off-line and/or on-line. Before making any generation unit offer, Company personnel engage in a planning process designed to minimize the total customer cost by maximizing each unit’s economic value.”

A number of factors, including unforeseeably low natural gas prices, an extremely mild 2011-2012 winter, increased wind generation, and other factors caused the energy price in the MISO market to drop in 2011 and into the first half of 2012, causing the company’s coal facilities to experience lower dispatch levels and even periods of economic shutdown which led to increased coal inventories, Swez noted.

“To remedy this situation, the Company started applying a coal price decrement,” he added. “Starting in late February 2012, a price decrement was applied to the dispatch costs of Gibson 1-5, Wabash River 2-6, and Cayuga 1-2 generating units to correctly reflect the economics of additional costs associated with avoiding or reducing surplus coal inventories. To the extent that the price decrement results in units being dispatched that otherwise would not be, coal coming into the station is consumed, other potential costs are avoided, and customers ultimately benefit because higher cost alternatives to manage the inventory are avoided. With the price decrement in place, the Company has seen a significant increase in generation output from these units.”

He continued: “In short, the price decrement is working as designed. It should be noted that on specific hours and days, the price decrement will have no impact on the commitment and dispatch of the Company’s generating units because the unit in question was already economic without application of the price decrement. In other words, the price decrement doesn’t make a difference under certain circumstances. For example, if a generating unit had a non-decremented dispatch price of $30/MWhr and an as offered price of $25/MWhr after application of a $5/MWhr price decrement, in an hour in which the LMP was $40/MWhr the application of the price decrement had no impact on the unit’s output because the unit would be at full load in either circumstance and, thus, the customer was not impacted as a result of the price decrement.”

Due to a hot summer of 2012, this situation has become a more frequent occurrence that one would expect due to higher demand across MISO, Swez added. “Finally, in the situation where a generating unit had a non-decremented dispatch price of $30/MWhr and an as offered price of $25/MWhr after application of a $5/MWhr price decrement, in an hour in which the LMP was $28/MWhr the application of the price decrement would have an impact on the unit’s output. The unit would likely be committed as a result of the price decrement and be dispatched to full output. The customer would be charged the actual fuel cost of $30/MWhr needed to run the unit, with the customer saving $3/MWhr on the $5/MWhr cost to dispose of the coal from the price decrement.”

Hot summer and low water caused two coal plants to derate

Significant derates and outages occurred during the summer of 2012 at Wabash River and Cayuga to comply with the company’s NPDES water permit limits at each station, Swez said. These restrictions limit the discharge of hot water into the Wabash River at these plants. The river is running very low due to the heat and drought. “It should be noted that the thermal derates and outages experienced this summer have prevented these units from running as expected and contributed to the surplus coal situation,” he added.

The price the company paid for delivered natural gas at its gas-fired stations increased slightly but stayed at relatively low levels during the period of June through August 2012 with a range of delivered gas prices between a low of about $2.30/MMBTU in June to a high of $3.40/MMBTU in August, Swez reported.

Wenbin (Michael) Chen, employed as Manager, Portfolio Optimization, by Duke Energy Business Services, provided additional details on gas price hedging. “Duke Energy Indiana relies more on natural gas for fuel for the Company’s peaking plants than it has in the past,” Chen noted. “In addition, natural gas prices have historically been volatile. From March 2006 through August 2012, prompt month natural gas prices have ranged from around $1.91 to nearly $13.58 per Mmbtu. Furthermore, because Duke Energy Indiana’s natural gas needs are somewhat linked to weather, the Company is further exposed to such fluctuations in natural gas prices. The natural gas market is highly visible and liquid and there are a number of hedging tools available to help protect against such price fluctuations. In my opinion, it only makes sense for the Company to take advantage of these tools.”

Chen added that Duke Energy Indiana also hedges purchased power prices. “Power prices have been volatile since the beginning of the [MISO] energy markets in April of 2005. Through the end of August 2012, the average peak daily Indiana Hub, and CIN Hub before 1/1/2012, Real Time LMP was $49.01/MWH. However, there was a wide range of prices, from as low as $18.59/MWH to as high as $221.21/MWH. There were 55 days in the same period that we experienced daily peak power prices of higher than $100/MWH. Moreover, we observed hourly Indiana Hub, and CIN Hub before 1/1/2012, Real Time LMP over $100/MWH in every month since April of 2005, with the highest LMP at $1,080.28/MWH and the lowest at negative $242.96/MWH. The highest price of $1,080.28 was set, during this FAC period, at hour ending 1400 July 5,2012. To help hedge against this volatility, if the position warrants, the Company enters into forward power purchase contracts that are financially settled on a specific future date at MISO Indiana Hub Real Time and Day-Ahead LMPs.The applicable LMPs on the settlement date for these contracts may be higher or lower than the price the Company paid for the forward contract and the Company will either payor be refunded the difference.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.