Consultant: Duke Energy Indiana needs to use coal hedging tools

Duke Energy Indiana should be required to use over-the-counter (OTC) coal trading tools, despite its reluctance to do so, since they would hedge factors like a recent low-sulfur coal contract that went bad due a court stay on the U.S. Environmental Protection Agency’s Cross-State Air Pollution (CSAPR), said consultant Richard Thomas.

Testimony from Thomas, who is working for Duke Energy Indiana (DEI) customer Steel Dynamics Inc., was filed June 6 at the Indiana Utility Regulatory Commission as part of a fuel adjustment clause (FAC) case begun this past spring. DEI is a unit of Duke Energy (NYSE: DUK).

Thomas said that DEI entered into a long-term, low-sulfur coal contract with a supplier whose name is redacted from the public version of his testimony. That coal was needed to comply with CSAPR. Then in December 2011, a federal court stayed the CSAPR program while appeals of the rule are argued. That stay is still in effect and so this relatively expensive low-sulfur coal is not needed for now. Due to the uncertainty of CSAPR’s final implementation, DEI should have purchased a call option for this coal rather than entering into a firm purchase contract, Thomas wrote.

“Call options for physical coal delivery are commonly traded either directly or via the Over the Counter (OTC) market and would have allowed the owner of the option (in this case, DEI) to purchase the coal at the time designated by the option or to allow the option to expire,” Thomas wrote. “DEI would have been required to pay a premium negotiated with the option seller for this right, however, the premium paid would have been small compared to the problems DEI now faces in disposing of this unwanted, expensive coal.”

DEI purchases the majority of its coal via long-term contracts with staggered expiration dates. The balance of its coal is purchased under spot deals. “Each year, the staggered expiring portion of the long term agreements plus any required spot purchases are subject to the vagaries of the marketplace,” Thomas wrote. “The portion of DEI’s long term contract portfolio which is due for replacement in any year and the spot purchases for that year, should be hedged well before the beginning of the year in order to protect against rising prices when the purchases are finally made. DEI’s fuels purchasing personnel did not use all available hedging tools that could have mitigated the effect of price volatility on the Company’s fuel costs since DEI does not financially hedge its coal purchases due to concerns regarding liquidity and transparency. Liquidity and transparency should not be considered detrimental to the use of OTC financial tools unless DEI is using too narrow a focus as to the underlying coal product.”

Thomas noted that the total domestic OTC and CME/NYMEX markets exceeded 300 million tons during 2011 and the international OTC market approaches 1 billion tons. “These large volumes show that liquidity has grown in both financial and physical OTC markets,” he argued. “The large numbers also show that coal is now considered a more fungible commodity since more than half of the traded volumes are financial products.”

He added: “While DEI purchases a majority of its coal in the Illinois Basin due to logistical efficiencies, there is a strong correlation between price movements in the Central Appalachian (CAPP) coals and the Illinois Basin coals. Financial hedging products for these CAPP coals are much more liquid than the financial hedging products available for the Illinois Basin and should, therefore be used until the Illinois Basin hedging volumes improve. No hedge is perfect and some price drivers may vary between the two coal producing areas, however, the aforementioned strong correlation in price movements allows DEI the ability to use the more liquid and transparent CAPP hedge products. Physical and financial hedges can be accomplished by a number of mechanisms including but not limited to (i) forward purchases, (ii) financial swaps, and (iii) call options.”

For example, a call option gives the owner of the option the right, but not the obligation, to purchase coal at a predetermined price (called the “strike price”). It provides a ceiling for pricing since the call option owner can exercise the option and take delivery at the strike price if market prices shoot higher than the strike price. “Using call options as a part of DEI’s buying portfolio could also relieve oversupply and high inventory problems caused by reduced coal demand such as those experienced by DEI during 2009, 2010 and currently,” Thomas wrote. “If coal demand is lower than expected, DEI would simply elect not to exercise its option to buy the option coal.”

Thomas: contract inflation indices just don’t cut it in all cases

DEI uses inflation indices in its long-term contracts, but Thomas said these indices are problematic if market prices are high when the contract is instituted such as was the case in 2008 when coal prices more than doubled in a matter of weeks. “When coal market prices are low (i.e., near cost of production), the use of inflation indices or fixed amounts to escalate long term contracts may be a logical choice for DEI,” he added. “However, when market prices have moved upward in a dramatic manner, such as during 2008, the use of inflation indices should not be used. Using inflation indices or fixed escalation amounts, such as DEI did in the cases of the aforementioned contracts denies the buyer (DEI in this case) the opportunity to benefit from a retrenchment in market prices. As the market recedes from its elevated level, the buyer will continue to pay the higher prices plus the inflation or fixed escalation.”

Thomas recommended two things to DEI and the commission:

  • DEI should immediately institute a financial hedging program to protect rate payers from adverse price movements in coal purchases. This program should include all available hedging tools, including but not limited to financial swaps, options (both physical and financial), and forward OTC purchases. “A financial hedging program can be implemented which will limit the negative effects of price spikes for the current year and at least two years forward, given existing tools,” he added. “If DEI had used physical option hedges during the test period, DEI would not be requesting rate payers to pay for the costs of disposing of the high priced coal purchased [from the redacted coal supplier]. Accordingly, the Commission should deny any such request made now or in the future.”
  • DEI should discontinue agreeing to or advocating the use of indices in long-term coal contracts. “While use of such indices may be a valuable tool when coal market conditions are low and prices are near the cost of coal production, the practice should not be utilized under all coal market conditions,” he added. “Had DEI fixed the high prices negotiated during 2008-2010 instead of agreeing to escalation provisions, the resulting 2011/2012 price would still be above the current market, but substantially lower than the prices being paid. This difference translates to $28,564,782 that DEI would not be asking rate payers to pay. Accordingly, the Commission should deny this amount on the basis of the unreasonable use of indices and fixed percentage escalators which resulted in coal costs that were higher than those reasonably possible.”

Duke Energy Indiana described coal situation in opening testimony

Elliott Batson Jr., Vice President, Regulated Fuels at Duke Energy Business Services LLC, a service company subsidiary of Duke, and a non-utility affiliate of Duke Energy Indiana, described the coal situation in April 30 testimony that opened this case. He didn’t mention OTC issues.

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, he wrote. 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.

“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.”

He added: “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 ResourcesPatriot 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. 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. 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 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, Batson noted, referring to the contract Thomas has issues with. Upon the stay of CSAPR by a federal court last December, the company evaluated its options related to this relatively small volume of coal. 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.

Indiana Consumer Counselor raises no issue about coal hedging

Michael Eckert, employed by the Indiana Office of Utility Consumer Counselor (OUCC) as a Senior Utility Analyst in the Electric Division, didn’t mention Duke Energy Indiana’s lack of a coal hedging program in his own June 5 testimony. He noted Batson had testified that Duke’s coal inventories had grown to about 3.8 million tons as of Feb. 15. As of April 15, the coal inventories had decreased to approximately 3.6 million tons due to the implementation of the coal price decrement on Feb. 24 and reduced coal shipments. “In addition, Duke’s latest forecast for coal inventory shows Duke’s coal inventories continuing to increase during the remainder of 2012 and 2013,” he added.

Duke has met with its coal suppliers, determined maximum storage at its facilities, and is exploring the option to resell surplus coal, potential coal contract buyouts, and decrement coal pricing, Eckert added. The decrement strategy involves bidding units into the MISO market at below cost in order to assure their dispatch to mitigate the accumulation of coal inventory. “This approach seems, at best, like a short-term solution and certainly not a long-term competitive response to low [locational marginal pricing],” he added about the decrement. “If this practice persists, the OUCC reserves all of its rights in future FACs or other proceedings with respect to this below cost bidding strategy, and its impact on customers.”

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.