Duke Energy Indiana may slash 2012 coal burn by up to 40%

Duke Energy Indiana is taking a number of steps to reduce its rapidly-swelling coal inventory, including re-negotiation of contract terms with coal suppliers, said Elliott Batson Jr., Vice President, Regulated Fuels at Duke Energy Business Services LLC, a service company subsidiary of Duke Energy (NYSE:DUK).

On Jan. 26, Batson opened a fuel adjustment clause (FAC) cost review case at the Indiana Utility Regulatory Commission with initial testimony. Then in Feb. 22 supplemental testimony, Batson said the coal inventory problem was rapidly getting worse than the one he reported on Jan. 26.

“As of February 15, 2012, Duke Energy Indiana’s coal inventory had grown to approximately 3,800,000 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 existing Gibson Station Remote pile,” Batson testified. “From December 1, 2011, through February 15, 2012, our coal inventories have increased by approximately 800,000 tons, a period of time in which historically inventories have decreased across the system.”

Extremely low natural gas prices and unseasonably mild weather for the period of December 2011 through mid-February 2012 have caused power prices in the Midwest ISO region to drop, Batson noted. In turn, the company’s coal units have experienced much lower dispatch levels as well as periods of economic shutdown. This was an unexpected change in the market and has led to a significant increase in coal inventories. Based on forecasted natural gas prices and electric prices, the company now has a reasonable expectation of significant coal inventory growth throughout the rest of 2012 and likely into 2013, Batson added.

Henry Hub natural gas prices dropped precipitously from the fall of 2011 through the first two months of 2012, Batson noted. As late as August 2011, natural gas for delivery in the winter of 2012 was trading at $4.60/MMBtu. By Feb. 8, Henry Hub natural gas spot prices had dropped to $2.49/MMBtu. This sharp decline in gas prices has allowed generation from combined cycle natural gas units to become increasingly competitive with coal units.

Also, the weather patterns in the Midwest from December through mid-February have been extremely mild as compared to historical weather patterns for the region. For the months of December 2011 through mid-February 2012, the average temperatures in Indiana ranked just shy of the 10th warmest winter in more than 117 years of tracking. Moreover, January 2012 ranks as being the 4th warmest on record over the contiguous United States.

For the months of December and January, the company’s Indiana coal-fired stations consumed about 45% and 40% less coal than during the same two-month period in 2009 and 2010, respectively. At the time of the filing of the Feb. 22 testimony, this low consumption pattern had continued in February. The company now forecasts that the annual coal burns for Indiana in 2012 will be as much as 40% lower than the coal burns for calendar year 2011.

In 2011, Duke Energy Indiana consumed more than 12.9 million tons of coal. As late as early November 2011, the company projected coal burns for 2012 to be in excess of 13 million tons, and the company had placed a large majority of this coal under contract for delivery in 2012, as is typical.

Steps being taken to reduce 2012 coal oversupply

To deal with the coal oversupply, Duke Energy Indiana has met with each of its long-term coal suppliers in Indiana to discuss deferral, cancellation and other commercial and operational options to decrease the shipments for 2012.

Other steps include:

  • Duke Energy Indiana has commissioned and completed a survey to determine the maximum storage capabilities at all of its plants. It has begun to prepare the existing Gibson Remote Pile adjacent to the Gibson station for additional coal. It has also 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 been actively exploring the option to re-sell surplus coal into the market.
  • Duke Energy Indiana is implementing a decrement to coal pricing inputs used to formulate supply offers to MISO beginning in the near future.
  • The company is considering its options to buy-out of the existing coal contracts or to pursue other legal options.

Batson said that simple default by Duke Energy Indiana on its coal contracts is not an attractive alternative for several reasons. In the absence of a valid claim of force majeure or other contractual right to cancel or defer the tons, the company is generally obligated to purchase coal it has under contract. If the company were simply to default on its contracts, it would be exposed to costly damage claims.

With a limited pool of mines able to supply the coal required for Duke Energy Indiana’s fleet, a contract default creates friction in the relationship that will likely be counterproductive to achieving mutually beneficial results in the future, Batson noted. “Other reasons to avoid default include not causing a supplier to terminate the contract, avoiding the shutdown of a mine, and loss of jobs in Indiana,” he said. “In an extreme example, the default could cause a financially weak supplier to go out of business, which could hurt competition and supply over the long term.”

Price decrement idea kicks up some confusion

In companion Feb. 22 testimony, John Swez, employed by Duke Energy Business Services as Director, Regulated Portfolio Optimization, explained the concept of a price decrement, which has caused some dispute in this fuel case.

“The price decrement represents the avoided cost associated with implementing a more expensive option to avoid or reduce surplus coal inventories, such as buying out of a coal contract, reselling the coal, or taking some other form of action,” Swez explained. “The dispatch and commitment costs of the appropriate coal units are reduced by the costs that would be avoided if the unit would be cleared and dispatched by MISO. Given the additional costs associated with avoiding or reducing surplus coal inventories, the company believes it makes sense to try to avoid some of these costs by offering the units with the decremental price subtracted from the current offer cost. To the extent the units are dispatched, coal coming to the station is consumed, other potential costs are avoided, and customers ultimately benefit. This is very similar to the manner in which the company successfully economically dealt with a surplus coal inventory situation at Gallagher Station in 2009.”

As an example, consider a generator that is on-line and has a $32/MWhr variable cost offer, Swez added. If the Locational Marginal Price (LMP) at the generator node is $30/MWhr, the generator  will be dispatched down by MISO until the unit reaches minimum load. Now add the fact that if this generator doesn’t burn additional coal, an additional expense of $5/MWhr will be experienced through an additional storage expense. In this example, $5/MWhr becomes the decrement price. By subtracting $5/MWhr from the original dispatch price offer of the unit, the new dispatch price offer becomes $27/MWhr. When the unit is offered in this case, because the offer of $27/MWhr is now below the LMP of $30/MWhr, the unit is increased in output until it reaches full output. Even though a decrement of $5/MWhr is used, because the generator is paid the LMP, the company actually saves $3/MWhr by use of the decrement. The company receives revenue of $30/MWhr, has coal expenses of $32/MWhr, but avoids the $5/MWhr incremental coal storage cost for a net savings of $3/MWhr.

For dispatch purposes, the decrement is only meaningful between the decremented price and the original variable cost offer, Swez added. When using a decremented offer price, if LMP’s are below the decremented unit offer there is no change in the dispatch of the unit as it is still at minimum load. Likewise, when using a decremented offer price, if the LMP is above the original offer, there is no change in the dispatch of the unit as it is still at maximum load.

The price decrement idea ran into flak in March 1 testimony from Michael Eckert, employed by the Indiana Office of Utility Consumer Counselor (OUCC) as a Senior Utility Analyst in the Electric Division. “Due to the timing of Duke’s supplemental filing, the OUCC has not had adequate time to review Duke’s request and the potential issues associated with that request,” said Eckert about the price decrement concept. “Therefore, the OUCC recommends that the commission defer a finding on this issue until Duke’s next FAC.”

In his March 1 testimony, Eckert recommended that the commission require Duke to provide the following information in its next FAC: update the commission as to how the shutdown of the coal-fired units 1 and 3 at the Gallagher plant on Jan. 12 and the purchase of a merchant gas plant from Duke Energy Vermillion II LLC will impact the company’s actual costs and its forecasted costs; update the commission on the applicant’s current coal inventory situation; and defer a finding on Duke’s request for coal decrement pricing until its next FAC.

In the same March 1 OUCC filing was testimony from Gregory Guerrettaz, President of Financial Solutions Group, which is providing consulting services to the OUCC. “Our questions focus on the fact that the ‘price decrement’ adjustment will impact a lot of items on a going forward basis,” he said. “It is my understanding that the OUCC has not had adequate time to evaluate this proposal and that this type of change being proposed at the ‘last minute’ of FAC91 is just not reviewable at this time. Preliminary questions were asked during the onsite audit process, but the impacts as to the MISO process and PACE process do not appear too addressable at this point. At this time, I would envision some additional work papers and audit steps being needed to verify the impact of the decrement. The concept appears to be straightforward, but the integration of the adjustments and verification of impact is a significant aspect in our minds.”

In March 6 response testimony, Barry Blackwell, employed by Duke Energy Business Services as Director, Rates, said the OUCC’s concerns about the price decrement idea are unfounded. He said that Duke Energy Indiana’s supplemental testimony was to simply notify the commission, the OUCC, and the intervening parties of its growing coal inventory and its plans to deal with it, including its implementation of the avoided cost decrement pricing. The company is not requesting approval from the commission of the price decrement at this time. In subsequent FACs, the company will include an update on the decrement and all parties will have an opportunity to review and comment, Blackwell said.

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.