Cheap gas-fired capacity available in the Midwest ISO market is a big factor in the depressed usage lately of the coal-fired generation of Duke Energy Indiana, said company representative John Swez in Jan. 29 fuel cost adjustment testimony filed at the Indiana Utility Regulatory Commission.
Swez is employed by Duke Energy Business Services LLC as Director, Fuels & Systems Optimization. Duke Energy Business Services provides various administrative services to Duke Energy Indiana, with both companies being subsidiaries of Duke Energy (NYSE: DUK).
A number of factors, including low natural gas prices, extremely mild weather during the winter of 2011/2012, increased wind generation, and other factors caused the energy price in the MISO market to drop primarily during non-summer months, causing the company’s coal-fired plants 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 early last year started applying a coal price decrement. That basically means the costs of eating coal supply contract tonnages instead of burning that coal are factored into the price offers made into the MISO market for power from the coal units, making those units more competitive than they would be on generation costs alone.
“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,” Swez wrote. “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. In short, the price decrement is working as designed.”
Swez noted that on specific hours and days, the price decrement will have no impact on the commitment and dispatch of Duke Energy Indiana’s generating units because the unit in question was already economic without 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 locational marginal price (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.
“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,” Swez added. “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.”
Locational marginal pricing defines the marginal cost of energy serving the next increment (i.e., 1 MW) of load at each location, based on generation dispatch, transmission constraints binding the dispatch, and the offers and bids of sellers and buyers participating in the energy markets, Swez noted. Because the LMP is based on the marginal cost of energy to serve the next increment of load, the energy clearing price is the same at each location supplying energy to or withdrawing energy from the market for a given market interval. Also, the LMP paid for energy withdrawn at a load zone (i.e., energy withdrawn to serve retail customers) includes costs for congestion in any market interval when the transmission system is constrained and the lowest price generator available cannot serve the next increment of load at that load zone because of such congestion, he wrote. The LMP also includes a component to reflect the marginal losses incurred to deliver the energy to the load zone.
Benton County Wind Farm having LMP issues in recent months
Swez also explained a problem that the utility has been having related to a wind farm. Starting at the end of February 2012 and continuing through May 2012, Benton County Wind Farm (BCWF) began to receive persistent negative day-ahead and real-time LMPs at the generator node. In addition, BCWF began to once again receive negative LMPs briefly in September through October 2012 and again in December 2012 and January 2013.
“To date, the occurrences in the fall of 2012 and winter of 2012-2013 have not been as significant as seen in the spring of 2012, but it has been an issue nonetheless,” Swez explained. “BCWF is currently registered at MISO as an Intermittent Resource, which means that it has no ability to be committed or decommitted by, or follow the setpoint instructions of, MISO. Due to the nature of the must-take contractual arrangement between the Company and BCWF and the way MISO treats offers from Intermittent Resources, the offer made by the Company to MISO for this generator is equal to the day-ahead forecast of the anticipated energy from the facility.”
Swez added: “The minimum and maximum loading possible for the unit is set equal to the forecasted generation amount and in addition, a commitment status of must run is used, meaning that MISO will clear the generator at any LMP in the day-ahead market. As a result, negative revenue (meaning that payments must be made to send the power into the MISO system) could be received by this generator in the day-ahead markets. Because the unit has no ability to be dispatched, no offer is made in the real-time market. Thus, it is possible to receive negative revenue in the real-time market as well if generation from the unit is greater than the day-ahead award and real-time LMPs are negative.”
To rectify this situation, Swez said that Duke Energy Indiana approached both BCWF and MISO to look for solutions. The company and BCWF are still in discussions regarding this situation. In addition, the company has been working with MISO to better understand the situation and is working towards a solution.
“MISO’s creation of the Dispatchable Intermittent Resource (‘DIR’) construct will allow MISO to better manage the output of intermittent resources, thereby allowing for better management of congestion in certain areas,” Swez added. “It is believed that the DIR construct will give MISO additional tools to help alleviate this negative LMP situation at BCWF. Under the MISO’s rules, Duke Energy Indiana, as the Market Participant, submitted an attachment B form with MISO to register BCWF as a DIR on November 15, 2012, and BCWF, as the generation resource, must be fully functional as a DIR by March 1, 2013. In addition, the Company is currently working on all other changes necessary under the DIR construct prior to the date of implementation.”