Starting in 2012, during various times primarily in the spring, fall, and winter seasons, Benton County Wind Farm (BCWF) received persistent negative day-ahead and real-time locational marginal prices (LMPs) at the generator node.
John Swez, employed by Duke Energy Business Services LLC as Director, Fuels & Systems Optimization, updated the Indiana Utility Regulatory Commission on this continuing problem with the BCWF in April 25 testimony filed in a fuel case. Duke Energy Business Services provides various administrative services to Duke Energy Indiana and other affiliated companies of Duke Energy (NYSE: DUK).
During this time in 2012, BCWF was registered at the Midwest ISO as an Intermittent Resource, which means it had no ability to be committed or decommitted by, or to follow the setpoint instructions of, MISO during normal energy market operations, Swez noted. MISO did have the ability to curtail the output of the units, however, through manual curtailment.
“Due to the nature of the must-take contractual arrangement between [Duke Energy Indiana] and BCWF and the way MISO treated offers from Intermittent Resources, the offer made by the Company to MISO for this generator was equal to the day-ahead forecast of the anticipated energy from the facility,” Swez wrote. “The Company set the unit minimum and maximum loading possible to equal to the forecasted generation amount and in addition, also used a commitment status of must run, meaning that MISO cleared the generator at any LMP, positive or negative, in the day-ahead market. As a result, negative revenue (meaning that payments must be made to send the power into the MISO system) was sometimes received by this generator in the day-ahead markets. Due to the fact that the unit was an intermittent unit, the unit had no ability to be dispatched up or down and as a result, no offer was made in the realtime market. Thus, it was possible to receive negative revenue in the real-time market as well if generation from the unit was greater than the day-ahead award and real-time LMP’s were negative.”
MISO’s creation of the Dispatchable Intermittent Resource (DIR) construct was designed to allow MISO to better manage the output of intermittent resources, thereby allowing for better management of congestion in certain areas, such as where Benton County Wind Farm is located, Swez pointed out.
On March 1, Benton County Wind Farm began operation as a DIR, as required by MISO. “Although it is early in this process, it appears that the DIR construct is giving MISO additional tools to manage congestion at Benton County Wind Farm and as a result, fewer negative LMP’s are appearing,” Swez wrote. “The Company and Benton County Wind Farm are continuing discussion on the impacts to the contractual relationship due to the DIR and any potential changes needed.”
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 explained. 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 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 that congestion. The LMP also includes a component to reflect the marginal losses incurred to deliver the energy to the load zone.