FERC Filings
REQUEST OF THE ELECTRIC POWER SUPPLY ASSOCIATION FOR REHEARING OF THE COMMISSION’S MARCH 9, 2001 ORDER DIRECTING SELLERS TO PROVIDE REFUNDS OF EXCESS AMOUNTS CHARGED FOR CERTAIN ELECTRIC ENERGY SALES DURING JANUARY 2001 OR, ALTERNATELY, TO PROVIDE FURTHER
BACKGROUND
March 9, 2001 Order Directing Sellers to Provide Refunds of Excess Amounts Charged for Certain Electric Energy Sales During January 2001 or, Alternately, to Provide Further Cost or Other Justification for Such Charges
The Commission’s March 9 Order bases its refund orders on implementation of the $150/MWh breakpoint mechanism adopted in the Commission’s December 15 Order. As the March 9 Order makes clear, the December 15 Order subjected public utility suppliers that bid above $150/MWh “to certain weekly reporting and monitoring requirements to ensure that market power would not be exercised and to ensure that rates remain just and reasonable.” Thus, suppliers were on notice as a result of the December 15 Order that their bids were subject to review and possible mitigation to prevent market power from being exercised to charge unjust and unreasonable rates.
The Commission’s March 9 Order establishes a “rate screen” above which refunds are either required or further investigation will be undertaken based upon a supplier’s election to submit additional cost justification. The Commission developed this screen as a means to approximate “the market clearing price that would have occurred had the sellers bid their variable costs into a single price auction, which is what would have occurred had there been competitive forces at work.” The Commission applied this “proxy” market clearing price only to Stage 3 conditions, when operating reserves are at or below 1.5 percent of load, because “potential market power is most likely to be exercised during periods of the most severe supply/demand imbalance.”
The Commission calculated the proxy market clearing price based upon the marginal operating costs of the least efficient gas turbines for each of the California Investor-Owned Utilities (“IOUs”), prior to divestiture. These units were identified to be the ones that would set the market clearing price during Stage 3 conditions, assuming “optimum conditions, whereby every unit bids its variable cost.” The Commission derived the proxy market clearing price by accounting for average monthly gas prices in southern California, average monthly NOx allowance prices in the Southern California Air Quality Management District, an average of NOx emissions rates and an average variable O&M adder. Individual generator data submitted pursuant to the December 15 Order was not used to derive the proxy market clearing price.
Attachment A to the March 9 and March 16 Orders contained estimates of potential refunds or offsets owed by the named Sellers. The Commission’s estimates of liability were apparently based on the confidential ISO and PX data submissions, which may have differed from data submitted by the generators. The Sellers listed were to notify the Commission on or before March 23, 2001 (and seven days after each subsequent Commission Order for the months of March and April), that they would either (1) refund or offset in the same markets the amounts of their transaction prices in excess of the proxy market clearing price, or (2) supply further cost or other justification for prices charged above the proxy market clearing price, as requested by the Commission. Sellers electing the first option were required to file concurrently a compliance report identifying their transaction volumes and the amount by which those transaction prices exceed the proxy market clearing price. The Commission indicated it would review and verify a supplier’s information, based on the reports received from the ISO and PX.