Background on the Relationships Among the Power Markets Run by the PX and the ISO in 2000

In order to comprehend the positions of the parties in this case, some understanding is necessary of the characteristics of the "day-ahead," "hour-ahead" and "real time" power markets that were being operated in 2000.

Under the electric restructuring regime established by AB 1890, the principal market for both buyers and sellers of power was envisioned as the day-ahead market, which was run by the PX. In its testimony, Edison gives the following description (which Universal does not dispute) of how the day-ahead market operated:

"The PX operates a day-ahead market in which bids are submitted by 7:00 a.m. on Day One for the 24-hour delivery period from midnight to midnight on Day Two. Bids for buying the quantity one desires at a specified price are submitted in price pairs. At one extreme one defines a desired quantity for purchase at the PX's maximum price of $2,500/MWh (megawatt-hour). At the other extreme, one states a quantity to be purchased at a minimum price. Since there are other opportunities to purchase power after the PX day-ahead market is closed, the system is designed so that the demand bids, in conjunction with supply offers, establish a market clearing price and quantity for each hour. After all parties' supply and demand bids are submitted in the PX, an Unconstrained Market Clearing Price (UMCP)[²] is established by finding the price-quantity pair that occurs at the crossing of the supply and demand curves." (Exhibit 6, p. 7.)

In addition to the day-ahead market, the PX also ran the "hour-ahead" (or "day-of") market in June 2000. ³ Edison gives the following undisputed description of this market:

"To the extent a buyer has been unable to procure its forecasted demand from the PX day-ahead market, the PX runs an hour-ahead market. There are at least four reasons why a buyer may wish to purchase additional power (or alternatively, sell excess power) in the hour-ahead market. First, based on more current information, its forecast of demand may have changed. Second, it may not have been able to purchase its full day ahead forecast based on the prices in the day-ahead market. Third, congestion may have made the delivery of the power it intended to purchase in the day-ahead market infeasible, resulting in a schedule cut. Fourth, a supply resource scheduled to provide power in the day-ahead market may have become incapable of meeting its schedule (e.g., a forced outage of a generating unit), requiring an additional purchase from the market to make up the schedule shortfall. For each of these four cases the converse is possible, resulting in the need to sell excess power after the PX day-ahead market." (Id. at 8-9; footnote omitted.)

However, because the hour-ahead or day-of market was "typically illiquid" and insufficient to meet the utilities' shortfall in the day-ahead market, (id. at 10), Edison was frequently obliged to turn to the final power market involved in this case, the so-called "real time" market run by the ISO. Edison's testimony notes that "the use of this market is particularly risky for a buyer," because "some costs in addition to energy are allocated to purchases in the real-time market." (Id. at 9.)

Because the day-ahead market had a price cap of $2500 per MWh, whereas the real-time market was subject to a price cap of $750 per MWh, Edison acknowledges that it devised a bidding strategy under which it did not always seek to meet its total forecast demand in the day-ahead market, and would instead satisfy some of its demand in the hour-ahead and real-time markets. In its testimony, Edison gives the following general description of this bidding strategy:

"SCE's objective was to purchase energy for its customers at the lowest possible cost. Accordingly, as long as no transmission congestion was anticipated, SCE submitted bids into the PX
day-ahead market which would result in a purchase of 95 to 100 percent of its customers' expected energy needs in each hour through the day-ahead market, depending on SCE's forecast for the next day's PX prices and the prices SCE expected in later markets - particularly in the real-time market which was subject to a Commission [FERC]-ordered price cap. SCE would also reduce its demand bids to reflect its expectations about transmission congestion. For example, SCE would bid in a way so as to purchase as much of its needed supply as it expected to be available after the ISO completed its congestion management process. The ISO and PX Tariffs permitted demand bidders to submit to the PX demand/price curves that, under certain circumstances, would result in only a portion of a load-serving entity's forecasted demand being met ahead of real time. Where the price sellers demanded in the PX day-ahead market exceeded the price SCE was willing to pay, SCE's demand bid would result in less than 100% of its forecast load being purchased in the day-ahead market.

"In such circumstances, SCE would purchase some of its customers' electricity demand in the later markets. In general, SCE would bid to buy its shortfall in the PX's day-of market, though this market was typically illiquid and insufficient to meet the shortfall. In this case, some of SCE's load would ultimately be met in the ISO's real-time market. Some of SCE's load would also be met in the ISO's real-time market because of (1) transmission congestion or (2) actual load exceeding forecast load (forecast error)." (Id. at 10.)

"Transmission congestion will cause a utility that procures power in the congested zone to receive a lower final energy allocation from the PX at a higher price than it would have in the PX's original day-ahead UMCP market. Thus, utilities in transmission congested zones get less and pay more." (Id. at 8.)