Edison's Position

Although Edison takes issue with many of complainant's contentions, it particularly disputes Universal's claims that SCE had a systematic policy of underscheduling load in the day-ahead market, or that if SCE had only been willing to bid somewhat more, it could have met all of its forecast demand for June 27, 2000 in the day-ahead market. To the contrary, Edison argues, it is now clear from documents recently produced by Enron that in the summer of 2000, generators were offering to sell significantly less energy in the PX's day-ahead market than they did in 1999 and 1998. Not only could it not purchase what was not offered for sale, Edison continues, but even if there had been no price cap on SCE's bid in the day-ahead market for June 27, only an additional 65 MWh of total supply would have been forthcoming. Thus, Edison concludes, its bidding practices in the day-ahead market cannot be considered the cause of the Stage 2 alert that was called by the ISO on June 27, the event that led to the curtailment request to Universal.

In his testimony on behalf of Edison, Stern notes that the PX's Market Monitoring Committee (MMC) had begun to observe supply withholding not long after the PX was established. The MMC's March 1999 report to FERC,⁶ portions of which are attached to Stern's testimony as Attachment 2, described the effects of such withholding as follows:

"Consider, in more detail, what happens during the hours when end-use demand exceeds offered supply in the PX market . . . At such times, the supply side has substantial market power . . . [B]ecause of the shortfall of supply, buyers (principally IOUs) are forced to buy in the real-time market. This has given rise to a controversy about so-called `load underscheduling' in the PX market; the claim is made that load servers are shifting their demand to the real-time market. But as Figure 14 shows, it would be more accurate to say that supply had been `underoffered' in such hours. No matter what price buyers offered in the PX market, they could not have met all their needs; not enough supply was offered. Increasing their demand bid prices would serve only to increase the PX market-clearing price, with negligible effect on quantity." (Exhibit 6, Attachment 2, p. 47; quoted in Ex. 6, p. 11.)

Stern also discusses a study that the PX prepared and shared with the Electricity Oversight Board (EOB) in June 2000. This study compared the amount of supply available in the day-ahead market at the peak hour (i.e., 4 p.m., or "hour 16") on three specific dates: August 25, 1999, June 15, 2000, and the same day at issue in this case, June 27, 2000. In Stern's view, the study demonstrates "the fact that although demand was willing to buy more, and at higher prices in 2000 . . ., there was as much as 10,000 MW less supply offered . . . This demonstrates beyond any doubt that the cause of increased real time volumes was the lack of supply offered in advance of real time, and not the bidding behavior of buyers." (Ex. 6, p. 12.)

Stern also notes that the under-supply problem was made worse by a variety of trading strategies employed by various power suppliers, strategies that came to light in 2002 when FERC released a memorandum from one of Enron's outside law firms. One of the strategies extensively employed in the California market was known as "Fat Boy." Under this strategy, Enron

". . . uses a phony load schedule matched against a quantity of power that it has acquired through a contract, to effectively sell that power into the real-time market of the ISO. By submitting a phony load that does not materialize, Enron has a supply that exceeds its demand, and is viewed as having a positive imbalance in the ISO's real-time market. Enron will thus be paid for effectively selling its excess power in the real-time market. But when Enron engaged in this strategy[,] it also withheld the sale of its contract power from the PX day-ahead market, making it unavailable for SCE or other buyers to purchase in advance of real time. This helped create an artificial supply shortage in the day-ahead market, thus requiring buyers like SCE to increase their purchases in the real-time market. Enron would then `solve' the problem it created by making extra supply available at high prices at the last minute in the real-time market." (Id. at 14.)

Another strategy Enron used in the California market involved making out-of-state sales of power that Enron had purchased from the PX. According to Stern, "Enron would buy power out of the PX market at effectively capped prices, and sell that power out of state at higher prices, once again taking power away from the California IOU buyers in the day-ahead market, and leaving them with no choice but to meet some of their load in the real-time market." (Id.)

A third strategy used by Enron in California was known as "Load Shift." Stern gives the following description of it:

"This strategy involved bidding load so as to create transmission congestion in the day ahead schedule on a path where Enron owned the transmission rights, and would thus receive payments - both for transmitting the power and for relieving the congestion they had created. The impact of this strategy on SCE's buying was that when SCE tried to buy in the day-ahead market to meet its demand in SP15 (California's southern transmission zone), congestion from Northern California to Southern California would appear to the ISO to be significant, making SCE's schedule infeasible and requiring the ISO to cut some of SCE's day ahead purchases. Since the congestion was created by phony Enron load bids, SCE's schedule would ultimately have to be met in the ISO's real-time market, where it could be characterized by naïve or sinister parties as load underscheduling." (Id. at 14-15.)

A final strategy used by Enron and other traders was known as "Ricochet." Stern states that "in this strategy, the sellers would schedule their California power for export outside of the ISO area in the day ahead scheduling. This would once again reduce the supply available for purchase in the PX day-ahead market, making it impossible for buyers to meet their demand without using the ISO's real-time market. The power scheduled out of the ISO area would then be `parked' there until it could be `imported' and sold to the ISO's real-time market." (Id. at 15.)

After describing Fat Boy, Load Shift, Ricochet and the other strategies that Enron officials have admitted to using in the California market,⁷ Stern concludes:

"[A]s a result of these and other withholding strategies, SCE could not have purchased its entire forecast demand through its bids in the day-ahead market on June 26, 2002, and could not have avoided the use of the ISO's real-time market on June 27, regardless of any action SCE could have taken in the day-ahead market." (Id. at 16.)

To support this conclusion, Stern provides a quantitative analysis based on available bidding data for hour 16 in the day-ahead market for June 27. Stern asserts that his analysis demonstrates that even if Edison had been willing to bid a "vertical demand curve" -- which he defines as a bid curve that is "vertical and price-inelastic, i.e., [one that tries] to purchase the full forecasted load at all price levels up to the highest limit of $2,500.00" -- Edison would not have elicited enough additional supply to avert the Stage 2 alert that was called. (Id. at 22.)

Stern also examined the ISO real-time market for each of the other hours on June 27, 2000. From this examination, he concluded that the imbalances between PX purchases and forecasted load from entities other than Edison were considerably larger than the imbalance shown by SCE. Thus, even if one "accept[s] the premise (which SCE asserts is false)[⁸] that Stage 2 conditions are the result of a large ISO real-time market, this [analysis] demonstrates that other entities were responsible for a much larger portion of the ISO imbalance than was SCE." (Id. at 24.)

Stern precedes his detailed analysis of June 27 with two important qualifications. First, he notes that although Universal clearly seems to be arguing that Edison should have submitted bids with a vertical demand curve, "such a curve is, in fact, unacceptable" under Rule 2.4.1.e of the PX Bidding and Bid Evaluation Protocol, because the rule provides that "for Demand Bids, the piece-wise linear curve . . . must have a downward slope." (Id. at 22; emphasis added.)

Second,

". . . all other day-ahead bids submitted for June 27, 2000, both supply and demand, by other UDCs [i.e., utility distribution companies] and market participants are assumed unchanged because SCE had no way to know, and certainly no way to change, their bids. This assumption, in fact, is necessary to show the impact that SCE's action alone would have had on the interruption." (Id.)

After reconstructing the aggregate demand and supply curves for hour 16 in the day-ahead market for June 27, and replacing Edison's original demand bid curve with a vertical bid curve, Stern concludes:

"If SCE had offered to pay any price to purchase its full forecast hour 16 load, i.e., if it had submitted a vertical demand bid curve, the PX DA market for hour 16 would have increased by only 65 MWh due to limited supply offers. This implies that the ISO real-time market for that hour would have been reduced by a mere 65 MWh. This would definitely not have reduced the risk of I-6 [tariff] interruption, even if one accepts the premise that I-6 interruptions were due to a large ISO real-time market, since the statewide `underscheduled' amount for hour 16, i.e., the size of the ISO real-time market, was more than 8,000 MWh. In other words, if SCE had submitted a bid with a vertical demand curve, as suggested by Universal, the size of the ISO real-time market would have been reduced by less than one percent. This would have had no impact at all on the risk of an I-6 interruption. While such a bid would have allocated more supply to SCE,[⁹] it would have resulted in less supply to other participants, with only a new 65 MWh (approximately 0.2%) increase in total PX supply." (Id. at 22-23.)¹⁰

Stern also concludes that if one compares Edison's PX imbalances with total PX imbalances for all of the hours during June 27, 2000, it is clear that Edison played only a small role in bringing about the Stage 2 alert on that day:

"[T]he imbalances from entities other than SCE are considerably larger than the imbalance from SCE. If one were to accept the premise (which SCE asserts is false) that Stage 2 conditions are the result of a large ISO real-time market, this graph demonstrates that other entities were responsible for a much larger portion of the ISO imbalance than was SCE. As noted previously, no bidding strategy by SCE could have reduced the ISO's imbalance appreciably on that day . . . Moreover, SCE's imbalance made up only a fraction of the total PX (or ISO) imbalance. Universal has not demonstrated how it is that SCE was the entity responsible for the large ISO imbalance that Universal asserts precipitated the Stage 2 condition on June 27." (Id. at 24.)

Stern closes by pointing out that at least three independent reports have concluded that Stage 2 alerts like the one experienced on June 27 were principally the result of the tight statewide electric supplies that had been evident since the spring:

"The ISO declares a Stage 2 condition whenever it has insufficient resources to maintain 5% operating reserves. In order to find the cause of the June 27, 2000 Stage 2 declaration, one must examine the demand and supply conditions on that date.

"Among other studies, the GAO report issued in June 2002 describes the supply demand balance as so tight as to reach scarcity beginning in May of 2000. This GAO report, the PX report of September, 2000, and the FERC Staff Report issued November 2, 2000 all agree that this tightness of available supply to meet an increasing demand beginning in May of 2000 contributed to the price spikes and reliability problems faced by the ISO, as well as the necessity for the ISO to declare Stage 2 emergencies. According to these varied sources, these conditions clearly existed in June of 2000. It is these conditions, not any bidding approaches employed by SCE, that caused the Stage 2 condition leading to the call for Universal to interrupt its load on June 27, 2000." (Id. at 28-29.)

"Beginning in approximately 1998, and ending in approximately 2001, I and other individuals at Enron agreed to devise and implement a series of fraudulent schemes through these markets. We designed the schemes to obtain increased revenue for Enron from wholesale electricity customers and other market participants in the State of California. The schemes required us to submit false information to the PX and ISO in the electricity and ancillary services markets described above. Among other things, we knowingly and intentionally filed energy schedules that misrepresented the nature of electricity we proposed to supply, as well as the load we intended to serve. We intentionally filed schedules designed to artificially increase congestion on California transmission lines. We were paid to `relieve' congestion when, in fact, we did not relieve it. We exported and then imported amounts of electricity generated within California in order to receive higher, out-of-state prices from the ISO when it purchased `out-of-market.' We scheduled energy that we did not have, or did not intend to supply. "As a result of these false schedules, we were able to manipulate prices in certain markets, arbitrage price differences between the markets, obtain `congestion management' payments in excess of what we would have received with accurate schedules, and receive prices for electricity above price caps set by the ISO and the [FERC]." (Attachment 1 to Edison's Opening Brief, Plea Agreement, ¶ 2.)

"The demand that the ISO must meet is the total demand on the system, of which the real-time market is just [a] component. While it is true that when more demand and supply are scheduled in advance of real time, less demand and supply must be scheduled in real time, it is also true that the total market determines the reserve requirement, not just the subset that is the real-time market. On June 27, 2000, there was a Stage 2 alert in California because total market demand was high (due to hot weather, limited conservation, and virtually no effective price responsive demand) and total supply was short (due to low hydro, a low level of imports because of regional needs outside California, and strategic withholding of power in California). In fact, total ISO demand reached 42,693 MW at hour 15 on June 27, 2000." (Id. at 29.)

"My understanding is that Edison would have acquired perhaps an additional 250 megawatt-hours, but other participants would have had their purchases reduced by some 175 or 180 megawatt-hours, such that the resulting total, the clearing price in the . . . PX's market for that hour would have only changed by 65 megawatt-hours." (Tr. 172-73.)

"Assuming SCE had been successful in its vertical demand bid, and assuming there had been no congestion management, SCE would then have been able to purchase its full forecast hour 16 load of 13,938 MWh at the [market clearing price] of $730.56 . . . However, this would have meant an increase in price of $80.56 per MWh from the original price of $650.00. Thus, SCE would have had to pay more than $1.1 million of additional cost for hour 16 alone. Compared to the penalty of $395,409.60 that Universal Studios refused to pay for continuing to operate during an interruption that lasted almost 3½ hours, the additional cost that SCE would have had to pay for hour 16 alone was almost three times as much." (Id. at 23.)