Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner and A. Kirk McKenzie is the assigned Administrative Law Judge in this proceeding.
1. In D.02-01-057, the Commission extended the one-year deadline applicable to this proceeding pursuant to Pub. Util. Code § 1701.2(d).
2. On June 27, 2000, Universal was a sub-transmission customer of Edison taking service pursuant to SCE's Tariff Schedule I-6, which provides for interruptible service to large customers.
3. A customer taking service under Schedule I-6 is obliged to reduce its energy use down to the customer's Firm Service Level (FSL) when requested to do so by Edison, or else pay excess energy charges as set forth in the schedule.
4. Edison's Tariff Rule 14 requires SCE to use reasonable diligence in delivering a continuous and sufficient supply of electricity to its customers and to avoid any shortage or interruption of delivery of such electricity, but also states that Edison does not guarantee a sufficient or continuous supply, and is not liable for any interruption or supply shortage (or for loss or damage occasioned thereby) if the interruption or shortage results from a cause not within Edison's control.
5. SCE's Tariff Rule 14 was applicable to customers taking service under the I-6 schedule.
6. On June 27, 2000, the ISO declared a Stage 2 alert, pursuant to which Edison asked customers taking service under the I-6 schedule to reduce their respective energy usages down to the applicable FSLs.
7. Prior to June 27, 2000, Universal had set its FSL at zero.
8. On June 27, 2000, Universal did not curtail its energy usage down to zero when asked to do so by Edison.
9. Pursuant to the I-6 schedule, Edison billed Universal for an excess energy charge of $395,409.60.
10. Universal refused to pay Edison the aforesaid excess energy charge and instead filed the instant complaint.
11. On September 12, 2002, Universal deposited the sum representing the disputed excess energy charge, $395,409.60, with the Commission's Fiscal Office.
12. In 1998, the Commission reduced from five years to one year the amount of notice that an Edison customer taking service under the I-6 schedule was required to give either to leave the interruptible program, or to reduce the customer's FSL.
13. In D.00-10-066, the Commission suspended the right of Edison customers taking service under Schedule I-6 to make an annual election about whether to continue taking interruptible service, or to adjust the customer's FSL.
14. In D.01-04-006, the Commission concluded that customers taking service under Schedule I-6 should once again have the right to make an annual election about whether to continue taking interruptible service or to adjust FSLs, and made this right retroactive to November 1, 2000. The Commission also decided that I-6 customers would remain liable for any excess energy charges that Edison had imposed through November 1, 2000.
15. Under the electric restructuring regime established by AB 1890, the principal market for both sellers of power and utilities seeking to serve load was envisioned to be the day-ahead market, which was run by the PX. In the day-ahead market, both buyers and sellers submitted bids on Day One for the 24-hour delivery period commencing at midnight on Day Two. Based on the matching of buyer and seller bids, the PX would then establish an Unconstrained Market Clearing Price (UMCP) for each hour in Day Two.
16. To account for transmission constraints in the applicable transmission zones, the PX would also run a congestion management auction when necessary, which resulted in a Zonal Market Clearing Price (ZMCP) for each transmission zone. In general, transmission congestion caused utilities procuring power in a congested zone to receive a lower final energy allocation from the PX, and at a higher price, than would have been the case without the congestion.
17. To the extent a buyer was unable to procure its forecasted demand from the day-ahead market, the buyer could turn to the hour-ahead market, which was also run by the PX. When the hour-ahead market was run for blocks of hours rather than individual hours, it was referred to as the day-of market. Use of this market allowed both buyers and sellers to adjust for late-breaking developments such as updated demand forecasts, reductions in PX power allocations due to congestion management, and the sudden unavailability of supply resources that had been scheduled in the day-ahead market. In general, the day-of market was illiquid and insufficient to meet the utilities' shortfall from the day-ahead market.
18. To the extent utilities could not meet their demand for power in either the day-ahead or the day-of market, they were obliged to turn to the real time market, which was run by the ISO.
19. 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 devised a bidding strategy in 1998 under which it did not always seek to meet its total forecast demand in the day-ahead market, but instead satisfied a portion of this demand in the day-of market or, more often, in the real-time market. Under this bidding strategy, Edison sought to purchase 95% to 100% of its forecast demand in the day-ahead market (depending on expected prices and transmission constraints), with the rest being purchased in the day-of and real-time markets.
20. From the early 1990s until the summer of 1998, Edison made no curtailment requests to its I-6 customers. In the summer of 1998, Edison interruptible customers were asked to curtail on four occasions.
21. When the ISO calls a Stage 2 alert and Edison's I-6 customers are asked to curtail, the additional costs that the Stage 2 alert imposes on Edison exceed the savings that SCE realizes as a result of having to purchase less power to serve the I-6 customers.
22. On several occasions in 1999 and 2000, the ISO conveyed its concerns to Edison that the volume of SCE's power purchases in the real-time market was exceeding the design parameters for that market, a situation that ISO management thought might lead to reliability problems. The ISO's Division of Market Analysis did not concur with this viewpoint.
23. Beginning in May 2000, Edison's purchased power costs regularly began to exceed the generation component of its I-6 rate and other rates.
24. The PX's Market Monitoring Committee began to observe supply withholding in the day-ahead market shortly after the PX was established in 1998.
25. A study that the PX prepared for the EOB indicates that the amount of supply offered during the peak hours on June 15 and June 27, 2000 was approximately 10,000 MWh less than the amount of supply offered during the peak hour about ten months earlier, on August 25, 1999.
26. A memorandum prepared by Enron's outside counsel and released by FERC staff in May 2002 indicates that between 1998 and 2000, Enron's energy trading company engaged in a variety of trading strategies that were designed to reduce the amount of power Enron would have to offer in the PX's day-ahead market, and to shift that power to the real-time market, where it would fetch higher prices. These strategies included Fat Boy, Load Shift and Ricochet.
27. On October 17, 2002, Timothy N. Belden, former Vice President and Managing Director of Enron's West Power Trading Division, pleaded guilty in U.S. District Court in San Francisco to an Information charging him with participation in a conspiracy designed to manipulate California energy prices by using strategies including Fat Boy, Load Shift and Ricochet. Belden admitted that this conspiracy had lasted from 1998 to 2001.
28. On June 26, 2000, Edison forecasted that its load during the peak hour on June 27, 2000 would be 13,938 MWh. Edison submitted a bid curve that included a bid for this amount at a UMCP of $556/MWh, and lesser amounts at higher prices. The initial preferred schedule in the day-ahead market awarded Edison 12,690 MWh at a UMCP of $650, but owing to congestion management, the final schedule reduced Edison's allocation to 12,026 MWh at a ZMCP of $653. Edison sought to obtain 2037 MWh, the balance of its revised forecast of peak hour demand for June 27, in the PX's day-of market, but was awarded only 214 MWh at a price of $750/MWh.
29. Metered demand for the peak hour on June 27 was 14,576 MWh, which indicates that for that hour, Edison had to purchase 2,336 MWh in the ISO's real-time market.
30. The PX's rules did not allow Edison to submit a vertical demand bid curve in the day-ahead market, i.e., a bid curve that is vertical and price-inelastic, such that the bidder is willing to purchase its full forecasted load up to the PX's limit of $2500 per MWh.
31. Even if the PX's rules had allowed Edison to submit a vertical demand bid curve in the day-ahead market for June 27, 2000, Edison's unrefuted analysis indicates that total supply during the peak hour would have increased by only about 65 MWh, with Edison being awarded about 250 MWh more and other bidders about 175-185 MWh less.
32. In conducting its analysis of the June 27 peak hour, it was reasonable for Edison to assume that bids by other suppliers and purchasers would remain the same, since Edison had no way to change these bids, or to know how different conditions might have led to different bids.
33. Universal's Opening Brief mischaracterizes Edison's testimony when it states that if Edison had submitted a bid of at least $730.56 per MWh for SCE's entire forecast load for the June 27, 2000 peak hour, Edison would have been able to purchase its entire forecast load for that hour.
34. Edison could not have purchased its full forecast demand for the peak hour in the day-ahead market for June 27, 2000, even if it had submitted a bid for the entire load at a price of $730.56 per MWh.
35. The day-of market for June 27, 2000 was illiquid and insufficient to meet Edison's shortfall in the day-ahead market.
36. Based on the consensus regarding market conditions reflected in a June 2002 GAO report, a PX report prepared in September 2000, and a FERC staff report issued on November 2, 2000, it is reasonable to conclude that the supply-demand balance in California beginning in May 2000 was so tight as to amount to a condition of scarcity.
37. In its December 15, 2000 Order, FERC prospectively imposed a penalty of up to $100 per MWh on California utilities that failed to schedule at least 95% of their forecasted load in the day-ahead market.
38. The penalty provision in FERC's December 15, 2000 Order gave sellers in the day-ahead market an incentive to demand even higher prices for their power. In the months immediately after that order, prices in both the day-ahead market and the real-time market increased dramatically, as did the number of Stage 2 and Stage 3 alerts the ISO was forced to call.
39. FERC made substantial modifications to the December 15, 2000 Order in June 2001, and formally rescinded the underscheduling penalty (which had never been collected) in the December 19, 2001 Order.
40. In January 2003, FERC approved a settlement between the FERC staff and certain Reliant companies pursuant to which the latter admitted that on June 20 and 21, 2000, they had purposefully withheld supply from the PX's day-ahead market for the purpose of increasing the prices paid by buyers in that market.
41. As shown by the guilty plea of Timothy Belden and the FERC staff's settlement with Reliant, Edison's difficulties during the second quarter of 2000 in purchasing enough energy in the day-ahead market to meet forecasted load was a function of under-supply (i.e., sellers withholding from the PX energy they had offered in the past) rather than of underscheduling (i.e., utilities purchasing from the PX significantly less than their forecasted load in the hope of obtaining a better price in the ISO's real-time market).
42. Since Edison's imbalances were not large in relation to total PX imbalances for all hours on June 27, 2000, these imbalances played only a small role in bringing about the Stage 2 alert on June 27, 2000.
1. This proceeding is a tariff interpretation case, and as such, it more nearly resembles a contract dispute than a tort case.
2. Proximate cause is a legal concept that has been applied in some types of Commission proceedings with a tort-like character, such as reasonableness reviews.
3. Universal's proximate cause test, under which Edison would be liable for the Stage 2 alert called on June 27, 2000 because SCE's conduct in 1998 and 1999 supposedly contributed to market forces that were in continuous and active operation up to June 27, 2000, should not be applied here.
4. The issue in this case is the extent of Edison's duty under Rule 14 to furnish its customers with electric energy in light of all the applicable circumstances on June 27, 2000, not during some earlier period.
5. On June 27, 2000, Edison was not obliged to purchase additional power at an exorbitant price in order to satisfy its obligation under Rule 14 of using reasonable diligence to deliver power to its customers.
6. In view of the language in Rule 14 that Edison is not liable for interruptions or shortages of electricity caused by circumstances beyond its control, Universal's interpretation of Rule 14 is not reasonable.
7. In order to determine whether Edison satisfied its obligation to use reasonable diligence in delivering power to its customers on June 27, 2000, the Commission must consider all the circumstances, including the existence of market forces beyond Edison's control.
8. In view of the modifications to Edison's interruptible program that occurred in 1998 and the interruption requests that began at the same time, it is not reasonable to conclude that Edison guaranteed that the frequency of interruptions in 2000 would be no greater than when Universal first entered the I-6 program.
9. In order to meet its burden of proof in this case, Universal must prove that (a) Edison could have met its forecast demand in the June 27 day-ahead market by submitting a higher bid that would have been acceptable under the PX's rules, (b) Edison's meeting its forecast demand in the day-ahead market would have obviated the need for a Stage 2 alert, and (c) in view of all the circumstances, Edison acted unreasonably by failing to submit such a higher bid.
10. Because the PX's rules in 2000 did not allow Edison to submit a vertical demand bid curve in the day-ahead market, and because Edison's analysis of the peak hour for June 27, 2000 shows that even if such a bid curve had been allowed, it would have elicited no more than 250 MWh of additional supply for Edison, Universal has not proven that Edison could have met its forecast demand in the June 27 day-ahead market by submitting a vertical demand bid curve.
11. Even if Edison had been able to obtain an additional 250 MWh of supply during the peak hour in the June 27, 2000 day-ahead market, such an increase would not have been enough to avert the Stage 2 alert called by the ISO on June 27, since the decision to call a Stage 2 alert is based on the reserves needed to support the ISO's system-wide demand, rather than on the reserves needed to support merely Edison's demand or the real-time market. Accordingly, Edison's scheduling practices in the day-ahead market did not bring about the Stage 2 alert on June 27, 2000.
12. The Commission should take official notice of the guilty plea by former Enron executive Timothy Belden and the FERC decision approving a stipulation between its staff and Reliant, as described in the foregoing findings.
13. The Stage 2 alert called by the ISO on June 27, 2000 was due to market circumstances not within Edison's control, including supply withholding.
14. In view of all the circumstances that prevailed on June 27, 2000, Edison exercised reasonable diligence in connection with its power purchases for that day, as required by Rule 14.
15. Universal has failed to meet its burden of proving that Edison has violated any law, rule or order of the Commission, as required by Pub. Util. Code § 1702.
16. Owing to its failure to meet the burden of proof imposed by Pub. Util. Code § 1702, Universal is not entitled to be relieved of the excess energy charge that Edison imposed on Universal due to the latter's failure to curtail down to its FSL when such curtailment was requested on June 27, 2000.
17. The Commission's Fiscal Office should be instructed to pay to Edison the $395,409.60 that Universal has deposited with the Commission, plus accrued interest.
18. Today's order should be made effective immediately.
IT IS ORDERED that:
1. Official notice is taken of the matter specified in Conclusion of Law 12.
2. The complaint filed herein by Universal Studios, Inc. (Universal) is denied.
3. Within 60 days after the effective date of this decision, the Commission's Fiscal Office shall pay to defendant Southern California Edison Company the sum of $395,409.60 that Universal deposited with the Commission in connection with this case, plus any accrued interest.
4. This proceeding is closed.
This order is effective today.
Dated April 28, 2004, at San Francisco, California.
