Federal and state interests clash as the FERC battles California over the future of the state's power exchange.
The California Power Exchange will not outlive its four-year mandate because it cannot compete with lower-cost exchanges, such as the New York Mercantile Exchange, Automated Power Exchange and low-cost over-the-counter brokers. So says Edward Cazalet, chief executive officer at Automated Power Exchange and chief rival of the CalPX.
Yet price appeared far down the list of items to consider, as the Labor Day weekend wound down and the Federal Energy Regulatory Commission took up arguments bearing on the future of the California Power Exchange.
On the surface, the issue seems simple: Should the FERC grant the application filed by San Diego Gas & Electric Co. for authority to sell wholesale power outside the PX? Yet the case has deeper ramifications.
SDG&E's application, though rightly filed at the FERC as the agency with authority over interstate wholesale power markets, nevertheless puts federal regulators in the difficult position of managing California's retail power market. The CalPX acknowledged the problem in its comments responding to SDG&E's motion:
"San Diego's application to this Commission [the FERC] is appropriate, because [it] has jurisdiction over sales for resale by utilities through the CalPX ¼ . However, SDG&E's application raises broad public interest issues regarding the mechanics of the California restructuring program, the length of the transition period and the efficacy of California's nascent development of an efficient competitive energy marketplace.
"In general, the [FERC] must evaluate SDG&E's proposal in light of the goals of the California restructuring program." (FERC Docket No. ER99-3426-000, comments filed July 29, 1999.)
FERC vs. CPUC: The Federal-State Conflict
Robert Berry, director of legislative affairs at Automated Power Exchange, puts the issue this way: "Suppose there had been several power exchanges operating in California at the time the FERC issued its order mandating that California's investor-owned utilities must buy and sell wholesale power only through the California PX. Would the FERC have had such authority? Could its order have survived on appeal?"
The case raises other questions as well:
* A Minimum Term? Did the California PUC impose a minimum transition period during which utilities must buy and sell through the CalPX?
* A FERC Admission? Did the FERC agree to a minimum term when it acknowledged in 1996 that a five-year term (later cut to four years) was crucial to California restructuring?
* Antitrust Only? Should the FERC conduct an antitrust analysis in reviewing the PX buy-sell requirement, looking only at market power?
* Broader Considerations? Should the buy-sell mandate end with the utility recovery of stranded costs, or does the term "transition" imply a larger goal, forcing the FERC to wait until California achieves true competition?
* A Split Obligation? Can the FERC waive the "sell" obligation even if the "buy" mandate remains in place?
* A NUG Exemption? Since state law exempted nonutility generation, why not accept the SDG&E motion as narrowed to apply only to third-party, non-QF purchased power?
* Market Too Thin? Is California's wholesale market robust enough to support trading through rival exchanges?
* Ratemaking Interference? Will a FERC decision interfere with California PUC deliberations on a ratemaking formula for the post-freeze, post-transition period?
Various parties have argued over what the PUC and the FERC intended in key rulings issued between 1995 and 1997. In its initial order setting the buy-sell requirement, the FERC appeared to require a full five-year term: "The five-year provision is a transition mechanism that appears to be critical to the entire retail restructuring proposal." Yet according to SDG&E, this statement by the FERC was designed merely to offer "preliminary guidance" to the parties. SDG&E acknowledged that early FERC orders "at several points refer to a five-year buy-sell requirement," but the utility says those references merely reflected the "general expectation" at the time that it would take that long for utilities to recover their stranded costs.
Many parties believe that the transition period should not terminate simply with recovery of stranded costs, but instead implies an organic process to achieve competitive markets - a process not yet complete. Comments from the California Electricity Oversight Board typify this view:
"The completion of certain actions that were to be completed within a transition period is not synonymous with completing the transition period itself. Elements of the California restructuring are still in a critical maturation phase."
Moreover, consumer advocates from the UCAN (Utility Consumers Action Network) and TURN (The Utility Reform Network) note that the California PUC is considering issues regarding post-transition ratemaking for the state's investor-owned electric utilities (see Application No. 99-01-016), including the idea of performance-based ratemaking tied to market benchmarks. As UCAN and TURN explain, one of the topics of debate in those cases is how to interpret prior PUC decisions regarding the intended duration of the transition period. UCAN and TURN urged the FERC to reject SDG&E's application and instead show "considerable deference" to California's prerogatives on restructuring. The Western Power Trading Forum agreed:
"Given the pendency of this proceeding ¼ the actions of the CPUC should be accorded significant weight."
SDG&E: Escape from Pasadena?
"SDG&E proposes to delete the requirement that its sales at market-based rates be made through the PX because ¼ SDG&E has recently divested itself of all its of its fossil-fueled generation, dramatically reducing the amount of generating capacity that it (or its affiliates) control," says Nicholas W. Fels. Fels, an attorney at Washington, D.C., law firm Covington & Burling, represents SDG&E.
The utility sees the question in antitrust terms. As the FERC has jurisdiction over interstate wholesale power markets, SDG&E argued that the FERC should treat its application to lift the buy-sell requirement in the same manner as it treats requests by power marketers for market-based pricing authority - by examining market power.
"None of the comments filed in response to SDG&E's request even attempts to rebut the showing that SDG&E lacks generation market power. This should be the end of the matter." (FERC Docket No. 99-3426-000, SDG&E answer filed Aug. 16, 1999.)
(To be precise, SDG&E already agreed in a recent California PUC case on post-transition ratemaking to continue to purchase power through the CalPX. Moreover, in its answer at FERC filed Aug. 16, SDG&E agreed to continue to sell its San Onofre nuclear generation through the CalPX, along with its in-system resources from qualifying cogeneration and small power production facilities. Thus, it would narrow its request to lift the buy-sell requirement only for sales of off-system-purchased power resources.)
Lynn Miller, chief financial officer at PX, says that SDG&E should not be allowed to leave the PX before the four-year mandate ends because that would make it more difficult for the PX to become competitive at the end of the mandate. Miller explains that the PX's financials were drawn up with the expectation that the three IOUs would sell through the PX for four years.
At the rival APX, Cazalet argues that the PX fully anticipated the possibility of early transition and that the primary voice against SDG&E leaving is the PX. "They have been concerned all along about the fact they would lose volume to competition because of their extremely high costs as opposed to what brokers charge."
Attorney Fels sees SDG&E's departure as no threat: "SDG&E is a small participant in a large market. The company has no market power requiring regulatory control of its participation in the market, having divested itself of 80 percent of its generating capacity in the San Diego Basin."
In its answer filed Aug. 16, SDG&E witness William Hieronymus (a consultant with PHB Hagler Bailly) countered arguments that the CalPX had seen thin trading volumes and claimed instead that allowing SDG&E to sell outside the PX would not have any significant impact.
"The total amount SDG&E currently sells through the CalPX is, at most, 1,349 megawatts, including 430 MW of San Onofre [SONGS] nuclear generation, 334 MW of QF contacts and 625 MW of purchased power contracts. This is only 6 percent of the average [of] 21,576 MW per hour of transactions that went through the PX in its first year and less than 10 percent of the minimum market-clearing quantity of the PX in any hour during April-December 1998."
Attorney Fels echoes that claim: "The only generation owned by SDG&E - its SONGS capacity - is only 430 MW, or about 2 percent of the amount of energy that is actually sold through the PX on an average day."
Ann Cohn, assistant general counsel at Southern California Edison, agrees that market power issues should no longer pose any concern.
"It is my belief that restricting the obligation to buy and sell from the exchange is only related to stranded-cost recovery," she says. Cohn adds that after the period of recovery of stranded cost, SCE should be able to procure energy where it wants.
"People can always buy from the [California] Power Exchange, but the obligation disappears," she says.
Cohn says any decision on the merits before FERC has precedence; however, it doesn't necessarily follow that a decision against SDG&E in its application would have any impact on SCE.
Block that Forward?
A Look at New Products
On May 26, the FERC granted an application by the California Power Exchange to set up a "block forward market" for trading blocks of energy out into the future - perhaps six months or more - through a newly established division at the PX called CalPX Trading Services. (Docket No. ER99-2229, 87 FERC ¶61,203.) The issue is not without controversy, however.
The initial application by the California PX, filed March 23, drew protests from NYMEX, Electric Clearinghouse [Dynegy] and APX, as well as spirited interventions from the California PUC, the state's Electricity Oversight Board, US Generating Co. Williams Energy Marketing, and of course Pacific Gas & Electric Co. and Southern California Edison.
The CalPX later added changes to assuage some concerns. In one change, as directed by the FERC, it said it would remove the eligibility requirement that block-forward market participants must also participate the PX's day-ahead market. Also, as the FERC suggested, it said it would file a quarterly listing or index of block-forward participants. (See Compliance Filing on Commission Order Accepting Proposed Block-Forward Market, Docket No. ER99-2229, filed June 9, 1999.)
Despite those changes, APX renewed its protest on June 28, arguing that CalPX had still failed to comply with the FERC's May 26 approval order. Moreover, Cazalet argues that the introduction by the California Power Exchange of block forwards marks an admission that the PX's original day-ahead blind auction does not work.
For example, says Cazalet, you may buy 100 MW at $25 when you get to the delivery hour. "The person that buys the power ignores the PX price in favor of $25 that was negotiated earlier. It is a way of admitting failure in the market."
Southern California Edison, Pacific Gas & Electric and, recently, SDG&E joined the PX's block forward market. Gary Cotton, SDG&E senior vice president of fuel and power operations says block forwards are another tool with which to meet electric commodity needs. Yet Cazalet argues that by introducing block forwards, the CalPX recognizes it will have to transform itself into what essentially is a bilateral market.
The PX assumes that the only way to achieve price discovery is by having a state-mandated, state subsidized power exchange, he says.
"We can provide all of the services that the PX could provide and do without such a mandate at a far, far lower price," he says.
"To extend the life of the PX another two years would be $70 million a year, which competitors could do for less than half."
Richard Stavros is senior editor, and Bruce Radford is editor-in-chief of Public Utilities Fortnightly.
The Case for Private Markets At Automated Power Exchange, CEO
Ed Cazalet says the choice should come down to price.
Ed Cazalet, CEO of Automated Power Exchange, the emerging rival of the California PX, claims that the PX's three largest customers, Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric, which together make up 90 percent of the volume going through the PX, would not sell through the PX if they were not state-mandated to do so.
Cazalet says that if all customers could choose their exchange, including the three largest investor-owned utilities, PX would lose out against competitors because of the high prices the PX charges to support its $70 million-a-year operation.
For example, Cazalet says, he competed against and underbid the PX for the development of an exchange in Illinois.
"[In choosing the APX], the ratepayers in Illinois are creating a power exchange at no cost to them. PX came in there with a high-budget, high-cost proposal that would essentially help them write off their high costs in California, and were rejected by the market in Illinois," he says.
The APX Illinois market is to open Nov.1 and the Ohio APX market opened July 1. In all of these states in which it will operate, there are no mandates for the APX, according to Cazalet. In Illinois, APX eventually will have to coordinate with an ISO, however, and will work with Commonwealth Edison and FirstEnergy's transmission until the Midwest ISO and the Alliance RTO are created.
"The question is that they were funded by a $125 million write-off paid for by the ratepayers of California. They currently enjoy a $70 million-a-year budget paid for by the ratepayers of California. Why should they be allowed to provide other services at the incremental cost which is essentially subsidized by the ratepayers of California?" he asks.
Cazalet says that PX's actions are evidence of a gold-plated bureaucracy trying to survive in the face of the impending end of its mandate, "in which case they will be in a 'death spiral,' to quote Becky Kilbourne," he says.
He argues that the PX is trying to mimic the private market using ratepayer subsidization and is not providing the final market. "Is the PX necessary after two years of poor design, poorly implemented at $5 million a month?" Cazalet asks.
Central Pool vs. Phone-and-Fax
Market observer Robert McCullough on the future of power trading.
Robert McCullough, managing partner of McCullough Research, a firm specializing in bulk power and restructuring policy issues in the United States and Canada, says that bureaucratic institutions such as the PX do not do business without force of law, and questions whether state-sponsored markets can survive in the long run.
"Doing business with the PX is vastly more expensive than doing business on the phone. The PX is an artifact of an administered market," he says.
McCullough claims that it takes at least 97 steps to do business with the PX, while it takes two or three steps to do business with everyone else. He also believes that it would be inconceivable for the PX to compete with the APX on price.
Even so, McCullough sees nothing wrong with the CalPX trying to open franchises in other states, though he does not believe the PX will be around after its mandate expires.
"It is perfectly possible for California to provide drivers' license bureaus to Nevada and Illinois. The question is, can you introduce a slow bureaucracy in another state where you have to wait in line."
But though McCullough finds the APX the more competitive of the two exchanges, he prefers specialists and open-outcry trading over computer programs.
"I like to open up the paper and call and make a trade. As a general rule, I would not want to trade through an automated computer program because they are vulnerable to gaming," he says. "I feel safer with a specialist at the New York Stock Exchange, rather than with computer-based price resolution."
For example, McCullough says that exorbitant PX averages push prices higher. The PX price can be $41.81 one day and $67.12 the next. Traders are stumped over changes in the PX market because the change implies the price of gas has gone up to $45, he says. Then you find out that there are no constraints in supply and the PX computer program is $20 over market price, he says.
"Someone learned to game the market," he concludes.
According to McCullough, Cazalet will discover that he is applying to be a specialist. (A "specialist" is a member of an exchange who maintains a fair and orderly market in one or more securities.)
McCullough likens the situation to the NYSE, which assigns a human specialist for each stock to make a market in that stock. The whole system is based on his intelligence and honesty, he says.
"NYSE could have replaced these guys with computers. Ed will play the specialist side of it," McCullough says. "People will prefer that he set the price. [In fact], I would rather call Ed Cazalet than his computer."
In fairness, McCullough predicts that Cazalet would recognize that he was being gamed and eventually change the rules at APX. Nevertheless, at the end of the PX mandate, McCullough fully suspects California will go back to standard markets where players buy from the cheapest source.
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