WHAT IS A SCHEDULING COORDINATOR?
At least 33 organizations know the answer to that question in California because by late last year that's how many SCs had filed to act as go-betweens to the independent system operator.
Although the definition varies depending on who's asked, an SC is simply a preschedule and dispatch office. An SC puts a power schedule together for itself or for energy service providers a day ahead or hour ahead. It submits the schedule to the ISO, gets it approved, then makes adjustments in "real time."
SCs are the outcome of a decentralized market, one where the ISO has few market-making functions. SCs were formed to manage a myriad of generation and transmission transactions from millions of users. The ISO, meanwhile, keeps the lights on for the state's 31.2 million people by operating the transmission system to accommodate the state's 58,000 megawatts of generation.
SCs will charge fixed or transaction-by-transaction fees for each schedule they put together. But since market participants estimate it costs as much as $3 million to get into the SC business full scale, coordinators will have to find additional income sources. Market savvy and transaction fees only go so far. One observer says that 10 cents either way on a megawatt-hour of commodity can make a transaction profitable or unprofitable for an SC, creating a "battle of the dimes" (see sidebar, "Sample SC Transaction").
Two requirements determine start-up costs: SCs must operate year-round, 24 hours a day so the ISO can always find someone to talk to. And SCs must be creditworthy; they are financially liable to the ISO for imbalances. Meeting agreed schedules at agreed locations is a coordinator's duty.
Many SCs so far are energy service providers or power marketers (see sidebar, "Application List"), although municipal utilities have filed to schedule their power. One important distinction is that ESPs are jurisdictional to the state; coordinators fall under federal authority. ESPs may get into the SC business because it's easy; they have trading floors and computer hardware and software adaptable to scheduling.
Early trends like that have some worried. Other questions heard in the market include:
Because they need to augment SC transaction-fee income, is the integrity of a combo ESP-SC at risk? Some participants fear if marketers dominate SC ranks, they could preempt budding SC organizations. Most agree that eventually markets will demand "pure" SCs.
Are SCs just another bureaucracy? The vote's split. Some say SCs must win as much business as possible and so can't be bureaucratic. On the other hand, "any regulation sets up some kind of cottage industry, and this is probably the cottage industry that's being set up by the new market structure established by the regulators," says Elena Schmid of the Office of Ratepayer Advocates. "Whether it's another layer of bureaucracy is a different question."
Could meter data passed to coordinators from ESPs and customers for settlement be tainted? No one is designated to enforce compliance with metering standards. Officials are working on it. Until a solution emerges, all SCs will pay for cheating.
If the granddaddy of SCs, the California Power Exchange, is subsidized through a CTC, will "everyday" SCs be put on unequal footing (see sidebar, "Startup Funding for the PX and the ISO")? Has the California PX cost too much, only to have its full functions delayed past the planned start of competition? The restructuring plan so far has cost $300 million.
Lastly, will the issue of managing risk associated with transmission congestion become more menacing as SCs begin to operate? Some say that by June 1998, market players will battle over the auction of physical rights at critical interfaces. The issue promises to envelop the country. Two solutions have been proposed: the auctioning of transmission congestion contracts, called TCCs, and the auctioning of physical rights at bottlenecks. The ISO couldn't decide internally on this issue and the Federal Energy Regulatory Commission has told it to develop an answer by mid-year.
Market participants have made themselves heard on SC issues since last February at the California ISO Scheduling Coordinator's User's Group. The 40-member group has grown to 130.
Gary Ackerman, regulatory affairs director of Mock/Avista Energy Inc., is the group's president. Some say he's part of the problem of a scheduler's market dominated by few players. Ackerman, however, believes markets are 200,000-pound gorillas that can't be tamed.
He admits that becoming an SC takes deep pockets and technical proficiency. "I wouldn't call it dominance," he says. "That's laughable." But he did say the necessary capital and proficiency posed significant barriers for new market entrants.
For those who see the SC as another layer of bureaucracy, Ackerman says SCs "can't afford it. They have to be efficient, otherwise they're going to lose their business, if not to a competing scheduling coordinator, then to a power exchange."
He says SCs will earn money by competing against the PX's cost with lower direct-access prices and by possessing more agility in rearranging supply portfolios hourly.
"The market price posted by the PX might be beaten on any given hour if the SCs are sharp enough and possibly take some risks that the PX might not take or that other SCs might not take," Ackerman says. "There's a trading function¼ you have to believe if there's gold to be had, that's where you have to find it."
One problem Ackerman foresees with coordinators is on the issue of tainted meter data.
Carl Imparato of Tabors, Caramanis & Associates, whose main client is Enron Corp., says there are proposals to remedy the tainted data issue. The California Energy Commission's solution would number meters and assure that each is accounted for monthly. Imparato estimates there are about 15 million meters in the state.
Imparato acknowledges the fear outsiders may have looking in: Should those turning to SCs be skeptical of moonlighting marketers?
What if a coordinator somehow used data from customer marketers to the benefit of its marketing arm? "It's certainly a risk," he says. On the other hand, he notes a marketer could create value by blending portfolios. In theory, a marketer like Enron could pay to have someone join a portfolio.
Marketers, meanwhile, are concerned that the rules of the ISO were put together by people who don't understand the commercial marketplace - people, who like Imparato, once worked in utilities.
He says people feel that the Enrons of the world, in supporting SCs, are trying to keep market transparency from occurring. "I just don't buy it," he says. "The crappier the rules or the marketplace, the more arbitrage there is and you can bet your money that marketers will take advantage of arbitrage," he says. "They should. But I don't believe that the California marketplace was put together with the idea of trying to create distorted rules. It was put together with the idea [that] as the rules evolved any bad rules would clean themselves up and these temporary arbitrage opportunities will go away."
Who Has the Rights?
Imparato says the marketers' biggest concern is that the ISO may put commercial rules into place that will distort markets. That's why, in the battle over the auction of physical rights, marketers have been fighting for firm transmission rights, or FTRs.
The traditional concept of physical rights is a contract transmission path, which may not be the real transmission path. "In the West, where we've been arguing for physical rights, what we really are arguing for is a different physical right," Imparato says. "A physical right which gets rid of the abuses of the old contract path system. The right is defined the same as the ISO's financial rights¼ It's a right that doesn't allow you to hoard the right."
By tradition, one buys a physical right. If it's not used, it's retained. The kind Imparato advocates is a "use it or lose it" provision, where the ISO gets to take back the right and sell it.
Imparato says by buying that right, a purchaser gets financial and operational certainty.
From the utility perspective, Ronald Cottom, Southern California Edison's grid strategies manager, admits physical rights don't work well. "We have loop flow," he says. "We've never been able to figure it out in 20 years."
Marketers, he says, fight physical rights because they never had to pay for loop flow. "It's a very simple market from an accounting standpoint. It says, 'I've bought certain rights.' From a utility standpoint, today when someone else uses your rights you have no ability to collect your money back.
"I think most marketers have never faced those types of things," he says. "They buy certain things, and they schedule it, and utilities today take it upon themselves to make everything work."
FERC has agreed to start out using the congestion rights proposed in the scheduling.
"What we want to do is make sure we target the people who use the path to pay the cost," Cottom says.
Besides congestion issues, utility distribution companies are concerned about SCs following their own operating instructions. If the ISO tells them to cut generation to balance with load because they're causing system problems, "my expectation is it better work," Cottom says.
Edward Cazalet, CEO of Automated Power Exchange Inc., looks at SC issues that will arise via the scheduling middlemen from another perspective.
APX employs about 20 people to build and operate power exchanges. On the operating side, APX will make its money by charging transaction fees.
"They're still thinking like a utility in the market," says Cazalet of his competition. "We charge both buyers and sellers. Our fees depend on whether you're an SC or not. If you're an SC, our fee is six and a quarter cents on each side of the deal. If you're not, they're twelve and a half cents."
Some of Cazalet's complaints about the California PX are worth hearing out. "They built something that's very expensive as far as hardware and software," he says of the exchange. "Their software-hardware design is cumbersome and behind schedule. As of Jan. 1, 1998, it is not scheduled to meet the original design requirements. They have deferred a lot of the functionality¼ I claim even when they have that functionality, it will be too complicated for most buyers and sellers to use."
Cazalet admits it's wonderful for his business, but at the same time, he doesn't want the PX to simply write off its start-up costs.
The APX CEO also decries how the PX is pricing its product. It charges about 31 cents per megawatt-hour to full-requirements customers, 37 cents to partial requirements customers and as little as 15 cents to large customers.
Even so, Cazalet thinks he will get a significant portion of the state's power exchange business. "Most of the major players have signed letters of intent with us," he says.
APX, Cazalet claims, has a few advantages over PX. For instance, traders can buy and sell up to a week in advance, similar to a standard commodity market. "You can press a button and buy, or press a button and sell¼ all the way up until just before delivery, you can be modifying your position," Cazalet says.
Cazalet's last beef is that the PX turned to OM Systems International/Hand-El for software development. OM is a Swedish company; Hand-El is based in Norway.
"Not that Norway's not a fine country," Cazalet says. "But if you're going to go for software development, where would you go? Silicon Valley or Norway?"
James G. Kritikson, scheduling director for the California PX, has an answer there: "Judgement was made that the pool they're running in Norway is very, very close to the type of pool auction and scheduling process that we are running here. And it was felt that there was enough similarities that it would be beneficial to go to the people who had already designed software to implement a pool that was quite close to the market we have in mind."
California's three utilities will form the bulk of the PX's market. The fact that the software and hardware won't work full-scale from the start has been long understood by the IOUs, Kritikson says. They know there won't be an hour-ahead market until March.
Other deferred functions include the day-ahead market, which will be run through an auction. The PX plans to run it as an "iterative" market where set bids create a preliminary market-clearing price. Participants will be free to change their bids on the buy and sell sides, but a series of activity rules will prevent gaming through the iterations. The software to prevent the gaming won't be in place until June.
Kritikson bats away Cazalet's claim that APX's week-ahead auction is beneficial. "They can't submit the schedule until a day before, just like us," he says. "So the transmission arrangements aren't firm until you get down to a day ahead when you submit the schedules to the ISO and there's a determination of whether there's
to be congestion."
Identifying the Options
Kritikson says from his PX roost, he sees people still uncertain of how the exchange will work on scheduling issues. He says the PX will enable contracts for existing transmission and for future power service contracts. "I think people need to understand they can arrange, in effect, for delivery of their contract power through the power exchange and get additional flexibility," he says.
He also has been asked: "If I have a bilateral contract, do I have to become an SC in order to get my contract scheduled directly with the ISO?" The answer is no. The contract can be effectuated by a simple buy-sell, or contract for differences, in the PX or through a coordinator.
Kritikson wants people to know, too, that if they're California PX participants, whenever there's over-generation, the PX energy price will drop to zero. Participants will be able to arrange for free power.
The number of retail customers who opt out of their current utility will drive development of the market. The more people who exit, the more likely the remaining IOUs will have QF take-or-
pay or nuclear and other contracts not susceptible to curtailment.
Changes are ahead for SCs, although perhaps not in all the areas these market participants raise. Susan Schneider, client services vice president at the California ISO, says the ISO will consider a market study to determine different levels of ISO service and charges.
"Now, you pay the grid management charge or you don't," she says. "Clearly, not everyone gets the same services from the ISO. Maybe people should have a choice about what they do, what they get from us and what they don't."
In 1998, the ISO will prioritize and analyze costs of changes.
The system operator also is very aware of the issue of data integrity.
"This whole system depends on people being honest and competent," Schneider says. "And most people will be both of those. But some people might not be one or the other and the question is, 'If there are problems, can we detect problems?' And then, 'Do we have something we can really do about it?'
"The only thing we can do now is say, 'Well, we revoke your ability to do business.' Well, for an inadvertent mistake, that's really a little bit much."
Ackerman thinks the future's scheduling process will be simplified.
"We've created a far too complex system," he says. Protocols, which, in trying to guarantee fairness and equality, add layers of complexity to the market and more cost than it is interested in bearing, he says.
"I foresee a lot of simplification and moving things back to a time like today where the wholesale transactions are done on a fairly routine basis," he says. F
Joseph F. Schuler Jr. is senior associate editor with Public Utilities Fortnightly.
Startup Funding for the PX and the ISO
Would a CTC Bailout Hurt SCs?
THERE'S a section in AB 1890, California's restructuring law, that
could butcher competition between the power exchange and SCs, according to market participants.
Section 376 concerns startup costs incurred to help implement direct access and fund the PX and the independent system operator. It reconciles such costs with the competition transition charge and the rate cap imposed on investor-owned electric utilities under AB 1890.
If the Federal Energy Regulatory Commission or the California Public Utilities Commission should approve PX or ISO startup costs for recovery through the CTC, but if such recovery would force utilities to back off recovery of costs for stranded generation investment in order to come in under the rate cap, Section 376 allows the utility to defer cost recovery until after Dec. 31, 2001, to the extent that such costs are not recovered from the PX or the ISO.
In November, the PUC told the three major electric IOUs to file plans to identify such costs by March 31 (Decision 97-11-074). On Dec. 3, it discussed a possible early termination to the rate freeze, which would speed up recovery startup costs. It voted 5-0 to force the IOUs to recover CTC costs as early as "feasible," including costs otherwise eligible for deferral under Sec. 376, and in any case to deny "complete flexibility" to the IOUs in managing cost recovery (Decision 97-12-039, Application 96-08-001). Some $85 million in PX startup costs are at stake, plus millions more in ISO costs. John Scadding, an advisor to PUC President P. Gregory Conlon, says the FERC has undertaken to review PX startup costs. The case (Docket ER98-210-000) was on the agenda for Dec. 17, the FERC's last meeting in 1997.
The prospect of this PX "subsidy" has SCs irate.
"We went to all this effort to separate the ISO from the PX and now to have the PX basically kill off all competition because its rate can be lowered by the fact that a competitor has to subsidize it - that doesn't make a lot of sense," says Carl Imparato of Tabors, Caramanis & Associates, whose primary client is Enron Corp.
Gary Ackerman, president of the Scheduling Coordinator's User's Group, is worried the $85 million would be recovered in rates.
"The amount of load which will flow through the power exchange yields an uplift charge or PX administrative charge of 31 cents per megawatt-hour," Ackerman says. That charge doubles if the $85 million is financed over five years and is included in rates, he says. "The scheduling coordinators get a credit against the PX. If the PX operating charge is only 31 cents per megawatt hour instead of its true full cost of 62 cents¼ that means it's coming out of our hide. That's the competitive issue."
Elena Schmid of the Office of Ratepayer Advocates says the PX is in a difficult situation. "It does seem to have a greater advantage [over other SCs] because it can turn to the ratepayers and get these additional dollars," she says. "At the same time, the power exchange is the mechanism that the majority of the core ratepayers are going to depend upon."
All of the IOUs must buy from the PX and sell into it through 2001.
"So if the price is not low," Schmid adds, "the ratepayers are going to pay one way or another. And this seems to be¼ the most cost-effective way¼
"The power exchange [is] balanced by the fact that it has many more regulatory responsibilities than any scheduling coordinator."
The PX, meanwhile, insists its costs were unavoidable. John Flory, PX business strategy director says: "We have incurred a lot of cost as an institutional player. The FERC expects us to do extensive market power monitoring. We had to put into place a business system designed by committee that cost us $30 million. If we could have chosen whatever system we wanted we could have gotten something closer to $3 to $5 million¼ By the time we started adding in all the California requirements, it pushed it up to $30 million, which by the way, was what the original budget that the PUC approved."
Scadding has the last word on Section 376.
"For the utilities, the Big Three who have got the stranded cost recovery, there's not a guarantee but a reasonable opportunity to recover their stranded costs," he says. "The 376 treatment is¼ saying¼ these implementation costs are passed through in rates and you have to pay them¼ But since you can't change the total amount your customers are paying you, what happens? Well, it comes out of their ability to collect stranded cost.
"If that happens, and that does not allow you to recover your full stranded costs except in a transition period, then we may permit you to continue that CTC collection past the original deadline."
So to sum up, ratepayers won't pay for PX start-up costs in rates, but in an extended CTC¼ an "electric welcome" to 2002.
American International Group
Arizona Public Service Co.
Automated Power Exchange Inc.
California Department of Water Resources
California Polar Power Exchange
California Power Exchange
City of Anaheim
City of Riverside
City of Seattle, City Light Department
City of Vernon
Duke Energy Trading
Enova Energy Inc.
Enron Energy Services
ENRON Power Marketing Inc.
LG&E Energy Corp.
Northern California Power Agency
NorAm Energy Services Inc.
Pacific Gas & Electric Co.
PG&E Energy Services
Portland General Electric
Power Resource Managers
Salt River Project
San Diego Gas & Electric Co.
Southern California Edison
Southern Energy Marketing
The Bonneville Power Administration
The Montana Power Group
Vitol Gas & Electric
Western Area Power Administration
Source: California ISO; applications acknowledged through Nov. 26, 1997.
Sample SC Transaction
SO how can an SC make money in the California market? Here's a simplified example of an electricity purchase of one megawatt-hour, assuming a purchase price of $20/MWh plus associated costs, but not including an SC transaction fee. As shown below, an SC would have to sell the electricity for $22.53 just to break even. The spot price for peak-firm delivery at the California-Oregon border on Dec. 18 was $21.75 to $22.75 per MWh, as reported by Reuters.
SC's energy cost: $20.00 (estimated per MWh price)
SC's coordination fee: + 0.30 (SC's cost to execute transaction)
Grid management fee: + 0.73 (actual tariffed rate charged by ISO)
Congestion fee: + 0 (assuming no congestion)
Ancillary services fee: + 1.50 (varies by hour)
SC's final cost: $22.53 (per MWh)
Note: All figures are estimates except the grid management fee, which is the ISO's administrative fee approved by the California PUC. The SC's coordination fee was based on the PUC-approved 31-cent coordination fee the California PX will charge full-requirements customers to recover its costs. For non-full-requirements customers, the PX will charge between 15 cents and 37 cents per MWh, depending on load. For simplification, losses aren't included. - Elizabeth Striano, managing editor.
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