And where the trouble spots lie in FERC's grid plan.
The mood appeared calm on June 26 in Washington, D.C., at the regular bi-weekly meeting of the U.S. Federal Energy Regulatory Commission (FERC). Key officials from various regional transmission organizations (RTOs) had gathered before chairman Pat Wood and the other commissioners to brief them on progress over the past year in reforming wholesale electric markets, and on what the FERC might expect in the summer at hand.
There was little hint of the fight playing out around the country on the very structure of those same RTOs-a fight that has tied the grid in knots-even as the date grew near when the FERC was expected to announce a new standard market design (SMD) for the transmission network.
Joseph E. Bowring, manager of PJM's market monitoring unit, voiced confidence.
"The markets worked effectively," he said, speaking of calendar year 2001.
"Not perfectly, but effectively."
A similar view emerged from Robert Ethier, manager of market monitoring and mitigation for ISO New England (ISO-NE), who saw markets in his region as "workably competitive."
He even bragged that ISO-NE was adding generation capacity faster than PJM. It was "investor exuberance," he said, that had left New England with forecasts that reserve margins through 2006 would double those that prevailed from 1999 to 2001.
California, of course, was not so confident. Anjali Sheffrin, director of market analysis for the California ISO (CAISO), warned that the market "still remained fundamentally frail." She cautioned that CAISO remained dependent on imports for 20 percent of supply.
And two weeks earlier, CAISO had warned of a growing generation shortage in its "Fourth Quarterly Report," filed at FERC on June 14. As the report explained, between April 15 and June 1, only about 100 megawatts of new generation had come on line out of some 1,988 MW that had been expected as "viable."
"This alarming trend," said CAISO "is largely due to financial difficulties facing new generation developers."
David Patton, who serves as independent market advisor back East for both ISO-NE and the New York ISO, affirmed the general mood of confidence, that New York markets had proved to be "very competitive" in 2001.
According to Patton, lower fuel prices and fewer power plant outages in eastern New York had led to lower energy prices statewide and substantially less congestion. In fact, he added, electricity prices in New York had fallen 52 percent from January to December 2001.
Patton noted that New York had succeeded even in introducing virtual trading in the day-ahead market with no evidence of strategic attempts to manipulate prices.
Looking ahead, Patton advised that New York represented "the direction FERC is taking in its standard market design."
Yet it remains to be seen whether the nation's regional grids will set their sails for the same point on the compass.
Even as FERC's anticipated issue date for SMD grew nearer, the details of the rule were largely known, and had been for at least six months. FERC had offered clues in various "working papers" and in a spate of hearings held last winter and spring.
A preferred RTO structure would likely feature an independent transmission company (ITC) that could define its own revenue requirement, but that would operate under an RTO "umbrella" that would design and file the grid tariff, and oversee planning, expansion, and market monitoring.
A bid-based, security-constrained unit commitment and dispatch was seen as essential. So was a day-ahead market. The RTO would use locational marginal prices (LMP) to manage congestion. Financial transmission rights clearly were preferred over physical. Some sort of capacity market would likely serve to assure generation supply, but the jury was still out on that one.1
Nevertheless, despite the advance warning on the contents of the rule, the experience of the past few months leading up to its anticipated release has seen a few of the various regional grid groups defending bits and pieces of policy that don't quite add up to the real, live SMD.
At the same time, other issues have emerged, both in discussions at FERC and in the crucible of the market, that suggest it won't be all that easy to craft a single coherent protocol.
Midwest. In the nation's midsection, the industry faulted a top-down, physical solution to congestion management proposed as a stopgap "day one" solution by the Midwest Independent System Operator (MISO, already certified as an RTO).
New York. In the Empire State, where the FERC accepted a complex computer-driven protocol for market monitoring that the New York ISO had offered up as an all-or-nothing package deal, opponents had shown how limitations in software programs would lead to dubious results.
California. On the West coast, where many have panned CAISO's proposed new MD02 market design as "fruit from the same tree," the ISO seemed bent on controlling prices and generator behavior, yet its budget appeared out of control.
RTO West. In the Pacific Northwest, where hydropower reigns supreme, planners envision an RTO that would turn FERC's dictates on end by managing congestion with voluntary "inc" and "dec" (incremental and decremental) bids to create a locational shadow price, but without a bid-based, security-constrained protocol for dispatch or unit commitment.
And FERC itself has showed concern that RTOs are not evolving the way they "should."
Where RTO boundaries are concerned, utilities have turned the map inside out, reversing common notions of East and West. FirstEnergy, an Ohio company, sees its future with MISO, a heartland region centered primarily on the upper Mississippi valley and the central plains states. Exelon, with its roots in Chicago, has eyes for PJM, centered back East.
"The area continues to evolve according to the idiosyncratic desires of the transmission owners," complained commissioner William Massey.
"We are all concerned," added Nora Brownell, "that RTO formation be done for the right reasons."
MISO: Managing Congestion Without a Market
MISO proposed a revised congestion management plan on May 1 as a temporary "day one" measure that captures in a nutshell the key confrontation over FERC's SMD. That confrontation pits two opposing views of proper grid management:
- Run the network as an engineering project, with top down control of dispatch and congestion; or
- Quantify the risks and settle them with cash or hedge them with financial instruments.
(Note: FERC OK'd MISO's plan on June 26, but the jury is still out on whether it will mesh with the SMD, as FERC suspended the effective date of its order and set a technical conference for later this year. See page 6 of this issue, for a letter of explanation from MISO spokeswoman Mary Lynn Webster.)
MISO's plan, known as "Attachment K," calls for MISO operators to identify constrained flowgates and then engineer a physical solution through redispatch, after calling for voluntary inc and dec bids (at least three pairs of bids to ensure no market manipulation).
MISO then would assign redispatch costs-sometimes on the basis of load ratio shares, as before, but sometimes (for larger impacts) through direct allocations to utilities owning the particular grid assets believed to be involved in the congestion. That utility-specific allocation would reflect data from the North American Electric Reliability Council (NERC) on real power flows.
In its defense, MISO said it had offered the plan only as a "day-one" solution. It explained that a PJM-style plan, with locational marginal pricing for energy, with a bid-based, security constrained dispatch, cannot be achieved until about the middle of next year.
That excuse, however, did not satisfy the plan's opponents, which included traditional investor-owned utilities, as well as merchant generators. They questioned whether MISO could succeed in identifying troubled flowgates and accurately allocating costs. They demand a more transparent protocol patterned after the SMD envisioned at the Federal Energy Regulatory Commission.
This reaction from Cinergy's Walt Yeager, manager for market development, was typical:
"Cinergy supports … markets designed around locational marginal pricing, such as the FERC has begun to assess in its SMD proceeding. However, the core features of such a design-a bid-based locational market for energy, and the ability to hedge against congestion costs-are missing here." (See FERC Docket No. ER02-1767-000, plan filed 5/8/02)
Others questioned MISO's attempt to effect a purely physical solution to congestion management-one that would ignore the monetary value that traders place on various constraints, as determined from their energy bids, and whether traders would just as soon be willing to buy through the constraint.
The unresolved problem, according to Duke Energy, was that MISO would redispatch to support firm transmission services in all circumstances, even when the cost of redispatch exceeds the benefits. MISO would pass along those costs to transmission customers, said Duke, "who are provided no advance notification of their transmission charges, nor provided an opportunity to manage their cost exposure."
Opponents lamented the lack of financial transmission rights (FTRs), which would allow customers to hedge or in effect arrange for their own redispatch.
"There is no opportunity for a financial hedge," said Cinergy.
"The transmission customer is notified after the fact that it must pay congestion costs, and has no opportunity to offset such costs."
MISO had defended its plan as avoiding TLR instructions (transmission line loading relief), but Duke saw that as no justification. "While MISO gives the impression that its new Day One congestion management plan will replace TLRs with a true market mechanism for managing congestion that will provide the same types of benefits as LMP/FTRs, this is simply not the case," said Duke.
Cinergy added that any attempt to value congestion without underlying energy bids and locational energy prices would prove fruitless. "Under PJM's LMP model," Cinergy advised, "the bids that determine congestion costs are bids into energy markets, which are robust and actively traded markets … The congestion costs derived from these markets are essentially a secondary effect of the energy bids," according to Cinergy. "Absent such a bid-based energy market, development of a full-fledged bid market solely to support relatively infrequent events of congestion and redispatch would be artificial."
New York: Better Monitoring Through Software
This spring FERC OK'd new automatic mitigation procedures (AMP) for the New York ISO for market monitoring and price mitigation. But the jury is still out, as FERC acknowledged potential limitations with the current software in place in New York, and warned that it might revisit the issue after release of its formal SMD rule. (Docket No. ER01-3155, 99 FERC 61,246, 5/31/02)
New York's AMP model involves a complex series of computer SCUC (security-constrained unit commitment) runs. The first SCUC run compares bids with market-clearing zonal prices (the "conduct" test). If the gap is too great (which might suggest improper bidding), the ISO conducts a second SCUC run to calculate how prices would have differed if suppliers instead had bid closer to their historic pattern. If that difference is great enough (the "impact" test), then the software triggers price mitigation.
The problem, however, lies in deciding how far to extend the relief. If improper bidding in one zone in a certain hour triggers offending price impacts in neighboring zones in that hour and perhaps others, should mitigation then apply in the bid zone, the neighboring zones, or across the state? And in what hours?
And can the software sort that out?
In practice, New York has opted for a simpler solution that requires less complicated software. Here is how the ISO explains it:
"A consequence of using a single SCUC run (the second pass) for the impact test is that units breaching conduct thresholds in any hour in any location will be mitigated for all of the hours and zones … .
"That is, while the SCUC implements a highly sophisticated and comprehensive unit commitment and pricing algorithm, a single SCUC pass cannot limit mitigation only to the particular hours and location in which there was a material price impact."
The ISO then adds that this situation "was known to stakeholders prior to the initiation of the AMP."
The ISO suggests that with software improvements, it may be able to add a third SCUC run to solve the problem, without imposing too many delays on the final posting of day-ahead market prices beyond the normal 11 a.m. deadline.
But it would not plan to run a third SCD (security-constrained dispatch) pass for real-time markets:
"The SCD must be re-run for every five-minute interval of the real-time dispatch," says the ISO. "Adding an additional impact test run is not feasible with the current capabilities of the system."
But opponents say that will force mitigation on many suppliers who did nothing wrong. (See Fig. 1, Price Mitigation in New York) Dynegy lawyer Steve Huntoon added more examples of how New York's AMP rule might lead to arbitrary price controls:
- Bidding History. It sets reference levels for bids based on the previous 90-day period, instead of comparing bids only for similar hours and similar seasons of the year;
- Out-of-State Generation. It exempts external generation that bids into the day-ahead market; and
- Network Resources. The ISO requires mitigation for generator capacity that fails to qualify as a network resource, since it applies AMP to installed capacity levels, without discounting for historical forced outages to calculate the net UCAP (unforced capacity) amount.
Huntoon asked why an in-state generator should suffer a greater threat of price mitigation than an out-of-state generator that does not qualify as a network resource and yet can bid into the New York market like a carpetbagger.
"A PJM generator," as Huntoon explains, "has the flexibility of bidding its unit up to $1,000/MWh, giving it the flexibility to sell energy into the highest-priced region … .
"In-state generators should be treated no worse."
California: New Design Wins Few Friends
In California, the bitterness left behind from the flawed market design that created the power market debacle there appeared quite evident in the way the electric industry reacted to CAISO's new market design (MD02), proposed with fanfare on May 1. "Untenable," said the City of San Francisco.
"Mayhem," said the Transmission Agency of Northern California (TANC).
"MD02 is an apple that falls near its roots and offers only incremental change that is unlikely to remedy the problems it identifies, rather than a fundamental rethinking of what has been proven to be a fatally flawed system," TANC added.
And the criticism cuts across all sides, from generators to utilities to marketers to regulators. Few appear happy.
And CAISO went a step further than called for under FERC's SMD structure, volunteering a new test to determine whether wholesale power prices qualify as "just and reasonable" under the Federal Power Act. That test would center not so much on a bid-based market but on producer profit margins.
Meanwhile, CAISO itself has seen its own budget soar out of control, putting the question to FERC on how much leeway to afford to RTOs in collecting their administrative costs through a grid management charge.
Generator Behavior. Williams Energy saw CAISO's proposed market design as aimed more to control power costs and generator behavior than to create a structure in which competition might flourish.
"It is clear from the filing that the politically motivated ISO is seeking a full return to heavy-handed command and control regulation, and the filing appears to be aimed more at controlling wholesale power costs than providing comprehensive market design proposals."
The Independent Energy Producers felt that CAISO had strayed too far from the SMD, as practiced in the Northeast. "Given the relative success of markets such as PJM and NYISO, and the past problems in California, IEP is wary of proposals that California blaze new and untested trails," the organization said. "CAISO's proposed belt, suspender, rope, and noose combination of must-offer unit commitment, local market power mitigation (through bid caps), AMP, damage control bid caps (at levels far below other markets), and a competition index is excessive and will ultimately harm the consumers it seeks to protect," the producers added.
The ACAP Rule. Many players opposed CAISO's proposed ACAP (available capacity) obligation to assure generation supply. CAISO would couple its ACAP regime with a must-offer rule and a residual unit commitment (RUC) process, to cover any "gap" that might exist between CAISO's forecast of day-ahead load and the total amount of supply resources that load-serving entities actually clear though the day-ahead market.
Power producers complained that the three-part protocol would fail to compensate them for startup and minimum-load costs, or take account of operating limits dictated by emissions rules. Edison Mission said that if CAISO forces plants to be available for dispatch to meet morning load, but they shut down after the afternoon peak, with that pattern repeating daily, a plant could quickly exhaust a year's worth of emission credits, because of too many cold starts.
The Bonneville Power Administration (BPA) also has attacked CAISO's ACAP plan, arguing that out-of-state suppliers who sell power into California could suffer discrimination.
The problem, says BPA, stems largely from the fact that operators in other control areas in the Western Interconnection cannot achieve automatic generation control or dynamic scheduling across control area boundary lines. That means that outside suppliers lack the capability to comply with CAISO instructions for intra-hour redispatch. In fact, said BPA, suppliers outside CAISO lack even the permission to adjust mid-hour configuration, as western reliability rules don't permit such deviations.
"The term 'deviation' is a misnomer in this situation," explained BPA attorney Lara Skidmore, "because the import supplier is not deviating from the amount scheduled according to the practices of its control area.
"Rather," she explained, "it is the ISO that is deviating from the amount it knows the importer is obliged to deliver. It is inappropriate to penalize importers for their inability to follow these ISO dispatch instructions, and it is discriminatory for the ISO to impose 10-minute dispatch on resources that are unable to follow its instructions."
This problem will apply as well to CAISO's redesign of its 10-minute real-time market, which also requires mid-hour re-dispatch unavailable to imports.
"As a result," said Skidmore, "imports are paid the 10-minute price even when those prices are below the bid price." That risk, she says, "makes the ISO real-time market less desirable than other West Coast markets, which have price certainty for sellers."
In instructive fashion, Sempra faulted the ACAP/RUC plan as focused wrongly on energy supplies, rather than arranging for capacity, or pure availability, as under UCAP and ICAP (installed capacity) plans in effect back east.
CAISO proposes to minimize the total cost of serving the expected real-time demand for energy, Sempra said, instead of minimizing the "capacity" cost (start-up and minimum load). "Thus, under CAISO's approach, the RUC service would be used to buy both additional energy and capacity. The PJM and New York ISOs, on the other hand, employ an objective function of minimizing the costs of 'capacity'," Sempra pointed out. "By restricting the objective function to minimizing the capacity cost, thereby refusing to purchase additional energy until closer to real time to see if it is actually needed, the eastern ISOs have less cost to uplift."
Sempra won agreement from the California Municipal Utilities Association (CMUA), which also saw the MD02 ACAP scheme as inferior to eastern ICAP rules.
"Certainly," said CMUA, "CAISO made no showing to demonstrate the need for such an intrusive and ISO-centric proposal. To [our] knowledge, this construct is completely at odds with the capacity obligations enforced in eastern ISO's, which CAISO admits." (See FERC Docket No. ER02-1656, comments filed 6/3-4/02)
A New Price Cap. As part of its MD02 redesign, CAISO also has proposed a new test to begin after Oct. 1 (after FERC's West-wide price caps end) to discern whether wholesale power prices are too high and to trigger price mitigation automatically.
The new test would create a new 12-month rolling index of average monthly price markups above cost. Then, whenever the markup exceeded five percent, CAISO would assume that power prices were no longer just and reasonable. CAISO offered statistical evidence to show that the largest price spikes over the past couple of years had corresponded with markups above five percent and vice versa. (See Fig. 2, California Power Prices) Also, it appeared that when prices spiked, the spike could be explained to a great degree by the size of the markup. (See Fig. 3, California Price Markups)
But some, including Lara Skidmore at BPA, heaved brickbats at the CAISO proposal. Skidmore argued that California is so dependent on summer hydro imports as to make the new test unworkable:
"The simple effect of hydro surplus during normal-to-wet years is to bring the real-time price down. … A secondary effect is displacement of relatively higher-cost thermal generation, bringing spot gas prices down … ." Skidmore also pointed out that "[d]uring drought, these effects are reversed, with both power and gas prices increasing due to the greater use of higher-cost generation to make up for the lack of surplus hydro. … This influence is prominent in the high-price periods that occurred in the ISO market in Oct. 1999, May 2000, and in the fall of 2000 when streamflow was less than expected." She added that if "automatic mitigation is triggered simply by an increase in the average price, it may be inappropriately triggered by year-to-year fluctuations in hydro generation." (See FERC Docket No. ER02-1656, motion filed 5/22/02.)
Budget Problems. Meanwhile, CAISO remains beset by budget woes-a problem that may well merit a rethink from FERC.
As a non-profit benefit corporation, CAISO's only source of revenue comes from the grid management charge (GMC) it collects for managing congestion and providing ancillary and control area services. Yet even as CAISO proposed a hefty boost to its GMC to keep up with administrative costs, demand for CAISO's grid services continued to fall, threatening a classic death spiral. (See Fig. 4, ISO Grid Management Charge)
Also the proposed GMC rate hikes seemed to mirror huge costs that CAISO has incurred over the past several years for litigation and crisis response-activities that more resemble lobbying than grid operation.
For example, in CAISO's latest "rate case," filed to set the grid management charge for 2002, the state public utilities commission (CPUC) recommended slashing $23 million out of CAISO's claimed revenue requirement of $244 million.
David Cohen of Navigant Consulting said he would have cut $45 million. Cohen tracked CAISO's employee count for 12 months, beginning in Sept. 2000, and concluded that the agency ran an average of eight to 10 percent in unfilled but budgeted positions over the period. In that light, Cohen described CAISO's proposed 2002 budget as proposing a "staggering increase" in full-time employees. (See Fig. 5, ISO Personnel Costs)
CPUC witness Manuel Ramirez noted that CAISO's budget for just managing transmission rivaled the cost of the service in its own right:
"It is worth noting," he said, "that Southern California Edison's recently filed transmission owner tariff case requests a transmission revenue requirement transmission of $207 million." (See FERC Docket ER02-250, testimony filed 3/25/02)
RTO West: Locational Prices With Traditional Dispatch?
The biggest fight between traditional utility practice and FERC's new-fangled SMD is playing out in the Pacific Northwest.
That's where the sponsors of RTO West have proposed a novel structure designed to preserve current rights under pre-existing transmission contracts, and to dispatch generating resources in a traditional manner not grounded on competitive bidding.
The RTO West plan would allow hydroelectric plant operators to honor historic obligations related to agriculture, reservoir operation, conservation, and wildlife management.
At the same time, however, RTO West would propose to solicit bids to manage congestion and create locational-based prices (LBP) with financial transmission rights. The locational price would equal the nodal price difference between the injection node and extraction node for any power transaction. As stated however, dispatch would remain completely independent of LMP.
That would make RTO West markedly different from the Northeast grid groups.
In the Northeast, and under FERC's SMD concept, the RTO gathers competitive bids from suppliers, and then "crunches" them using a computer run that schedules or rejects each bid based on a simultaneous ranking that reflects both price and the constraints of the grid. The process yields a set of locational, nodal "shadow" prices that reflects market preferences and physical realities.
The question, then, is whether the RTO West LBP model can make a market in financial grid rights that commands enough respect to allow the players to hedge congestion with confidence and to trade FTRs in a secondary market.2
Will FERC accept this rather drastic reworking of its SMD? Local utilities see little choice in the matter. Listen to PNGC Power, a generation and transmission cooperative.
"The dominance of the hydro system in the RTO West geographic area, and the multi-use nature of the hydro system, make it a poor candidate for FERC's SMD concepts."
The co-op notes that even the grid system is different: "In the West, path rating changes after day-ahead [market clearing] occur frequently due to events like ambient temperature changes, range or forest fires, and lightening storms, etc." The co-op also points out that de-rating operational transfer capability based on these factors occurs far more frequently in the West than in the Eastern Interconnection, due to the long distances traversed by transmission lines. Thus, the co-op said, "marginal bus prices should not be used to send price signals to path users."
The sponsoring utilities for RTO West acknowledge their differences with FERC, but defend their novel proposal as workable. "The process for clearing congestion that arises during the scheduling process will rely on a system of voluntary bids … . Participation in the inc/dec bidding process must be voluntary to avoid disrupting the system of hydroelectric and thermal optimization that is fundamental … in the RTO West geographical area." According to the RTO West sponsoring utilities, this optimization process relies on operator self-commitment of resources. To the extent that a voluntary bidding structure raises concerns that markets may not be as deep and liquid as needed for competitive outcomes, the RTO West proponents says that their proposal provides several tools to address these concerns.
Yet opponents are not convinced.
Serious doubts are voiced by the Northwest IPP/Marketers Group, which includes Calpine, Reliant, PPL Energy Plus, PG&E National Energy Group, UBS AG, TransAlta Energy Marketing, and the Western Power Trading Forum, among others. The group fears the lack of a day-ahead market forged in a bid-based, security-constrained computer run.
"Without a full day-ahead energy market there will be no assurance that locational prices set in the RTO West congestion redispatch market will match prices in bilateral trading hubs [e.g., COB, Mid-Columbia]. … If the RTO-determined prices do not match hub prices, the transmission rights sold by RTO West will be imperfect hedges and RTO West will pose needless risk to participants," the RTO West doubters said.
For what it's worth, the LBP concept claims support from a group of Canadian planners, including ESBI Alberta, Ltd., the Alberta Dept. of Energy, and the Power Pool of Alberta. Again, they point to physical differences in the grid: "In the West, transmission networks are sparser and less meshed than for electric systems on the eastern seaboard. The system is characterized by stability issues rather than thermal issues; hence the determination of available transmission capacity is less transparent and in many cases there are no generators physically present downstream of a constraint."
They would favor the RTO West model for Canada, too.
"In Alberta, due to the geographically dispersed loads and centralized generation resources, the LBP model would provide more re-dispatch options than LMP." In an interesting twist, RTO West proposes no ICAP or ACAP model to assure g eneration supply. Perhaps that is due to the region's dependence on hydroelectric plants, which are energy limited (reservoirs are finite) but offer capacity to spare.
In truth, RTO West does propose a number of innovations, including its regime of cataloguing transmission rights under pre-existing contracts, and a so-called "lockdown" to limit a last-minute exercise of CTRs and mitigate the problem of phantom congestion that has plagued California.
Nevertheless, the RTO's eight-year transition period for retaining license-plate pricing does bear some notice.3
- For example, the Montana Consumer Advocate sees long-running license-plate, or "company" rates as detrimental to Big Sky ratepayers, who presumably might see cuts in transmission rates in moving from license-plate pricing to a unified postage-stamp rate:
- "Aspects of the RTO West design that have a negative impact on Montana consumers, such as the increased export of low-cost energy from Montana to the rest of RTO West, happen on Day 1, while provisions that might be expected to help Montana consumers, such as the potential move to wider sharing of the high costs of the transmission system in Montana being used to deliver and export the low-cost energy, are deferred at least until after the company rate period (eight years), and may never occur."
Yet some suggest that an eight-year honeymoon for license-plate pricing may prove insufficient to protect grid customers if Bonneville Power Administration should update its own "company" rates on joining the RTO.
Consider these comments from Northwest Requirements Utilities, a group of transmission-dependent utilities who rely for their energy supplies on the Bonneville Power Administration, and who called for a longer, ten-year transition:
"Even with the attempt to avoid cost shifts, the cost to BPA transmission customers will increase by at least 15 percent as a result of Bonneville's participation in RTO West.
"This increase is before consideration of the various costs that will come with RTO West and the potential tax liabilities that Bonneville and others may incur."
Finally, the question remains whether, in seeking to protect its hydro-based system, RTO West might end up hurting merchant generators that burn gas or coal.
The IPP/Marketers Group acknowledged that coordinated hydro operation might justify some variation from market design elements "that might otherwise be considered standard." Yet the Group warned that honoring CTRs for hydro optimization and the omission of a fully bid-based, security-constrained dispatch might make thermal plant operation less efficient.
That system, said the Group, "takes no account of effects on the dispatch of non-hydro resources, unnecessarily raising the cost of energy in the RTO West Region."
- See generally, "A Hope, Wing, and a Prayer: Toward a Standard Market Design for RTOs," by Bruce W. Radford, Public Utilities Fortnightly, Apr. 15, 2002, p. 34.
- Note that RTO West would rename its FTRs as FTOs, as they would function as options, rather than obligations. Holders would "cash" their FTOs only against physical transactions-known as a "use-it-or-lose-it" model. Holders of grandfathered contract rights would gain CTRs-catalogued transmission rights-that would operate in much the same way. CTR holders also could exchange their rights for FTOs, but many see no incentive to do so, predicting that markets for FTOs will prove shallow and illiquid, without a bid-based security-constrained dispatch to give a market basis for the value of congestion. Many also opposed the notion of option-based rights, which insulate the holder from having to pay on a hedge if congestion flows in the opposite direction from expectations. They argued that obligation style-rights would allow RTO to issue a greater quantity of rights and deepen the secondary market.
- License-plate pricing schemes are designed to recover embedded costs by charging a fee to transmission cstomers. That fee covers the revenue requirement of the utility that owns the transmission system containing the load served by the transaction in question. License-plate tariffs are called "company rates" in RTO West parlance.
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