Transmission & ISOs
Market Monitoring. Less than one month after it found anticompetitive behavior and asked to suspend trading in its own market for 10-minute nonspinning reserves, the New York Independent System Operator filed "Addendum A" to its Market Monitoring Plan, listing thresholds and cutoff points it will use to identify market abuses.
However, the ISO said it would impose mitigation measures only for conduct deemed "significantly inconsistent" with competition. That means conduct that produces a "material change" in either prices or guaranteed production cost payments in New York power markets. It defined "material change" as an increase of 200 percent (or $100 per megawatt-hour) in the hourly day-ahead or real-time locational marginal price (LMP) of energy at any location, or a 200 percent increase in daily guaranteed payments owed to a market participant.
Overall, the ISO will monitor three types of conduct related to power production or bidding. It offered examples for each type, along with threshold levels used to identify suspicious conduct:
- Physical Withholding. Refusing to offer bids to sell output from a power plant, falsely declaring a unit to be out of service, or running a unit at too low an output. Defined as (a) operating a unit at less than 90 percent of the ISO's dispatch instruction, or (b) withholding 10 percent or 100 megawatts of the capability of a single unit, or (c) withholding 5 percent or 200 MW of the total capability of a market participant.
- Economic Withholding. Bidding at "unjustifiably high" prices, either to avoid dispatch or to ensure that a bid sets the marginal market-clearing price. Defined as increasing a bid too much (such as 300 percent) above mean or median bids reflected in bids submitted during the previous 90 days for similar hours or load levels. The ISO added that bid increases above prior mean or median levels of $100 per megawatt-hour (for energy) or $50 per MW (for real-time spinning reserve) would also draw attention.
- Uneconomic Operation. Boosting unit output to uneconomic levels to create a transmission constraint and gain a benefit. Examples are running a unit above 110 percent of the ISO's real-time dispatch instruction, or scheduling energy at a locational marginal price less than 20 percent of the applicable base level (the mean LMP for the lowest-priced quartile of hours that the unit was dispatched over prior 90 days).
The ISO suggested it would not monitor markets outside New York. As it noted, "taking advantage of opportunities to sell at a higher price or buy at a lower price in a market other than a New York Electric Market shall not be deemed ... inconsistent with competitive conduct."
However, it acknowledged that by setting and disclosing the precise thresholds that trigger sanctions, it actually might influence decisions by generators. Thus, the ISO said it would monitor future conduct focusing on whether the very act of disclosure might require it to fashion an entirely new set of thresholds.
ISO Funding. The Midwest ISO asked the Federal Energy Regulatory Commission for authority to issue $200 million in debt, saying it had no other source of funds but a short-term letter of credit from UNICOM, and that it could not meet the FERC's test for independence with its only funding source coming from its largest transmission owner.
MISO said the debt would be rated "A3" by Moody's and "BBB" by Standard & Poor's. The ISO said it was "at the point of executing contracts with vendors" for telecommunications and integrated control center systems, and needed financing to "demonstrate the ability" to fund such purchases.
Congestion Pricing. On March 31, ISO New England filed amendments to the New England Power Pool's restated agreement containing a proposed congestion management system (CMS) and a multi-settlement system (MSS) for the New England control area, as did a splinter group of NEPOOL participants, identifying themselves as the "Supporting Generators."
But NEPOOL itself was unable to file a CMS or MSS plan, as it required a two-thirds vote of its participants committee, but only 64.88 percent had agreed to put the question on the ballot.
So the FERC voted 3-1 to extend authority to NEPOOL until June 1 to continue to apply its current method for allocating congestion management costs as a stopgap measure. Commissioner Curt Hébert dissented, pointing to the "familiar routine" of NEPOOL filing for more time, and complained that FERC had tied the lifting of price caps to filing of a redesign. "With price caps in place, NEPOOL has no incentive to submit a redesign," he complained. Docket No. ER00-1659-000, April 12, 2000 (F.E.R.C.).
Meanwhile, a group of utilities in the Northeast (the so-called "Anti-Subsidy Complainants) had anticipated the ISO's action and already filed a complaint attacking the plan.
The ASC group (including Central Maine Power, Northeast Utilities, United Illuminating, Unitil Power Corp., and Vermont Electric Power), said they expected to be able to support "most of the ISO proposal," including the adoption of locational marginal pricing. As the group noted, "there is a clear consensus in NEPOOL in favor of adopting LMP." However, they noted that some NEPOOL members wanted to retain the current "socialized" method for assigning congestion costs until the ISO actually could implement LMP, which they said could take two years.
As the ASC group explained, "this continued 'socialization' of congestion ... creates a subsidy that has no economic or other justification ... no participant that supports LMP should be opposed to the earlier implementation of a more efficient and cost-justified CMS that eliminates 'socialized' congestion immediately." Docket No. EL00-59-000, complaint filed March 31, 2000.
Retailer Access. Noting that firm transmission capacity was scarce for the upcoming summer peak season, the Michigan PSC set aside requirements in the tariffs of Consumers Energy and Detroit Edison that had given Nordic Electric (a retail marketer) only 180 days to procure grid access and meet credit requirements after Nordic was declared the winning bidder in a supplier solicitation held in September.
According to the PSC, "the lack of firm transmission capacity into [Michigan] during the summer ... may be hindering, at least temporarily, the entry of new suppliers."
Detroit Edison said it would not oppose a temporary suspension of the deadline during "the infancy" of the state's open access program. By contrast, Consumers Energy opposed the waiver, saying it recently had shared information with Nordic indicating that firm transmission into Michigan from Chicago, Dayton, and western Pennsylvania "may yet be available."
According to the PSC, Consumers Energy had complained that Nordic simply wanted "an excuse it can give its retail customers regarding why it has failed to commence service."
Salt River Project. The Salt River Project's board of directors on April 10 approved a measure to allow all 710,000 of its electric customers to choose a generation supplier sometime after May 31, 2000 - seven months earlier than required by Arizona's electric restructuring law - which would make it the first public power entity in the nation to open its entire service area to competition.
Metering. The staff of the Illinois Commerce Commission proposed a rule for certifying meter service providers that would require each MSP to maintain a customer call center with minimum performance standards for call answer time (60 seconds) and abandoned calls (not to exceed 10 percent).
The staff said the MSP requirements were "parallel" to those required for competitive energy retailers.
Gas Rate Design. To save residential and small commercial customers from paying higher rates to cover costs that arise when large customers switch rapidly between transportation and sales service (to profit from short-term price movements in natural gas markets) the North Carolina commission authorized Public Service Co. of North Carolina to modify its tariffs to include separate methods for setting gas commodity cost charges for residential and small commercial natural customers vs. large-volume customers.
Commodity charges for smaller users will remain tied to a benchmark derived from long-term gas price projections, but commodity charges for large-volume customers will change monthly on the basis of reported market prices.
Electronic Data. The New York Public Service Commission directed utilities within 180 days to file final standards for using Electronic Data Interchange for sharing customer enrollment and billing information - and to start testing EDI protocols during the fourth quarter of 2000, so as to "begin the cutover" to full EDI implementation by 2001.
The PSC also solicited comments, due within 45 days, on modifications to its uniform business practices needed to accommodate EDI, and expected that proposed revisions would be compiled by the end of July.
Weatherization. The Maryland PSC said that for now it would maintain "narrow parameters" for home weatherization projects eligible for funding assistance, restricting projects to shell repairs and upgrades, and excluding other measures such as appliance replacement.
Commissioner Catherine I. Riley disagreed with the failure to include inexpensive measures such as energy-efficient light bulbs and showerheads under the weatherization umbrella. "This new interpretation is a step backward," she said.
The Michigan PSC OK'd an alternative capacity solicitation process for Detroit Edison and Consumers Energy to update procedures last set in 1992, deciding not to bar the utilities from buying capacity from affiliates, but warning that it will not accept any affiliate transaction designed to bypass the solicitation process entirely.
Public Purpose Surcharges. The Vermont board denied a petition by 14 municipal utilities to adjust the state's energy efficiency charge (a surcharge on utility bills) to avoid overcollecting the EEC if utility rates also increase.
It agreed with hearing officer Sandra A. Waldstein, who said the EEC lay outside the reach of a rate case, but remains subject to an independent end-of-year true-up.
Electric Restructuring. The Virginia commission took comments until May 22 on rules governing the separation of electric utilities' generation services from their transmission and distribution services (Case No. PUA000029), and relations between electric cooperatives and their non-regulated affiliates . The rules are to become effective July 1, 2000, and utilities are to file functional separation plans by Jan. 1, 2001 in preparation for the start of retail choice on Jan. 1, 2002.
Utah Power & Light asked the Idaho PUC to approve a voluntary electric rate option based on blocks of power generated by renewables (solar, geothermal, and wind) under which customers would pay an additional $4.75 per month per 100-kilowatt-hour block of renewable energy.
CMS Energy Corp. plans to sell its 50 percent interest in the 2000-MW Loy Yang Power plant and coal mine complex near Melbourne, Australia. The proceeds from the sale will be added to the $600 million to $750 million the company expects to receive for non-strategic assets sold by April. Alan M. Wright, senior vice president and chief financial officer, said that "the company has determined that Loy Yang is no longer strategic to CMS Energy's portfolio and it has not met the company's original financial expectations."
Six of the largest gas and electricity marketers in the United States have formed a new independent energy trading consortium, which will own and operate an Internet-based business-to-business, over-the-counter energy trading platform. The new trading platform, which initially will offer an over-the-counter market for natural gas and electricity in North America, is expected to be in operation by the end of the year and will be open to all wholesale energy industry participants. The consortium's members are American Electric Power, Aquila Energy (subsidiary of UtiliCorp United), Duke Energy, El Paso Energy, Reliant Energy, and Southern Co. Energy Marketing.
CES International has been contracted by San Diego Gas & Electric to enhance power delivery service and reliability for more than 1.2 million utility customers with the deployment of the Centricity operations resource management system. SDG&E will use CES International as its prime contractor to support its personnel in the deployment of the Centricity operations resource management system.
Andersen Consulting and edocs Inc. have formed an alliance to enhance both companies' respective abilities to replace the standard bill-and-envelope billing method with electronic payment and presentment. Andersen Consulting and edocs Inc. will provide electronic billing solutions to clients to help them meet consumer demand for the service and cut costs.
Entergy System Coordination. Citing problems in the South Central United States as states introduce retail choice on different timetables, the Louisiana PSC and the Council of the City of New Orleans filed a complaint at FERC seeking amendments to the Entergy System Agreement.
The PSC and the city council alleged that benefits achieved through coordinated operation of the Entergy System would be lost once retail competition begins in Arkansas and Texas (as is planned in each state for Jan. 1, 2002).
According to the PSC and the city council, "Retail competition cannot reasonably and fairly be implemented in some jurisdictions served by the Entergy System, but not others, unless the System Agreement is modified."
Among other points, the agreement bars the signatories from selling capacity off the Entergy system without first offering the capacity at cost to the other Entergy subsidiaries. The PSC and city council said that benefits such as economy pool energy, reserve capacity, and fuel mix diversity could be lost to Louisiana consumers once capacity from the Texas and Arkansas subsidiaries is taken out of the cost allocation equation.
In fact, the Arkansas legislation (Sec. 23-19-108) requires any Entergy subsidiary in the state "to consult" with the state PUC and its staff on changes to the agreement that may be "necessary or appropriate." Also, the PSC and the city council noted that at a meeting held Aug. 6, 1999, the Entergy Operating Committee had agreed to move toward amending the agreement, and to require any Entergy subsidiary operating in a state that implements retail access "to cease participation in the System Agreement at the time such access occurs."
As of April 27, Entergy had not answered the complaint, but state PUCs from Arkansas and Mississippi had intervened. The Louisiana PSC and the New Orleans City Council defended their decision to file a complaint rather than seek an alternative dispute resolution, noting that they had met in December with PUCs and regulators from nearby states, but had been unable to reach a consensus on how to proceed.
Studies & Reports
Customer Switching. By the end of the year, at least two-thirds of the industrial load of the three major Pennsylvania utilities operating within the PJM ISO will have switched to competitive supply, according to recent predictions by XENERGY Inc. in its new "Retail Energy Foresight" publication.
But the consulting firm adds that many retail energy market sectors across the nation can expect to see dips this summer before resuming steady growth in cumulative switch rates.
XENERGY also predicts that switching in the New Jersey PSEG market will surpass switching for some Pennsylvania territories, jumping from 2 percent to 7 percent for residential and 18 percent to 24 percent for nonresidential customer load by year-end.
Currently, the report says, switch rates span from a low of 0.1 percent for residential customers in Massachusetts to a high of 67.3 percent for industrial customers in Pennsylvania's GPU territory.
Power Consumption Growth. Consulting firm Citizens for Pennsylvania's Future reports that vastly different rates of growth in electric usage among Pennsylvania utilities will dramatically affect the prospects for consumer savings, renewable power products, and system reliability, as the growth rates will force changes in kilowatt-hour competitive transition cost charges and shopping credits, which were set initially to reflect assumptions regarding energy usage.
Penn Future cites the service territory of PECO, where the higher-than-projected electricity usage led to higher-than-expected stranded cost recovery. There, the 1999 settlement forecast for stranded cost recovery was $577.4 million, but the actual number came in at $599.3 million. Meanwhile, usage rates in 1999 for PECO's residential and commercial classes rose by 7 percent and 10 percent, respectively.
By contrast, Penn Future says that the Allegheny service territory had zero usage growth. Call 1-800-321-7775.
Merchant Generation. In a ruling that rocked independent power producers, the Florida Supreme Court held essentially that private power producers from out of state cannot build merchant generating plants in Florida and then sell the output in the open market.
The court reached that result by finding that, before building, a merchant generator must first prove "need," which to the court meant proof that an electric utility regulated in Florida (having a duty to serve Florida consumers) would have a committed need for all of the power output from the merchant plant. Furthermore, the court said that the projected need of unspecified utilities throughout the peninsula "is not among the authorized statutory criteria" for granting determinations of need.
The court's 6-1 vote reversed a state commission ruling (also on a divided vote) that had OK'd construction of a 514-mw gas-fired plant proposed to be built by partners Duke Energy and the municipal electric utility of New Smyrna Beach. The court stressed that electric utility policy in Florida still originates with the state legislature, which has not yet enacted a bill on electric restructuring or retail choice.
Justice Harry Lee Anstead sided with the PSC majority. He declared, "Clearly, the Commission was created to regulate utilities seeking to operate in Florida. In my view that is precisely what the Commission is doing here."
Stranded Costs. In the first such complaint filed at the FERC in the new year, Montana Power will seek to recover $23.8 million in wholesale stranded costs from two rural electric cooperatives (Big Horn County and Central Montana), saying it had a reasonable expectation to continue to supply wholesale power to the two co-ops at least as recently as 1995.
It claimed that at a meeting in March 1992, representatives of Central Montana reportedly had said they had "no interest in switching suppliers," even if open transmission were available.
Leaseback Rights. The California Power Exchange and the Nevada Attorney General and PUC filed protests at the FERC against a plan by Nevada Power to sign "transition purchased power contracts" (TPPCs) to retain rights to the output of its generating plants after they are sold off (and with prices capped at cost), so the company can obtain energy and ancillary services to perform as supplier of last resort, as required under state law.
The PX complained that the proposed TPPCs would "impede Western power markets" by preventing the new owners of the divested power plants from selling into the PX markets for energy and ancillary services. The PX added that since Nevada Power would give plant owners only a half-hour's notice ahead of scheduling deadlines on its purchasing decisions, the new plant owners would find it impossible to sell uncalled energy into day-ahead or hour-ahead markets for energy or ancillary services at the PX or the California ISO.
As the PX observed, "The shortest span of time between a CalPX auction and real time is four hours. ... Since the ISO accepts final hour-ahead bids ... no later than two hours before real time, the new owners ... could not even sell into the ISO grid through a bilateral transaction."
The Nevada PUC added that the plan would violate a March 10 order that gave first call on ancillary services to the planned Mountain West Independent System Administrator. The state attorney general objected that by reserving a call on ancillary services at a capped cost-based price, Nevada Power's plan would lessen interest of plant buyers and depress prices at the auction, hurting the state's electric ratepayers.
Florida Study. On April 13, the Committee on Regulated Industries of the Florida State Senate voted 7-0 to forward Senate Bill 2020 to the Senate's Committee on Governmental Oversight and Productivity.
Senate Bill 2020 would create the "Energy 2020 Study Commission," a 27-member committee to study industry activities around the country and assess Florida's electric needs over the next 20 years. See www.leg.state.fl.us/session/2000.
Interconnection Policy. On remand from a federal appeals court, the FERC approved revisions to the interconnection policy of Panhandle Eastern Pipe Line Co. It said it will now allow pipeline interconnections when five conditions are met:
- * parties seeking interconnection must bear cost of construction or build the facilities themselves;
- * interconnection must not adversely affect pipeline's operations;
- * interconnection and the resulting transportation must not diminish service to pipeline's existing customers;
- * interconnection must not cause pipeline to violate any environmental or safety regulation;
- * interconnection must not cause pipeline to violate its right-of-way agreements or contractual obligations.
Describing the situation as "getting worse and worse," the California PUC filed a complaint against El Paso Natural Gas Co., accusing the gas pipeline of anticompetitive conduct by awarding firm transportation capacity rights of approximately 1,200 million cubic feet of gas per day through a series of contracts to two marketing affiliates, El Paso Merchant Energy-Gas L.P. and El Paso Merchant Energy Co., which won out over some 24 other competing bids.
As the PUC charged, "Of course, El Paso Merchant could afford to pay above-market prices, because it was simply recirculating El Paso's shareholder money from one pocket to another." Supported by other electric and gas utilities, the PUC argues that El Paso will be able to monopolize gas capacity into California and "artificially drive up prices in California for both natural gas and electricity." The PUC acknowledged that the FERC recently upheld similar contracts granting large blocks of released pipeline capacity in the Southwest to Dynegy and Enron, but said of latest El Paso contracts, "this case cries out for a new FERC precedent."
Southern California Gas Co. endorsed the PUC's complaint, asking why the FERC cited excess capacity in the California market in July 1999 in approving the prior Dynegy contract, but yet found a need to expand gas pipeline capacity into California in January, in approving a certificate for pipeline construction for the Questar Southern Trails Pipeline.
In its answer, El Paso distinguished the Dynegy and Enron deals, noting that those contracts were fashioned under the FERC's negotiated rate policy, and remained subject to review, whereas the latest contracts with its affiliates reflect rates, terms, and conditions already authorized under El Paso's filed tariff, and thus should raise no objection.
But Southern California Edison countered that "El Paso has established a perfect identity of interests between itself and its shipper by selling the capacity to its marketing affiliate ... Ironically, because of this identity of interests, the [contracts] here did not need to be negotiated ... as a result [they] were not before the commission as a matter of course."
QF Status. A federal appeals court has ruled that a small power facility that sells all of its gross power output can still retain its status as a "qualifying facility" under the Public Utility Regulatory Policies Act if it received certification from the FERC before the commission changed its policy and barred QF status for such plants in a 1991 order. Connecticut Valley Elec. Co. v. FERC, No. 98-1294, April 14, 2000 (D.C.Cir.).
Demand-Side Management. The Idaho Supreme Court affirmed an Idaho PUC order allowing Idaho Power Co. to accelerate recovery of deferred demand side management expenses from a 24-year period to a five-year period, without a general rate proceeding, but with a decrease in the allowed carrying charge to reflect the lesser risk of accelerated cost recovery.
Emissions Monitoring. A federal appeals court set aside a guidance document issued by the Environmental Protection Agency that directed state officials to issue new emissions-monitoring requirements for stationary sources, on finding that the EPA had amended its regulations without appropriate notice and comment.
As the court said: "the entire Guidance, from beginning to end...reads like a ukase."
Utility Pole Attachments. In a 2-1 vote a federal appeals court ruled that sec. 224 of the Telecommunications Act does not give authority to the Federal Communications Commission to regulate attachments to utility or telephone poles by wireless carriers, nor attachments used to provide Internet access.
The three judges agreed that the FCC's current pole attachment rules effect a "taking" or private property of utilities, but said the issue was not yet ripe for a constitutional review.
State Restructuring Plans. A state appeals court upheld rulings by the state utilities board that OK'd a restructuring plan and securitization of stranded costs for Public Service Electric and Gas Co., even though the board had not opened all hearings to the public and had even begun some hearings even before the enabling legislation was enacted.
Transmission Pricing: California's Grid Gambit
In a bold attempt to expand its reach, the state's ISO proposes a sweeping new scheme for transmission pricing.
By Bruce W. Radford
Is it a bribe offered to public power to join the ISO, or an honest attempt to make transmission prices more reflective of costs?
Either way, the proposal filed by the California Independent System Operator to retreat from license-plate pricing and move toward a grid-wide postage-stamp access charge drew passionate comments from investor-owned utilities, the state PUC, plus various municipal utilities, irrigation districts, and industry associations and coalitions. In short, the ISO proposal is nothing less than a complete restructuring of transmission pricing and power markets in the western United States. (See "L.A. vs. The ISO," , May 15, 2000, p. 4.)
Postage-Stamp Pricing. By a 16-5 vote of its governing board, taken at a meeting held on March 22, the PUC approved its Tariff Amendment No. 27 - a far-reaching proposal to replace its license-plate pricing method and begin a 10-year transition to a uniform "postage-stamp" transmission access charge (TAC) paid by all ISO transmission customers across the grid - at least for service that uses high-voltage lines of 200-kilovolts or above.
According to the proposal filed at the Federal Energy Regulatory Commission, the ISO will retain license-plate pricing for the TAC for lines below 200 kV, whereby the transmission plant revenue requirement (TRR) is based on grid costs specific to the utility service territory from which power originates, and is paid by local energy customers in those areas. However, starting with the moment that a new participating transmission owner (TO) should join the ISO, the ISO would begin to implement its revised TAC for higher-voltage lines, eventually producing a two-tiered access charge.
During a 10-year transition, transmission users first would pay separate interim TACs in each of three or four so-called TAC areas, corresponding to each of the former control areas that were combined to form the single ISO control area. But after 10 years, customers would pay a single, grid-wide postage-stamp access charge.
Fixing "Phantom" Congestion. The new pricing plan is designed to conform with California's initial electric restructuring law (Assembly Bill 1890), which had required the ISO to submit a revised TAC method within two years of its startup.
State law had required the ISO to recommend a new rate method to the FERC, reflecting "an equitable balance of costs and benefits." But in practice, the issued boiled down to the question of how to widen participation in the ISO beyond the three major investor-owned electric utilities that were required to join and hand over control of their transmission facilities when the state created (and the FERC approved) the California ISO and the Power Exchange.
The ISO wanted public power's participation. But it acknowledged "the concerns of entities that own transmission facilities or entitlements [but] that have not yet chosen to place [them] under the ISO's operational control."
The ISO also argued that pricing reform was required to weed out inefficiencies and market distortions. Consider the problem of transmission customers with preexisting contracts at nonconforming rates or conditions. The ISO explained how attempts to preserve the rights under those contracts had skewed markets.
"In its 1997 order ... the FERC required the ISO to structure its operations so that customers receiving transmission service under existing contracts could ... submit schedule changes after the ISO's scheduling deadlines [for other grid users]. To fulfill this requirement, the ISO reserves some transmission capacity from availability for scheduling [by other customers]. ... This sometimes results in insufficient capacity being available to accommodate all desired schedules, requiring the ISO to resort to its congestion management procedures in the day-ahead and hour-ahead markets."
But, as the ISO noted, "the holders of [the preexisting contract rights] have no obligation to notify the ISO in advance of the size of the transactions they intend to schedule ... or whether they intend to schedule any transactions at all. As a result ... capacity that was reserved in forward markets for the later use of existing rights holders is often unused, even though other scheduling coordinators are required to pay congestion costs in those forward markets. ... This phenomenon, referred to as 'phantom congestion,' imposes substantial costs on all market participants."
The Loyal Opposition. Some applauded the ISO's move. Pacific Gas & Electric said it "supports the ISO's TAC proposal." Southern California Edison called the package an "appropriate compromise." However, it appeared that the ISO board was able to win approval for Amendment 27 without support from public power, as PG&E noted wryly.
"PG&E regrets that none of the government agency representatives on the ISO board, for whose benefit this proposal was created, were able to support it. But PG&E is committed to continue to work with those agencies in this proceeding, to see if further improved arrangements for expanded membership [for participating transmission owners] are possible."
Nevertheless, the Amendment 27 drew considerable opposition. It would take a book to describe fully all of the objections against the new tariff, but Sempra Energy, which filed a scathing protest, offered a fairly concise case for the opposition. Sempra argued that the new rate plan would:
- Shift Fixed Costs - from customers of new entrants to customers of TOs already participating in the ISO;
- Confound Grid Expansion - by socializing higher fixed costs among all grid users, while benefits of grid expansions would remain specific to certain grid locations;
- Undermine PUC Policy - by giving preferential treatment to new entrants to induce membership in the ISO;
- Prompt Uneconomic Bypass - of low-voltage transmission and distribution systems;
- Distort Economics - of energy transactions;
- Subsidize Public Power - by extending preferences to customers of governmental entities by artificially mitigating their congestion costs;
- Discourage ISO Expansion - by deterring out-of-state grid facilities from being brought under common operational control with the ISO network; and
- Threaten Tax-Exempt Debt - because of a "system-wide socialization" of high-voltage transmission costs.
Sempra saw the ISO proposal as a bid to entice municipal utilities and other nonjurisdictional transmission owners to join the ISO. As the company explained, the state had postponed transmission pricing reform since it could not reach a consensus at the time of passage of AB 1890. "This issue," said Sempra, "was then and is now thoroughly commingled with the question of whether the transmission-owning nonjurisdictional California governmental entities will place their facilities under control of the ISO."
In a Nutshell. Enron described the ISO's new pricing proposal as "discriminatory." It complained that new transmission owners joining the ISO would be "held harmless" against increase in the transmission access change and the ISO's grid management charge. It added that the new tariff would shift approximately $730 million in costs - from customers of current TOs that belong to the ISO, to customers of other transmission-owning utilities.
In short, Enron saw the entire process as political: "Instead of concentrating on developing a just and reasonable rate proposal, the ISO instead converted this process into one whose purpose is to cajole and induce new participating transmission owners to join the ISO through a series of subsidies and preferences.
"This has distorted the entire process and explains in a nutshell why the ISO's proposal is so unfair and unreasonable."
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Transmission & ISOs