Transmission & ISOs
Grid Management Charges. Faced with mounting complaints from customers who are angry about having to pay for services they don't need, the California ISO proposed a new grid management charge to recover its administrative and operating costs. It would unbundle the new GMC into three "buckets," or service categories(1) control area services and scheduling, (2) interzonal scheduling (congestion management), and (3) market operations, billing, and settlementswith each category using a different billing determinant.
Charges for the three service buckets would be determined, respectively, by (1) exports and gross load within the ISO, (2) net scheduled interzonal flow per path for a given scheduling coordinator, and (3) the ratio of any SC's total purchases and sales of energy (auxiliary, imbalance, and supplemental) to total purchases and sales by all SCs. .
Software Costs. The Federal Energy Regulatory Commission allowed the PJM ISO to use its formula rates under its Open Access Transmission Tariff to bill customers to collect $136 million in costs incurred to acquire information technology and other assets from its transmission owners in order to conduct ISO operations. .
Return on Equity. Complaining of cost shifting and a "rapid-fire series of seemingly never-ending pancaked rate increases," many players protested Pacific Gas & Electric Co.'s fifth transmission rate increase filed within a period of three-and-one-half yearsa request that proposes a return on equity of 12.8 percent and a revenue requirement of $396.2 million, representing an increase of $57.1 million (or 16.8 percent) above the level of the prior (fourth in a series) application.
As Sacramento Municipal Utility District put it, "The transmission function seems to be getting the brunt of cost impacts. ... Even though the ISO is now operating PG&E's transmission system ... expenses are increasing dramatically. ... The effects of inflation and necessary upgrades and replacements ... can neither justify nor explain the large increases. ... As PG&E sells off its generation, PG&E is proposing to shift many of the costs of generation tie lines and generation step-up transformers to the transmission network function."
SMUD questioned PG&E's reliance on natural gas companies as a proxy group for a transmission sector ROE, adding that "PG&E is also using its [grid] facilities for purposes other than electric service, such as telecommunications services." SMUD joined other parties complaining of allegedly unsupported costs, including the Modesto Irrigation District, the Transmission Agency of Northern California, and the California PUC, which complained that the proposed 12.8 percent ROE was "much higher" than the 11.22 percent rate the PUC OK'd on June 8 in PG&E's rate case for retail wires services.
Also protesting the application was Southern California Edison, which said its own wheeling revenues would be affected by the rate methods chosen by PG&E. Edison complained that PG&E's regional/local allocation method was inconsistent with the high/low voltage allocation method proposed by the ISO in its tariff amendment 27. It alleged that PG&E's method would allow it to "continue to collect an inequitable share of wheeling revenues, to the detriment of other transmission owners" participating in the ISO. .
Innovative Ratemaking. Led by Michigan Attorney General Jennifer Granholm, a host of electric industry players urged the FERC to rehear and overturn its Sept. 28 order allowing International Transmission Co., formed by DTE, parent company of Detroit Edison, to charge transmission rates derived from the transmission component of bundled retail rates set for Detroit Edison by the Michigan Public Service Commission.
Dynegy, ELCON, and the advocacy group ABATE (Association of Businesses Advocating Tariff Equity) all complained that the FERC should not use its Order 2000 to justify innovative rate treatment for a "transco" like ITC that would not qualify as an RTO.
Attorney Sara Schotland, representing ELCON, complained that, "once again, FERC's 'beg-and-plead' approach to RTO formation leads it to award excessive and inappropriate incentives." According to Granholm, "the incentives ... are unnecessary and ... will discourage the entrance of new competitors in Midwest power markets." .
Congestion Contracts. Morgan Stanley Capital Group lost its bid to postpone the New York ISO's planned auction of two- and five-year transmission congestion contracts until the ISO irons out market irregularities to give traders a better inkling of the real value of grid congestion. The FERC countered that TCCs were still valuable in hedging against congestion costs despite uncertainties caused by market disruptions. .
Midwest ISO Convulsions. The Midwest ISO announced on Nov. 3 that it had assumed management responsibility for operations of the Mid-America Interconnected Network, but prior weeks were marked with uncertainty, as Midwest ISO CEO Matthew Cordaro acknowledged on Oct. 31 that Commonwealth Edison intended to withdraw from the group and instead join the Alliance RTO, while Dynegy had announced a similar intention on Oct. 13 on behalf of subsidiary Illinois Power.
Com Ed senior vice president Elizabeth Moler said Alliance made more sense for her company, since more of Com Ed's business would lie in the Eastern U.S. after the merger with PECO Energy (to form Exelon Corp.)
Dynegy explained its strategy in a letter sent to the FERC:
"One advantage is that the Alliance RTO will put all similarly situated transmission users on the same tariff at the same rate at RTO inception ... all users that deliver energy to the Alliance RTO facilities at a common input point and [that] receive energy back at a second, common removal point will pay one uniform rate for that service. ... In contrast, the Midwest ISO will take at least six years for the transition to a single rate for a single transaction for all users." .
OASIS Standards. The FERC revised its business practice standards for transactions conducted over its Open-Access Same-Time Information System for reserving transmission service. .
Interregional Coordination. Electric utilities, state regulators, ISOs, consumer advocates, and even a smattering of power producers and marketers overwhelmingly oppose a complaint filed in early October by Morgan Stanley Capital Group that asked the FERC to equalize certain rules in the PJM ISO with those expected to apply in the New York ISO and ISO New Englandall in the name of interregional coordination.
In particular, MSCG asked the FERC to terminate PJM's installed capacity market (ICAP) and associated deficiency charge to match the same step taken in ISO New England, and also to ensure that PJM's permanent bid cap of $1,000 per megawatt-hour (which has applied in the PJM ISO since its formation) will sunset simultaneously with the expected termination of price caps of the same amount in the New York and New England ISOs.
- Abolishing ICAP Markets. Morgan Stanley had urged the FERC to follow the lead of New England in abolishing ICAP markets and deficiency charges throughout the Northeast, citing studies submitted by economists (such as William Hogan of Harvard Univ.) that ICAP markets are "valueless" and that capacity deficiency charges ought to be set at zero. (Pending the adoption of a new structure to replace its ICAP market, ISO-NE has proposed a deficiency charge of 17 cents per kilowatt-month as a transition measure, but PJM still retains a stiffer deficiency charge of $54.40 per kilowatt-year.)
- Coordinating Price Caps. MSCG also urged the FERC to coordinate bid-cap policies among regions so that power producers, marketers, buyers, and sellers are not tempted to game markets by selling in one region to avoid a price cap in another. Nevertheless, by early November, Morgan Stanley appeared to have won support for its request only from Williams Energy and the Mid-Atlantic Power Supply Association. Nearly all other responding parties have opposed the request, including state PUCs from Pennsylvania and Maryland, the staff of the Virginia commission, plus consumer advocates from Pennsylvania, Delaware, Maryland, and New Jersey.
- Stressing Reliability. Denise Goulet, the senior assistant consumer advocate from Pennsylvania, acknowledged that the PJM ICAP market was in need of review and reform, but warned against eliminating the requirement without another structure to ensure reliability and generation adequacy. She added that PJM already was considering alternative plans through its Future Adequacy Working Group, or FAWG.
- Defending ISO Independence. The PJM and New York ISOs both suggested that each region should map its own course. New York said that it "strongly disagreed" with New England's position that ICAP markets and deficiency charges are "inherently unworkable and anachronistic." It said its own ICAP market rules "should be preserved and ISO-NE and PJM should be free to make their own decisions."
- Warning of Disruptions. PJM asked the FERC to dismiss the complaint absent any evidence specific to the PJM that its ICAP market wasn't working: "PJM should not be forced to eliminate its ICAP rules simply because ISO New England has chosen to do so, just as ISO-NE should not be forced to retain its ICAP market because the New York ISO intends to keep its own." PJM argued that if it terminated its ICAP market, it actually would make regional differences greater, since New York had not shown a similar intent. "Adoption of Morgan Stanley's complaint," said PJM, "would create a PJM/NY seams issue where none now exists." .
New York Locational Reserves. The New York ISO announced "significant" reductions in locational reserve requirements for the eastern and Long Island sectors for 30-minute reserves and 10-minute spinning and nonspinning reserves, so as to allow western energy suppliers to participate more fully in wholesale power markets in the state, and to allow it to lift interim bid caps imposed on suppliers in reserve markets. .
PJM Transmission Rights. The PJM Interconnection filed amendments to its Open Access Transmission Tariff to provide for a reallocation of fixed transmission rights (on the basis of load) among network transmission customers on an annual basis, to replace the prior procedure whereby network customers received a one-time allocation and could then retain FTRs in perpetuity, so long as they retained enough load. PJM's Energy Market Committee had recommended an annual reallocation because of "significant fluctuations in load" occurring among load-serving entities, due to retail choice in the PJM region. .
Revenue Assessments. The FERC announced a new method to assess annual charges against electric utilities to fund its activities, based only on the volume of electricity transmitted, rather than both transmission and volume of wholesales, as before. .
Mountain West Funding. The Nevada PUC denied a request by the Mountain West Independent System Administrator to set up a method for electric utilities to fund startup and operating costs and for the ISA through a surcharge on distribution rates, explaining that state law requires utilities to submit such a request. It also questioned whether state regulators should guarantee recovery of costs for transmission functions subject to federal jurisdiction. .
Interconnection Standards. Virginia Power filed amendments to its Open Access Transmission Tariff to include procedures for dealing with requests to interconnect new generating plants with the utility's transmission system, and to allow for recovery of costs from interconnection applicants in a manner that the FERC rejected in a similar case involving Carolina Power & Light Co.
Virginia Power's standards require the interconnection customer to pay the entire cost of any required evaluation study and facilities study, including costs related to a change in configuration or operation of adjacent transmission systems--a cost allowance that the FERC had rejected for CP&L.
Virginia Power argued that changes on adjacent systems (including interconnection queues) would affect power flows and congestion on its own system. It reasoned that the FERC had denied such costs in the prior case only because CP&L had failed to offer supporting evidence. .
Station Power Requirements. Citing doubts about whether the proposal was just and reasonable, the FERC accepted and suspended tariffs filed by the PJM ISO that would allow power producers the option of purchasing station power requirements (energy consumed on-site by generating plants) either at retail from utilities or at wholesale from the PJM Interchange Energy Market. .
California Price Caps. Though it declined to order retroactive refunds of excessive wholesale power costs, the FERC proposed a new "soft" price cap of $150 per megawatt-hour for the next two years in wholesale power markets operated by the California Independent System Operator and Power Exchange, whereby any suppliers bidding $150 per megawatt-hour or less may receive the market-clearing price, but those bidding more must take a price equal to their bids and file detailed information with the FERC to explain and justify their higher requests.
The FERC also proposed other remedies to correct California's power markets, which it described as not workably competitive:
- Buy/Sell Rule. Release the state's three major investor-owned utilities from obligations imposed under state law to sell into and buy only from the California PX, encouraging them to rely more on bilateral trading and forward markets.
- Penalty Charges. Impose a penalty charge for under- or overscheduling of load in excess of 5 percent of hourly requirements.
- ISO Governance. Remake the membership structure of the ISO board from the ground up, along guidelines provided by the FERC.
- Plant Interconnections. Require the ISO to draw up a tariff governing interconnections of new power plants with the transmission grid.
Commissioner Massey concurred, but he questioned the $150 figure for the soft price cap, saying that changes in natural gas prices might justify a lower ceiling. Commissioner Hébert also concurred, but said he would rather just abolish the single-price auction altogether, and criticized the commission for imposing any particular organization on the ISO Board, warning of a needless constitutional showdown. .
Pacific Northwest Price Caps. Taking a page from California, Puget Sound Energy asked the FERC to set a cap on prices for electric energy or capacity sold at wholesale into the Pacific Northwest at a level identical to any price cap it might approve in California markets, arguing that the two regions each are part of the "substantially integrated wholesale power market" consisting of the entire Western Interconnection.
PSE added that any one-way price cap in California markets would be "fundamentally unfair," as it would expose wholesale purchasers in the Pacific Northwest (such as PSE) to uncapped prices when they need power to meet winter demand, but yet "hobble" their ability to offset the costs of such purchases with uncapped prices when they have surplus power to sell to California, such as during periods favorable to hydroelectric generation. .
New York Price Caps. Citing delays in developing a new "market protective mechanism," which would trigger "circuit breakers" in the event of market disruptions, the New York ISO asked the FERC to extend the life of its current bid cap of $1,000 per megawatt-hour through the winter until April 30, otherwise set to expire on Nov. 1.
The ISO described the price cap as "a blunt instrument" with "undesirable consequences," but stressed that caps were needed to counteract market imbalances that it said were caused by delays in licensing and siting of much needed new generating facilities.
"Our staff estimates that there are 74 [generating] projects indicating a desire to build in New York [but] only one of these (Athens) is likely to be complete during the next three to four years. This situation is an invitation both to severe reliability problems and to price disruptions. ... It is unacceptable." .
Functional Separation. California Power Exchange president George Sladoje wrote to FERC chairman James Hoecker to offer several reasons why the PX should not combine with the state's Independent System Operator, after Hoecker had asked for comment on the idea at the public hearing on California power markets held in San Diego on Sept. 12.
Claiming the PX-ISO schism had nothing to do with market disruptions, Sladoje argued that the PX actually had developed a greater variety of liquid trading products than ISO-operated energy markets in Eastern states.
"The CalPX ... has created numerous exchange services that are not available in PJM or in the other eastern ISOs," said Sladoje. "ISO-operated energy markets are largely self-contained within the 'four walls' of that ISO's control area," he added, while "Cal PX, in contrast, has ventured beyond the boundaries of the ISO-operated grid [to] the broader market represented by the Western Systems Coordinating Council."
And Sladoje defended the PX as gentle on power prices: "California's wholesale prices were somewhat lower than those in the Pacific Northwest and the Inland Southwest in May through August." .
Post-transition Ratemaking. Claiming that "electric restructuring in California is at a crossroads," Southern California Edison urged the state PUC, in its investigation of post-transition ratemaking mechanisms for the state's three investor-owned electric utilities, to adopt a four-point plan to manage the crisis:
- Continued market reform with greater freedom for utilities;
- Confirmation that utilities eventually will be permitted to recover their "reasonable" energy procurement costs incurred on behalf of customers;
- A new, post-freeze rate stabilization plan to replace the current immediate passthrough of volatile wholesale power costs to utility generation customers; and
- A prompt final decision on whether the PUC will permit the utilities to sell off their remaining generation assets.
Said Edison, "Allowing the uncollected power costs to continue to grow without providing assurance of their probably ultimate recovery--and without actually commencing the process of that recovery--will almost inevitably lead to serious statewide consequences, including the probability that financially weakened utilities will not be able to build and modernize necessary infrastructure [or] contract for power." .
Standard Offer Re-enlistment. As an emergency measure, the Maine PUC re-instated a rule requiring electric customers to pay an opt-out fee or commit to receive 12 months of service on quitting a competitive energy supplier and returning to standard offer retail service.
The PUC earlier had relaxed the rule for service changes requested outside the summer months, but reneged on discovering it had weakened the deterrent effect of the opt-out fee, calling the prior decision an "inadvertent error." .
Retail Gas Choice. Michigan allowed Consumers Energy Co. to double and then triple the number of customers eligible for its voluntary program for retail gas choice, from 300,000 accounts to 600,000 in April 2001, and then 900,000 by April 2002. .
Electric Bill Formats. Ohio issued rules governing bill formats for electric utilities, for both customers taking standard offer service and for those who shop for alternative supply services, setting out rules for unbundling separate prices for generation, delivery, and customer account charges, plus any added discounts above a generation back-out credit designed as an incentive to encourage customers to switch suppliers. Case Nos. 00-1596-EL-UNC, 00-1998-EL-UNC, Oct. 26, 2000 (Ohio P.U.C.).
Winter Gas Rate Relief. New York OK'd a natural gas rate settlement for National Fuel Gas Corp. designed to offset anticipated higher-than-usual gas commodity costs for the winter heating season.
The settlement extends a $10 million aggregate rate credit to ratepayers and modifies the current program for sharing excess earnings with customers (on a 50-50 basis) by cutting the benchmark rate return on equity from 12 percent to 11.5 percent. Case 00-G-1495, Oct. 23, 2000 (N.Y.P.S.C.).
Vertical Disaggregation. Virginia regulators adopted rules governing the functional separation of generation, transmission and distribution services provided by electric utilities.
In so doing, it denied arguments by Virginia Power that once a utility divests all generation, the commission then loses authority to regulate purchased power costs passed through to retail distribution customers, since such default service functions merely as an assurance of available generating capacity, which is deregulated. .
Rate Freeze Legislation. Michigan ruled that the rate freeze imposed under the state's electric restructuring legislation does not bar the state's electric utilities from boosting rates to recover costs incurred to pay avoided cost rates to qualifying cogeneration facilities for purchased power. .
Return on Equity. Marking a break from past practice, Kentucky set rates reflecting return on equity measured against the utility's financial statement capitalization, rather than an original cost rate base. It called capitalization a "better measure of the real cost of providing service," especially where rate base exceeds capitalization, indicating that sources other than debt are available to finance assets. .
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