The Federal Energy Regulatory Commission by a 5-0 vote last Monday extended its power market mitigation program across the western states 24 hours a day, seven days a week through September, 2002, with a two-part cost-based formula addressing spot prices during emergency and non-emergency periods (EL00-95-031). The new mitigation program went into effect June 20.
All five commissioners enthusiastically endorsed the measure, although Commissioners William Massey and Linda Breathitt had reservations on certain items. The FERC action addressed the super-high power prices being paid in California since last summer. It came amid a months-long campaign of recriminations and threats by California politicians who have declared an all-out war on power generators, the Commission and the Bush administration, claiming they are responsible for California’s high prices.
The FERC order, which also included a schedule for a settlement conference that promises to resolve California claims of back overcharges of up to $9 billion within a month, appeared to dampen the political fires to some degree. Not those of the California governor, however, who told a Senate committee Californians want their money back and criticized FERC’s scheduling and directions to the settlement conference. Wall Street reacted by sorting out power generators with the most exposure to the spot market. One company with large generating interests in the state adopted a laid-back attitude, citing its long term contracts to supply power to the California Department of Water Resources in which DWR has to supply the gas (see related stories, this issue).
The measure “will ensure that wholesale rates in spot markets in California and the rest of the WSCC will fall within a zone of reasonableness.” Chairman Curt Hebert said the measures were aimed at “getting the California market under control. It’s time to stop blaming and start solving problems.” The commissioners noted that extending the price limits across the western states would address the “megawatt laundering” accusations that claimed in-state generators were selling power out of state, so it could be brought back in without being subject to price controls.
Responding to questions at a press briefing after FERC’s meeting, Hebert stuck to his guns in insisting that FERC’s latest action should not be labeled a price cap. “People are welcome to think they want to think, but I would invite them to explain to me, why they think it’s a price cap and I’ll explain to you why it’s not.” He also said he hasn’t seen any evidence of megawatt laundering, “but since they [generators] no longer have the ability to trade out and back in, we don’t have to worry about that anymore.”
Hebert cited lower power prices since FERC’s original mitigation program kicked in at the end of May, pointing to May 29 when spot prices hit $300/MWh. After the mitigation formula was applied prices dropped to $120/MWh. “Prices continued to fall in subsequent days and remained low,” he said.
Massey, however, disputed the chairman’s logic, pointing to “a confluence of circumstances” that mitigated prices recently, including better hydro conditions, liberalization of emissions restrictions and the expiration of the large transportation capacity contract on El Paso Natural Gas “that could have affected gas prices.” Massey applauded the Commission’s action, saying he has been pushing for this type of extensive mitigation for the last eight months.
Commissioner Patrick Wood said he was very interested in the Commission’s natural gas price investigation going forward and was glad to see the price cap formula would include an average of a generator’s gas prices. The order states that any justification for prices above the benchmark price would be viewed in connection with the power supplier’s total portfolio of gas prices. “I think what happens in a desperation market like we’re seeing on the West Coast where the customer will pay anything, is that there is very little incentive to manage risk since you can pass it all the way through to the customer.” Monday’s order should provide “sufficient disincentive to the spatial spiral of gas prices,” Wood said, although he would be willing to investigate the issue of gas prices further.
The order, which expands the market mitigation plan issued earlier for California emergency power periods (see NGI, April 30), creates two market clearing price formulas, one to be used during emergency, low-reserve periods, and an offshoot for all other times. Under the expanded mitigation plan sellers into the Cal-ISO day-of and day-prior auctions during reserve deficiency (less than 7%) emergencies (Stages 1, 2 & 3) will bid their generating capacity into the market based on a proxy gas price times the unit’s heat rate, with a $6/MWh adder for operating and maintenance expenses. The market clearing price — which will be paid to all participants in the auction — will be the bid of the highest cost generator called on to supply power. For bilateral spot contracts in California and in the rest of the WSCC, the market clearing price will serve as a ceiling, and they will be paid their negotiated price up to that ceiling. The ISO must also add 10% to the market clearing price paid to all generators for all sales in its markets to reflect the credit uncertainty of sales to California entities.
The Commission increased the O&M adder from $2/MWh in its April mitigation plan to $6/MWh, “based on a 17-year average of actual non-fuel O&M expenses for oil and gas-fired steam plants,” noting “the California market primarily consists of older oil and gas-fired steam plants.”
The proxy gas price to be used in the formula will be the bidweek midpoint for that month at three points, Southern California Border-SoCal Gas, PG&E Citygate and Malin as published by Gas Daily. The Commission said it had made the change to using the three points and the bidweek number, as opposed to daily quotes used in the previous formula, at the request of the Cal-ISO. The choice of a bidweek index came as a surprise to some in the market, who pointed out that although Gas Daily is more often used for daily indexing in the aftermarket, “it’s just automatic” that when traders talk about indexing California deals during bidweek, they always mean NGI’s Bidweek quotes.
The latest FERC order removed fuel start-up and emissions costs from the April formula. Those costs will be levied across the ISO load and paid directly to generators by the ISO.
For non-reserve deficiency periods the market clearing price will be set at 85% of the highest hourly market clearing price set during last preceding Stage 1 (not Stage 2 or 3) alert.
Generators can apply to FERC for higher payments if they can justify higher actual gas costs. In this case they must be able “to document and support their gas purchasing portfolio and allocation among all generating units at the relevant time.” Marketers must be “price takers” and cannot apply for prices higher than the clearing price.
All public and non-public utilities which own or control generation in California will continue to be required to offer available capacity in the ISO’s spot markets. “This applies to any non-hydroelectric resource whether owned or under contract to the extent is output is not scheduled (or committed for minimum operating reserves) for delivery in the hour.” Non-hydro generators in the remainder of the WSCC must offer available capacity to the “spot market of their choosing.”
The order clarifies that generators will be exempt from the must-offer requirements if running the unit violates a certificate, would result in criminal violations or penalties, or would result in Qualifying Facilities (QF) units violating their contracts or losing their QF status. Further, QF facilities must offer capacity that is not already contractually committed or would not violate its contractual obligation to its thermal host.
To monitor compliance through the WSCC outside California FERC directed all public utilities that are control area operators to have their wholesale merchant function calculate on a daily basis the amount of capacity that will be available after load and operating reserve forecasts have been calculated. They should post the information on their company web sites and on the Western System Power Pool web site. Every marketer and independent power producer should also post available capacity on a daily basis on its own web site and on the WSPP site.
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