Western Price Survey / Archives
July 12, 2002
For the first time in slightly more than a year, the California Independent System Operator on July 9 declared a Stage One Emergency, as reserve margins slipped below 7 percent for an extended period. Cal- ISO followed that with both a Stage One and a Stage Two on Wednesday. System load reached 42,441 MW at 3:30 pm but then dropped by about 1,100 MW with a concerted conservation response from utilities, voluntary curtailments by interruptible customers and load-shedding by the state water system.
Cal-ISO said that much of the voluntary load shedding came from Southern California Edison, which contributed 700 MW of demand reduction at peak. The air-conditioning cycling program reaped 260 MW and industrial curtailments added 440 MW. Pacific Gas & Electric called on 121 interruptible customers for up to 400 MW of reductions, while San Diego Gas & Electric contributed 28 MW.
While the voluntary curtailment programs are much less than two years ago, every megawatt helped, said state officials. The new California Power Agency demand response program announced last month has not yet gotten off the ground and only has 6 MW signed on, said CPA executive director Laura Doll. Otherwise, California officials emphasized the availability of the 20/20 rebate programs and other conservation efforts among state agencies.
Even though peak demand reductions are less than last year, "Californians are responding better than we anticipated," said California Energy Commission chair Bill Keese. Compared to the year 2000, peak demand during June was down 11.2 percent, but last year it was over 14 percent, Keese said.
Though California's largest electric utilities remained in the comfort zone load-wise because of coastal cooling, public-power utilities from Sacramento to Redding established new peak demand records during the week. They were joined by utilities in the desert Southwest, where the heat wave centered (see related story below).
Cal-ISO attributed its shortfall to record heat, competition for power with surrounding states leading to reduced imports and the loss of about 2,200 MW of in-state generation as it faced the worst heat storm of the year. Some reports attributed the need to enter the Stage Two to the unexpected loss of the 750 MW Ormand Beach No. 2 plant, owned by Reliant Energy. The 715 MW Ormand No. 1 was already off line for mechanical problems. However, since those units are located in Cal-ISO's SP15 zone and the brunt of the heat hit well north of path 15, Reliant was unwilling to accept responsibility for the emergency. "We would not want to contribute to a Stage 2," said Reliant spokesperson Richard Wheatley. "We've been running our units as hard as we can. If you do that you risk problems."
The specific problem at Ormand No. 2 was loss of fans and a too-rich fuel mixture that made it dangerous to continue operating, Wheatley said. "That could have been catastrophic."
There were other unit outages scattered through the state, as well, even though many plant on scheduled maintenance managed to return to service. By Wednesday, Cal-ISO had only 3,184 MW on the list; 391 MW of planned maintenance and 2,793 MW in unplanned outages.
With net imports limited to about 2,500 MW much of the time, Cal-ISO was largely dependent on in-state resources and conservation to make it through the squeeze. During a mid-week news conference, state officials also promoted the addition of 3,000 MW of new generation since last year as a safety net. Duke Energy has touted 1,060 MW from its two refurbished Moss Landing units, while Calpine's new Delta facility added 887 MW more.
Nearly ready to start commercial operation is AES Corporation's 225 Huntington Beach No. 3, which is currently in final testing for another week. GWF's 92 MW Henrietta peaker is nearing full operations and managed to contribute power to the grid during the emergencies.
The Department of Water Resources, which has 9,200 MW of capacity under contract and access to another 4,300 MW of short-term energy seemed to be well covered. On Tuesday there was more than enough to sell about 700 MW per hour to other parties at market prices, confirmed Oscar Hidalgo, and on Wednesday, the agency was able to minimize spot purchases.
One consequence of the alerts was a reformulation of the 91.87 mills/KWh energy price cap established by the Federal Energy Regulatory Commission's June 2001 mitigation order. On Tuesday, the price fell to $57.14/MWh, which had the effect of limiting transaction prices throughout the region, except in the Pacific Northwest, where the continued glut of hydroelectricity put a natural cap on prices below $20/MWh. While the emergency continued, Cal-ISO reset the price several times as the combination of fuel prices and last units dispatched changed each hour. The price eventually landed at $55.26/MWh at 7 pm Wednesday-the hour after Cal-ISO terminated the Stage Two.
The new pricing structure proved short lived. On Thursday, FERC issued an emergency order to reset the cap to $91.87/MWh through September 30 when the original mitigation order is scheduled to end. FERC was responding to Cal-ISO's request for clarification of the proper reserve margin trigger for refiguring the caps [EL00-95058 et al.].
Citing the two days of power alerts, FERC expedited a ruling it had intended to consider on July 17 but went further. "We act now because we cannot expose customers in California and other Western states to the risk of a low price cap," FERC ruled. To delay "could cause severe supply disruptions."
Indeed, some power buyers reported that generators would not sell energy at the lower price. "I did run into people who would not sell to us," confirmed Kevin Hart, who heads up the power trading operations for the Sacramento Municipal Utility District. "I was rejected during trading in the prescheduled market." SMUD managed to find enough energy to meet a new record peak with a little to spare for sales to the state, but Hart added, "I would have liked to buy more power."
Southwestern entities also worried that they would be put at a disadvantage to California, even as they were facing new all-time demand or helping others meet those peaks. Public Service New Mexico CEO Jeff Sterba had told investors his company would ask FERC for emergency relief from the caps to ensure that supplies will flow profitably.
Rather than risk supply disruptions and a constantly changing pricing structure that might be triggered by Cal-ISO's own actions to procure power during emergencies, FERC decided to terminate the formula it had previously set and impose the hard cap throughout the region. "There should be no reason for energy suppliers to differentiate between California and other Western spot markets," the FERC order held.
Reaction to the FERC order by power sellers was strongly in favor. "It's a recognition of the realities of the marketplace," said Reliant's Richard Wheatley. "We were finding it very, very difficult to recover our costs of producing under the lower amount."
Dynegy, one of the generators that had been pressing for an even higher price at $108/MWh, endorsed the hard cap. "FERC's decision gives certainty to the market," said spokesperson Dave Byford.
Jan Smutny-Jones, executive director of the Independent Energy Producers association, said "the previous formula set the law of supply and demand on its head. As demand went up, prices went down." the result of lower emergency prices-caused by the current level of fuel costs and addition of more efficient units to the dispatch queue-is "totally counterintuitive," Smutny-Jones said. "If allowed to continue, it would have caused short-term problems. The question of how caps are set needs to be dealt with in a broader ISO market design, but this reestablishes some stability."
Cal-ISO concurred with the sentiments. "We think it's a good thing," said spokesperson Gregg Fishman. "It indicates that the $91.87 price has provided a lot of stability." The need to constantly refigure the cap during emergencies was "becoming an onerous work load," he said.
The hard cap took effect Friday-meaning that lower prices for power sold this past week will stay on the books, but prices for the rest of the summer will be allowed to float with market circumstances up to the $91.87/MWh level. FERC also promised that it would "act in the near future to establish appropriate mitigation measures and encourage infrastructure development for the period beginning October 1" [Arthur O'Donnell].
Peak Records Tumble Across West
Peak load records fell by the wayside in Northern California and the desert Southwest this week. Topping the list is the Sacramento Municipal Utility District clocked 2,779 MW at 6 pm Wednesday. That surpassed SMUD's prior record of 2,759 MW from July 1999.
The Northern California Power Agency's power pool hit 739 MW on Wednesday afternoon, said spokesperson John Fistelara. Among pool members that also saw new peaks either on Tuesday or Wednesday were Redding, Roseville, Healdsburg, Turlock Irrigation District, Biggs and Ukiah. Previously, the pool's peak was 721 MW, also set July 1999. The Roseville Electric Department carved out successive peaks records of nearly 258 MW on Tuesday and 269 MW on Wednesday.
In the Southwest, Sierra Pacific and Nevada Power said that they had no problem in meeting demand even though Nevada Power hit a new peak of 4,488 MW Tuesday July 9 then followed it with a new all-time peak of 4,501 MW the next day. Sierra Pacific also logged a new peak at 1,585 MW on July 10.
Nevada Power's previous peak record of 4,412 MW was set July 2, 2001 but the prior Sierra record of 1,429 MW goes back to 1998. The Salt River Project said it set a new peak of 5,296 MW on July 9, compared with previous peak of 5,164 MW on July 2, 2001. Demand is high because the monsoon season has started and consumers run air conditioner in part to reduce humidity said Scott Harelson, a spokesperson for SRP.
Arizona Public Service hit 5,772 MW on Tuesday afternoon, about 90 MW higher than its prior mark [A. O'D.].
How Power Traders Responded to New Caps
After running up to 70 mills/KWh at most California hubs and as much as 90 mills/KWh in Nevada early in the week, Western power prices soon fell into line with the variable price caps established by the California Independent System Operator beginning Tuesday. While the lower price caps triggered on July 9-10 proved temporary, they almost immediately resulted in changes to power trading activities, according to marketers and utility schedulers:
Lower trading volumes: Spot volumes of daily trades decreased by 40 percent at Palo Verde from Monday to Wednesday, according to figures from Intercontinental Exchange (ICE), while picking up slightly or holding steady at Mid-Columbia and the California/Oregon Border. As one trader put it, "If you can sell at SP15 at the cap price, why would anyone wheel energy to Mead or Palo Verde and pay more to deliver it?" Using a 55 mills cap price, for example, the revenue difference can be substantial for a sale at nearly 61.5 mills at SP15, when sellers might realize only 50 mills/KWh at Mead or PV.
Altered trading patterns: Some of the reduction in spot activity was attributed to traders extending the terms of deals to balance-of-week or balance-of-month sales, which are not covered by the mitigation prices. One seller described the choice in this manner: "People will have to decide whether to take short-term pain or spread it out over a longer period."
Another strategy was noted at Palo Verde, where 24- hour blocks were being priced at the cap. The net effect was that buyers could secure more peak-period power even if they paid more for off-peak. That did not seem to be true at other hubs; after an initial trend upward, off-peak prices slid to their previous levels.
Sitting out the market: With natural gas moderately prices in the $3.13 to $3.23/MMBtu range at the Southern California Border/Topock, the cap price was lower than the cost of firing up peakers or other units with less efficient heat rates. This means power that might otherwise be available is lost to buyers.
Ignore the cap and hope for the best: There were several anomalous trades reported in the 75 mills to 125 mills/KWh range even after the caps went into effect. Traders speculated that buyers bid higher to secure power with the expectation that FERC would force the seller to write the transaction down to the cap later. "The seller still has to justify the cost," noted a scheduler.
Others who safely ignored the FERC cap were buyers and sellers in the Pacific Northwest-but for entirely other reasons. The continued glut of hydroelectricity and constraints on transmission kept Mid-C and COB prices locked in another league altogether. Mid-C was still down around 15 mills/KWh for peak and 6 mills to 7 mills/KWh off-peak midweek, even as prices elsewhere bumped up against the variable caps.
The excess water situation was most pronounced in British Columbia, where BC Hydro had to spill water from dams at Peace River and WAC Bennett reservoirs for the first time since 1984. Water levels on the Peace River watershed are 120 percent of normal because of high snowpack and continuing rains [A. O'D.].
Gas Prices Insulated from Power Spikes; Rockies Supply Rules
All the action seemed to be in electricity markets this week, although relatively low natural gas prices played a featured role in the setting of new power price caps during California's midweek emergencies.
Despite the press of demand by generators to meet record loads across the West, gas pipelines were full and seemed to be getting fuller. Helping to cap supply prices was producing region competition, with end- users all of a sudden taking a strong interest in Rocky Mountain gas, given some exceptionally low prices at Opal and Sumas, where costs were pegged at $1/MMBtu.
Southwestern basin prices were weakening at San Juan to the $2.08/MMBtu level after having reached $2.68/MMBtu during the height of the power emergency. Permian Basin fell from a high of $2.92 to $2.65/MMBtu. The Topock price had been holding steadily around $3.25/MMBtu while fuel demand was strong but fell below $3/MMBtu on Thursday.
An apparent drying up of demand from the Midwest and possibly some maintenance constraints on eastward flows helped keep Alberta in check. At its highest, the AECO index price hit just $(C) 2.15/Gigajoule and fell to the $1.65 to $1.85/Gj level late in the week [A. O'D.].
Water Leak Puts Pressure on Washington Nuke
Operators at the Columbia Generating Station in Washington had a close encounter with a forced outage this week as they struggled against a deadline to replace a system water pipe that developed a small hole. Even though the water was for non-nuclear diesel backup units, Nuclear Regulatory Commission rules required that the 1,150 MW nuclear unit might have to shut down if it did not have its full complement of auxiliary power available. Facing a 72-hour deadline to insert, weld and test a new section of pipe, Energy Northwest crews managed to fix the problem with hours to spare and the unit was able to stay at full power most of the week.
Had they been unable to finish by 10:30 pm Wednesday, operators were prepared to ask the NRC for a special waiver to allow continued generation during the week of system crunch [A. O'D.].
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