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Energy Market Report Thursday, January 3, 2002 *See attached pdf file. __________________________________________________________ Western Pre-Scheduled Firm Electricity Prices($/MWh) January 3, 2002 for January 4 and 5, 2002 Peak(Heavy) Low Change High Change NW/N. Rockies 18.00 -4.00 19.50 -4.50 Mid-Columbia 18.00 -4.00 19.50 -4.50 COB 21.00 -2.50 24.25 -1.00 N. California 22.00 -4.00 26.50 -1.00 Midway/Sylmar NA NA NA NA S. California 23.15 -3.35 25.00 -3.50 Mead 24.00 -2.75 24.75 -3.25 Palo Verde 22.75 -2.25 24.50 -3.00 Inland SW 22.75 -2.25 24.75 -3.25 4-Corners 21.50 -3.75 24.00 -2.50 Central Rockies 21.25 -0.75 24.50 -12.50 __________________________________________________________ Off-Peak(Light) Low Change High Change NW/N. Rockies 17.00 -1.00 18.50 -1.00 Mid-Columbia 17.00 -1.00 18.50 -1.00 COB 16.00 -2.00 20.00 1.00 N. California 16.00 -3.50 21.00 -1.50 Midway/Sylmar NA NA NA NA S. California 15.50 -4.00 19.25 -4.00 Mead 17.00 -2.00 19.50 -1.00 Palo Verde 15.25 -0.25 17.00 -2.00 Inland SW 15.25 -0.25 19.50 -1.00 4-Corners 15.50 -1.00 17.50 -0.50 Central Rockies 17.25 -1.00 22.50 -3.50 __________________________________________________________ Too Much Gas Day-ahead peak power prices in the WSCC fell for the second session in a row, largely on the reduced loads associated with a Friday/Saturday combo. Several players believed that mild forecasts for much of the West and abundant hydro supplies in the Northwest were also adding to the bearish tenor of the marketplace. "Prices were really bad [weak] today, and looking at the weather forecasts, that's not going to change anytime soon," said one marketer. "Even with businesses and schools back in full swing next week, the upside will be limited due to the mild weather, ample gas storage, and abundant Northwest hydro power," he added. Peak power prices began the day weak, and continued to fall throughout the trading session. Light load goods were also on the decline, though not as significantly as peak hour prices, in most cases, as overnight temperatures in many areas remained well entrenched in heating demand territory. NYMEX Henry Hub contracts were lower midday on Thursday, then fell sharply following the release of yet another bearish AGA inventory report. February Hub gas shed an impressive 19.7 cents or eight percent to close at 2.268$/mmBtu, while March lost 18 cents to settle at 2.263$/mmBtu. Thursday's AGA report showed a draw of 124 bcf in the U.S. last week, below most industry estimates that were calling for a 140 to 150-bcf decline. The same week saw a 209-bcf draw last year, and an average drop of 147 bcf over the past five years. Total U.S. inventories of 2.856 tcf are 1.127 tcf above last year, and 615 bcf above the five-year average. Of the 124 bcf drawn last week, only 12 bcf were removed from the Consuming Region West. Western stocks stood at 82 percent of full at 414 bcf, well above last year's level of 286 bcf. Heavy load energy costs in the Northwest fell by an average of 4.25$/MWh for the Friday/Saturday package, while light load goods only fell by 1$/MWh. Lighter weekend loads and abundant hydropower were the most oft-cited explanations for the falling dailies. According to Weather Derivatives, heating demand in the Northwest was only expected to average 84 percent of normal through January 9, while the latest six-to-ten from the NWS was predicting above-normal temperatures in the region's major load centers from January 9 through 13. "Given the amount of available hydropower and the over-abundance of gas in storage, it will take some prolonged cold weather to boost the day-ahead market, something that looks doubtful anytime soon," said one Northwest utility trader. Flow forecasts for Chief Joseph remained strong at 105 kcfs Friday, 75 kcfs Saturday, 60 kcfs Sunday, 110 kcfs Monday, and 105 kcfs next Tuesday through Thursday. As weaker gas prices took their toll on the highly dependent California market, electricity prices for the Friday/Saturday package softened on Thursday, despite more off-line megawatts than a day ago. "The gas glut has been a problem so far this winter, and now the plentiful rain in the north is just adding more to the off-kilter supply dynamic. The dailies came off a lot late in the day, which I think will continue on Friday," commented one Golden State guru, while another confined himself to saying, "The AGA was not good." Spot gas at the Southern California Border notched down another few cents, transacting between 2.33 and 2.38$/mmBtu. Heavy load goods at NP15 saw action from 22 to 26.5$/MWh, with the bulk of deals done between 23.5 and 24.5$/MWh. The light load product traded between 16 and 21$/MWh, with the low end reached late. In unit news, Morro Bay #3 (337 MW) was operating at 185 MW on Thursday, while Alamitos #4 (320 MW) was derated to 100 MW. Los Medanos (550 MW) upped its output to 150 MW. Large gas-fired Pittsburg #7 (682 MW) exited the grid for unplanned maintenance. The weather picture stayed steady (read: boring) on Thursday. Mid-state load centers expected highs in the mid-50s and lows in the mid-40s on Friday, while Southern cities anticipated temperatures about 10 degrees warmer. Little change was forecast through the first day of the new week, and the latest six-to-ten called for continued above-normal temperatures from January 9 to 13. Despite some ongoing outages, day-ahead electricity prices in the Southwest fell for the weekend combo. Peak power at Palo Verde traded anywhere from 24.75$/MWh early, to 22.75$/MWh, and possibly lower, in late trade. Most players did not anticipate much strength in the days to come, as was evidenced by balance-of-the-month contracts that were heard selling between 24 and 25$/MWh on Thursday. In unit news, Cholla #4 (375 MW) was still off-line with no available ETR as of this writing. Coronado #1 (365 MW) was expected to return on January 8, while Mohave #2 (790 MW) was sporting an ETR of 14:00 MST on January 6, but players familiar with the unit said the ETR has been getting pushed further back on a daily basis. There were reports that San Juan #1 (350 MW) was off line, but no confirmation was obtainable. The latest six-to-ten from the NWS was calling for above-normal temperatures in Arizona and normal temperatures in New Mexico from January 9 through 13, while weather derivatives pegged heating demand in the desert region at 90 percent of normal through January 13. Patrick O'Neill and Jessie Norris _________________________________________________________ Western Generating Unit Outages Current Begins Ends Reason CAISO units <250/6054 total NA NA planned/unplanned* Alamitos #3/320/gas 04-Dec-01 ? planned Big Creek Project/1020/hydro 09-Dec-01 ? @752MW, planned Cholla #4/375/coal 01-Jan-02 ? unplanned Coronado #1/365/coal 22-Dec-01 08-Jan-02 main transformer* Etiwanda #3/320/gas 22-Dec-01 ? planned Etiwanda #4/320/gas 22-Dec-01 ? planned Grand Coulee #19/600/hydro 10-Dec-01 March repairs Helms PGP #2/407/hydro 01-Oct-01 ? planned Hyatt/Thermalito/933/hydro 02-Oct-01 ? @607 MW, unplanned Los Medanos/550/gas 25-Dec-01 ? @150 MW, unplanned* Mohave #2/790/coal 29-Dec-01 06-Jan-02 unplanned* Moss Landing #7/739 29-Dec-01 ? planned Ormond Beach #1/725/gas 28-Dec-01 ? planned Ormond Beach #2/750/gas 05-Oct-01 ? @350 MW, unplanned Pittsburg #6/317/gas 22-Nov-01 ? planned Pittsburg #7/682/gas 03-Jan-02 ? unplanned* Redondo #8/480/gas 09-Dec-01 ? planned For unit owners refer to pdf version. *Indicates a change from previous EMR. ______________________________________________________________________ Eastern Markets Pre-Scheduled Firm Power Prices ($/MWh) January 3, 2002 for January 4, 2002 Peak (Heavy) in $/MWh Low Change High Change Into Cinergy 25.00 1.00 29.50 -1.00 Western PJM 26.95 -1.90 28.25 -2.75 Into Entergy 24.50 1.25 28.25 3.00 Into TVA 26.00 2.00 30.75 4.75 ___________________________________________________________ As regional differences made their presence felt in the market, peak power prices posted mixed results across the Eastern Interconnect on Thursday. Propelled by a snowstorm and unseasonably cold temperatures, day-ahead electricity prices strengthened at the southeastern hubs, while spot prices at northern hubs weakened slightly, but still maintained Wednesday's robust levels. With warming in the extended forecast, traders were not optimistic that prices would stay high into the new week. On another down note, the AGA listed last week's national draw at 124 bcf, below most industry estimates. Traders said they were expecting a draw of around 140, and were hoping for a number closer to 160. NYMEX Henry Hub natural gas futures plunged on the news, with the front-month losing 19.7 cents to settle at 2.268$/mmBtu. March shed 18 cents to close at 2.263$/mmBtu. With the return of a key unit to the grid and a break in the below-normal temperatures expected by Saturday at the latest, heavy load electricity prices softened on Thursday. Big nuke Salem #2 (1,106 MW) was back in service on Thursday, along with approximately 1600 additional MW of power. Western PJM goods changed hands between 26.95 and 28.25$/MWh, skidding down almost 3$/MWh on the high and 2$/MWh on the low. From a high of 55.83$/MWh at 09:15 EST, LMPs declined steadily as the day progressed, averaging 22.59$/MWh through 15:00 EST. Forecasts for Friday predicted highs in the low-40s and overnight lows in the mid-20s across PJM. Temperatures were expected to remain within 3 degrees of normal through Sunday, and the latest six-to-ten from the NWS called for mostly normal temperatures from January 9 to 13. Amid forecasts calling for slightly warmer weather and rumors of a unit outage, day-ahead energy costs fell in the Midwest on Thursday. According to Reuters, Illinois-based Cordova (537 MW) was off-line for much of Thursday, but returned to the grid in the late afternoon, however, traders were unable to confirm the outage. Into Cinergy peak products were bought and sold between 25 and 29.5$/MWh. Daytime high temperatures were expected in the 34 to 39 degree range in ECAR on Friday, with the corresponding lows expected in the high-teens. Lows were predicted to be well out of the teens by Saturday, and the most current six-to-ten called for mostly normal temperatures, with above-normal conditions at the northwestern edges of the region, from January 9 to 13. As very cold weather kept electricity demand high and despite much weaker natural gas prices, peak power prices for Friday delivery firmed up in the Southeast on Thursday. Into Entergy deals were done between 24.5 and 28.25$/MWh, while Into TVA heavy load goods transacted from 26 to 30.75$/MWh. The bulk of deals were heard above 29$/MWh. Friday lows were expected to drop into the frigid teens, while highs were expected to climb into the upper-30s. The latest six-to-ten called for below-normal temperatures from January 9 to 13. ___________________________________________________________ California ISO Congestion Index in $/MWh Path Peak Off-peak for 04-Jan-02 NW1 to NP15 0.31 0.00 NW3 to SP15 0.00 0.00 AZ3 to SP15 0.00 0.00 LC1 to SP15 0.00 0.00 SP15 to NP15 0.00 0.00 OTC Forward Peak Electricity Contracts in $/MWh Mid-C PV SP-15 Bid Ask Bid Ask Bid Ask BOM 21.00 22.50 23.50 24.50 25.00 26.00 February 19.00 20.50 23.50 24.50 24.00 25.00 March 16.50 18.00 22.50 23.50 23.50 24.50 April 16.50 18.00 22.00 23.00 22.50 23.50 Q2 '02 16.25 17.75 26.00 27.00 26.00 27.00 Q3 '02 30.25 31.75 40.50 41.50 39.00 40.00 Q4 '02 25.00 26.50 26.50 27.50 29.00 30.00 Q1 '03 26.00 27.50 26.00 27.00 28.00 29.00 Cal '03 26.00 27.50 31.50 32.50 33.00 34.00 Represents the most recent bid/ask spread obtainable by the Energy Market Report. Alberta Power Pool Index (C$/MWh) Peak(14) Peak(16) Off-Peak Flat Change for 02-Jan-02 44.89 44.08 21.77 37.31 9.29 BPA's Offer for 1/06/02 through 1/07/02. Hours Amount NW delivered COB/NOB delivered 1-6,23,24 100MW Market Price* Market Price* 7-22 100MW Market Price* Market Price* *Market price will be determined at time of request. NYMEX Henry Hub Gas Futures in $/mmBtu Close Change Feb 2.268 -0.197 Mar 2.263 -0.180 Natural Gas Spot Prices in $/mmBtu Low High Sumas 2.09 2.14 So. Cal Border 2.33 2.38 San Juan 2.15 2.20 __________________________________________________________ Economic Insight, Inc. - 3004 SW First, Portland, Oregon 97201, Telephone (503) 222-2425, Internet e-mail emr@econ.com - Copyright, Economic Insight, Inc. 2002.
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