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Western Price Survey / Archives

June 22, 2001
Western Power Market Sails into Summer with FERC at the Helm

If power markets seemed uncertain and jittery this week, it was not because of system emergencies--there were none despite early warnings of possible problems in California. Instead, the ups and downs of prices through the week were largely a result of traders and schedulers trying to figure out what an acceptable price for power will be under the Federal Energy Regulatory Commission's expanded market mitigation plan that took effect June 20.

"Everybody is feeling a little constrained by FERC," reported one trader. Several others admitted looking for guidance in the ruling but raising only more questions about how to do their jobs without incurring possible refund penalties.

Under the order, spot power transactions throughout the West will be capped by a new proxy price established by the California Independent System Operator. Though FERC's own documents calculated a starting price of $108/MWh as the operative price until the next Stage One Emergency is declared, the first price posted by Cal-ISO was much lower-$91.86/MWh plus a 10 percent adder for sales into California's imbalance energy market.

Where market prices had been climbing after two weeks of very moderate levels on expectations of hot weather, they reversed course midweek for fear of violating the new cap. By the time schedulers were putting together weekend power packages, there was another increase in prices to near the proxy level.

As a result, the volatility of prices was contained but no less disconcerting for market watchers. The market began the week in the 60 mills to 70 mills/KWh range and jumped to as much as 130 mills in the Southwest and 110 mills/KWh elsewhere while alert notices were pending. Following the FERC action, they dropped to as low as 70 mills in California and the Northwest before rebounding to 80 mills, with Palo Verde hitting 85 mills/KWh bracket. Off-peak prices experienced the same dynamics but at a low level, with prices ending up around 58 mills/KWh in the north and 30 mills/KWh in the Southwest.

Traders said price points moved quickly and supplies dried up rapidly as everyone was "feeling their way around" the newly attenuated market.

Though it began the week by enacting its new advance blackout-warning system, Cal-ISO breezed through the week without major incident. The closest call came Wednesday when operators forecast a mere 230 MW margin between expected demand and available supply, but concerns evaporated with the return to service of many generation units that had been preparing for summer. Although a few big units in Southern California, including Redondo Nos. 7 & 8 and Ormand Beach No. 2 fell off line midweek, there seemed to be plenty of others available, as well as an unexpected bounty in the form of Pacific Northwest imports. "There's enough to go around," reported one hydro marketer. Barely noticed was the unplanned outage at Colstrip No. 4 early in the week.

Still missing in action was the Columbia Generating Station, which was late returning from a refueling outage that began in mid-May. Unexpected repairs, including cleaning up after a lightning strike three weeks ago that took out a transformer and all the resulting paperwork, kept the unit behind schedule. The plant is expected to begin its restart sequence Friday and may be back to full service next week.

Early Friday morning, the Diablo Canyon Unit No. 1 dropped to 50 percent on a possible condenser leak [Arthur O'Donnell].

Gas Tanks on Storage Surpluses

Once again this week, natural gas prices around the nation dropped mightily following the release of American Gas Association healthy storage injection figures. While Western basins and borders followed suit, Northern California bucked the trend by ticking up a bit on the realization that, for the first time since April 28, there were no operational flow orders on the PG&E pipeline system. "Inventories are on the low side," said one trader, "It's finally worth moving supplies out of Canada."

Malin and SF CityGate spreads held fairly steady. Malin was seen in the $3.60 to $3.85/MMBtu range, while CityGate mimicked the PG& E/Topock tariff in the $4.95 to $5.05/MMBtu vicinity.

The SoCal Border price dropped from $8 to $6.45/MMBtu as San Juan Basin supplies lost $1 to hit $2.35/MMBtu Thursday. Permian Basin fuel slipped from a hiogh of $3.94 to $3.65/MMBtu.

Traders see the continued softening of Topock prices as weather moderates. Balance of month contracts were reportedly dropping to $5.60/MMBtu.

In Canada, Alberta hub prices rallied to $4.78/Gigajoule but ended at $4.50/Gj on the national trend [A. O'D.].

DWR Power Contracts Revealed to Scrutiny and Criticism

Governor Gray Davis' office finally revealed many details of 38 power purchase contracts signed by the California Department of Water Resources. In all, the state has committed to buying 600 million MWh at a total price of about $43 billion over the next 17 years. Exactly how much money is involved depends on specific terms of the deals that are still unknown.

The state's partial disrobing of the long-term power contracts June 15 show that average energy costs have dropped from previous estimates but the true price for half of the agreements is tied to the price of natural gas. All references to natural gas indices and points of delivery were blacked out. The redactions are being challenged in court by news agencies and Republican legislators.

Davis' key energy adviser, David Freeman, said it was necessary to hide the natural gas provisions to ensure that generators buy gas at the lowest price. "We don't want to add to the ability of marketers to game the market," he told CALIFORNIA ENERGY MARKETS.

Also hidden in all the contracts were power delivery points and specific generation sites.

Still, the release of the agreements has many generators and marketers upset that the confidentiality provisions of the contracts were violated and that other marketers can use trade information against them-presumably while their own lawyers are combing through the contracts to find trade information on their competitors.

Contracting generators are not the only unhappy ones. Only a tiny fraction of the contracts are for renewable power, although the power was priced below the average $0.07/KWh cost over the next 10 years. Critics said DWR refused to let more than a token amount of renewables in the door.

Another sticking point is that nearly 70 percent of the deals are for power that will come from unbuilt plants. Given the uncertainties, the state signed more contracts than needed under the assumption that not all the facilities will reach completion. Freeman defended the strategy, saying "We bought enough power so that if one or two deals fall through, we are still in fine shape." Ray Hart, director of DWR, said on June 20 that 1,800 MW have fallen by the wayside.

Under the agreements, the energy price drops over time, from an estimated average $138/MWh the second half of this year to $59/MWh in 2010. The shortest contract runs 14 months and the longest one lasts 17 years, and includes both peaking power and base load energy.

The award for the highest average price goes to Coral Power at $249/MWh and the lowest-cost to Constellation for $58/MWh.

According to DWR, the contracts helped reduce spot market prices from a high of $275/MWh in mid-January to $121/MWh in June-even though little of the capacity is currently being delivered.

Republican Assembly Caucus leader Dave Cox immediately attacked the contracts, calling them sweetheart deals for the suppliers. Sounding much like a ratepayer advocate, he noted that the contracts saddle ratepayers with the cost of additional pollution fees, any windfall taxes and may prevent the California Public Utilities Commission from lowering rates in the future. "The most frightening aspect of these contracts is that Gray Davis' mismanagement has saddled this state with high rates and uncompetitive economic climate for years to come," Cox said.

Cox asked some ratepayer representatives to join him in his press release blasting the deals but they declined.

The contracts include many of the following elements:

  • Windfall-profits tax. Nearly all the contracts have a provision that would neutralize potential windfall-profits taxes. Many have a clause that requires the state to pay any increases in taxes after the contract was executed, with the converse, that if taxes are lowered, DWR gets a credit on sales.
  • Eminent domain. Many contracts contain clauses that allow them to cancel if legal actions of eminent domain are implemented.
  • Legal action. If legal action or legislation threatens contractors' profits, some made a deal to share contractors' legal costs of fighting actions with taxpayers.
  • Environmental++At least two companies would redirect environmental liabilities to the public. Dynegy Power Marketing's agreement states the company "will not suffer the effects of any costs or restrictions imposed by environmental agencies." If there are costs or restrictions, the state will either reimburse them or reduce state buys. The Williams Trading deal includes in the section on "other charges" the cost of emission credits.
  • No-bond option++Several contracts have the option for sellers to cancel if the state has not issued bonds to cover the general fund payments by July. However, state treasurer Phil Angelides hopes to have up to $5 billion in short-term loans in hand before the end of June to cover power purchases that will likely satisfy this requirement.

No IOUs++Practically every contract made it clear that payments are to be made in cash. Contractors' are not going to take the "full faith and credit" of the state.

The bulk of the power is provided by nine contracts, and ratepayers groups are most critical of the deal with Sempra Energy, part of which was blacked out. Preliminary estimates show Sempra raking in between $750 million and $950 million from 2003 to 2011 from the high capacity payments. "The [full] contract has got to see the light of day and be killed by public outrage," said Bill Marcus, head of JBS Energy.

The specific deals are as follows:

Alliance Colton-Two 40 MW plants on nine-year fixed payments. From August to December this year: $4.1 million/month; January to May 2002, $1.3 million/month; June to October 2002, $4.49 million/month; winter 2002: $1.3 million/month. The balance of the contracts runs about $3 million/month.

Allegheny Energy--This holding company for Pennsylvania's Monongahela Power made a deal for 2003 only. It will deliver 150 MW of firm power and 1,080 MW of peak power at $76/MWh.

Bonneville Power Administration--The federal agency wins for the narrowest contract details. The energy is round-the-clock but highly specialized. There is 12 MW for federal buildings, 4 MW for the US Army and 2 MW for Yosemite National Park.

Calpine--This 24-hour baseload contract is barely lower than the lowest-cost hourly average at $58.60/MWh. From October to December 2001, Calpine offers 200 MW, plus 350 MW in 2002; 600 MW in 2003 and 1000 MW in 2004. A longer-term aspect of the contract sets the price at $61/MWh for 1,000 MW from mid-2002 to the end of 2011. A peaking part of the contract sets the energy price at $73/MWh, but there are also capacity payments. For the first five years payments are $90 million, dropping to $80 million for the remainder of the contract.

Coral Power-This contract also has a clause for separate payments based on gas prices. It calls for an energy payment of $249/MWh for 100 MWh of peak this month; 150 MWh in July; 250 MWh in August; and 325 MWh in September. The price drops to $115/MWh from October to June 2002 for 300 MW of peak and 100 MW off-peak. The term runs to 2012. These all appear to be from peakers.

Constellation--This Baltimore utility has two contracts. One is for its under-construction High Desert plant and one for other power. The High Desert contract is for its total 840 MW expected capacity. At base load, the state will pay $58/MWh from July 2003 to September 2011. If the plant is late starting up, Constellation will pay the state $230,000/day from July to September 2003. If not on-line by March 31, 2004, Constellation would forfeit $5 million to the state. The second contract is for 200 MW at $154/MWh from April 2001 to June 2003, with deliveries set from 7 am to 10 pm Monday through Saturday.

Dynegy Power Marketing--This deal was on behalf of three generators and is one of the few indexed to natural gas prices. For this year, there is 100 MW at peak and 200 MW off-peak. From 2002 to 2004, there is 200 MW base load, plus an operations and maintenance fee between $1.35/MWh and $1.50/MWh and $20.25 for system contingent capacity. The price into the Cal-ISO firm market is $119/MWh.

El Paso Merchant Energy--Another working-day deal, Monday through Saturday, this has two prices for two delivery points, both from February through the end of the year for 50 MW each. One is priced at $115/MWh and the other is $127/MWh.

GWF Pittsburg--This company's lawyers certainly got the most billable hours award for its contract for 430 MW. The complicated deal has three phases, apparently to match build-outs at the plant. Unlike the other contracts, the financial details were highly obscured. The only numbers that appeared were capacity payments from 2001 to 2011 up to $30.81/KWh and a variable operations and maintenance charge of $4.25/MWh. An unusual clause in this contract required both parties not to seek rate changes at the Federal Energy Regulatory Commission.

Imperial Valley Resource Company--The contractor has 16 MW it is selling to the state 24 hours a day. It began deliver June 1 for $100/MWh, down to $95/MWh next year and $90/MWh in 2003.

Mirant America Energy Marketing--This short-term contract with the Atlanta-based supplier is packed full of exit clauses. They will sell 500 MW from 7 am to 11 pm everyday but Sunday at $148.65/MWh. The deal is in effect from June 1, 2001 to December 31, 2002.

Morgan Stanley Capital Group-The deal went into effect one day after it was signed. It involves the sale of 50 MW of firm energy around the clock, every day of the week from February 15, 2001, until the end of 2006 at $95.50/MWh.

Pinnacle West--This Arizona utility gets the prize for the clearest contracts. It has one deal that provides 100 MW for 120,800 MWh. The cost was $115/MWh in May and $145/MWh in June. From July to the end of August it will be $185/MWh. A second contract for 125 MW and 137,740 MWh averages $156.75/MWh for this summer only with capacity payments of about $3 million/month.

PG&E Energy Trading--The company will sell 66.6 MW of wind power from two projects, which are expected to be running by October for 10 years. The juice will be sold on an "as available" basis at $58.50/MWh.

Sempra Energy Trading--The company signed a 10-year deal, which has several different prices. From June 1 to September 30, 2001, the company will receive $189/MWh for 250 MW supplied six days per week, 16 hours each day. From April 2002 to September 2002, 150 MW is priced at $100/MWh for power round-the-clock. If the power is supplied six days a week, from 7 am to 11 pm, the price rises to $160/MWh.

The following eight months, 220 MW would be supplied and after that the amount of energy jumps around every few months, from 1,000 MW to 800 MW and back up to 1,200 MW. The price is $69/MWh plus a tolling charge that will fill Sempra's coffers.

Soledad Energy--The Idaho-based seller signed a five-year deal to sell 31/MW from a waste to generation plant beginning June 30 at $80/MW the first year, $82/MWh in 2002 and 2003 and $84/MWh the last three years of the agreement. The contract guarantees only 75 percent of the biomass plant output and from June to July, and 70 percent the rest of the year.

Williams Energy Marketing and Trading--This deal presumably involves power from projects that have or are scheduled to come on line, and are divided into four categories, two of which are 10 year agreements. One contract is for $35/MW from June 1 to September 30, 2001, for 35 MW all day, every day at $62.50/MWh. The output will rise to 40 MW after October 1, grow an additional 20 MW each year until 2005, and then reach 600 MW in 2006, which it will pump out until the end of 2010.

Under the second arrangement, 175 MW would be provided from April 1, 2001 to September 30, 2001. The amount of supply would rise to 200 MW in October, be bumped up an additional 50 MW in 2003 and reach 300 MW by January 2005 until end of 2010. The electricity would be supplied six days a week from 7 am to 11 pm at $87/MWh.

The third part of the deal runs until December 31, 2005, and would provide 160 MW from June 1, 2001 to September 30, 2001, increase to 160 MW in October, 240 MW in January 2003 and would reach 400 MW by 2005 at an average price of $62.50/MWh. The supply would be available from Monday through Saturday 7 am to 11 pm.

The agreement also provided that an additional 300 MW, contingent upon feasibility of installing air emission control technology, would be available last April and May.

Mirant claimed permitting and dispatch orders from the California Independent System Operator to keep the plant running has held up the installation of selective catalytic controls [J.A. Savage and Elizabeth McCarthy].

Western Electricity Prices
Week of June 18-22, 2001
Hub Peak (heavy) Off-peak (light)
Alberta Pool (C$) 52-169 9-50
Mid-Columbia 60-110 44.5-65
COB 61-108 44.5-63
NP 15 64.5-111 42-59
SP 15 63.5-110 30-47
Palo Verde 70-130 30-35

Archives of the Western Price Survey for the past year are also available online.


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