The finger-pointing and calls for market intervention — mostnotably centered on electricity price caps — heated up fasterthan the temperatures on both coasts this week, with merchantgenerators and incumbent regulated utilities drawing the ire ofstate and federal policymakers.

A combination of the weather, partially functioning markets andill-timed forced outages of generating units all contributed toproblem, along with rising natural gas prices.

New England, New York, Pacific Northwest and California energyofficials all issued various forms of electricity alerts andinstituted voluntary measures to lessen peak demands on theirrespective electrical grid systems. Natural gas transmissionsystems were operating full-bore as a result, and regulators wereeither instituting or lowering electric price caps in New York andCalifornia, respectively.

In New York City Thursday, the city council announced publichearings in which it will have Consolidated Edison, the city’smajor combination utility serving Manhattan, appear July 6 toexplain how it can stop a nagging series of service interruptionsand the specter of the major blackout. A ConEd spokesperson wasquoted by Reuters as saying outages were caused Monday when threeof 28 feeder lines failed on a key transmission system in easternManhattan.

ConEd had to curtail service and reduce voltage by 8% as aresult, affecting about 76,000 customers. This happened the daywhen Manhattan experienced an all-time record demand of 11,200 MW.Easterners took some consolation in reminding state and localofficials that the problem this summer is nationwide and not uniqueto certain regions.

Citing May increases driven by early sustained heat that droveelectric prices from about $30/MW-hour to $3,900/MW-hour, New YorkState’s public service commission has proposed instituting a$1,000/MW-hour price cap, despite opposition from producers,distributors and environmentalists, each for different reasons.

Energy Secretary Bill Richardson on Wednesday appeared beforeCongress and expressed worries for the overall reliability of thenation’s grid with particular concerns for the Pacific Northwestand California.

With bipartisan pressure from state lawmakers and regulators,the California Independent System Operator (Cal-ISO) board decidedlate Wednesday to roll back price caps to $500/MW (from the present$750 level) through the summer months, along with taking steps todetermine what new rules and operations are needed before all capscan be lifted. The action came in the midst of the state’s thirdweek in less than two months where alerts mandating curtailmentsand conservation measures were necessary due to a combination ofsustained heat throughout the West and unavailable generationunits.

In almost six hours of discussions and debate, the 24-memberCal-ISO board revealed a majority that clearly does not favor pricecaps, but nevertheless it lowered the caps in the face of strongpressure from the principal state lawmaker who crafted California’s1996 electricity law. The pressure came as a result of continuinggeneration constraints in the state when demand breaks the 40,000MW mark. Ultimately, the board found a compromise in which 16 boardmembers were able to swallow the lowering to $500, a figure theboard earlier had agreed was the level to use if the $750/MW provedunworkable.

“This is what we told everyone we would do if the markets turnedout not to be workably competitive, and it does recognize the factthat there have been significant changes in the market — mostsignificantly the doubling of natural gas prices,” said JanSmutney-Jones, Cal-ISO board chairman and head of the state’sindependent energy producers’ trade association.

The $500 price cap is to stay in place at least through Oct. 15,by which time the Cal-ISO hopes to have various analytical workcompleted to identify the rule and operational changes needed toallow eliminating any caps.

Merchant power plant generators and other market participantsbefore the ISO board’s vote gave detailed explanations of what theythink is wrong with California’s market, citing everything fromunclear price signals to arduous too-time-consuming power plantsiting requirements. Depending on the speakers’ points of view, theproblem could be centered on a still-immature market that needsmore government supervision, generators who are withholdingcapacity from the market to drive up prices or incumbent regulatedutilities that are failing to schedule adequate supplies in thestate power exchange’s block-forward markets.

One Texas-based plant operator outlined in detail how even areturn to regulated markets with bundled services and demandcharges for customers would end up costing customers more than the$750/MW price for peak load power supplies because of the relativefew hours during a calendar year when the market reaches thoselevels.

“It is clear that California’s energy and ancillary servicesmarkets are not workably competitive, and there is [therefore] aneed for price caps to prevent customers from being victimized bythe exercise of [unharnessed] market power,” said state Sen. StevePeace (San Diego), the leading lawmaker on the state’s electricityrestructuring. “Many factors must be in place before the market canbe success, including the construction of generation and badlyneeded transmission.

“The market is not that mature, and acting as though it isdoesn’t make it so,” Peace told Cal-ISO board members gathered atISO headquarters outside of Sacramento and six of the 24 of whomwere hooked via telephone from points scattered around the stateand globe.

Merchant generators, including Duke Energy Services, ReliantEnergy, Williams and Dynegy, echoed one another in saying that theyfeel prices caps are not the solution, but rather more hedging byincumbent utilities, accelerated power plant/transmission sitingand a redesign of the market’s incentives will lessen the extent ofprice spikes and improve the state grid’s reliability.

Reliant’s John Stout, vice president power projects, said:”Perhaps we need to rethink the fundamental design of the marketand the way people are compensated for capacity. We perhaps need torevise the market so we have a capacity market, rather than anall-energy market.”

In the Pacific Northwest, which normally provides substantialimports to California, was confronting its own regional constraintsin the midst of unusually hot temperatures and electrical unitsforced out of service. The result was California’s ability toimport supplies was cut to about 20 percent of normal.

Two of the major electrical operators, however, expressedconfidence they would be able to fulfill their customers needsthroughout the six-state region of Washington, Oregon, Idaho,Nevada, Utah, and western Montana. PacifiCorp, the unit of ScottishPower with 15, 000 miles of transmission, generation facilities in8 states and customers in six states, said through a Portland,OR-based spokesperson that it hasn’t experienced any major forcedcurtailments over the past 20 years, and it doesn’t see the needfor any developing in the wake the current supply-demand strains.

“We have a lot of flexibility in meeting the customers’ needsand delivering our own energy through interconnections that allowus to purchase energy,” said a the PacifiCorp spokesperson, notingthe company would not comment on the status of any of itsindividual power plants. “Our portfolio is stable.”

Further north in Seattle, Puget Sound Energy was more concernedabout natural gas prices than electricity reliability. Pugetannounced Wednesday it is asking state regulators for a $137million rate increase (16.7 cents/therm) to cover rising gas costs.It gets most of its supplies from the Rocky Mountains and westernCanada through Northwest Pipeline Co., principally, and PG&EGas Transmission-Northwest.

“The rise of natural gas prices is at least partially a functionin the increased electric generation demand, but it isnationwide-not just in the Pacific Northwest,” said Bill Donahue, aPuget Energy senior regulatory analyst in Seattle. “To the extentthere are utilities acquiring natural gas on the open market,without prior contracts, that is creating additional demand. But itis nationwide in scope.”

Donahue said Puget expects a regulatory decision in July and thegas cost rate increase to be effective Aug. 1. He added that unlikeother areas of the country, Puget Energy is ahead of schedulestoring natural gas, despite the extreme electric load demands. Thehave interests in storage facilities in both the state ofWashington and Utah.

Sandra McDonough, a Portland-based spokesperson for PG&ETransmission said “We have high demand and we’re as full as we canbe at the southern end of our system. We’re moving more than 1.8Bcf/d and 1.9 Bcf/d at different points in Oregon.”

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