Price spikes ahead?

April C. Murelio

Associate Editor

When the trading bell finally tolled last June and power marketers either announced record profits or filed for bankruptcy, two key questions emerged: Why did it happen, and will it happen again?

In the months after prices soared from an average of $25 to $35 per MWh to anywhere between $400 and $7,500, numerous parties examined reasons for the volatility plaguing the Midwest electricity market June 22-26, 1998.

Both those urging a cautionary approach to competition and those ready to rumble gleened fodder for their arguments from these examinations.

According to the Federal Energy Regulatory Commission (FERC) and many others, contributing factors included capacity shortages; a hot summer and a long-term trend toward rising demand throughout the Midwest; an immature electricity market; and poor or non-existent risk manage- ment and counterparty credit verification practices.

Today, as the summer starts to sizzle and the market shows signs of boiling up, “Will it happen again?” becomes the question posed most by nervous lips.

“I think it`s going to be pretty bad. If it stays cool, it will be OK, but if it gets hot, look out,” said Dilip Daswani, president of Enterprise Automation Advisors (EAA), a trading software and consulting firm.

Although it`s unlikely traders and marketers will find themselves contending with $7,000 MWh this summer, electricity seems to be a commodity prone to wild fluctuations. Despite reassurances by the North American Electric Reliability Council (NERC) that capacity should be “adequate to meet projected electricity demands,” this summer already appears a bit sticky.

The market first showed signs of action in early May when an East Central Area Reliability Council (ECAR) report caused minor spikes at Midwest hubs. For example, Midwest electricity for June delivery at the Cinergy hub rose from $2.09 per MWh to $63.10 on the New York Mercantile Exchange (NYMEX), representing a 30 percent increase from the contract price in April.

ECAR expects capacity margins-the difference between expected demand and available generation-in its nine-state region to be 10.8 percent during peak demand this summer compared with 9.3 percent last summer. However, ECAR and NERC both admit that hot temps and high demand could narrow and even eliminate this small gain.

“The ECAR transmission system is expected to perform adequately under a wide range of summer electrical demand conditions,” said Brant H. Eldridge, ECAR`s executive manager. “However, should significant transmission system outages occur during periods of heavy demand, local area power interruptions could occur.”

Recent reports also cast a dim light on power markets in the Western System Coordinating Council (WSCC). A new study by the energy practice group of ICF Kaiser Consulting warns that the WSCC region is “poised on the precipice” of capacity shortfalls and extreme price volatility this summer and next.

“The West stands at least a one in three chance of experiencing price spikes similar to those seen in the Midwest market…,” said Judah Rose, a senior vice president with ICF and study director.

Already this summer, utilities and Independent System Operators (ISOs) like Consumers Energy of Michigan, Con Edison of New York, and ISO New England have warned customers about overloading the grid. Con Edison alone expects to set a record peak demand of 11,650 MW, surpassing the previous record of 11,013 MW.

“The ESCOs (energy service companies) are a little worried,” said Derek Porter of Henwood Energy Services Inc. (HESI). “They`re seeing prices in May that they didn`t expect until July or August.”

With power plants like Niagara Mohawk Power`s 850 MW Oswego 5 tripping off and on, prices may continue to climb, and contingency plans designed to manage this potential price risk are becoming popular.

In May, NYMEX raised margin rates on three of its five electricity futures contracts by 50 percent. Besides curbing trading, higher margin rates decrease potential credit risk and often signal expectations of high volatility.

Off the trading floor, Aquila Energy and ConEdison Solutions now offer their customers ways to manage price risk. Aquila offers GuaranteedGeneration, with several features, including one that allows utilities the option to purchase replacement power at predetermined prices. ConEdison`s Power Interruption Contingency program helps businesses and organizations-small and large-develop, test, or improve contingency plans and meet their needs when the power fails.

But weather and high demand may not be the only factors feeding this summer`s volatility. For example, Northeast traders reported an increase of at least $5 to $7 per MWh for next-day energy because of the new NOx emissions standards.

In many respects, last summer`s spikes occurred as the electricity market took its first wobbly steps. The June `98 shakeup produced more savvy and competitive power brokers and marketers, and divestitures moved more capacity into the hands of these entrepreneurs. “There are a lot of players with assets that are now entrepreneurial in nature,” Porter said. “Their paychecks depend on how high the price goes.”

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