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Business & Money

The collapse of wholesale markets has utilities once again making the purchasing decisions, and taking all the risks.
Fortnightly Magazine - June 1 2003

The collapse of wholesale markets has utilities once again making the purchasing decisions, and taking all the risks.

If a common theme is emerging from the various policy directions across the country, it seems to be that responsibility for supply resources is moving away from open markets and back into the hands of load-serving utilities.

This is partly a survival response from an industry that has been in crisis. In the absence of a liquid wholesale power market, state regulators and utilities are reverting to resource planning systems that hearken back to the early 1990s. This dated practice-known as integrated resource planning (IRP) and competitive bidding processes-is being welcomed by regulators and even beleaguered merchant players desperate for reliable revenue streams.

"IRP is tried and true. It's something that regulators are familiar with," says George Gross, a professor at the University of Illinois at Urbana-Champaign, and formerly a manager of electric resource planning at Pacific Gas and Electric Co. "For lack of anything better, IRP is a possibility at this point. But I am not convinced this will be effective policy."

The industry has changed, Gross says, and even integrated utilities are loath to return to the old environment. At the same time, however, a return to IRP in some form might help the industry get off the dime and move into its next stage of evolution, some analysts say.

IRP: Merchants Return To Their IPP Roots

Merchant power producers are struggling to find a new business model that works in the current market, while not setting them up for failure in the future. In some ways, the emerging model looks a lot like the IPPs of old. Namely, their power plants increasingly will depend on long-term power purchase agreements (PPA) for stable cash flow.

Some things are notably different, however. First, the definition of "long-term" has changed. While the IPPs of old frequently operated under 15- to 30-year PPAs, today's long-term contracts specify five- to 10-year terms. Additionally, while classical IPPs had virtually all of their output committed under contract, the new merchant IPPs must continue to market much of their capacity via spot-market sales and short-term contracts.

In many parts of the country, an apparent oversupply situation has limited utilities' new capacity requirements in recent years, and long-term contracts have been virtually absent from the market. Now, however, signs of life are beginning to return to the market.

"We're seeing an uptick in RFPs and bidding processes," says Steven Schleimer, Calpine's director of market and regulatory affairs for the western region. The illiquid power market, ironically, is partly responsible for this increase in demand for long-term power supplies. "Utilities and merchants are both looking to manage their risks with longer-term deals," Schleimer says.

Regulators, likewise, are eager to prevent the price spikes and supply dislocations that have jolted consumers in recent years. "The regulatory agencies seem to want to take a more active role in overseeing utilities' portfolios," Schleimer says.

Power Returns to the PUCs

IRP and competitive bidding programs represent a logical way for public utility commissions to take

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