State Regulators Cite Over-Dependence on Gas

Over-reliance on natural gas as the fuel for new electric generating plants nationally carries with it an inherent risk to reliability and the threat of exacerbating already volatile wholesale markets, according to three industry executives who addressed a meeting of state regulatory commissioners in San Diego last week.

Somewhat hidden problems are quietly arising from the over-dependence on gas-fired power generation, the speakers stressed, because of a combination of factors. But with incidents like California's gas and power curtailments last week, more attention is going to be drawn to solving the problem by looking at electricity and gas load and infrastructure planning in tandem.

A single 1,000 MW gas-fired power plant operating at a 60% load factor uses about 37 Bcf annually, but the significance of the concentrated gas loads has been "hidden" somewhat because a lot of the new generating plants are taking supplies directly off interstate transmission pipelines, so the local distribution companies are not seeing this load growth in a direct sense, said Craig Frew, CEO of Iroquois Gas Pipeline.

Inadequate price signals for both gas and electricity and the illusion of a lot of spare gas pipeline capacity add to the potential problems in the future, Frew told the state regulators' meeting. "There are a lot more traders in the market doing a lot more transactions to give themselves the comfort that they have a shield in all of this," Frew said. "Paper is great but it doesn't move any gas physically to the burner tip."

Noting that in the short-term there will be higher prices with more volatility, Frew and the other two speakers, Jim Mahoney, a senior vice president with PG&E's National Energy Group, and Peter Esposito, vice president and regulatory counsel for Houston, CA-based Dynegy, presented different perspectives on the situation. The three agree, however, the growing reliance on gas-fired power is converging the prices of the two energy sources and creating increased price volatility and less market stability --- two factors California and federal energy officials have been wrestling with this fall.

"The generating community is ready to respond and respond quickly," said Esposito, representing the generator, marketer and trader sectors. (Dynegy currently owns or manages 20,000 MWs of power and has a goal of increasing that to 70,000 MW by 2003, he said.) "We're out there ready to take the risks and not push them over to the customers, as seems to be the case here in southern California."

The theoretical and real energy worlds met in San Diego during several sessions of the National Association of Regulatory Utility Commissioners (NARUC) annual meeting, but none was more striking than last Wednesday's panel discussion of 'Natural Gas and Merchant Plants" which occurred as California's energy infrastructure suffered through continuing shock waves from both energy sources (see Daily GPI, Nov. 16).

California's Independent System Operator (Cal-ISO) for the first time issued power alerts in November throughout the week, although peak demand was far below record levels. Wholesale power prices soared toward $250/MWh; natural gas prices spiked to $8 and then $11 an Mcf. At the same time, a statewide cold snap caused power plants in the southern end of the state where NARUC members were meeting to switch to oil for the first time since they were sold to merchant operators three years ago.

If the NARUC speakers are correct, the growing reliability stresses straining both the electric grid and natural gas pipeline transmission systems are the result of a complicated array of factors, many tied to restructuring and the advent of more competitive markets. Long-term, fixed capacity contracts have been frowned upon, and the much greater reliance on interruptible contracts, means power supplies are less assured than ever.

"All of this can be managed, but we need a balanced approach and we need people to begin focusing on this and developing regional energy policies to address the issues," said PG&E's Mahoney, citing two recent studies of New England where some 7,000 MW of new gas-fired generation is under construction, bidding to drastically change the region's balance of fuel diversity. The 7,000 MW addition presents a daily gas load of 1.2 Bcf.

A major reliability and pricing factor is the growing emphasis among the plants that are being built to have no alternate fuel capability, as a means of getting approved more quickly for construction. Among some 30,000 MW identified for long-term construction in New England, 11,000 MW are expected by 2005, with 8,000 of the total already under construction, and 60% of that has no back-up fuel capability. Similar pushes to build gas plants are going on in all other regions of the country, Mahoney said.

The growing dependence of gas-fired electricity places the generators in competition with core gas customers when the temperatures drop, Mahoney told the NARUC audience. In New England, some 77% of the region's current gas pipeline capacity could be consumed by the new power plants slated to come on line between now and 2003, he said.

Dynegy's Esposito said the industry needs to be "looking at ways to get new pipe in the ground in areas where we are going to be seeing new power generation." Although he thinks there are a lot of challenges presented by the gas-electricity convergence, none of them are insurmountable, he said. "The worst thing we can have at this point is uncertainty because it will delay new investment and at the end of the day that is going to result in higher prices than necessary when supplies get short."

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