Over-reliance on natural gas as the fuel for new electricgenerating plants nationally carries with it an inherent risk toreliability and the threat of exacerbating already volatilewholesale markets, according to three industry executives whoaddressed a meeting of state regulatory commissioners in San Diegolast week.
Somewhat hidden problems are quietly arising from theover-dependence on gas-fired power generation, the speakersstressed, because of a combination of factors. But with incidentslike California’s gas and power curtailments last week, moreattention is going to be drawn to solving the problem by looking atelectricity and gas load and infrastructure planning in tandem.
A single 1,000 MW gas-fired power plant operating at a 60% loadfactor uses about 37 Bcf annually, but the significance of theconcentrated gas loads has been “hidden” somewhat because a lot ofthe new generating plants are taking supplies directly offinterstate transmission pipelines, so the local distributioncompanies are not seeing this load growth in a direct sense, saidCraig Frew, CEO of Iroquois Gas Pipeline.
Inadequate price signals for both gas and electricity and theillusion of a lot of spare gas pipeline capacity add to thepotential problems in the future, Frew told the state regulators’meeting. “There are a lot more traders in the market doing a lotmore transactions to give themselves the comfort that they have ashield in all of this,” Frew said. “Paper is great but it doesn’tmove any gas physically to the burner tip.”
Noting that in the short-term there will be higher prices withmore volatility, Frew and the other two speakers, Jim Mahoney, asenior vice president with PG&E’s National Energy Group, andPeter 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 poweris converging the prices of the two energy sources and creatingincreased price volatility and less market stability — twofactors California and federal energy officials have been wrestlingwith this fall.
“The generating community is ready to respond and respondquickly,” said Esposito, representing the generator, marketer andtrader sectors. (Dynegy currently owns or manages 20,000 MWs ofpower and has a goal of increasing that to 70,000 MW by 2003, hesaid.) “We’re out there ready to take the risks and not push themover to the customers, as seems to be the case here in southernCalifornia.”
The theoretical and real energy worlds met in San Diego duringseveral sessions of the National Association of Regulatory UtilityCommissioners (NARUC) annual meeting, but none was more striking thanlast Wednesday’s panel discussion of ‘Natural Gas and Merchant Plants”which occurred as California’s energy infrastructure suffered throughcontinuing shock waves from both energy sources (see Daily GPI, Nov. 16).
California’s Independent System Operator (Cal-ISO) for the firsttime issued power alerts in November throughout the week, althoughpeak demand was far below record levels. Wholesale power pricessoared toward $250/MWh; natural gas prices spiked to $8 and then$11 an Mcf. At the same time, a statewide cold snap caused powerplants in the southern end of the state where NARUC members weremeeting to switch to oil for the first time since they were sold tomerchant operators three years ago.
If the NARUC speakers are correct, the growing reliabilitystresses straining both the electric grid and natural gas pipelinetransmission systems are the result of a complicated array offactors, many tied to restructuring and the advent of morecompetitive markets. Long-term, fixed capacity contracts have beenfrowned upon, and the much greater reliance on interruptiblecontracts, means power supplies are less assured than ever.
“All of this can be managed, but we need a balanced approach andwe need people to begin focusing on this and developing regionalenergy policies to address the issues,” said PG&E’s Mahoney,citing two recent studies of New England where some 7,000 MW of newgas-fired generation is under construction, bidding to drasticallychange the region’s balance of fuel diversity. The 7,000 MWaddition presents a daily gas load of 1.2 Bcf.
A major reliability and pricing factor is the growing emphasisamong the plants that are being built to have no alternate fuelcapability, as a means of getting approved more quickly forconstruction. Among some 30,000 MW identified for long-termconstruction in New England, 11,000 MW are expected by 2005, with8,000 of the total already under construction, and 60% of that hasno back-up fuel capability. Similar pushes to build gas plants aregoing on in all other regions of the country, Mahoney said.
The growing dependence of gas-fired electricity places thegenerators in competition with core gas customers when thetemperatures drop, Mahoney told the NARUC audience. In New England,some 77% of the region’s current gas pipeline capacity could beconsumed by the new power plants slated to come on line between nowand 2003, he said.
Dynegy’s Esposito said the industry needs to be “looking at waysto get new pipe in the ground in areas where we are going to beseeing new power generation.” Although he thinks there are a lot ofchallenges presented by the gas-electricity convergence, none ofthem are insurmountable, he said. “The worst thing we can have atthis point is uncertainty because it will delay new investment andat the end of the day that is going to result in higher prices thannecessary when supplies get short.”
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