A top official with PG&E Generating last week confirmed whatsome, such as FERC, have suspected already – that the increase innatural gas demand for power generation will not be as great as hasbeen anticipated for the immediate future.

“Nationally, even in light of various forecasts, we’re not asconvinced that there will be a huge increase in electric generationuse for natural gas for the next five or six years. We’re not asbullish as some of the pundits are,” such as the Energy InformationAdministration and the Interstate Natural Gas Association ofAmerica, said PG&E Generating President and COO Chrisman Iribeat the 11th annual LDC Forum in Chicago, IL, last Tuesday.

“But nevertheless, what we’re looking at is something in theneighborhood of 80,000 MWs [of new generation capacity], splitroughly 50-50 between baseload and peaking,” which would translateinto about 3 Tcf of additional annual gas demand, he told gasbuyers and pipeline executives at the Forum, sponsored byInterchange Energy Group. That would be about 15 Bcf/d of more gasdemand in the middle of the summer when electricity consumption isgreatest.

In the New England region (six states except New York), he notedmore than 30,000 MWs of new generation capacity has been “proposedor talked about.” Of that amount, about 5,000 MWs of new capacity”is in construction, and we don’t expect there will be too manymore…because the market frankly doesn’t need too many morefacilities.” Still, he said 5,000 MWs will require a “substantialamount of additional gas” – about 750 MMcf/d, which would equate to250 Bcf per year.

In the Midwest market, “our own estimates show something in theneighborhood of 27,000-30,000 MWs of new capacity” will be built, a”significant chunk” of which will be peaking facilities – meaningthey would run only two to three months during the summer. “You’retalking about 2.5 Bcf/d [of] increased demand for brand new peakingfacilities over the next three to four years,” and an equal amountfor baseload generation plants, Iribe estimated. The potential hikein gas demand will be sufficient to keep busy “Alliance or whoever[is] your favorite new delivery pipeline” into the Chicago area.

PG&E Generating, a major developer of gas- and coal-firedgeneration plants, is doing its part, he noted. The company isbuilding “right now” two key gas-fired facilities in New England,plans to start construction “in the next three or four months” onthree more plants on the Atlantic Coast and in California, andexpects to start work on two other facilities in Michigan andWisconsin next spring, according to Iribe. “All told, myconsumption of natural gas nationwide to make electricity willexceed 1.5 Bcf/d in four years. We’re a major user of gas, andanticipate that we’re going to be one of your best friends.”

He said his company favors gas-fired facilities because of thefavorable economics. He estimated it costs PG&E Generatingabout $500 per kW to build a gas-fired generation plant, comparedto more than $1,700 per kW for a coal-fired facility. “Thatdifference in capital — a huge amount of capital, hundreds ofmillions of dollars of capital [that] we don’t need to expend for agas-fired facility — puts a huge premium value on natural gas forus. Gas would have to go up 2 1/2 times at the wellhead to get usto be willing to [build] coal-fired facilities today,” Iribe noted.

Still, he said that PG&E Generating was “in no way afraid”of coal-fired facilities. He estimatedcoal presently accounts forabout 60% of his company’s fuel consumption, while gas averagesabout 20-25%. But that mix will change over the next few years, asKing Coal plays a lesser role. “I’m not sure there’s going to be ahuge resurgence of coal, even in existing facilities, as we gothrough the next decade or so.”

To serve generation plants, Iribe said pipelines and LDCs willhave to deal with the wide swings in their demand. “We have afacility in New England that we’ve intended to be baseload thatburns approximately 100 [MMcf/d],” he noted, but added there aretimes, even on peak days, when demand can “run down to as little as20 MMcf of daily use,” and then shoot back up to the 100 MMcf/dlevel. These “swings within a day [are] something that is very realto us,” and developers are hoping that once new generationfacilities are completed the gas pipelines and LDCs will come andbe able to meet their needs — it’s “sort of like in the [movie],Field of Dreams.”

Iribe said generators also depend on and require more frequentprice signals, as often as every five minutes. “Someone has saidthat the electric world is already on the Internet if you thinkabout the real-time information that we have to play with. And thegas industry probably needs to join us,” he told gas industryexecutives.

Iribe said power generators and LDCs currently “are reallygrappling with [gas] requirements that are fundamentally verycomplementary.” For instance, “I need gas in the summer,” whichwon’t interfere with LDCs’ traditional peak demand in the winter.”I need gas in the middle of the day. I don’t need gas at night.Most of my facilities are dual fuel, [which means] I can give upgas for a short period — a total of 14 to 20 days — in thecourse of a winter season.”

He sees natural gas, which traditionally has enjoyed peak demandonly in the winter, evolving into a market with two peak periods tomeet the needs of power generators. But the summer demand ofgenerators would coincide with the storage injection season tosupply LDCs’ traditional winter demand, possibly creating a sort oftug-of-war between the two factions. “There may be as much demand,and I guess we saw it this past summer, for natural gas to go into[gas turbines] as there is to put it into storage” during thesummer for winter use. “I suspect that there may be a better pricefor gas converted to electricity than gas stored for wintertimeconsumption.”

Susan Parker

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