With June natural gas futures soaring to a dizzying high of$4.50 last week, projections by Lehman Brothers and Salomon SmithBarney that spot prices will average $3.50 the rest of the yearseem a bit too conservative. A few weeks ago, those price levelswould have seemed astronomical.

In a research note released May 19, Robert Morris of SalomonSmith Barney, said he expects prices to average $3.50 during thethird quarter and $3.75 during the fourth quarter of this year. Hisfull-year 2000 composite spot price forecast is now $3.25/MMBtu(raised from $2.78/MMBtu) and his 2001 forecast is $3.25/MMBtu, upfrom $2.65/MMBtu. Morris, however, admits these prices could be onthe low side. The 12-month strip on Friday was $4.15 and thesix-month strip was $4.239.

“[W]e expect deliverability to be off at least 1 Bcf/d thissummer compared with last year. This is based on a, perhapsaggressive, assumption that the domestic natural gas rig countexpands to 700 by November (the domestic natural gas rig count iscurrently 634). In addition, our analysis indicates that thedomestic gas rig count would have to rise above 800 just to returndomestic deliverability to where it stood at the beginning of 1999.

“In the interim, we expect the demand to increase due tocontinued economic expansion and the start up of new gas-firedelectric generating capacity. Also, we don’t expect much help fromCanada this year with the fundamentals and storage outlook similarto the U.S.”

Meanwhile, Richard Gross, senior vice president of LehmanBrothers Energy Research, said he expects Henry Hub prices willaverage $3.30 this year and $3.35 in 2001.

The industry simply “can’t fill storage and meet power needsthis summer,” Gross said in an interview with NGI last week. “We’regoing to get pretty high prices and we aren’t going to get storagefilled. As a result, we are going to have $3.25/MMBtu gas this year(average wellhead price) and $3.35 next year, and if we’re wrongthese prices are too low.”

Gross, who discussed the booming market at the mid-year meetingof the Independent Petroleum Association two weeks ago, said heexpects to see 2,600 Bcf of gas in storage on Nov. 1 if theindustry can match the injection pace of 1999 over the same period,and that’s a big “if.”

“We’ve run about 2.2 Bcf/d less [than that] season to date.We’ve got about 20% of the season complete. The big fill —whether we make or break the year — is probably the next four orfive weeks,” he said. “Once we get into the cooling season, it’sgoing to be tougher to get some of the big [injection] numbers.We’ll get another crack at it in September and October, dependingon what kind of weather we get. But so far, the early returns showit will be a struggle to meet both markets.”

Gross noted that last winter the industry relied more heavily onstorage for supply than in recent years because of a decline inwellhead deliverability. Although wellhead deliverability probablywill improve some by next winter, the reliance on storage still isexpected to be significant. “If you look at the draw per degree dayin the last five years, it goes from about 0.35 Bcf per degree daydraw to 0.50 Bcf, 0.55 Bcf and to last year when it was 0.64 Bcfper degree day. For each degree day we get, even if it’s gettingwarmer and warmer, we are utilizing storage more to supplementwellhead supply. I don’t think normalized is 0.64 Bcf per degreeday; I think it’s probably in the high 0.50s Bcf. It’s becausewe’ve been short [wellhead supply]. We basically lived off ofstorage in 1999; that’s how we balanced the market. We won’t havethat luxury in 2000 and 2001.

“Every which way you twist and turn and look at the market, itjust feels tight. If you talk to the processors (Dynegy, Duke,Williams…) they’ll tell you they are still struggling a littlebit. All of these things tell us it is going to be very difficultto serve both masters this summer.”

Gross said he doesn’t expect producers to return to 1997 levelsof wellhead deliverability until 2002. “All of this is predicatedon fairly high drilling levels; for instance, the average between2000 and 2004 has to be 50% higher in drilling activity than theprevious five years. Those are big-time assumptions. We’ve got toman those rigs. We’ve got to develop those prospects. We’ll seewhere we go. I’m a firm believer in the resource base. I spent mostof my 25-year career as an E&P analyst so I’m relativelysanguine about the response. It’s just that there’s a lag, whichmakes 2000 and 2001 pretty tight.”

Another bullish factor is hydroelectric generation, which isshort this year. “If you look at past years of depressed demand,they have been very good hydro years. This year is going to bemediocre, and that’s a big swing. In California alone, from areally good year to a crummy [hydroelectric] year, it is 300 Bcf ofdemand, and in the second quarter it is probably 2 Bcf/d. It’shuge. We are seeing it right now. They have a couple of nukes downout there. Normally they would get hydro, but they aren’t gettingit this year.” He said hydroelectric generation in January was downmore than 10%.

Gross estimates that there is going to be an additional 1 Bcf/dof gas demand for power generation this summer compared to lastyear. Another noteworthy factor is that when nukes go down thisyear, the impact on the gas market likely will be greater than inyears past, he said, because the market is relying more this yearon existing nuclear power. Nuclear generation plants are operatingat much higher efficiency rates compared to years past. “The riskis that the nuke fleet doesn’t operate like champs moving forward.One breaks down, it’s a big deal; it’s 1,000 MW a pop.”

Rocco Canonica

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