With normal cooling degree and heating degree days in the third and fourth quarters, Stephen Smith Energy Associates estimated in its latest Monthly Energy Outlook that third quarter Henry Hub natural gas prices will average $5.82/Mcf and fourth quarter prices will be $5.62, yielding an average annual forecast of $5.80 for 2004. If the estimate holds, gas prices would average 40 cents higher than in 2003, but would be well below the $6.20 average set by Energy and Environmental Analysis Inc. (EEA) consultants last week (see related story).

The Smith report did say that there could be higher prices than those in it’s base forecast if a series of oil supply “scares” keep West Texas Intermediate (WTI) closer to a $40/bbl average and if the summer is 5-7% warmer than normal. If those factors are in place, “we would add about $0.50-1.00 to our third quarter forecast.”

In contrast, EEA consultants see gas prices at the Henry Hub averaging near $6.20, and said there is a good possibility that prices will reach a “sustained” level of $7/MMBtu in 2005.

“We expect Henry Hub prices for the remainder of the current injection season, June 2004 [through] October 2004, to average approximately $6.50 per MMBtu,” EEA said, but “any type of hot summer could easily push gas prices to around $7 per MMBtu.” EEA’s forecast is consistent with the New York Mercantile Exchange’s projection of an average price of $6.49/MMBtu for this year’s injection season, but current futures prices are below EEA’s forecast of $6.98 for the peak winter months.

The monthly report by Mississippi-based Smith’s consulting group estimated not only gas prices, but also the outlook for gas storage, production data and power trends.

“At first glance, with gas storage levels running 340 Bcf higher than year-ago levels and about 180 Bcf over our 1994-2003 seasonal norms,” the above $6/MMBtus gas prices “appear quite high,” said the Smith consultants. “However, when the gas price is viewed as a percent of Btu-parity with Gulf Coast distillate…it can be seen that the gas price has been in the normal range (80-90%) versus Gulf Coast distillate for most of the past year.”

There is one key difference, however, between this year and 2003. “The recent upper-80s gas/distillate ratio is similar to the ratio seen for most of last summer, but current storage-versus-normal is much higher than last summer,” because there was a “chronic weather-normalized weekly surplus last summer averaging about 15 Bcf per week…” while “this spring, storage-versus-normal was high, but depleting at about 7 Bcf per week…on a weather-normalized basis. This is a key point.”

Smith expects to see the “re-emergence of a 5-7 Bcf weekly deficit as hydro generation follows its normal seasonal decline from June through October. This should reduce the current 180 Bcf surplus to considerably close to normal levels by November 1.” The base case scenario is based on $36 WTI for a third quarter average and normal summer cooling degree days. “Under these assumptions, we’d look for $5.50-$5.90 gas at the close of the September contract.” However, oil disruptions or a warmer-than-normal summer will increase the September Henry Hub close, said Smith.

On the production side, the Smith consultants echoed recent reports in noting the continuing decline in North American production. They used three sources to estimate domestic natural gas production: the monthly Department of Energy (DOE) data, Texas and Louisiana production data, and their internal survey of gas producers. “Ignoring hurricane effects, the DOE data shows a 1Q2001 production peak of about 54 Bcf/d, and a trend decline to about 52.6 Bcf/d for February 2004. Both the January 2004 and February 2004 production numbers appear to be unrealistically high, and we expect some downward revisions.”

On the good news side, Smith reported that gas production in Texas appears to be increasing. The state’s production in November 2003 was 15.9 MMcf/d, while production in March 2004 was 16.3 MMcf/d. “This appears consistent with the strong production growth in the Barnett shale, and the continued intensive drilling in the Bossier area and in South Texas.” Louisiana production “appears to be in mild trend recline over the same four months,” but it’s “not enough of a decline to offset the Texas growth.”

There also is strong gas production growth in the Rocky Mountains — especially in coalbed methane — but it’s not enough to sustain the annual decline, said Smith. Reviewing all of the production data across the country and incorporating Minerals Management Service numbers from the Gulf of Mexico, the “best estimate for the Lower 48 production decline rate for 2004 is roughly 1.5-2% per year.”

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