Despite the current surplus of gas in storage and some predictions that working gas levels could end the injection season at maximum capacity near 3.7 Tcf, Chris McGill, managing director of policy analysis at the American Gas Association (AGA), warned gas buyers not to bet on it.

McGill told attendees at the Colorado Oil and Gas Association’s (COGA) Rocky Mountain Natural Gas Strategy Conference that he’s expecting storage levels on Nov. 1 to be near or only slightly above average levels of about 3.2-3.3 Tcf prior to the start of the winter heating season.

“The fact is we will probably enter this coming winter heating season with about the same [level of gas in storage] as we did last year,” said McGill. So the long position of gas in storage is a temporary one. Once you get to the winter heating season, the resources you need to meet consumer demand at its peak really hasn’t changed much in the last five years.”

McGill noted that there hasn’t been a supply disruption this year from hurricanes, but demand from power generation has gone up substantially due to above-normal temperatures, resulting in a declining storage surplus.

Last January’s much above normal temperatures and the recovery of supply infrastructure after the hurricanes last year enabled storage to fill to above-normal levels and push gas prices lower this summer, but McGill warned end-users and local distribution companies they should expect an underlying tight supply-demand balance to resurface, keeping gas prices above a $6/MMBtu floor.

The relationship between U.S. gas production and productive capacity has not changed, he said. Basically there is no excess productive capacity that currently isn’t being utilized.

“The market really isn’t that much different today than going back to the 2000-2001 winter heating season.”

Gas purchasers looking for Canadian production to save them in the short term may be disappointed, he added. While Canada has steadily supplied about 3 Tcf/year to the United States, growing oilsands production likely will mean demand in the North rises. “Will Canada be a growing supplier of gas to the United States? Most of the producers that I’ve talked to in Canada say, ‘No.’ The Canadian Association of Petroleum Producers describe themselves as ‘stable suppliers’ of natural gas to the U.S., not ‘growing suppliers.'”

McGill also said buyers should be a little skeptical about the prospects for the Mackenzie Delta pipeline project, which would bring 1.2 Bcf/d to Alberta and the Lower 48 from the far north by 2011. And the Alaska gas pipeline also should be greeted with some degree of doubt. “Right now it doesn’t look real good for it happening,” he said. “Something else is going to have to happen politically for the Alaska project to get going.”

And while liquefied natural gas (LNG) looks promising, McGill doubts it will be the “player” in the gas market that some expect it to be. Even looking over a longer term, McGill sees LNG still providing less gas to the U.S than Canada currently provides.

Stephen Thumb, a consultant with Arlington, VA-based Energy Ventures Analysis Inc., told the COGA audience that LNG regasification capacity is likely to grow by leaps and bounds in North America. But Thumb added that regas capacity will be lucky to be maintained at a 60% capacity factor.

In the short-term, global liquefaction constraints will slow LNG supply to the U.S., he said. LNG growth will be very slow until 2008 and it won’t be until 2010 that the LNG industry “begins to mature.”

Thumb said after the end of the decade, the U.S. could be taking in 8-10 Bcf/d of LNG supply, at times potentially putting downward pressure on prices. But Thumb agreed with McGill that the domestic price floor at the Henry Hub won’t go much less than $6. Thumb said $5.30 was probably the absolute bottom at which gas would compete with coal for power generation load.

Of the 99 LNG regasification projects planned in North America, Thumb said only 18 are likely to be built. Thirty-one LNG regas projects already have been canceled. Another 50 are teetering on the edge, and 16 of those are considered only “possible.”

Out of the 34 LNG regasification projects planned on the Atlantic and Pacific coasts, Thumb said none are likely to be built; only four are considered “possible.” Despite these odds, however, total U.S. regasification capacity is likely to balloon to an overbuilt level of more than 26 Bcf/d and only the lucky ones will reach 60% utilization over the long term, Thumb predicted.

“Even with all the talk about LNG, the thing that supplies consumers with the most natural gas is our Lower 48 state production,” McGill noted. “That’s the monster. That’s the thing that if it goes away you can’t replace.” If the U.S. wants to do something about supply, domestic production is where it should look first, he said. That’s where efforts should be focused.

“The dollar investment has been there,” he noted. Gas directed drilling, at more than 1,400 rigs, is the highest it’s ever been. “However, we haven’t seen much change in the actual productive capability. Reserves are actually up… We have higher reserves today than when we included the North Slope in the U.S. reserves set back in the mid to late 1980s. But a lot of the reserves are what we see here in the Rockies area, tight sands, shales, other resources,” and those generally produce less and have steep initial declines.

McGill said the AGA will continue pushing responsible ways to access the remaining U.S. gas resource for customers.

Regarding prices, McGill said, “In a $70/bbl oil world I just do not believe we can see natural gas prices in this country go back to $3/MMBtu and stay there. It’s just not going to happen. Obviously there’s going to be volatility. We’ve seen a market floor somewhere around $6.

“AGA’s view is that the supply-demand balance — forget the storage picture — is tight and will remain tight. Consumption is poised to grow. Supply gains will come, but they will come from new frontier areas,” LNG and unconventional domestic supply if technology and access is provided.

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