As the curtain slowly falls on gas supply from the Gulf ofMexico Continental Shelf, the deep-water waits in the wings.Canadian producers are scripting their role on the U.S stage. Andthe Alaskan gas play’s Lower 48 audience can’t buy tickets to theshow for about a decade.

The line “30 Tcf market” has turned to cliche, but the gassupply drama unfolded before many curious eyes at GasMart/Power2000 last week in Denver. While it’s true all metaphors must end,the struggle to grow gas production apparently never will.

The challenge to keep pulling gas out of the Continental Shelfwas described as a “fairly steep treadmill” by Andrew L. Hardiman,vice president of Chevron USA Production Co. for the Gulf of MexicoDeepwater Business Unit. “Clearly, the majors have abandoned theShelf… You still make a lot of money in the Shelf. It’s just thatthe quality of the investment has deteriorated.” Independents rulethe shallower waters, and Hardiman credits them for their abilityto get “the last bit of value out.”

The Shelf is nearly 70% gas, about 14% of that associated withoil production. The make-up of the resource base is much differentin the deep-water where it’s 64% oil and only 36% gas, with 25% ofthat associated with oil. “If you want the gas, you’ve got to getthe oil.” Further, Hardiman speculated the gas-to-oil ratioprobably will decline as producers move farther out. If historytells us anything, that swim to the ultra-deep likely will besooner rather than later. It took the industry 40 years — 1938 to1978— to get into 1,000 feet of water. Thanks to technology andinitiatives such as deep-water royalty relief, producers are nolonger wading but sprinting toward the depths like Olympicswimmers. Hardiman said the 8,000-foot water depth mark isn’t faraway. By 2020, projections show between 7 and 12 Bcf/d of gascoming from the deep-water, about 22 Bcf/d from the entire Gulf.

“Our belief is the deep-water has similar potential to theShelf,” said Andy Inglis, vice president of BP Amoco’s western gasbusiness unit. Other areas where he sees potential are Alaska’sMackenzie Delta and liquefied natural gas (LNG) imports fromTrinidad and elsewhere. Alaskan gas could make it to the states inthe form of LNG, through gas-to-liquids technology or a Lower 48gas pipeline, probably a combination of all three, Inglis said. BPAmoco is a “major partner” in a Trinidad LNG project.

As for the existing supply from the San Juan Basin, producershave had more to smile about in the last couple of years, Inglissaid. From 1996 to 1998, San Juan producers were getting about$1.45/Mcf for their gas, compared to $2.00 Henry Hub prices. Todaythey’re getting about 90% of the Henry Hub benchmark. Thankpipeline infrastructure for that.

Western Canadian producers can do the same. “Building theinfrastructure and being connected has proven to be of value to theCanadian producer,” said Petro-Canada’s John D. Miller. Canadianproduction is expected to grow 2 to 3% per year but has yet to takeoff. “Although we have the record drilling numbers, we are stillnot seeing the production response.”

The Western Canadian Sedimentary Basin has more proved reservesthan any other basin in North America, Miller said. The WCSB hasproven reserves of 76 Tcf, more than double the offshore Gulfestimate of 29 Tcf. Right now Canadian producers are targeting thelow-hanging fruit. “Elephants are harder to find. We’re gettingdown to smaller pools. We have to attract equity.

“Canada will decline, although it will be over time, and theremight be hiccups. Bottom line, Canada will deliver, but it will bebumpy for the next couple of years.”

The next several months will see the arrival of the AlliancePipeline on the scene. In-service is targeted for October 1, butMiller said to expect it Nov. 1.

Joe Fisher, Denver

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