Multiple Basins Starring In Gas Supply Plot
As the curtain slowly falls on gas supply from the Gulf of
Mexico Continental Shelf, the deep-water waits in the wings.
Canadian producers are scripting their role on the U.S stage. And
the Alaskan gas play's Lower 48 audience can't buy tickets to the
show for about a decade.
The line "30 Tcf market" has turned to cliche, but the gas
supply drama unfolded before many curious eyes at GasMart/Power
2000 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 Shelf
was described as a "fairly steep treadmill" by Andrew L. Hardiman,
vice president of Chevron USA Production Co. for the Gulf of Mexico
Deepwater Business Unit. "Clearly, the majors have abandoned the
Shelf... You still make a lot of money in the Shelf. It's just that
the quality of the investment has deteriorated." Independents rule
the shallower waters, and Hardiman credits them for their ability
to get "the last bit of value out."
The Shelf is nearly 70% gas, about 14% of that associated with
oil production. The make-up of the resource base is much different
in the deep-water where it's 64% oil and only 36% gas, with 25% of
that associated with oil. "If you want the gas, you've got to get
the oil." Further, Hardiman speculated the gas-to-oil ratio
probably will decline as producers move farther out. If history
tells us anything, that swim to the ultra-deep likely will be
sooner rather than later. It took the industry 40 years --- 1938 to
1978--- to get into 1,000 feet of water. Thanks to technology and
initiatives such as deep-water royalty relief, producers are no
longer wading but sprinting toward the depths like Olympic
swimmers. Hardiman said the 8,000-foot water depth mark isn't far
away. By 2020, projections show between 7 and 12 Bcf/d of gas
coming from the deep-water, about 22 Bcf/d from the entire Gulf.
"Our belief is the deep-water has similar potential to the
Shelf," said Andy Inglis, vice president of BP Amoco's western gas
business unit. Other areas where he sees potential are Alaska's
Mackenzie Delta and liquefied natural gas (LNG) imports from
Trinidad and elsewhere. Alaskan gas could make it to the states in
the form of LNG, through gas-to-liquids technology or a Lower 48
gas pipeline, probably a combination of all three, Inglis said. BP
Amoco is a "major partner" in a Trinidad LNG project.
As for the existing supply from the San Juan Basin, producers
have had more to smile about in the last couple of years, Inglis
said. From 1996 to 1998, San Juan producers were getting about
$1.45/Mcf for their gas, compared to $2.00 Henry Hub prices. Today
they're getting about 90% of the Henry Hub benchmark. Thank
pipeline infrastructure for that.
Western Canadian producers can do the same. "Building the
infrastructure and being connected has proven to be of value to the
Canadian producer," said Petro-Canada's John D. Miller. Canadian
production is expected to grow 2 to 3% per year but has yet to take
off. "Although we have the record drilling numbers, we are still
not seeing the production response."
The Western Canadian Sedimentary Basin has more proved reserves
than any other basin in North America, Miller said. The WCSB has
proven reserves of 76 Tcf, more than double the offshore Gulf
estimate of 29 Tcf. Right now Canadian producers are targeting the
low-hanging fruit. "Elephants are harder to find. We're getting
down to smaller pools. We have to attract equity.
"Canada will decline, although it will be over time, and there
might be hiccups. Bottom line, Canada will deliver, but it will be
bumpy for the next couple of years."
The next several months will see the arrival of the Alliance
Pipeline on the scene. In-service is targeted for October 1, but
Miller said to expect it Nov. 1.
Joe Fisher, Denver