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NGSA Official: U.S. Gas Production Flat at 50 Bcf/d Despite Record Drilling, Spending

The domestic natural gas-directed rig count is at a two-decade high, gas well completions are at a record high, and the number of seismic crews searching for gas onshore has increased, but the production of dry gas in the United States has remained essentially flat at 50 Bcf/d since early 2002, an official with the Natural Gas Supply Association (NGSA) said last Monday.

U.S. dry gas produced declined by approximately 200-250 Bcf in 2004, or by a little more than 1% from 2003, noted NGSA Chairman Joseph Blount during a press briefing at the Canadian Embassy in Washington, DC, where he and an official from the Canadian Association of Petroleum Producers (CAPP) provided an update on the gas supply situation in North America. Much of the decline -- about 150 Bcf -- was attributed to Hurricane Ivan that struck the Gulf Coast last September.

Energy analysts and consultants expect U.S. natural gas production to stabilize and possibly move up slightly in the current year, Blount told reporters. He said production could grow by as much as 2% this year.

While onshore gas production was on the upswing last year, production in the Gulf of Mexico fell, he said. Shelf production in the Gulf of Mexico continued to decline in 2004 to 6.6 Bcf/d from 7.5 Bcf/d in the prior year, and deepwater production tumbled to 4.1 Bcf./d in 2004 from 4.3 Bcf/d in 2003.

About 1,175 rigs were in operation as of April 15, reaching a two-decade high and up 18% over the April 2004 count of 996 working rigs in the United States, said Blount, who is also president of Unocal Midstream and Trade. Offshore rig activity was relatively flat last year, while onshore rig activity rose significantly. The land rig market has been very tight, especially in the Rockies, he noted.

He estimated that almost 24,000 wells were completed last year, mostly onshore unconventional wells. The cost per natural gas well rose 82% in real terms from 1992 through 2002, and the cost of a gas well per foot rose 41% during the same period. The cost for operating shallow water jack up rigs more than doubled in two years, costing $20,000/day in 2002 and $50,000/day at the end of 2004.

"So the bottom line [is] it's costing a lot more to extract this natural gas. The fields have become much more mature. And the finds [have] become much...smaller than we saw in the past," Blount said. "Our expenses as producers are up substantially."

He noted that producers' capital outlays for U.S. upstream projects were expected to be $65.9 billion this year, up from $62.3 billion in 2004 and $56 billion in 2003. The larger capital budgets reflect the higher costs to produce natural gas and the expansion of drilling efforts.

Natural gas reserve replacements in the Lower 48 have risen significantly, from 158 Tcf of dry gas in 1999 to 181 Tcf in 2003. Based on a study, the American Gas Association estimates that replacement reserves rose another 12% in 2004, bringing total replacement reserves to 183 Tcf at year's end.

Blount said as much as 40% of the Lower 48 technical resource base is in unconventional, tight gas shale and coalbed methane (CBM). He pegged the total U.S. gas reserve base at 1,200 Tcf, which he noted was "more than enough gas to last 60 years" at the current production and demand rates.

On top of production activities, he noted that U.S. producers are investing billions of dollars to construct liquefied natural gas (LNG) import terminals. Blount estimated that companies will have to invest about $44.5 billion just to obtain 6.2 Bcf/d of incremental imports by 2010. This would include $2.5 billion for U.S. terminals, $18 billion for LNG tankers, $13 billion for liquefaction plants, and $10.8 billion for gas field development, processing and transmission facilities.

He further noted that producers have taken on "very large risks" associated with the construction of the $20 billion long-line pipeline from Alaska's North Slope to the Lower 48 states.

In Canada, natural gas activity is not as high as it was during the 1990s, but the potential for gas still is there, said CAPP Chairman Ross Douglas, who is president and CEO of Mancal Energy Inc. "The rumor of our death...is greatly exaggerated." There still is a lot of conventional natural gas to be found in Western Canada, he noted.

It's estimated that while 146 Tcf of conventional gas has been produced in the Western Canadian Sedimentary Basin, there still are 144 Tcf of conventional resources remaining in the basin, Douglas said. In addition, he noted that 167 Tcf of CBM resources exists along with 70 Tcf of conventional resources in northern Canada, Douglas said.

He noted that Western Canadian gas production rose by more than 200 MMcf/d in the first quarter of 2005 over last year. The Canadian Energy Research Institute has pegged Canada's productive capacity at between 6 Tcf/year and 7 Tcf/year, and expects it to exceed 8 Tcf/d year by the year 2014.

Douglas further pointed out that while the CBM resource potential of Canada and the U.S. are about the same (167 Tcf for Canada, 169 Tcf for the U.S), the CBM production in Canada (55 Bcf/year) is far below that of the United States (1.6 Tcf/year). That means Canada has far more CBM reserves still to be tapped than the U.S., he said.

Canada drilled only 3,300 CBM wells in 2004, but it expects to almost double this rate by 2010, according to Douglas.

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