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EOG CEO: Barnett Gas Volumes to Peak in 2009, Plateau by 2011

The Barnett Shale's natural gas production should peak in 2009 at around 5 Bcf/d and plateau in 2010 and 2011, which will require exploration and production (E&P) companies to look for new North American resource plays, EOG Resources Inc. CEO Mark Papa said last week.

The remarkable North Texas gas shale play, which currently is pumping more than 4 Bcf/d, has transformed the North American energy industry, and EOG has been a big part of the success. EOG, whose focus is in Johnson County, TX, estimates the total net reserve potential of its 650,000 net acres is 5.0-7.2 Tcfe. The Houston-based producer's proved reserves in the Barnett at the end of 2007 were 1.4 Tcfe.

"The point I would like to make is that in a lot of analysts' minds, the Barnett Shale, which has been far and away the biggest single growth driver in the last three or four years, people believe the Barnett Shale will continue to grow in depth year after year," Papa said during a conference call to discuss quarterly earnings. "Our view is that the Barnett Shale, as aggregate, has one more year of decent growth, [and] that's 2009."

Papa's assertion about when the Barnett may peak were discounted by Chesapeake Energy Corp. CEO Aubrey McClendon during a conference call Friday (see related story).

By the end of next year, Papa said Johnson County's shale gas "will be pretty well drilled up by all operators...and it will remove a lot of the thrust...There will continue to be drilling in Tarrant [County, TX], but that's urban and limited...People who are viewing the gas macro for 2009 and later ought to assume that the Barnett is not going to be the big driver except for one more year."

Papa's comments triggered several questions from energy analysts during the conference call.

"A lot of people say to me, 'Why can't you go in and refrac, drill on 15-acre spacing?' We believe that particularly in Johnson County, refracs are not likely to work, and we're not going to get a big surge from that," Papa said. "We believe drilling the wells on more concentrated spacing also in our view won't work in the Barnett in Johnson County. It's a one-time shot, and until we get some new technology that I'm not aware of, it's not likely."

Well known for offering an unvarnished view of the North American gas macro outlook, Papa also offered a cautious outlook about the commercial potential for two of the big emerging shales now getting a lot of press: the Appalachian Basin's Marcellus Shale and the Haynesville Shale, which spreads across East Texas and northwestern Louisiana.

"We have 100,000 net acres there in the Haynesville," he said, "but I can't opine about the efficacy of this play." EOG's legacy land position is "a pretty good spread. The acreage is in areas that other companies see as prospective. We just have no firsthand results ourselves about Haynesville. The big argument in the industry is whether Haynesville is a really big play, a localized play...We will stay out of that argument until we get data on our own."

EOG's Marcellus Shale leasehold is around 220,000 net acres. One rig is operating now, and some results are expected by the end of the year.

"If it works," Papa said of the Marcellus, "it will be a very slow developing play because of the infrastructure...It won't contribute to the macro gas supply until 2012-plus." EOG is "not chasing any additional acreage up there at this time. What we are seeing, though, is guys on the sell side well aware...and resource costs on first movers' acreage costs have gone up dramatically. What we're doing is trying not to take the 'hot' plays per se."

EOG's Loren M. Leiker, senior vice president of exploration, explained the company's hesitancy about the Marcellus Shale.

"We're more measured than others on the play because the thickness is less than the Barnett," Leiker said. "It's good quality rock, it's well distributed over broad areas...It's a thickness issue, a pressure issue. The most unknown risk factor is frac efficacy. The kind of results we're hearing about in parts of the play, 3-4 Bcf a well doesn't work well with the kinds of IPs [initial production] we're seeing in the rest of the play. We're seeing 1-2 Bcf/d per well. It's hard to average 3-4 Bs across the play...There are differences in frac barriers throughout the play, geographic areas...that's the biggest unknown."

The Marcellus "rocks are considerably thinner than the Barnett," Papa added. "The average IP in Johnson County [Texas] is not 3-4 Bcf a well. It's less than that...It just doesn't make much engineering resource sense when we're not getting that in Johnson County...It's unrealistic. Clearly, we do have a problem with containing fracs, more of a problem in the Marcellus than we do in the Barnett. That's another reason for caution."

The EOG management team was more enthusiastic about early results from its Horn River Basin gas operations in British Columbia. Gas sales are under way from two wells that recently ramped up; a third well is expected to go online within the next two weeks. Because of a lack of infrastructure, however, EOG expects to be limited to producing 35-50 MMcf/d "until we are at full capacity in 2011," said Papa.

Even with some expected declines from its gas operations in the Barnett region, EOG has a lot of firepower still to be unloaded across its oil and gas operations. On the horizon is an emerging oil play in the Barnett, which is expected to become a "2009 event," and strong production from the Bakken Shale, also an oil play, in Wyoming, said Papa.

"In addition to the Bakken and other resource plays, we're also developing new resource plays," said Papa. "I'm very confident of our company's strategy. We don't have to capture any more assets to be assured of strong production growth well beyond 2010. These are home-grown assets," and EOG is "well set up" to generate 13-15% production growth in 2009 and 2010 without buying anything.

"I've watched a lot of companies' strategies over the course of this year, and there's seems to be lot of companies paying premium prices for acreage in hot areas, producing properties in hot areas," said Papa. "We have stepped back, looked at the inventory we have today, and even if we don't add, we're pretty well set up well past 2010. We just don't see any need to go out and spend literally billions and billions of dollars chasing some of these assets, and it's extremely unlikely we'll do that this year or in 2009."

Asked about the collapse in natural gas prices over the past few weeks Papa said that when prices were around $13/Mcf, "personally, I was wondering why it was up so much. I couldn't see a fundamental supply/demand situation. My sense is, we were overpriced a month ago, and now back in my mind it's about right at $10, $9. It's a more rational price, assuming a normal winter this coming winter."

Predicting the North American gas market "is more difficult because of the big influence of winter weather," the CEO said. "The market is currently balanced, based on the last nine weeks of storage injections..." EOG expects the heating season storage to begin at 3,300-3,400 Bcf, "a little bit lower than last year, but not much lower and then it's really kind of a weather call. If it's normal weather or cold, as an E&P [exploration and production] company, we'll be very happy with $9 gas. If it's an extraordinarily hot winter, the whole sector may be disappointed in gas prices."

EOG reported 2Q2008 net income of $178.2 million (71 cents/share), compared with 2Q2007 net income of $306.1 million ($1.24). The latest results included a loss of $843 million ($542 million or $2.16/share) for mark-to-market transactions. Cash flow was $138.1 million.

U.S. natural gas volumes in the quarter rose to 1,139 MMcf/d from 960 MMcf/d for the same period a year ago. Canadian gas volumes fell to 215 MMcf/d from 232 MMcf/d. Including Trinidad and volumes from the United Kingdom, EOG's gas volumes in 2Q2008 rose to 1,583 MMcf/d from 1,464 MMcf/d in 2Q2007.

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