The adjectives used to describe the Barnett Shale play — “prolific,” “gas-rich,” “abundant” — may have, at times, seemed superfluous. But the simple language EOG Resources Inc. CEO Mark Papa used last week to describe his take on the Texas play may be the most descriptive: “bigger than we expected.”
The Barnett field, now second only to the San Juan Basin in New Mexico, appears to extend much farther south and farther to the west than previously estimated, Papa told investors and energy analysts last Wednesday.
EOG, he said, began applying its savvy horizontal drilling techniques to some of the company’s leasehold in noncore formations and discovered something interesting. Outside of the Barnett core, generally considered to be the Fort Worth Basin, horizontal drilling, which begins vertically and then bends parallel to the surface, parlayed into more gas reserves. So sure was EOG’s management team about the bonus from the horizontals, it added 103,000 more acres about 55 miles south of the core holdings in Johnson County.
The new Hill, McLennan and Bosque county acreage, in the “heart” of Texas, has extended EOG’s total Barnett leasehold to more than 600,000 acres. Already, said Papa, the Hill County wells are producing “substantially” more gas when compared with the Johnson County wells.
“EOG’s previous net reserve potential in the Barnett Shale was 3,000 to 4,700 Bcfe,” said Papa. “We’ve increased our estimate by 1,500 to 2,000 Bcfe…and our current estimate is now 4,500 to 6,700 Bcfe.”
Several things are driving EOG’s increased Barnett production expectations: Johnson County downspacing added 500-700 Bcfe net; discoveries in Hill County and additional acreage in its “southern extension” counties added another 800-1,300 Bcfe net; and increased acreage in its “western extension” counties added 200 Bcfe net. By the end of this year, Papa said, EOG’s estimated year-end exit rate in the Barnett will be around 200 MMcfe/d. A year from now, EOG estimates its Barnett output will be around 280 MMcfe/d.
“We have a step change in service agreements that we’ve secured in 2007,” he said. EOG’s new drilling rigs sport new technology, making them “significantly faster and cheaper.” It also has fractionation agreements in place to reduce costs and increase the number of wells completed. “We are applying new technology, with improved well design and cost optimization in all phases of our drilling, completion and production operations…which continues to improve our well performance and reduce costs.”
Canaccord Adams energy analyst Irene Haas, who has covered the Houston-based producer for several years, said EOG always backs up its claims with substantial data.
“This is pretty solid news,” Haas told NGI last week. “They are doing something right. EOG has excellent 3-D [seismic] data. They understand the rock properties, and they have a whole lot more data than people think.
“They have kept really quiet on the Hill County exploration. They had some 3-D, they had some expression. And now EOG has got it locked up. It is at the cutting edge.”
Like other shale exploration, successful technology is key, said Haas. “When you crack the code, the risk is lower. This bodes really well for other onshore activities by a lot of other companies.”
Eric Potter, associate director of the Bureau of Economic Geology (BEG) at the University of Texas, Austin, said seismic data and engineering have always driven shale exploration — especially the elusive Barnett. All producers say the same thing: every Barnett well is different.
“We have never produced so much from something about which we know so little,” Potter said.
The BEG is studying what comprises the Barnett’s pore networks, its natural fracture networks and its interaction with frac treatments. Because the shale has similar characteristics to a reservoir that is also its own source rock, it’s a play unlike any other. “The closest thing we have to a reservoir that is also its own source rock is coalbed methane,” said Potter.
The Barnett’s unique characteristics propelled most of the latest microseismic technology, Potter noted. This “significant tool” tells geologists what the well spacing should be and how far a frac job goes. What challenges shale operators, he said, is that all shales are not alike. They are not alike within one well and there are basin-to-basin differences.
Haas noted the growing interest in shale plays follows a similar trend in studying coalbed methane, which awakened unconventional gas exploration in the late 1990s. Besides the Barnett, the more established shale plays include the New Albany Shale in the Illinois Basin (productive since the 1850s), the Ohio Shale of eastern Kentucky (productive since the 1920s); and the Antrim Shale in Michigan (productive since the 1940s).
“In addition to these established plays, we are seeing a proliferation of ‘clones,'” Haas said. These clones include the Barnett noncore extension, as well as the Fayetteville Shale in Arkansas and the Woodford Shale in Oklahoma. Still others are emerging, she noted: the Floyd Shale and Conasauga Shale in Mississippi, and the Bend Shale in the Palo Duro Basin of North Texas.
“In our view, we could see a revival of shale gas production in the Appalachian Basin if the economic conditions are right,” said Haas.
EOG’s Papa said horizontal drilling will make it happen.
“The macro view is that about 10% of all wells drilled onshore now are horizontal wells,” Papa said. “Over the next five years, we think that figure will go to 30%…to 35%. Resource plays can be developed a lot more intensely through horizontal drilling. Some wells are not amenable to vertical wells, but they are amenable to horizontal wells. Those are the types of plays we’ll be going after.”
EOG is not tying all of its success to the Barnett.
The producer is testing several “stealth” plays, including conducting some horizontal drilling techniques on a leasehold in South Texas. Papa said last week EOG has located about 500 Bcf of gas in sandstone at an undisclosed location there. For the cost of a vertical well in South Texas, Papa said EOG is extracting about .5 Bcf. At twice the money for a horizontal well, EOG is able to extract 3 Bcf.
EOG also is exploring another stealth shale play in West Texas, he said. The company also wants to accelerate development of its Mesaverde legacy properties in the Uinta Basin of Utah. Based on recent pressure and core-testing data, EOG plans to increase drilling activity in the area on 20-acre spacing between wells, with the ultimate potential to go to 10-acre spacing. EOG may have more data on some of those plays in February.
The producer’s organic assets alone remain on track to achieve 9% growth in its oil and natural gas output this year, Papa said. In 2007, EOG is targeting 10% growth. Annual production growth between 2008 and 2010 is expected to range between 7% and 11%.
“We’re very unlikely to pursue mega-acquisitions,” Papa said. “About 90% of our budget this year went toward organic, and it will likely be the same in 2007. We never had the goal to be the largest E&P [exploration and production] company. We never bought into the super-independent, the mega-independent. We’ve had two goals. One was to always have the best profit metrics. The second goal was to have the best long-term equity performance. Since 1999, we’ve achieved both goals.”
EOG’s capital spending in 2007 will jump to $3.4 billion, excluding acquisitions, from $2.8 billion this year. About one-third of the increase will be directed for service cost increases, but most of the boosted spending will go toward expanded drilling programs, Papa said.
In a note to clients, energy analyst John Gerdes of SunTrust Robinson Humphrey/the Gerdes Group, wrote, “Assuming that [EOG’s] North American liquids, Trinidadian and UK production remain constant, this guidance implies ’07 North American gas production growth of 15.8%. Notably, we forecast ’07 North American gas production growth of 18.8% and are unlikely to change our expectation as we view this updated guidance as positive and modestly conservative.”
Haas noted that EOG has done most of its growth organically. “They don’t need any acquisitions,” she said. But she admitted that its substantial success makes it an attractive takeover candidate.
“Look, today, anything onshore domestically is free game,” said Haas. “Look at Western Resources…Kerr-McGee [bought earlier this year by Anadarko Petroleum Corp.] I don’t think EOG would mind being sold, and Mark [Papa] would agree this would be for the shareholders’ benefit. But the bigger companies, they don’t have the agility, the same mindset, the management, in particular.”
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