By Edward Klump – Mar 22, 2012 7:00 PM CT
Energy companies in search of oil riches rivaling the biggest finds from Brazil to Angola are flocking to Texas shale, where new wells have triggered a 230- fold increase in crude output in three years
More than 115 years after a gusher 55 miles (88 kilometers) south of Dallas ushered in Texas’ first oil boom, U.S. producers such as ConocoPhillips and Marathon Oil Corp. (MRO) are counting on the Eagle Ford Shale to boost crude output amid a glut-driven slump in natural-gas prices.
Drilling for oil in the brush-covered plains of south Texas is cheaper and less risky than exploration offshore Brazil, the largest oil find in the Western Hemisphere in 30 years, and more profitable than the remote, rougher terrain of the Bakken Shale in North Dakota and Montana.
“The Eagle Ford is the top basin we have in the world today,” David Roberts, chief operating officer at Marathon Oil, told analysts and investors on a conference call last month.
Surging production in shale formations has transformed the U.S. energy landscape, flooding the market with gas and boosting domestic oil production by 14 percent from three years ago after dropping by a third in the previous 17 years, according to Energy Department data. After worries of a global oil shortage drove prices to record highs above $140 a barrel in 2008, politicians and industry executives now are discussing the prospect of the U.S. weaning itself from dependence on imports.
Marathon Oil and ConocoPhillips (COP) both plan to double their production in the Eagle Ford this year. EOG Resources Inc. (EOG), based in Houston, calls the Texas shale play its biggest source of growth, and last month boosted its estimated recoverable reserves there by 78 percent.
Oil production in the Eagle Ford jumped almost sevenfold in 2011 to surpass 30 million barrels, still less than Bakken production in North Dakota that exceeded 128 million barrels. This year daily oil production in the Eagle Ford is forecast to expand by 200,000 barrels, roughly the same amount as the Bakken, according to estimates by Wood Mackenzie Ltd. cited by Hill Vaden, an analyst with the industry consultant.
The South Texas oil fields are winning a larger portion of producers’ investment because it’s easier and more profitable to drill there compared to many prospects in the U.S. and in the world. Wells are faster and cheaper to develop, and the formation is located closer to refineries on the U.S. Gulf Coast, lowering transportation costs.
EOG said it costs about $5.5 million per well in the Eagle Ford, compared with more than $8 million per well in the Bakken, because of different well configurations. An offshore Gulf of Mexico well can cost $100 million, said Brian Uhlmer, an analyst at Global Hunter Securities LLC in Houston.
Deep-water wells can take five months or longer to drill, compared to a couple of weeks for a well in the Eagle Ford, said Brian Cain, a spokesman for Anadarko Petroleum Corp. (APC)
Producers can get a higher price for their Eagle Ford output than they can in the Bakken. Prices for Texas and Louisiana (USCRLLSS) crude this week are as much as about $38 a barrel more than production in the Bakken (USCRLLSS), according to data compiled by Bloomberg.
“The economics there are absolutely stellar,” said Danny Brown, a general manager who helps oversee Anadarko’s Eagle Ford operations. Anadarko has said it is considering selling its exploration properties offshore Brazil.
Less Political Risk
Texas provides a more stable investment environment compared to many international projects, said Pavel Molchanov, an analyst at Raymond James & Associates in Houston.
“Clearly, there’s less political risk in Texas than in Libya, let’s say, or Kurdistan,” he said. Marathon Oil last year had output suspended in Libya during unrest in that country.
The Eagle Ford cuts across a 400-mile swath of southern Texas, according to the Railroad Commission, which regulates oil and gas production in the state. Producers have unlocked the resource using advances in horizontal drilling and hydraulic fracturing, which sends jets of water, sand and chemicals underground to break up rock.
Petrohawk Energy Corp., acquired by BHP Billiton Ltd. (BHP) last year, first drew attention to the Eagle Ford when it announced a gas find in 2008, a year when futures for the fuel in New York averaged more than $8 per million British thermal units.
Expanded use of fracturing, or fracking, across the U.S. caused a surge in gas output that drove prices to a 10-year low this month of $2.204 per million Btu. Meanwhile, crude in New York has climbed 15 percent since the end of 2010 and is trading for about $105 a barrel.
The Eagle Ford will help lead a surge in state drilling permits that’s on pace to reach 25,000 this year, the most since 1985, said Barry Smitherman, the commission’s chairman.
“It’s by far the most sought-after play anywhere — not only in this country, but anywhere around the world,” said Fadel Gheit, an analyst at Oppenheimer & Co. in New York.
A Sanford C. Bernstein report last August estimated Eagle Ford production would reach 1.2 million barrels of oil equivalent a day in 2015, with 750,000 of that being liquids.
“A long-time oil field axiom is that big fields tend to get bigger over time, and that’s certainly the case here,” EOG Chief Executive Officer Mark Papa told investors during a Feb. 17 conference call. “This continues to be the hottest and highest reinvestment rate-of-return play in North America.”
To contact the reporter on this story: Edward Klump in Houston at firstname.lastname@example.org
To contact the editor responsible for this story: Susan Warren at email@example.com
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By Joe Carroll
Exxon Mobil Corp. (XOM)’s failed shale-gas wells in Poland may hobble the nation’s effort to become one of the world’s major energy sources and dismantle Russian dominance of Eastern European natural-gas markets.
Exxon, the world’s largest energy company by market value, said two exploratory wells drilled in a Polish shale formation last year weren’t commercially viable. The gas discovered in the wells, Exxon’s first in Poland, failed to flow in sufficient quantities to justify bringing them into production, David Rosenthal, vice president for investor relations, said during a conference call yesterday.
International energy prospectors, including Marathon Oil Corp. (MRO), Chevron Corp. (CVX) and Talisman Energy Inc. (TLM), are probing Poland’s shale deposits to see if drilling techniques that revolutionized U.S. gas production can unleash reserves big enough to supply Polish demand for more than three centuries. Exxon’s setbacks suggest Poland’s shale poses unique challenges that may increase costs and delay output, said Gianna Bern, founder of Brookshire Advisory & Research in Chicago.
“Shale exploration is a very high-cost and high-risk business and the Polish shale market is still in its infancy,” Bern, who advises major oil companies on risk management and strategy, said in a telephone interview yesterday. “It’s early in the game for Poland, and they have significant potential reserves over there.”
Poland’s shale formations hold 187 trillion cubic feet of recoverable gas, according to an April 2011 assessment by the U.S. Energy Department. Those resources are 32 times larger than the country’s conventional gas reserves and enough to supply domestic consumption for 322 years.
For Poland, successfully unlocking gas from shale would be a boon to domestic manufacturers and power producers by diminishing the need for Russian imports that now supply two- thirds of demand, said Benjamin Schlesinger, president of Benjamin Schlesinger and Associates Inc., a Bethesda, Maryland- based adviser to gas producers, utilities, regulators and financial-services firms.
Poland’s dominant gas company, Polskie Gornictwo Naftowe i Gazownictwo, pays Russia’s state gas company Gazprom OAO (GAZP) $500 for 1,000 cubic meters ($14.16 per million British thermal units) of gas. That’s six times the benchmark U.S. price for the fuel.
“Poland’s shale resources are enormous,” said Schlesinger, a Stanford University-trained engineer who helped the New York Mercantile Exchange design its gas futures contract. “Poland should be able to capture a good deal of those resources and reduce reliance on the Russian Federation.”
Gazprom’s depositary receipts rose 2.5 percent to $12.40, the highest closing price since Oct. 28. The London-listed receipts each are worth two ordinary shares in the Moscow-based company.
Exxon’s failures followed disappointing results at Polish wells drilled last year by 3Legs Resources Plc and BNK Petroleum Inc. (BKX) London-based 3Legs’s Lebien well and BNK’s Lebork well flowed at lower rates than similar prospects in the Barnett and Fayetteville shale regions in the U.S., Sanford C. Bernstein & Co. said in a Nov. 10 note to clients.
“Poland is cited among Europe’s best shale prospects, but Exxon’s result supports our caution on achieving material near- term volumes,” Oswald Clint, a London-based analyst at Bernstein, said in a note today.
Even so, it may be too early to draw any firm conclusions from Exxon’s drilling failure, said Pawel Poprawa, who specializes in shale at the Polish Geological Institute in Warsaw.
“If we look at the experience from the U.S. or Canada, no single well can provide the answer if the basin has potential or not,” he said. “Low flows seem to be a technological problem.”
Marathon Oil said today that it’s evaluating data after finishing its first well in a Polish shale formation. The Houston-based company said in a statement that it intends to drill three more wells during the next few months and withdraw rock samples for testing. Marathon plans a total of six to seven Polish shale wells this year, according to the release.
The Polish shale results come after Exxon encountered a dry hole in Hungary in late 2009 drilled in a tight-sand deposit similar to shale. Exxon walked away from the $75 million project after striking more water than gas.
Exxon and other major North American energy producers have been lured to explore shale prospects from Germany to Argentina after largely missing out on the boom in shale extraction in the U.S. that began in the middle of the last decade.
Smaller explorers such as EOG Resources Inc. (EOG), Chesapeake Energy Corp. (CHK) and Range Resources Corp. (RRC) came to dominate the U.S. shale industry by default as the biggest international companies focused on locating billion-barrel offshore crude fields in places like the Gulf of Mexico and West Africa.
Shale formations were ignored by much of the energy industry for most of the past century because the rocks were considered too hard to crack using traditional drilling techniques. That began to change in the late 1990s with the development of new horizontal drilling practices and more- intensive hydraulic fracturing that succeeded in unlocking gas and crude from shale and similarly dense geologic deposits.
‘Attractive Fiscal Terms’
Exxon sought to jump-start its shale program in June 2010 with the $34.9 billion acquisition of XTO Energy, a Fort Worth, Texas-based pioneer of shale development. In addition to shale wells and undrilled prospects that stretch from the Mexican border to Canada, Exxon wanted to transfer XTO’s in-house expertise to foreign shale fields.
Exxon hasn’t disclosed its plans for further drilling in Poland. The shares rose 0.3 percent to $83.97 at the close in New York.
Poland has led European shale exploration by virtue of its tempting geology and by offering “attractive fiscal terms” to prospectors, the Energy Department in Washington said in a September report.
Still, a “likely aggressive tax burden” to be imposed on shale-gas producers may damp investor enthusiasm, analysts at Bank Zachodni WBK SA, based in Wroclaw, Poland, said yesterday in a note to clients.
Polish drilling also has been hindered by a scarcity of rigs, water and specialized equipment needed for shale wells, Bern said.
“Getting the things you need to drill these wells is much more difficult in Poland than in the United States, where the shale industry is very well-developed,” Bern said.
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