It looks like some of the un-drilled acreage leased by EOG Resources in the western side of the Eagle Ford Shale may be next on the list to get drilled. Rather than let leases expire, the company indicated in a recent conference call that it will shift some of the rigs that are currently drilling in the more productive east toward the western side of the play. EOG has reported completing some “monster wells,” in the east, such as the Boothe #10H in Gonzales County. The Boothe #10H IP-ed at 4,820 barrels of oil per day and 7.5 MMcfd of rich gas. In EOG Resource’s most recent earnings conference call, dated August, 2, 2012, chairman Mark Papa indicated that the shift of rigs toward the west was primarily to hold acreage.
- Shale oil gamble has EOG sitting pretty (fuelfix.com)
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 email@example.com
To contact the editor responsible for this story: Susan Warren at firstname.lastname@example.org
- Pioneer Bets On West Texas Shale Oil To Rival Bakken (mb50.wordpress.com)
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By MARILYN ALVA, INVESTOR’S BUSINESS DAILY Posted 01:41 PM ET
U.S. oil production is enjoying a renaissance, thanks to new technology that has made oil recovery possible in tight shale rock.
The Eagle Ford in South Texas and the Barnett “combo play” (gas and oil) in North Texas are also fairly famous unconventional plays.
But the Wolfcamp Shale?
“Over the next two or three years, everybody is going to be making a beeline to the Wolfcamp,” said Scott Sheffield, chief executive of Pioneer Natural Resources (PXD).
Spanning numerous counties across West Texas, the Wolfcamp formation is located below the long-plied Spraberry field, which helped make Midland, Texas, oil-central starting in the early 1950s.
Its location in the Midland Basin is within the larger Permian Basin.
Sheffield and other oil experts say the Wolfcamp is probably the thickest of any onshore U.S. oil shale play, with up to 1,000 feet of potential payout across hundreds of thousands of acres.
Biggest And Thickest
“It will be the biggest, and it is already the thickest,” Sheffield said. “So it’s got the most pay zones of any oil shale play in the U.S. I call it the third or fourth coming of the boom in West Texas.”
If Wolfcamp does turn out to be the next big oil shale play, Pioneer is on the ground floor. With 900,000 acres under lease in the Spraberry, it has the largest land position.
Pioneer believes that more than 400,000 of those acres are ripe for horizontal drilling.
Its game plan: drill 10,000 feet down through the Spraberry to the Wolfcamp and then out 7,000 feet horizontally.
For now, it’s targeting 200,000 acres in the southern portion of the Spraberry field.
Pioneer’s two completed wells in the Wolfcamp have already exceeded expectations, each producing 800 to 1,000 barrels of oil a day, and they’re still early in production.
EOG Resources (EOG) started drilling in the Wolfcamp earlier and is now seeing higher output from its 35 or so wells.
But Sheffield says Pioneer will be a bigger operator in the Wolfcamp in the sense that it has 400,000 prospect-worthy acres to EOG’s 100,000.
“We are going to drill 80 wells in 2012 and 2013,” he said.
EOG’s wells in the Wolfcamp are producing 2,000 barrels a day, says Dan Morrison, analyst with Global Hunter Securities.
“Even if Pioneer’s don’t get to 2,000 barrels a day, at 800 barrels a day the play is incredibly economic,” Morrison said.
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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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- Halliburton: Moving Quickly on the Global Shale Boom (mb50.wordpress.com)
- Seven People Have Been Charged With Corruption Over Shale Gas Exploration In Poland (businessinsider.com)
- Fracking Coming To Poland, Schlumberger Stock Going To $101 (forbes.com)
Kitimat LNG partners Apache Canada Ltd. (Apache Canada), EOG Resources Canada Inc. (EOG Canada) and Encana Corporation (Encana) has announced that the National Energy Board (NEB) has granted Kitimat LNG a 20-year export licence to ship liquefied natural gas from Canada to international markets.
”The Kitimat LNG project represents a remarkable opportunity to open up Asia-Pacific markets to Canadian natural gas and we’re leading the way in being able to deliver a long-term, stable and secure supply to the region,” said Janine McArdle, Kitimat LNG President. “This export licence approval is another major milestone for Kitimat LNG as we move forward and market our LNG supply. LNG customers can have even more confidence in a new source of supply.”
“Today marks a historic day for Canada’s natural gas industry and this is fantastic news for our project and the communities where we operate. Kitimat LNG will bring revenues and jobs and the associated benefits to Canada,” said Tim Wall, Apache Canada President. “The Kitimat LNG partners are very pleased with the NEB’s approval of our export licence and we’d like to thank them for their support and confidence in the project.”
The facility will be served by Pacific Trail Pipelines Limited Partnership’s natural gas pipeline which will run from Summit Lake to Kitimat. The 463-kilometre underground line will provide the terminal with a direct connection to the Spectra Energy transmission pipeline system and excellent access to natural gas supplies in British Columbia.
Kitimat LNG is currently carrying out a Front End Engineering and Design (FEED) study which will provide certainty around project design, construction timelines and costs and labour force requirements. The FEED study is expected to be complete by early in 2012 followed by a final investment decision by the partners.
About the Kitimat LNG facility and the PTP Pipeline
Apache Canada, EOG Canada and Encana plan to build the Kitimat LNG facility on IR#6 Bish Cove, approximately 650 kilometres (400 miles) north of Vancouver. The facility is planned to be built on First Nations land under a unique partnership with the Haisla First Nation. The initial phase of the facility has a planned capacity of approximately 5 million metric tonnes of LNG per annum or the equivalent of nearly 700 million cubic feet per day. PTP is planning to build a 463-kilometre (287-mile), 914-mm (36-inch) diameter underground line from Summit Lake, B.C. to Kitimat. Pacific Northern Gas Ltd. (PNG) will operate and maintain the planned pipeline under a seven-year agreement with Apache Canada, EOG Canada and Encana, with provisions for five-year renewals.
- B.C.’s Kitimat LNG terminal wins export licence (theglobeandmail.com)
- Kitimat LNG export licence gets regulatory approval (calgaryherald.com)
Encana Corp. foresees a “renaissance” in natural gas prices once terminals begin to pop up along the West Coast to export the fuel to energy-hungry Asian markets, but others addressing an energy conference on Tuesday weren’t quite so enthusiastic.
“We think that the prices are going to stay robust in Asia. You look today in Japan, it’s still $13 US (per 1,000 cubic feet) over there,” Mike Graham, who heads up Encana’s Canadian division, told the Peters & Co. event.
“In three to five years, when LNG really starts to pick up in North America, I think you’ll see another renaissance in natural gas prices.”
The huge supplies of gas flowing out of shales throughout North America have been landlocked for some time, resulting in a major supply glut that has kept prices in the anemic $4 range US.
One of the ways Encana Canada’s largest gas producer, seeks to remedy the situation is to tap into Asian markets. It, along with U.S. partners Apache Corp. and EOG Resources Inc. are planning to build a liquefied natural gas terminal in Kitimat, B.C.
There, gas piped in from northeastern British Columbia will be converted into a liquid in extremely cold temperatures. In a liquid state, the liquefied gas, or LNG, can then be loaded onto specialized tankers and sent overseas.
“China is going to consume just about all the natural gas that the world can give them. They’ve only got maybe (one billion cubic feet per day) of LNG now, but they’re looking to put in 10 and even grow from there,” said Graham.
“I think it’s going to be very robust. I think it’s going to have a tendency to pull oil prices down, and have a tendency to pull natural gas prices up. It does look quite likely that maybe a few years outbound, I think the forward curve will start to reflect LNG over the next couple of years and things will get a bit more robust soon.”
John Langille, vice-chairman of Canadian Natural Resources Ltd. (said he’s not quite so gung-ho.
“I’m not quite as bullish, I don’t think, as some of my peer group here in terms of what time-frame,” he said.
Canadian Natural has a large land position in northeastern B.C.’s shales, but has been focusing most of its attention on developing oil- properties in Western Canada and abroad. It has signalled no interest so far in jumping aboard the LNG bandwagon, though Langille said eventually the gas will have to find its way out of North America.
“And that will happen, but it’s a five-year scenario before that happens,” he said.
John Dielwart, chief executive officer of Arc Resources Ltd. said he sees prices recovering, but to a somewhat underwhelming extent.
“Where we thought we might get back to $6, $7, maybe $8 gas a couple of years ago, now we’re saying $6 will be a pretty good price,” he said.
“So I think the level at which gas prices might recover, I would say, has been tempered in many of our views. But the ability to stay where we are now for an extended period of time, year after year after year, I just don’t think that’s on the table.”
But Dielwart said he’s optimistic about demand growth. In Arc’s own backyard — Alberta — more and more power plants are making the switch from carbon-spewing coal to natural gas.
An in terms of LNG, Asian countries are most interested in gas from B.C. because the travel distance across the Pacific is so much shorter than from the Middle East, for example.
“We certainly haven’t done any joint ventures, but we certainly talked to a lot of parties who are coming through Calgary. I would say the traffic has increased in the post-Fukushima world,” said Dielwart, referring to the March disaster at the Fukushima Dai-ichi nuclear power plant in Japan.
“I think it’s only going to become a growing and growing story and LNG will be going to Asia out of northeast B.C. in the not too distant future.”
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