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Energy: Texas Tops Finds From Brazil to Bakken as Best Prospect

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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.

Doubling Down

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.

Higher Prices

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.

Surging Production

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.

While drilling has slowed in U.S. shale gas fields such as the Fayetteville in Arkansas, development has accelerated in South Texas as producers focus on the formation’s oil-rich geology.

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 eklump@bloomberg.net

To contact the editor responsible for this story: Susan Warren at susanwarren@bloomberg.net

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Pioneer drilling buys Go-Coil for $110 mln (San Antonio, TX)

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By Mia Lamar

Pioneer Drilling Co. PDC +6.41% has acquired a privately held provider of coiled tubing services for roughly $110 million in cash, a purchase the company said it expects to add to earnings this year.

The purchase of Go-Coil LLC, whose services are aimed at oil and gas exploration and production companies, helps boost Pioneer’s offerings in its production services division, noted Chief Executive Wm. Stacy Locke.

“After studying coiled tubing for the past couple of years, we believe this new service offering has expansion opportunities as well as cross-selling opportunities with our existing business,” Locke said.

Go-Coil operates a fleet of 10 coiled tubing units, seven of which are onshore units. Current operations are located in Louisiana, South Texas, Oklahoma, and Pennsylvania.

Pioneer, which provides contract land drilling services to oil and gas operators, in November reported it swung to a third-quarter profit with help from a 38% jump in revenue.

Shares closed Friday at $9.68 and were inactive in premarket trade. The stock is up 51% in the past three months.

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Top 5 Rigzone Articles of 2011

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Consider this the Grammys for Rigzone (minus the red carpet, celebrities, movies, etc.). A special thanks goes out to our dedicated Rigzone readers for making this a wonderful year for the Rigzone team.

So without much ado, click through the slideshow below to view

Rigzone’s top five most-read articles of 2011.

Energy companies eyeing drones to survey pipelines

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Cara Bayles
Staff Writer

Published: Sunday, December 18, 2011 at 6:01 a.m.
Last Modified: Sunday, December 18, 2011 at 1:24 a.m

New regulatory recommendations expected to be released by the Federal Aviation Administration soon could allow oil-and-gas companies to purchase light-weight unmanned drones akin to those used by the military.

Energy companies already use remotely operated vehicles to monitor and manipulate wells at extreme underwater depths, and unmanned aircraft companies hope that in the coming years, companies will be able to hire or buy aerial drones to survey pipelines, check on hard-to-reach parts of platforms and gather information after an offshore accident occurs.

The current federal regulations were first introduced in 2007, as production and development of unmanned aerial systems began to grow. The proposed regulation changes, which will be released in a few weeks, will be subject to a comment period and review, a process that generally takes 12 to 18 months.

“The concerns about these unmanned aerial systems, whether they’re operating in the Gulf of Mexico or over land, remain the same,” said FAA spokesman Lynn Lunsford. “We want to make sure that they’re used in such a way that the safety of other aircraft is not compromised.”

That could be particularly challenging in the Gulf, where, according to Lunsford, planes and helicopters traveling back and forth to offshore rigs make more than 800 trips per day.

California-based AeroVironment already had agreements with several oil-and-gas companies just before the 2007 regulations were introduced, according to Steve Gitlin a vice president at AeroVironment.

“We’re ready,” he said. “As soon as the FAA says ‘Go,’ we’re ready to provide capabilities to the customers who want it. These aerial systems will save money, save lives and allow for more effective use.”

Lindsay Voss, senior program development manager at the Association for Unmanned Vehicle Systems International, said that the FAA’s longtime complaint is that it needs more data, like a complete picture of the drone accident rate.

“You could say there’s a lot of operational time with Department of Defense,” she said. “We probably have about 6,000 hours a year in Iraq and Afghanistan. But it’s difficult to take that info and apply it to national airspace.”

Voss said several companies that operate in the Gulf of Mexico, including Shell, BP and ConocoPhillips, have expressed interest in the technology.

BP spokesman Daren Beaudo said the company has been an industry leader in developing ways to deploy drone technology for pipeline inspection.

“We have been working cooperatively for over five years with other members of the oil-and-gas industry, the aviation industry and the FAA to enable eventual deployment of drones to assist us in leak and machinery threat detection once (new FAA) regulations are in place.”

Currently, BP and other companies use manned helicopters to survey their pipelines. But helicopters can run about $300 an hour, while renting a lightweight drone can cost as little as $20 an hour, said Voss.

Drone makers say their machinery has a range of applications beyond pipeline surveillance as well.

“The color and infrared video could be very useful if they want to check out the condition of an offshore platform. If there’s a disaster, people tend to be evacuated from a platform, but the operator will still want to have eyes on the target,” said Gitlin. “We’ve done some demos for offshore oil companies in the past and, using infrared, were able to detect oil slick in the water.”

Kevin Lauscher, who does industrial sales for the Canadian company Draganfly Innovations, said that in the past year, he’s already sold some drones that weigh less than 10 pounds for deepwater oil platforms in the Gulf of Mexico.

“They’re used for inspectional purposes. It gives them the ability to more easily view platforms, rather than putting people on cranes or scaffolding as they’ve had to do in the past.”

He attributed the boon in sales to the tightening of federal safety regulations in the past year as a result of the Deepwater Horizon disaster

“Safety has been brought to the forefront as a result of that,” he said.

Voss said that it could be a few years before drones under 50 pounds are flown over domestic waters.

“They’re still at the very beginning of this process,” she said. “It doesn’t look like the rule will be out until 2014. After that, I think we’ll start to see a pick up, but it’s still going to depend on how things go after the agencies put out the rule.”

Staff Writer Cara Bayles can be reached at 857-2204 or at cara.bayles@houmatoday.com.

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USA: ConocoPhillips Allocates USD 14 Billion for E&P in 2012

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U.S. oil & gas  exploration and production company, ConocoPhillips, announced a 2012 capital program of $15.5 billion. The 2012 capital program for E&P is $14.0 billion and includes $2.2 billion for worldwide exploration, $0.4 billion of capitalized interest and $0.7 billion for the company’s contributions to the FCCL business venture and loans to other affiliates.

Approximately 60 percent of the E&P capital program will be spent in North America. This represents an increase in the U.S. Lower 48 and Canada compared with prior years, reflecting improved market conditions, with additional emphasis on liquids-rich resource plays and high-return investments.

Capital spending in Alaska is expected to be slightly down compared to 2011 levels, and will be directed toward development of the existing Prudhoe Bay and Kuparuk fields, as well as fields on the Western North Slope.

In Europe, Asia Pacific and Africa, total spending is expected to be approximately 40 percent of the E&P capital program.

In the North Sea, spending is planned for existing and new opportunities in the Greater Ekofisk Area, the Greater Britannia fields and development of the Jasmine and Clair Ridge projects.

“The 2012 capital program reflects our strategic emphasis on delivering value by investing in the most profitable opportunities,” said Jim Mulva, chairman and chief executive officer.

The company will continue its focus on accessing, testing and appraising material opportunities in both conventional and non-conventional oil and gas plays. ConocoPhillips plans further appraisal of the Poseidon discovery in the Browse Basin, offshore Australia, and the Tiber and Shenandoah discoveries in the Gulf of Mexico. The company also plans to test material prospects in the Gulf of Mexico and Kazakhstan. Delineation of the company’s position in the Eagle Ford shale play will continue, as will pilot programs in shale plays in the Canadian Horn River Basin, Australia and Poland.

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Ironically Texas May Be Forced To Export Unrefined Crude By 2012

The US oil industry is in a bit of a quandary. The Houston & Louisiana refining area is the largest in the world. It has just had tens of billions of dollars thrown at it, to prepare it to run heavy sour sources. These heavy sour grades are typically cheaper, and contain lots of secondary products during the refining process.

In simple terms, we have spent the last twenty years preparing to make more out of lower quality oil. It was a great idea, when the handwriting on the wall said these would be the only real sources of future growth in hydrocarbon volumes.

This is now a problem for some companies, as their own refinery’s need the heavy sour crude’s to fuel these their product runs. What are they to do with a flood of light to super light sweet crude’s?

If they ran this stuff, they would  have to turn off a significant number of units at their refinery’s that are designed to capture and crack the heavy sludge. This leave the US refining patch in a bit of a jam.

The new Eagle Ford shale oil is coming online in large volumes. Rumors are that Eagle Ford production will crack 500,000 barrels by the end of 2012, if they can get around localized shipping constraints.

Right now it is the gathering of the stuff in quantities that are easy to ship/export that is the issue.The crude is so light in some places, they need specialized trucks to collect it and bring it to a gathering location. There isn’t the capacity to pick up the crude and bring it to market available right now.

We are talking about 100,000 barrels of oil production behind pipe right now, and growing daily as people rush to install new smaller capacity pipelines around Texas to help haul it away.

The number of companies that believe they can growth their domestic production by 100,000 barrels of oil in the next couple of years is growing.

The irony is that the new supply is super light & sweet. A mix never expected in the US again.

Platts had an article on this exact topic in June of 2011.

The US could resume exporting some of its domestic crude oil production in 2012 when the output from Eagle Ford Shale in Texas ramps up.

Eagle Ford shale crude’s gravity ranges from 42 API to 60 API with very low sulfur content, which in the US Gulf Coast refining terminology is considered a super light crude.

But that’s the problem for US refiners: they aren’t built to process that type of crude. So the highest value for it may be outside the country.

The US exports may be to the US East Coast first. The refinery’s based on the east coast tend to have a higher sweeter demand over their Southern units.

In fact, the blow out in Brent prices has severely affected their profits due to sourcing costs increasing significantly this spring with the Libya revolution. There have been at least 3 refinery’s put up for sale or being put into mothballs until a cheaper source of crude is available.

“U.S. east coast refining has been under severe market pressure for several years. Product imports, weakness in motor fuel demand and costly regulatory requirements are key factors in creating this very difficult environment,” ConocoPhillips said when it put Trainer on the auction block.

If the three refineries on the block shut down, what does this mean for oil markets?

In the case of the US, if Texas starts to export light sweet crude by large barges to the east coast. You could see a Renaissance in US exports of refined products as these units produce above domestic demand needs.

The irony is that in the US we have removed the demand for the lighter sweet crude’s, so much so we will soon be exporting it from our primary refining center due to excess capacity in supplies. NOT DEMAND.

The energy crisis of 2005 is not the supply crisis everyone was looking for. I wonder how long it will take society to catch up to the new reality. The US is going to become an energy exporter, even if its Texas shipping crude to those Yankees up north.

Before you fall out of your chair laughing, look at this chart, conceptualize it, and then leave me a comment in the section below. I look forward to your thoughts on this chart.

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It’s a chart of barrels of oil produced per year from a specific zone in Texas. It will double every year for the next few. Then think about other new zones like it coming online in the next few years. Its a small amount today, but a not so small amount by tomorrow.

US Shales: Whether its a Revolution of Evolution, Shale Gas Delivers

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Shale gas enhancing energy supply, security

Whether you call it revolution or evolution, one thing is clear: Shale natural gas is producing jobs and economic benefits across the nation.

This week, shale gas was the focus of a major conference in Houston involving industry representatives, government officials and academics who gathered to discuss the technologies and future of this increasingly important source of energy.

For most of the nation, the contributions of shale gas may seem like a revolution. Shale gas has created thousands of new jobs, meant millions of dollars in new government revenues and enhanced energy security for America.

Of course, those of us who work in and around the energy industry understand that shale gas has been more of an evolution than a revolution.

The technologies used to develop these natural gas supplies aren’t new. Our industry began directional drilling in the 1920s, leading to substantial use of horizontal drilling in recent decades. And we have used the process of hydraulic fracturing since the 1940s. In that time, the industry has safely drilled more than a million wells.

The transformative impact of shale gas is challenging us all to think in new ways.

Not long ago many worried about a natural gas supply shortage in the U.S. But as President Obama recently stated, a “century’s worth … [lies] in the shale beneath our feet.” A decade ago gas from shale accounted for less than 2 percent of U.S. natural gas production. Today it is nearly 30 percent and growing.

As our nation considers this potential, we are reminded of the importance of reliable, affordable energy to our economy – especially during challenging economic times. Affordable supplies of natural gas – driven by the increase in shale production – have helped reinvigorate the domestic petrochemical industry, which relies on gas as a feedstock to make plastics and the other building blocks of modern manufacturing. These supplies are strengthening America’s steel industry, which is building new mills and hiring workers to support shale gas drilling. And areas where production of shale oil or natural gas is occurring are experiencing economic growth, job creation, and increased tax revenue.

For instance, in North Dakota, unconventional oil and gas production in the Bakken Shale has provided enormous economic benefits, with close to $5 billion in direct economic activity in 2009. In Texas, a study of the Barnett Shale formation near Fort Worth estimates it is now responsible for $11 billion in annual economic output and more than 100,000 jobs for the North Texas region. And in Pennsylvania, state labor statistics show 214,000 Marcellus Shale-related jobs at the beginning of 2011. Penn State researchers meanwhile calculate that Marcellus drilling could add nearly $10 billion in value to the Pennsylvania economy this year.

We also must not forget that hydraulic fracturing helps our nation reach our shared goals for responsible environmental stewardship. Natural gas produces about 50 percent fewer greenhouse gas emissions than coal when used to produce electricity for consumers and businesses, and significantly reduces other emissions such as mercury, sulfur and nitrogen oxide. It also uses a small fraction of the water used in coal, nuclear and solar power generation processes to produce a barrel of oil equivalent energy.

To ensure economic and environmental benefits continue, the people of the natural gas industry understand that we must remain firm in our commitment to properly manage the risks involved in drilling operations. That means meeting the highest standards of well design and well integrity. It means training our personnel and contractors to ensure adherence to established operating procedures. It means safely and efficiently handling the water and additives used to fracture wells. And it means working with state regulators to ensure protection of water and air quality.

The United States’ shale gas resources are an extraordinary energy endowment for our country, and our industry knows how to produce these resources safely and responsibly. We must keep these facts in mind as the public and policymakers discuss energy policies – and what increased access and technology mean for the energy industry.

With a commitment to operations integrity, wise development of our shale gas can provide new supplies of affordable, reliable energy in a safe, secure and environmentally responsible manner. And the rise of this resource comes at a time when our country – and the world – clearly needs the economic and environmental benefits that natural gas stands ready to deliver.

Mark W. Albers is a senior vice president at Exxon Mobil Corporation.

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Alice considers building multipurpose convention center amid Eagle Ford boom

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By Mark Collette

ALICE — For a city that always has lived and died by the oil field, life is good right now.

Flush with cash generated from sales and hotel occupancy taxes — all bringing in money associated with the oil and gas boom — the town is planning something most South Texas cities couldn’t contemplate even a few years ago: paying for a new event center without dipping into reserves and without taking on debt.

In the past two fiscal years, Alice set aside more than $4 million in seed money for the project, envisioned as a multipurpose convention center and natatorium. It has committed $70,000 to an assessment to determine the type and scale of facilities the community wants.

This phase included a town hall meeting Tuesday night, dominated by the community’s swimmers, including swim team coaches and student athletes lamenting the practice time lost on hourlong bus rides to and from Corpus Christi, site of the nearest pool that serves their training needs

Years from now, Alice swimmers may not draw a connection between the convenience of a modern, hometown pool and the heavy oil field trucks that lumber to and from town with loads of sand, water and drilling equipment. But to project planners and city leaders, that connection is everything.

Alice sits just south of the Eagle Ford Shale, a 400-mile long underground rock formation in Central and South Texas unleashing ancient stores of natural gas and crude oil with new technology called hydraulic fracturing. In the past two years, oil field service companies have expanded their Alice facilities, brought hundreds of jobs and filled up every hotel room in Alice, prompting more to to be built.

“If Eagle Ford Shale was not in play to the level it is, there would still be a need (for a multipurpose center), but it would not be as big,” City Manager Ray De Los Santos said. “There would still be funding available, but it would not be as much.”

For the fiscal year ending Sept. 30, Alice budgeted $650,000 a month in sales tax revenue. Only one month came in under $1 million, giving the city a $6 million surplus.

The event center project was being considered even before the Eagle Ford boom started in earnest in 2009. But the facility almost surely will be larger than what was initially imagined because the city can afford it, and because it anticipates the demand will be there to support it for years to come.

Oil boom and bust cycles notoriously are unpredictable and, at least in the past, short-lived on the boom end. But with Eagle Ford, analysts are expecting a ramp-up in production to last as long as 10 years, with production remaining steady at least another decade.

“This has changed the model for communities in South Texas because they have a long-term horizon where they can plan for capital improvements,” said John Michael, project engineer for Naismith Engineering. Naismith is conducting the needs assessment in Alice and has contracts with governments throughout the region.

Michael said there has been a dearth of new swimming pools in South Texas in the past 30 to 40 years because the last bust cycle drained the financial resources of communities and they never fully recovered.

De Los Santos said Alice isn’t taking Eagle Ford longevity for granted. Other South Texas cities have struggled with keeping convention centers and similar venues afloat. Last fiscal year, the American Bank Center convention center and Selena Auditorium in Corpus Christi posted a $1.3 million loss. And in Aransas Pass, the convention center has become a political football as officials try to figure out how to make it profitable.

It’s unclear how much the Alice multipurpose center would cost, where it will be built or exactly what it will entail. Project planners want to spend more time gathering input before making decisions.

The $70,000 study includes market analysis, financial projections, economic impact analysis, and aquatic and convention center complex conceptual analysis, De Los Santos said.

The general vision is a campuslike setting with meeting facilities, room for a privately-developed hotel, walking trails in a parklike area, and, of course, the pool.

Swim team coaches, members and athletes told the planners Tuesday that the city, with only one six-lane municipal pool that’s at least 30 years old, sorely needs a facility ready for competition, for family relaxation and for general health in a community suffering high obesity rates.

The town has a nonprofit swim group of more than 100 participants in the summer, and its school swim teams regularly compete at the state level.

Alice High School‘s senior class president, Horacio Rangel, said he rides two hours on the bus every day to keep up his swim training, but the bus isn’t the best environment for homework. He recently dropped to No. 22 in academic ranking in his senior class.

“I’d be top 20,” he said, “if I had more time to study.”

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