Gas Boom Or Not, More Oil Rigs Now

- Gas Boom Or Not, More Oil Rigs Now

Thursday, August 18, 2011
Houston Chronicle
by Tom Fowler

Natural gas drilling has been the dominant energy story in the U.S. for the past few years, but oil is back with a vengeance.

For the first time in 18 years, the number of oil rigs working in the U.S. has exceeded the number of natural gas rigs, according to July rig data compiled by IHS-CERA, covering both land and offshore rigs.

By 2020 this surge in oil drilling could increase U.S. oil production by as much as 3 million barrels per day, Peter Stark, head of IHS-CERA's industry relations said Wednesday during a session launching the start of Summer NAPE, the semi-annual oil and gas prospects expo being held in Houston.

Two factors are spurring the surge in oil production.

The combination of horizontal drilling and hydraulic fracturing, which has unlocked previously inaccessible gas, also has opened up new possibilities for oil production.

Relatively low natural gas prices have prompted companies to focus exploration efforts on more valuable oil and natural gas liquids.

Oil actually may have returned to the top of the heap among U.S. drilling rigs earlier this year, according to another data set. Baker Hughes' rig count for onshore and offshore rigs has oil surpassing natural gas on April 21, (913 oil rigs vs. 878 gas rigs) for the first time since April 28, 1995 (343 oil rigs vs. 321 gas rigs).

And on June 24 the number of rigs drilling for oil surpassed the 1,000 mark for the first time since 1987.

IHS-CERA predicts oil production could directly and indirectly generate another 1.3 million U.S. jobs over the next decade and raise an additional $97 billion in federal taxes and royalty payments.

The oil boom is showing up in well-known U.S. oil fields, like Texas' Permian Basin, and in newer fields like North Dakota's Bakken shale and the Utica shale in Ohio.

The surge could slow if natural gas prices continue to rise and make gas projects more attractive -- which many analysts expect in the next year.

Benchmark crude rose 93 cents Wednesday to $87.58 per barrel in trading on the New York Mercantile Exchange. Natural gas rose a penny to $3.93 per million British thermal units.

But at least for now, producers have reasons beyond crude and gas prices for renewed interest in oil.

In some cases drilling for oil can cost less than for gas. Tom Ward, CEO of SandRidge Energy, said his company is spending as little as $760,000 per well in the Central Basin field in the Permian, compared to several million per well in most shale gas fields.

John Christmann, head of Apache Corp.'s Permian Basin operations, said his company has acquired acreage in the Empire ABO field in the Permian, a field where no new wells have been drilled since 1984.

"In some cases you have million-barrel wells that have never had an offset drilled near them," Christmann said, seeing strong potential for large quantities of oil.

Oil shales will be a big topic on the floor of NAPE this year, as attendees assess potential oil and gas drilling and production projects.

Started in 1993 as the North American Prospect Expo with 80 booths and about 800 attendees, NAPE is now held twice a year, and the winter 2011 gathering in Houston had 1,600 booths and drew 16,000 attendees.

This week's Summer NAPE is expected to draw about 5,600 attendees and 600 booths.

Scott Wilmoth, a vice president at Houston investment bank Simmons & Co., said NAPE gives big firms and small a chance to see a lot of different deals in one place.

"Deals get done across the board," Wilmoth said.

NAPE is also a networking opportunity, said Charles Cusack, Petrohawk's Vice President of Exploration.

"The main benefit has been the multitude of contacts made at NAPE that have indirectly led to deals," Cusack said. "The most significant NAPE transaction was my first meeting Dick Stoneburner (Petrohawk's chief operating officer) at NAPE in 2000 that led to my working with him for over a decade."

Wilmoth expects a lot of discussion at NAPE about tight oil plays, including the Utica, the Lower Smackover Brown Dense in Arkansas and Louisiana, the Tuscaloosa Marine Shale and horizontal Wolfcamp in the Permian basin, among others.

The shale gas plays will still get attention, however -- including the areas in the Eagle Ford that yield oil and natural gas liquids, and the Marcellus shale in the northeast U.S., Wilmoth said. Internationally, unconventional oil and gas opportunities in Argentina may be a big draw at NAPE as well.

While the business is famously cyclical, the recent oil boom surprised some in the industry.

During a recent meeting of the National Petroleum Council in The Woodlands, the group discussed an upcoming report on U.S. natural gas reserves. Not surprising, the group said, the study would report that North American natural gas resource potential was enormous.

"Secondly, and perhaps surprisingly to some of us and certainly to many Americans, our Canadian and American oil resource base is also very big news," said NPC member Susan Tierney.

Copyright (c) 2011, Houston Chronicle

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Western N.D. Oil Boom Offers Beacon to Unemployed

- Western N.D. Oil Boom Offers Beacon to Unemployed

Tuesday, July 19, 2011
Knight Ridder/Tribune Business News
by Lisa Miller, The Dickinson Press, N.D.

The diversity of Dickinson continues to grow as more and more people from all parts of the country and walks of life move to western North Dakota for employment.

A recent energy boom including the discovery of oil and gas in the area, have many people seeing dollar signs.

Lexi Sebastian, the executive director of the Dickinson Area Chamber of Commerce , said since the beginning of the year the Chamber has received approximately 500 phone calls and 225 walk-ins requesting information about the community.

She added the chamber receives about 40 contacts a day from people looking to relocate and mails about that many relocation information packets a month.

Steve Kass of Hayward, Wis., is one of those relocators.

He moved to Dickinson after work in Wisconsin slowed.

"I used to work construction, panelizing and building walls," Kass said. "In the summer of 2006 I was working on a big commercial project in Illinois when day after day union carpenters began coming in looking for work. I thought to myself if they are slow what's coming next?"

And he was right.

"By the fall I had to let between 15 and 20 guys go because there was just no business," Kass said. "It was a very difficult thing to do."

Kass then did remodeling on his own until that "petered out" too.

"My family, (wife Amy and kids Tyler and Jordan) were barely getting by and this spring I decided I had to do something," Kass said.

He added a few people in his community were moving to North Dakota because they had heard a lot of places were hiring.

"So I decided to check it out," Kass said. He and a friend packed-up one weekend and attended a job fair.

But on the way one of the tires on the camper the pair was toting blew out near Richardton.

"We went into town for help and a young man offered so we went and got the tire fixed and then he offered to let us park the camper on his dad's farm," Kass said. "One thing that really surprised me was how nice everyone in North Dakota is."

He added other things that surprised him were the lack of trees, general landscape and the amount of wind.

"Everyday there is wind," Kass said laughing.

Two days after the job fair both men were hired.

"It was such a relief," Kass said.

He now works for Steier Oil Field Service as a roustabout.

"Its kind of like being a mechanic. We fix things on location," Kass said.

He added one nice thing about Steier Oil Field Service is that they are big on safety.

"I had no experience," Kass said. "I did not even know what an oil field looked like, but they trained me and things are going well."

Kass said sometimes he feels like a fish out of water yet because of his lack of experience and because most of his coworkers are younger than him.

"My boss is 21, I'm 42," Kass said. "I never thought I'd have to start over again."

Kass said what he misses most is his family.

"I talk to them every day and always get the same question 'Dad when are you coming home?'" Kass said. "It's tough, its really tough to be away from family and missing out on all their big adventures. It's also tough because I have always been the protector and made sure everyone was safe, happy and healthy and I can't do that from here."

He added he really wants to move his family here but can't find affordable housing nor can he sell his home back in Wisconsin because they are having housing problems of the opposite kind.

"My wife is an accountant, so we both have good jobs but in today's economy and cost of living things are tight," Kass said.

Right now Kass and his friend are living in their camper.

"I have to find something before the winter," Kass said. "But if housing stays this way it's almost not worth staying. It's cheaper to buy another house, but then my wife and I will be paying for two houses."

Kass said on a typical day he starts at 6:30 a.m. He heads out to get job orders then goes from location to location and returns to the camper between 7 p.m. and 8 p.m.

"I work as many hours and weekends as I can because I am trying to earn money for my family and because there is nothing to do," Kass said. "Actually I shouldn't say there is nothing to do because that's not true, I just don't feel like going out without my family."

He added once in a while he goes golfing with some friends but many nights he sits at home watches TV, eats a microwave meal, showers and goes to bed.

"It's just so different than what I have done in the past," Kass said. "It's a different way of life."

He added another nice thing is that Steier Oil Field Service doesn't have a problem with employees going home, they are very family friendly.

"The problem for me is home is hundreds of miles away," Kass said. "It's expensive both to fly and drive and it's almost a 10 hour drive. I go home for two days. The time just seems so short but it is worth it."

Kass added the economy everywhere else in the country is crud.

"You hear and learn about the great depression, I never thought I'd live it," Kass said. "No one is hiring back home, people in North Dakota should feel very blessed because it's not like this everywhere else, you really don't know unless you've seen it."

Kass said he wishes he had this kind of work at home not only for himself but his neighbors as well.


Copyright (c) 2011, The Dickinson Press, N.D.

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Another Boom?

- Another Boom?

Monday, June 20, 2011
Knight Ridder/Tribune Business News
by Chuck Slothower, The Daily Times, Farmington, N.M.

Since the San Juan Basin first boomed after World War II, natural gas has formed the backbone of the local energy industry.

Reliable natural gas production brought jobs, pumped tax revenues into government coffers and, in many ways, built Farmington. Oil production, meanwhile, was at best an afterthought.

That may be about to change. New technology, coupled with high oil prices, is spurring renewed interest in oil buried deep within San Juan Basin shales.

"We've always known that there's hydrocarbons in the shales. We haven't been able to get it out in economic quantities," said Steve Dunn, drilling and production manager at Merrion Oil & Gas in Farmington. "That's changing."

Though it's far from certain, oil and gas industry insiders say there's also a realistic possibility that San Juan County could be on the verge of an oil boom.

Several major producers are exploring the potential for drilling San Juan Basin oil, industry officials said. Companies recently have approached local independent oil and gas firms to discuss buying rights in the Mancos Shale, the oil-rich geologic layer of the basin.

"We're on the cusp of a lot of interest," Dunn said.

One major North American company in discussions with Merrion Oil & Gas flew geologists to Farmington to evaluate the basin, said Dunn, who declined to identify the company, citing ongoing discussions.

The geologists estimated the Mancos Shale holds 59 billion barrels of oil, of which perhaps

3 billion is recoverable -- 10 times more than the basin has produced in the past 90 years.

"That would make this a big, big prize, and that's why these companies are coming in," Dunn said. "If they see success, there will be a boom overnight, assuming the price of oil holds."

Elliott Riggs, a Farmington-based independent petroleum geologist, has studied the San Juan Basin for more than 50 years. He sees potential for significant oil production in the Mancos Shale.

"It's real," he said. "Every 10 years, something happens here unanticipated and unexpected in the basin that changes the economics of the basin. The last big change was coal-bed methane 10 or 15 years ago. I predict the Mancos will be the next big change."

Forbidden shale

The Mancos Shale stretches across the San Juan Basin from Durango, Colo., at its northern extreme nearly to Gallup southward, and from Shiprock to the Chromo, Colo., area.

At 3,600 square miles, the basin is the largest natural gas-producing region in the Rockies.

Natural gas dominates the basin to the north, while oil is thought to be more prevalent in the south. Oil and gas officials say the Mancos Shale is geologically similar to the Niobrara Shale in Northeast Colorado, where production has boomed.

San Juan Basin oil is difficult to drill. The shale is a tight and nonporous layer of rock, and only in recent years have drillers perfected two techniques that could set the oil free: horizontal drilling through thousands of feet of rock, and multiple-stage hydraulic fracturing that can shatter shale rock, allowing oil to flow.

The techniques were pioneered in the Barnett Shale near Fort Worth, Texas, where they revolutionized oil and gas production.

The process is expensive and raises numerous environmental concerns. But drillers say it's the only way to bring oil to the surface in significant quantities.

Black Hills Exploration and Production, a Denver-based firm, is among the first companies to pursue Mancos Shale oil. The company in April drilled a test well for Mancos Shale oil. Results are expected by the end of the year.

"It's our first horizontal well drilled in the Mancos Shale in the San Juan Basin," said Amy Estes, a Black Hills spokeswoman. "Certainly, depending on when the results come in, we may develop further."

ConocoPhillips, which has major operations in the San Juan Basin, also is taking a look.

"We are aware of the potential in the Mancos, and we're in an early evaluation stage," said Jim Lowry, a Houston-based ConocoPhillips spokesman. "But right now we don't have any Mancos development under way."

Likewise, BP said it is evaluating the shale play.

"BP has acreage in a number of shale basins in the U.S., including access to acres in the Mancos play," spokesman Daren Beaudo said. "At this time we are evaluating the potential opportunity there but are not able to speculate further about its potential or our plans going forward."

Sources caution it's not clear that large-scale oil production can be done profitably in the San Juan Basin.

"The jury is still out," said John Byrom, president and CEO of DJ Simmons Inc. in Farmington. "It's a legitimate possibility. The rocks have the potential."

Tucker Bayless of Bayless Drilling Co. said he has heard rumblings about Mancos Shale oil. But, he said, "I also hear it's just as likely to be gas as oil."

Companies look for land

Out-of-state companies looking at drilling for San Juan Basin oil face a major challenge: The land is taken.

For decades as natural gas production surged in the San Juan Basin, companies snapped up leases on nearly every conceivable productive corner of land.

"There is no open acreage here in the San Juan Basin," Riggs said. "In the producing area, you probably couldn't find 40 acres that isn't leased."

That leaves the out-of-state companies interested in the Mancos Shale seeking to make deals with small, local firms such as Merrion Oil & Gas on the assumption that international firms such as ConocoPhillips and BP won't deal away their rights.

Merrion is listening.

"It's too expensive for us to experiment with," Dunn said. "It takes somebody with size to come in and do the science part."

Companies are working to cobble together significant acreage to undertake the work, industry officials said.

Oil prices are driving interest in San Juan Basin oil. While natural gas prices have stagnated, oil remains highly valuable, trading for $93 per barrel on the New York Mercantile Exchange on Friday.

Natural gas, meanwhile, has been trading for less than $5 per million British thermal units, far below levels seen a few years ago. Natural gas production in Northwest New Mexico has declined steadily since 2006.

Oil drilling has helped compensate. Production has increased for three consecutive years, according to state Oil Conservation Division data.

In the San Juan Basin and across the nation, oil and gas firms are retooling their operations to focus on oil.

High oil prices may make expensive operations worth undertaking for large firms. Drilling for oil in the Mancos Shale would require a huge investment, making it necessary for a large firm to take the first plunge into the shale.

"It's a big deal to do one of these wells, and a lot of capital up front," said John Thompson, president of the Independent Petroleum Association of New Mexico. "Somebody's got to go first."

A boom town again?

If drillers find significant oil in the Mancos Shale, it could transform Farmington once again into a boom town.

Communities across the nation from Utah to New York have seen dramatic transformations when shale plays exploded, marked by a rush of jobs coupled with growing environmental concerns.

The Bakken Shale in North Dakota and Montana has been one of the busiest drilling areas in recent years. It boomed after an accidental discovery.

"The Bakken, nobody knew about it until one guy had to drill horizontally under a lake," Thompson said.

An economic boost would be welcome in San Juan County. The steep decline in natural gas production, coupled with low prices, has been felt in a widespread economic slowdown marked by lost jobs, slow retail sales and closed businesses. The county's unemployment rate surged past 9 percent in 2010 before declining to 7.2 percent in April.

While sales tax data suggest retail sales are improving, the recovery is expected to be a slow one. The Mancos Shale may be Farmington's best shot at a dramatic recovery.

"I hope it works," Byrom said. "It would provide a lot more economic development here when our activity is on the decline. If it is successful, it could reverse all that."

Copyright (c) 2011, The Daily Times, Farmington, N.M.

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Analysis: Shale Boom, Independents Drive U.S. Reserves, Capital Spending

- Analysis: Shale Boom, Independents Drive U.S. Reserves, Capital Spending

Wednesday, June 15, 2011
Rigzone Staff
by Karen Boman

The U.S. shale oil and gas drilling boom boosted U.S. oil and gas reserve growth to a five-year high in 2010, while upstream spending more than doubled from 2009 to 2010 largely due to producers' acquisitions of shale properties, according to Ernst & Young's fourth annual U.S. E&P Benchmark Study.

The survey of the 50 largest oil and gas companies by end-of-year reserves found that end-of-year oil reserves grew 11 percent from 16.1 billion barrels in 2009 to 17.8 billion barrels in 2010, and natural gas reserve grew 12 percent from 156.2 Tcf in 2009 to 174.3 Tcf in 2010, the strongest combined annual growth posted from 2006 to 2010.

Shale Rock

The oil production replacement rate for U.S. oil reserves from all sources, including extensions and discoveries, improved recovery, revisions, purchases and sales of proved reserves, was 234 percent in 2010, compared with a 158 percent replacement rate in 2009. The U.S. natural gas production replacement rate from all sources was 252 percent last year, compared with 156 percent in 2009.

Production replacement rates for 2010 that excluded purchases and sales were 205 percent for oil, 249 percent for gas, and 232 percent on a combined BOE basis.

The study found that independent oil and gas producers led in terms of oil production replacement rates for 2010, with independents replacing 601 percent of oil production from all sources last year and, excluding purchases and sales, replacing 433 percent of oil production.

Large independents replaced 241 percent of production from all sources, and 290 percent of production from sources other than purchases and sales. Meanwhile, integrated oil and gas companies replaced 141 percent of oil production from all sources, and 111 percent of production from sources excluding purchases and sales.

Integrated companies had a gas production replacement rate of 436 percent from all sources; however, this replacement rate reflects ExxonMobil's acquisition of XTO Energy, which was completed in June 2010. When purchases and sales were excluded, integrated companies had a gas production replacement rate of 111 percent.

Independents replaced 408 percent of gas production from all sources in 2010, or 375 percent when purchases and sales were excluded. Large independents recorded a negative gas production replacement rate of 34 percent, largely due to the ExxonMobil/XTO transaction, as XTO is classified as a large independent. Excluding purchases and sales, large independents had a gas production replacement rate of 263 percent in 2010.

Reserve replacement costs on a total basis, including proved property acquisitions, were up once again, increasing to $15.26 per BOE in 2010 from $12.78 per BOE in 2009. Reserve replacement costs on a finding and development basis, excluding proved property acquisitions, increased to $17.84 per BOE, up from $13.01 per BOE in 2009.

Upstream spending more than doubled from $72.8 billion in 2009 to $177.9 billion in 2010. ExxonMobil's acquisition of XTO Energy accounted for 51 percent of proved property acquisition costs of $42.2 billion and 40 percent of unproved property acquisition costs of $59.3 billion in 2010. Apache Corp.'s acquisition of Mariner Energy and assets from Devon Energy and BP contributed significantly to proved and unproved property acquisition costs, as did acquisitions by Chesapeake Energy and Denbury Resources.

Exploration costs increased eight percent from $14.3 billion in 2009 to $15.5 billion in 2010, while development spending increased 36 percent from $44.8 billion in 2009 to $60.8 billion in 2010, primarily due to shale oil and gas development. The increase in exploration and development spending was primarily driven by ExxonMobil, Chesapeake Energy and EOG Resources. Of the 50 companies surveyed, only four decreased their exploration and development spending in 2010 – BP, ConocoPhillips, Loews and Plains Exploration & Production.

The companies' plowback percentage, or total upstream spending as a percentage of netback, increased to 170 percent in 2010, the highest of the five-year period from 2006 to 2010, as companies reinvest in shale activity. In 2006, the plowback percentage reached 121 percent as a result of an increase in investment activity driven by a relatively high priced commodity environment.

ExxonMobil's acquisition of XTO and similar deals are part of the trend of major oil and gas companies following the lead of independent oil and gas companies, who were first movers in North American shale plays. This trend is occurring as integrated majors are finding it difficult to replace reserves organically. The rise of national oil companies overseas has made it more difficult for the companies to access foreign reserves, as have restrictions placed U.S. offshore drilling. U.S. independents and oil service companies have been at leading edge of technology, including developments in horizontal drilling, which have changed the oil and gas industry.

Horizontal drilling

Strong oil prices and weak, but stable, gas prices in 2010 encouraged investment in shale exploration efforts and production technology. The shift from gas to oil-focused drilling has created a drilling renaissance in the Permian Basin that has operators looking at plays nobody thought was possible.

However, consistency in commodity prices, as well as companies' abilities to find enough skilled employees and addressing issues surrounding hydraulic fracturing, are needed to allow companies to capitalize on shale properties. Despite controversy over hydraulic fracturing, the practice will likely continue, said Marcela Donadio, Americas Oil & Gas Leader for Ernst & Young, noting that companies are taking efforts to conduce fracing responsibly.

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Shale Boom, Gas Demand to Make North America LNG Exports Reality

Shale Boom, Gas Demand to Make North America LNG Exports Reality

Friday, April 29, 2011
Rigzone Staff
by Karen Boman

The increase in North American natural gas due to the shale gas boom and a projected increase in global gas demand mean that North America will become a liquefied natural gas (LNG) exporter within the next few years.

The recovery in global LNG consumption in 2010, combined with anticipated gas demand growth in emerging economies of China and India presents opportunities for LNG exports, as does growing demand in Europe, where gas production is expected to decline and demand for gas-fired power generation is expected to grow. Near-term LNG demand also will be impacted by Japan, where the earthquake and tsunami damaged nuclear power facilities, resulting in strong demand for natural gas to fire electric power plants. However, it is too early to tell how this will impact Japan's long-term plans.

North American LNG exports should be sustained as long as North American shale gas production remains at existing levels, said Zach Allen, publisher of PanEurasian Enterprises NATS report, which tracks global LNG markets. Cheniere Energy's Sabine Pass in Louisiana and Freeport LNG in Texas are two existing LNG regasification facilities that will have liquefaction capacity added to allow for LNG exports.

Sabine Pass's liquefaction facilities are scheduled to begin operations in 2015, drawing from onshore Gulf Coast conventional gas plays as well as the Barnett, Haynesville, Bossier, and Eagle Ford shale gas plays. Freeport LNG's liquefaction facility also is expected to be in service in 2015, and will draw its supply from the Eagle Ford, Barnett and Haynesville shale plays as well.

Cheniere noted that adding liquefaction infrastructure to Sabine Pass will allow the company arbitrage opportunities for Henry Hub versus oil prices. Worldwide LNG prices are predominately based on oil prices, or between $10-$25/MMBtu, while Cheniere estimates the cost of delivering gas from Sabine Pass to Europe and Asia at between $7 - $12/MMbtu. The project also has the advantage of having significant infrastructure already in place, including storage, marine and pipeline interconnection facilities, which means lower capital costs.

The Cove Point LNG regasification facility near Baltimore, Maryland could potentially serve as an export facility for Marcellus shale gas, Allen noted. He sees Marcellus gas as a stranded asset, as it's difficult to move gas south from the Marcellus region. "Through displacement, you can move a certain amount of it to the north and east, but that precipitates a price war," said Allen, who also speculates that Sempra Energy's Cameron LNG facility in Louisiana might also be another possible LNG liquefaction facility.

Allen sees Gulf Coast liquefaction facilities as primarily serving the European market, while the Kitimat LNG plant in British Columbia has a competitive advantage in serving northeast Asian markets due to its proximity to Asia. The terminal would also provide a market for Canadian gas, as incremental demand in northern Washington, Oregon and northern California does not provide enough market for gas supply in the region.

Last month, Kitimat partners Apache Canada Ltd., and EOG Resources Canada said Encana Corporation would acquire a 30 percent working interest in the planned facility. The three companies have a significant presence in the Horn River Basin. According to a report by Scotiabank Group, demand for Kitimat LNG is expected to be boosted in the medium-term outlook as shifting to gas-fired power generation occurs in the U.S and parts of Europe and Japan shifts from nuclear energy to imported LNG.

One challenge facing North American LNG exporters is the lack of liquidity and transparency in the European LNG market. Since LNG traded on power exchanges in Europe can be done privately, with no price information disclosed, "we have no idea what LNG prices really are," Allen noted. The market is at best opaque, said Allen, but market forces will eventually push for more transparency.

North American exports of LNG have the potential to compete in cost terms in the global LNG market, Barclays Capital noted in an April 19 report. However, the successful development of liquefaction terminals will depend not only on economics, but ability of project sponsors to secure long term off-take agreements, access to capital and regulatory permits. The higher oil price environment anticipated by Barclays will help make North American LNG exports competitive; however, they are likely to come at the higher end of the LNG supply cost curve.

Solid credit is key for a company developing a North American liquefaction project due to the fact that U.S. and Canadian gas not stranded, as it usually is with liquefaction projects. In a traditional stranded gas project, the project developer would have to ensure that the sale price, with a known floor price, covered the break-even cost of the integrated facility and secured a certain return on the investment.

Both the U.S. and Canada have deep and liquid domestic gas markets that offer an alternative for feed gas; these alternatives make the all-in cost of LNG production a moving target. "It would take an enormous balance sheet to shoulder the risk of buying gas at Henry Hub and selling it at oil equivalents in Europe or Asia over a 20-year time-frame," Barclays noted.

Shale gas development around the world also could dampen LNG consumption, including China. However, Barclays estimated in a March 22 report that the effect of shale gas on Chinese LNG imports would be limited to about 1 Bcf/d over the next decade, given the constraints China faces in developing its shale gas. Shale gas exploration and development in other countries is still in the early stages, but worldwide success of shale gas development "could pose a significant downside risk to LNG import needs."