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 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 in northeast British Columbia, which is one of the areas from which gas supply for Kitimat will be sourced.

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 breakeven 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 timeframe," 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."

An Analysis of Shale Gas, LNG & the Coming Impact of Wet Shale

Two years ago, suggesting North America would be in the position to export LNG would have seemed delusional. The wisdom, based on conventional gas theory in place for forty years also saw gas on the global scale as depleting or insecure and thus open to price volatility.

The proposed solution, famously endorsed before Congress by Fed Chairman Alan Greenspan at the height of his reputation, was to restart mothballed LNG import terminals even as a dozen or so new terminals sprang up on both coasts of North America.

In the meanwhile, in what must be one of the worst examples of bad timing in any industry, the unconventional wisdom came up with massive new shale reserves, not merely providing the solution but turning it on its head. Supply was now so massive that demand fears were irrelevant. Shale gas emerged so rapidly and so successfully that North America had the exact opposite problem: they needed a bigger market.

Today it is clear North America has resources that can be called game-changing, or “mind-boggling” as Range Resources CEO John Pinkerton recently described Pennsylvania’s Marcellus Shale.

Conventional gas flows of North America have depended on big pipelines hauling big volumes from production areas in the Gulf of Mexico, Mid-Continent and Alberta to consumers in the North East, upper Midwest and Eastern Canada.

Whereas the Marcellus is still in its infancy, surging production from the Barnett Shale in Texas and the Haynesville Shale in Louisiana is already creating problems by competing with Canadian gas even several years before the Marcellus production would be significant. The North American shale experience started in the Barnett Shale in Texas in 2002, but it is the Marcellus which has evolved into the mother of all shales. The Marcellus had reserve estimates in January 2007 of 5 Tcf but 50 Tcf by December the same year. Now it is ten times that: the second largest gas field on earth has come out of nowhere. The size alone would be significant anywhere, but the bounty lies within commuting distance of one of the great gas markets in the world in the North Eastern United States. The Marcellus is to natural gas what Spindletop was to oil a century ago - and more. The Marcellus experience is almost certainly repeatable in multiple locations on every continent.

But LNG marketers have been slow to understand the looming impact of North American shale on world LNG markets. Just as the modern shale combination of hydraulic fracturing and horizontal drilling was opening up undreamt of deposits; U.S. LNG import capacity was built or upgraded.

The first hint that the paradigm was not shifting so much as shattering was in 2009 when the planned Kitimat terminal in British Columbia was reborn as an export terminal. The gas would come from western Canada’s Horn River and Montney shales. Pre-2009, the theory was that gas imported to Kitimat would compete for Asian markets with gas from Australia and Peru. Post 2014, when the terminal will be completed, BC gas will compete in Asian markets against Australian, Peruvian and many more LNG exporters who had seen one leg of the three-legged world gas stool of North America, Europe and Asian markets sawn off.

In 2011 there is talk of LNG exports from another terminal near Kitimat and possibly even from Oregon. But the big game changer occurred in May 2010 when Cheniere Energy, operator of the Sabine Pass LNG terminal on the Gulf of Mexico announced plans to export US gas from 2014 - a plan quickly added to by other operators in Cameron, LA and Galveston, TX.

World LNG markets still appear to be in denial about the possibility of shale removing still more markets out of the demand equation even as yesterday’s customers become tomorrow’s competition. The shale story outside of the U.S. is still forming, but it is finally dawning on the conventional wisdom that in the future, they will be unconventional and shale gas will be the usual. The U.S. experience shows how quickly it can emerge. The Barnett shale produced zero gas in 2002 but enough in Q3 2010 to supply the entire annual gas use of Sweden and Switzerland combined from Fort Worth’s Tarrant County alone.

Cheniere Energy told the Heren LNG Trading conference in London last month that they expected U.S. Henry Hub prices could reach $2.50 MMBTU. Cheniere liquefaction costs add $2.75 and transport to Asia another $2.50. European delivery would be in the area of $2, meaning that Henry Hub gas would be competitive even up to $6 with Asian and European prices of $10 to $12 today.

Many LNG marketeers are still denying the long term capacity of U.S. shale. In this, they echo the disparate groups who depend on a view of insecure or expensive gas to make the economics work. Groups such as nuclear, Coal CCS, renewables and Russia normally have nothing nice to say about one another, now find themselves united in the face of the sudden emergence and looming permanence of shale. One commonly shared objection is that by 2014, U.S. gas will prove environmentally unacceptable or start depleting instead of growing, thus leading to U.S. gas becoming too expensive to compete in world markets.

As much as this depends on a probably unrealistic view of shale gas potential, it is blissfully unaware of the true economic background of gas prices. Simply put, today’s gas is all about oil. The two key shale techniques of fracturing combined with horizontal drilling are now releasing undreamed of oil riches. The Eagle Ford shale in Texas holds special promise, with some analysts stating it is the largest U.S. oil discovery since the Alaskan North Slope – and far closer to markets. But the story here is that wet shales, i.e. ones that contain gas, oil and liquids are all part of the package from the same hole. In this scenario, oil is the $100+ prize and it is now four times more valuable than gas measured on BTU equivalency.

With limited growth potential and surging supply in U.S. markets there are only two possibilities for gas - flaring or giving it away. Flaring is not an option, but to access high priced oil, literally giving gas away, or even more incredibly paying someone to take it off their hands makes economic sense in the Texas markets. Gas, the wonder fuel of the 21st century to most customers may well grow up to become the problem child of the hydro-carbon industry.

The shale oil story lies behind the disconnect between WTI and Brent Crude markers, even as much of the Gulf of Mexico production shut down in 2010.The massive volumes coming out of North Dakota’s Bakken oil play were, like shale gas, originally assumed by the European gas industry to be merely an interesting anomaly. The question now is not if, but when, the experience of wet shale plays will break out world-wide.

Duke University Study Finds Methane Contamination Rises Near Shale Gas Wells

Researchers at Duke University have issued a study showing a link between methane contamination of drinking water wells and their proximity to shale gas drilling sites.

The study would suggest potential for widespread contamination of rural drinking water from drilling in the Marcellus Shale under Pennsylvania, New York and other states. It could also provide substantial backing for drilling opponents and drill-site neighbors who blame drilling for fouled drinking water.

"Some of these landowners have a legitimate complaint. It looks like there's a real problem," said Robert Jackson, an environmental chemist at Duke University who authored the paper being published in Proceedings of the National Academy of Sciences.

What the study did not find is evidence that hydraulic fracturing fluid or flowback waste is getting into drinking water. The contamination was methane, the principal component in natural gas, which can build up inside houses and cause them to explode. The study found average methane was 17 times higher within 3,000 feet of drilling than water farther away.

Industry groups are criticizing the study, noting that there is no "baseline" before-and-after data and no proof drilling wells caused the methane contamination.

"What you have here is a paper that draws pretty firm conclusions without much data at all to back any of them up," said Chris Tucker, spokesman for Energy In Depth, a drilling industry group.

Still, the peer-reviewed study injects some scientific rigor into a debate long characterized by shouting matches and partisan counterclaims. The report says it is the first scientific study of water contamination near shale drilling sites.

And researchers plan to go back into the field to test wells where gas was drilled since the samples were taken last year. Some of the wells they sampled far from drilling sites last year now have active production nearby.

The researchers, who also include Stephen Osborn, Nathaniel Warner and Avner Vengosh, all at Duke, have recommended more research into the medical effects of methane exposure and more study of the disposal of fracturing fluid and the brine waste that comes back up with it.

The research team found that 85 percent of the 68 wells they tested in Pennsylvania and upstate New York had some amount of methane. That is consistent with industry contentions that lots of wells in drilling areas had methane before exploration began.

But they found that within 1 kilometer, about 3,000 feet, the concentration spikes upward sharply, and the chemical makeup more closely resembles the deep shale gas the companies are producing.

The study noted the average level found within a kilometer of drilling -- 17 times higher than non-drilling areas -- is higher than the level at which federal coal mine regulators recommend immediate action, such as ventilating the area, and possible changes to the water supply.

But John Conrad, a groundwater geologist from upstate New York, says the researchers may have "jumped the gun" to blame drilling when they have not compared the same water wells before and after drilling.

"This is possibly an interesting trend," said Conrad, who has worked with the Independent Oil & Gas Association of New York. "But with this small number of data points and no baseline data, it doesn't prove it. It might reflect the amount of gas that's always been there."

Jackson concedes that the study does not have baseline data and said he expected the criticism. But he said the correlation between drilling and contamination is strong.

"It's pretty difficult to understand for me without that being the cause," Jackson said. "There's not much difference between them except for drilling."

But America's Natural Gas Alliance (ANGA), another industry group, said in a statement that they are geologically different and said the study makes an "apples to oranges" comparison. The group also criticized the study for not including exactly where the groundwater samples were taken.

"We welcome serious, fact-based scientific inquiries into how we do our work," ANGA said. "Upon initial review, however, this study lacks key data that would be needed to validate its conclusions."

And Energy In Depth, a project of the Independent Petroleum Association of America, also criticized the researchers for including "hydraulic fracturing" in the title of the study, when they found no contamination from fracturing.

Advances in fracturing technology are what made production of shale gas possible in Pennsylvania, New York and other states.

Critics have long contended it could be contaminating drinking water. But industry representatives have said it cannot be, because the fluid is injected too deeply underground, a mile or so, to get back to drinking water near the surface.

The Duke researchers said the gas they found in water is not coming up through rocks from the pressure of fracturing but coming up through the wellbore.

"The study found no evidence of contamination from hydraulic fracturing fluids or saline produced waters," their report says. But it also suggests more study into whether the intense pressures used in fracturing may cause more leaks in the wellbore.

The study also found that not all water wells close to drilling operations had methane, suggesting that the methane leakage is not an inevitable side effect of drilling but improperly run drill-pipe, called casing.

"It's leaky well casings," Jackson said.

In addition to their recommendations for more study, the researchers offered two policy suggestions. Both relate to hydraulic fracturing, though they found no indication of contamination from the fracturing process.

Governments, they said, should require disclosure of the chemicals in fracturing fluid and Congress should order federal regulation of fracturing under the Safe Drinking Water Act (SDWA). That has been proposed by congressional Democrats for several years, with legislation called the "FRAC Act." But it has never passed.

"In our view, the inclusion of hydraulic fracturing in the SDWA, whether this is accomplished through the passage of the FRAC Act or through some other means, would strengthen public confidence in hydraulic fracturing and natural-gas extraction," they wrote.

But Jackson noted that the impact of such a move could be limited and said the best solution was for industry to find solutions.

"The Safe Drinking Water Act doesn't apply to the water we tested," he said. "For me, the default should be to self-regulate. If that doesn't work, I'd start at the state level. Federal regulation does have a place in setting the baseline."

Quail, Layne Christensen Announce Alliance to Provide Treatment and Disposal Solutions in Shale Gas and Wastewater Treatment Applications

Fountain Quail Water Management LLC, a subsidiary of Aqua-Pure Ventures, Inc., has announced an alliance with Layne Christensen Company. The parties have executed a Teaming Agreement enabling the firms to join forces to provide treatment and disposal solutions in challenging shale gas and other industrial wastewater treatment applications. The agreement takes effect immediately. The alliance allows both companies to market the other’s products and services, and seeks to exploit their complementary technologies to provide shale gas operators with a “turnkey solution” for treatment of flowback, produced water and other waste streams.

The combined services will provide a comprehensive solution for pre-treatment, re-use and disposal of drilling wastewater using both mobile and permanent facilities.

“We are extremely pleased to team with an industry leader like Fountain Quail, which has developed the most cost-effective and viable wastewater recycling process in the industry,” said Greg Aluce, Layne’s President of Water Technologies. “We believe our combined marketing efforts and technical expertise position us as a formidable player in the rapidly expanding shale gas market.”

“Our relationship with Layne is an important milestone in our company’s history, enabling

Fountain Quail to compete aggressively for business in virtually every shale play across

North America,” said Brent Halldorson, Fountain Quail’s Chief Operating Officer. “Layne is an outstanding company with impeccable credentials, and we are pleased to team with them at this pivotal moment in our industry’s development.”

In addition to pursuing the vast North American markets, the companies plan to jointly explore global opportunities for their combined technology services, as well as applications in heavy oil, power, mining and other related industries.

Layne’s recent acquisition of Intevras Technologies, a leader in the treatment and disposal of heavy brine in the oil and gas markets, further enables the companies to offer a synergistic suite of technologies ranging from basic on-site treatment to complete zeroliquid discharge solutions.

Layne recently made global headlines when it collaborated with its Latin American affiliate Geotec Boyles Bros. to successfully reach and free 33 miners trapped in a Chilean mine.

Big U.S. Oil Companies Face Growing Concern over Fracking

Large blocks of investors in the two biggest U.S. oil companies on May 25 demanded more disclosure about the environmental risks of extracting oil and gas through hydraulic fracturing. Exxon Mobil Corp defended the practice at its annual shareholder meeting, even as investors peppered Chief Executive Rex Tillerson with concerns and questions about it. A proposal requiring more disclosure by Exxon on the impact of "fracking" received about 30 percent of the votes by shareholders in the world's largest publicly traded oil company.

At rival Chevron Corp; which became heavily involved in fracking through a recent acquisition, 41 percent of shareholders backed a similar resolution. "Breaking 40 percent on a first year resolution has only happened a few times in the last few decades, so it shows how seriously the company's shareholders are taking this issue," said Michael Passoff, who focuses on fracking at San Francisco-based corporate responsibility group As You Sow.

Hydraulic fracturing involves injecting a mix of water, chemicals and sand into the earth to break up shale rock, in order to release oil or natural gas. Environmentalists say it can contaminate groundwater with dangerous chemicals. The industry insists it is safe, and Tillerson said there were claims about the 50-year-old technology that had no basis in fact.

The company regularly meets with local officials and politicians, and is running an advertising campaign aimed at addressing public concerns. While acknowledging the risks, Tillerson said Exxon works to bring together regulators in states with shale drilling to examine current rules and determine which are most effective. "We're not trying to characterize this as an activity that does not have risks," he told reporters after the meeting in Dallas. Regulators in states where shale drilling is growing at breakneck speed are "stretched", but rules governing fracking should not be set at the federal level, he said. Chevron echoed a desire for regulation to stay at state level.

However, Passoff said even regulators acknowledge that the current regulation by states is inadequate. Exxon made a $35 billion bet on shale gas when it bought XTO in 201O, and aims to double U.S. natural gas output in a decade. As a result of this and other ambitious plans, oilfield service providers such as Schlumberger Ltd and Halliburton Co have seen huge growth in their fracking operations. Chevron became involved in the Marcellus shale region centered on Pennsylvania through its $3 billion purchase of Atlas Energy and then an acreage deal with Chief Oil & Gas.

Chevron is growing production from Atlas aggressively, with plans to expand output at least seven-fold. But at the May 25 meeting at Chevron headquarters in San Ramon, California, speakers raised other environmental topics, including an $18 billion judgment against the company in Ecuador.

Chevron is battling that ruling in a U.S. court, and accuses the plaintiffs of extortion. A few dozen protestors were outside the sprawling Chevron campus.

Earlier, New York State Comptroller Thomas DiNapoli, who runs a fund that owns 7.5 million Chevron shares, urged the company to "face reality" and settle the 18-year-old Ecuador case. "Investors don't derive any benefit from this never-ending courtroom drama," DiNapoli said in a statement. Inside the meeting, Amazon Watch founder Atossa Soltani reminded Chief Executive John Watson that, at an annual meeting a decade ago, she had warned Chevron of the environmental damage liability in Ecuador it would inherit by buying Texaco. Watson responded by running a video setting out Chevron's case, including an infamous clip in which Soltani, as she listens to the plaintiffs' lawyers discuss tactics for intimidating the Ecuadorean court, warns them: "I just want you to know that it's illegal to conspire to break the law."

AMERICAS

U.S.

ETP, Regency Plan New $350-$375 Mln, 100,000 bpd Fractionation Facility at Mont Belvieu

Energy Transfer Partners, L.P. (ETP) and Regency Energy Partners LP on May 5 announced that Lone Star NGL LLC ("Lone Star"), the joint venture that acquired the midstream assets of Louis Dreyfus Highbridge Energy, will construct a 100,000 barrels per day natural gas liquids (NGL) fractionation facility at Mont Belvieu, Texas.

ETP will utilize a substantial amount of this fractionation capacity to handle NGL barrels it will deliver from its Jackson County, Texas processing plant, which is supported by multiple ten year contracts with producers as a part of ETP's Eagle Ford Shale projects. Additionally, Regency expects to provide barrels to this project.

Lone Star expects to have the fractionation facilities completed by the first quarter of 2013 at an estimated cost of between $350 and $375 million. As part of the project, Lone Star will develop additional storage facilities for y-grade liquids and other components. The project will also include interconnectivity infrastructure to provide NGL suppliers and NGL markets with significant access to storage, other fractionators, pipelines and multiple markets along the Texas and Louisiana Gulf Coast.

"There is a growing demand for fractionation capacity, storage capacity and interconnectivity at Mont Belvieu and this is the first major step toward becoming an even larger service provider in the Mont Belvieu area," said Greg Bowles, Senior Vice President of Lone Star. "This project is strategic for our long-term growth plans and demonstrates the types of opportunities we intend to pursue to provide our customers comprehensive services in the liquids energy markets."

In addition to the Lone Star fractionation project, ETP has advised Lone Star that it is in negotiations with other pipeline operators to secure pipeline capacity that will provide NGL transportation from Jackson County to Mont Belvieu. In the event ETP determines it is more prudent to build a new pipeline rather than secure pipeline capacity through another pipeline operator, ETP has advised Lone Star that it will construct a 130-mile, 20-inch pipeline from its Jackson County NGL processing facility to Mont Belvieu. ETP has also advised Lone Star that the NGL pipeline from its Jackson County facility would provide capacity for barrels currently contracted by ETP and would be able to accommodate significantly more barrels from the Eagle Ford Shale or from a potential NGL pipeline from west Texas. The capacity of the 20-inch pipeline would be approximately 340,000 barrels per day.

BHP to Face Class Actions from Arkansas Landowners

BHP Billiton will be facing an assortment of class actions in the U.S. as Arkansas landowners claim that mining techniques used in the company's recently acquired shale gas business are causing earthquakes, poisoning their water supply and polluting the soil and air over the environmental effects of a controversial gas mining technique that is about to become a enormous industry in Australia.

Arkansas landowners allege that BHP's Houston-based petroleum division's recently acquired $US4.75 billion Fayetteville shale gas business, along with three other gas producers, of reckless and irresponsible disregard for their safety by allegedly allowing noxious emissions to contaminate water, air and soil and is causing earthquakes, poisoning their water sources and polluting the soil and air.

Another group alleges that reinjection of salt water underground has triggered a disturbing series of earthquakes, culminating in a magnitude 4.7 quakes on March 4.

The pending class suit comes amid growing environmental concerns surrounding the emerging $50 billion Queensland and New South Wales coal seam gas industry.

In a well operated by Shell and PetroChina near Dalby, Queensland that resulted in gas and water explosion has prompted calls for tighter control and regulation of the industry.

Shale gas and coal seam gas operations use hydraulic fracturing to liberate the gas. It involves injecting high-pressure water, sand and chemicals, and results in large volumes of salty water coming to the surface.

In one class action, Arkansas landowners allege that BHP and three US gas producers allowed noxious emissions to contaminate water supplies, air and soil.

The landowners are praying for millions of dollars in damages, and improved environmental monitoring.

BHP in a recent statement said its objective was to develop the facility in line with the company's values of ensuring that we fully protecting the people, the environment and communities where it operate.

The District Court plaintiffs each want damages of $1 million and they want the court to levy $5 million of punitive damages against the companies.

The Arkansas residents also want each of the cases that are filed are to be accepted as class actions for fellow residents to participate.

El Paso Corp Spins Off its Exploration and Production Business to Create New, Publicly Traded Company

Natural gas pipeline giant El Paso Corp. will spin off its growing exploration and production business into a stand-alone public company, a move that has long been anticipated by analysts and investors.

The new company would be a midsize E&P company with significant acreage in a number of shale plays, including the Haynesville gas shales in Louisiana, the Eagle Ford and Wolfcamp oil shales in Texas and Utah's Altamont oil shales.

Following the spinoff, El Paso Corp. will be a natural gas pipeline business with more than 43,000 miles of pipe, midstream processing business and general and limited partner interests in El Paso Pipeline Partners, a public master limited partnership that owns some of the pipeline assets.

The as-yet-unnamed company will be Houston-based with about $4.7 billion in assets. The current head of El Paso Exploration and Production, Brent Smolik, will be CEO. The tax-free spinoff is expected to be completed by year's end.

"We believe that the creation of these two stand-alone public companies will result in significant and sustainable value creation," said Doug Foshee, chairman and chief executive officer of El Paso.

On May 25, El Paso raised its full-year earnings outlook from the 90-cent to $1.05-per-share range to a range of $1 to $1.10 per share, based largely on its improving E&P business. The 2011 exploration and production budget has also been increased by $300 million to $1.6 billion in order to step up activity on the oil-rich Eagle Ford shale in South Texas.

El Paso was one of several companies that tried its hand at the merchant energy business model in the 1990s — owning and operating a wide range of assets from pipelines to power plants to energy trading businesses. With the collapse of the biggest of the energy merchants in late 2001, Enron Corp., many of the other companies fell on hard times and had to sell off assets and exit businesses.

In 2003, El Paso went from being involved in around 20 different industries to just two: pipelines and E&P, Foshee said.

"We got down to our core and thought we could be good and competent managers of those two businesses," he said.

The E&P business was tough shape, however, he said, the company as a whole was saddled with a lot of debt and the pipeline business was about to embark on nearly $8 billion in expansion projects.

The idea of a spinoff of the E&P business has been considered for quite some time, but the unit needed to first rebuild itself and the corporation to strengthen its balance sheet, Foshee said in an interview.

The turnaround for E&P between 2007 and the end of 2010 has been strong. From about 3.7 trillion cubic feet equivalent of reserves in 2007, El Paso now has about 8 tcf equivalent, due largely to the unconventional shale plays. Reserve replacement costs have declined from $3.55 per mcf equivalent in 2007 to $1.40 at the end of 2010.

In 2007, 38 percent of the company's reserves were considered oil, but by the end of 2010 it was 48 percent. More than two-thirds of future growth prospects are in the oil area, the company said.

El Paso's exploration business has operations in Brazil and Egypt and some shallow-water Gulf of Mexico holdings, but the bulk of its efforts are focused on onshore unconventional oil and gas.

The company became active in the Haynesville in 2007 when it acquired leases through the acquisition of People's Energy. The company perfected its drilling and production techniques in the Haynesville, driving down costs significantly.

El Paso acquired 138,000 acres in the Wolfcamp play in West Texas and has seven years to assess and develop the field. In the Eagle Ford, El Paso has 170,000 net acres, with about 60 percent of them in areas considered rich with more valuable oil and natural gas liquids.

In Utah's Altamont field, El Paso has about 193,000 net acres. It plans to use enhanced oil recovery techniques, like CO2 injection and infill drilling, to boost production in the coming years.

Analysts are not of one mind on an El Paso split. In a research note, Tudor Pickering Holt & Co. said it believed the company would be better off focusing on creating cash flow to continue to reduce debt for the next few years before doing a spinoff that would generate relatively little cash.

But Pearce Hammond, director for E&P research for Simmons & Co., said it's a sensible move that will appeal to shareholders.

"I would think they would pick up a number of investors who didn't want a piece of the pipeline business," Hammond said.

El Paso's focus on oil production growth makes sense given how much more oil is getting on the market compared to natural gas, Hammond said.

"But gas will have its day in the sun again," he said. "There seems to be a lot more demand for natural gas in the U.S. in the next decade than for oil."

Central NC Wraps Up Study of State’s Natural Gas Deposits

After studying 59,000 acres in the Deep River basin for 15 years state geologists are finished with their research in central North Carolina. They have concluded that Lee, Chatham and Moore counties could produce enough natural gas from shale to make North Carolina self-sufficient for 40 years at current levels of consumption.

"That's what we think," said Kenneth Taylor, chief of the N.C. Geological Survey. "We could become a net exporter."

The geologists recently sent their findings to the U.S. Geological Survey in Denver, which is being asked to assess the full potential of the Sanford sub-basin, a shale formation near the center of the Deep River basin. The sub-basin has the potential to hold the state's richest natural gas deposits, though exploration will continue elsewhere in the state.

Taylor said an assessment and fact sheet is expected from the U.S. Geological Survey by July.

The assessment would then be made available to energy companies eager to explore and begin commercial gas production in the sub-basin.

The findings could one day lead to riches for landowners - many of whom already have signed land-lease deals with the energy companies - and huge revenues for the state.

"The benefits from revenues that the state of North Carolina would gain from a productive natural gas industry would be immeasurable," said state Rep. Michael Stone of Lee County. "Citizens owning property with natural gas will benefit directly, while all people in our area will benefit indirectly."

But with the potential rewards come significant risks. The process of extracting natural gas from shale combines a relatively new technology; horizontal drilling, with a controversial process called fracturing - or fracking - that involves using chemicals and vast amounts of water to force natural gas out of the shale.

Earlier this month, a Duke University study concluded that fracking appears to elevate methane levels in groundwater wells near gas drilling sites. New York has put a moratorium on the practice.

Fracking and other controversies surrounding natural gas excavation have not gone unnoticed in North Carolina.

"We have to protect the environment in which we live and not at the expense of having another fuel source," said Russ Patterson, chief geologist with Patterson Exploration Services of Sanford. "We live here. We live on planet Earth. We have to take care of it."

Before any drilling could occur in North Carolina, state laws would have to change. The state does not allow horizontal drilling or fracking, though bills recently introduced in the General Assembly by Stone and other lawmakers could change that.

Although drilling still may be years away, one thing is becoming clear: North Carolina has an abundance of high-quality natural gas.

"The first thing about it: Do we have a total petroleum system?" Taylor asked. "Do you have rocks with high enough total organic carbon above a certain value above 1.4 percent? Our samples are running 3, 5, 15 percent hydrocarbon.

Enerplus Selling Portion of Shale Gas Interests for $575 Mln

Enerplus Corp. (ERF) expects to record a significant gain on the $575 million sale of a portion of its Marcellus natural gas interests in Pennsylvania, Maryland and West Virginia.

But the Calgary-based oil and gas producer will retain a "concentrated, meaningful position" in the shale play, which it said will enhance its ability to control the pace and level of capital spending going forward.

The buyers of the primarily non-operated portion being sold weren't identified. The sold interests include about 91,000 net acres in southwest and central Pennsylvania, Garrett County in Maryland and northern West Virginia. Current output is about 5.4 million cubic feet equivalent a day.

It expects to close the deal by the end of the second quarter.

After the sale, Enerplus will retain all of its non-operated acreage in Bradford, Susquehanna, Lycoming, Columbia, Tioga, Wyoming and Sullivan counties in northern Pennsylvania, as well as its operated acreage in Clinton County, Pa. Garrett County, Md. and Preston County, W. Va.

It will retain ownership in about 110,000 net acres of land with an independent best estimate of 2.3 trillion cubic feet equivalent of natural gas contingent resource and 92 billion cubic feet equivalent of proved plus probable natural gas reserves, each as of December 31, 2010. Of this total, about 60% will be operated by Enerplus.

Proceeds from the sale will more than eliminate the company's current bank debt. Enerplus will review its 2011 capital-spending and production guidance as a result of the sale.

Harvest to Build Fourth Eagle Ford Pipeline

Harvest Pipeline on May 23 announced a project underway to build a pipeline to deliver crude oil from the Eagle Ford shale play to an existing terminal on the Corpus Christi (Texas) Ship Channel.

"We are building a line with segments of 12 inches and 16 inches in diameter, with initial capacity of more than 100,000 barrels per day" said Steve Jacobs, president of Harvest. "The line can be expanded to 150,000 to 200,000 barrels per day, depending on producer interest." Shell Trading (US) Company (Shell Trading) has signed a capacity agreement for a majority of the space on the pipeline to gather and transport Eagle Ford crude oil to downstream markets. The pipeline will enable Shell Trading to offer attractive transportation solutions in the rapidly expanding Eagle Ford crude oil production region.

All pipe has been ordered, right-of-way acquisition has made good progress and first construction will begin in July. The total 140-mile line will be operational in early 2012. "Producers have shown very strong support for this line and the market solutions it offers," according to Fred Muck, vice president of business development at Harvest. "We have firm commitment for the capacity of this line."

The pipeline will originate at the Gardendale terminal of Velocity Midstream and will include direct connections to producers along its route. The destination terminal in Corpus Christi is adding tankage and includes a deep water dock in addition to a barge terminal. Across all its systems in the Eagle Ford, Harvest will have total pipeline capacity of approximately 250,000 barrels per day; providing producers access to multiple crude buyers and multiple markets. Their systems can be expanded to more than 350,000 barrels per day as the trend develops.

Harvest Pipeline is the operator of Arrowhead pipeline systems, which run through the Eagle Ford trend from Maverick County to San Patricio County. Harvest also operates an extensive system of oil and gas gathering and mainline systems across South Texas and Louisiana.

PA State Senator Backs Granting Utility Status to Pipeline Company

Pennsylvania State Sen. John Blake is urging members of the Public Utility Commission to grant utility status to Laser Northeast Gathering, a controversial move that would give the shale gas pipeline company the authority of eminent domain, or condemning private land for company use.

Laser's request for a "certificate of public convenience" -- the document that would acknowledge the pipeline as a utility -- has been before the commission since last year.

Nevertheless, Laser Northeast, under the guidance of chief executive Tom Karam, a Scranton native, pressed forward, breaking ground February 1 on the 33-mile natural gas gathering network for Susquehanna County gas wells, connecting to an interstate pipeline to the north.

Mr. Blake, D-22, Archbald, said he supports Laser's petition not because he wants such pipeline companies to have eminent domain power, but because he wants pipeline construction and operation thoroughly regulated. That level of regulation requires a utility status, he said.

"Eminent domain is not the only issue," Mr. Blake said. "We have this phenomenon of natural gas exploration in our state, and it is important we have uniform standards at the highest bar. We need a pipeline industry, and it needs to be highly regulated."

Some of the most vocal opponents to Laser's petition are other pipeline companies, Mr. Blake said, because they prefer to avoid PUC regulation.

Mr. Karam could not be reached for comment.

In supporting Laser's petition, Mr. Blake asks commissioners to disregard the recommendation of their own administrative law judge, Susan D. Colwell, who in an advisory decision issued in December said Laser didn't meet the definition of a utility, nor did it require utility status to do business.

While Laser reached a consensus with many property owners and environmental advocates who intervened in the case, Judge Colwell said most of the provisions could not be enforced by the PUC under current law. She was uncomfortable allowing companies to voluntarily seek utility status, a hint at having the Legislature determine that all or none of the collection and gathering systems be regulated.

Mr. Blake said he did not read Judge Colwell's 96-page decision.

In the meantime, Laser presses on with construction. During the groundbreaking, Mr. Karam said the company would comply voluntarily with the terms of the settlement agreement, which pleased Deborah Goldberg, an attorney for environmental group Earthjustice.

"That is an exemplary way of behaving and not something we are used to seeing from those in this industry," she said.

Ms. Goldberg said she does not endorse eminent domain for gas companies, but reached an agreement with Laser because of the concession and oversight the company agreed to.

"We don't want a company to have eminent domain unless it comes with very strict oversight," she said. "We want the PUC to recognize it has the ability to regulate the citing and the environmental impacts of pipelines, but they have been reluctant to acknowledge that role."

Mr. Blake said Laser's level of cooperation and concessions could provide a model for other pipeline companies in the state.

PUC spokeswoman Denise McCracken said it is not unusual for elected officials to weigh in on matters before the commission, noting that any citizen is free to comment on matters before the group.

PAA Commits to Build $330 Mln Eagle Ford Infrastructure

Plains All American Pipeline, L.P. (PAA), announced May 17 that it has entered into a commitment to construct a new 130-mile crude oil and condensate pipeline, a marine terminal facility and 1.5 million barrels of storage capacity to service growing Eagle Ford production in south Texas.

The project is expected to cost approximately $330 million and to be in service in the fourth quarter of 2012. To underpin the project, PAA has secured a long-term throughput agreement with Chesapeake Energy Marketing, Inc., a subsidiary of Chesapeake Energy Corporation. The project is designed to provide approximately 300,000 barrels per day of take-away capacity from the western region of the Eagle Ford play to Corpus Christi, TX and other Gulf Coast markets.

PAA has agreed to provide Chesapeake Midstream Development, L.P. the opportunity to acquire up to a 25% joint ownership interest in the project. Additionally, PAA and Flint Hills Resources have executed a Memorandum of Understanding regarding Flint Hills' potential joint ownership in this project. Flint Hills Resources operates a 300,000 bpd refinery in Corpus Christi.

PAA owns and operates a network of approximately 16,000 miles of liquids pipelines, approximately 90 million barrels of liquids storage capacity and handles over 3 million barrels of physical product on a daily basis.

Kodiak Oil & Gas Acquires New Properties in Williston Basin

Kodiak Oil & Gas has announced it has closed a deal with a private firm to acquire new properties in the Williston Basin.

The move will see the company gain some 25,000 acres and will increase its total acreage in the region to approximately 95,000 acres.

Along with the land, the deal will see Kodiak Oil & Gas acquire associated assets, which when combined with leasehold interests will total some $85.5 million (£53.05 million). A fifth drilling rig, pipeline connection facilities and other surface equipment are also included in the deal.

The $85.5 million will be paid in a combination of cash and the issuance of 2.5 million company common shares.

"Today's transaction, when closed, will add significantly to our leasehold and bolster our core operating area in McKenzie County," comments Lynn Peterson, Kodiak's president and chief executive.

Focusing primarily on the Rocky Mountain region of the US, Kodiak Oil & Gas is an independent exploration and production firm.

CANADA

Technip Wins Horizon EPC Contract

Technip has been awarded by Canadian Natural Resources Limited an engineering, procurement and construction support services contract, worth approximately EUR100 million, for the Horizon project in Fort Mc Murray, Canada.

The contract covers the expansion of the existing delayed coking unit, completed by Technip in 2008. It confirms Technip's leading position in the refining of non-conventional hydrocarbons such as refining bitumen.

Technip's operating center in Rome, Italy will execute the contract which is scheduled to be completed in 2013. Detail engineering, procurement and supply of materials and equipment will be delivered on a lump sum basis while the construction management will be charged on a reimbursable basis.

Imperial Provides Update on Oil Sands Project

Imperial Petroleum, Inc. announced that its wholly-owned subsidiary, Arrakis Oil Recovery, LLC, has successfully completed commercial scale demonstration tests for multiple parties on oil sands from various locations. The Company has entered into Letters of Intent (LOI) with at least two of the parties so far to begin the development of oil sand recovery operations later this summer and is completing definitive agreements to begin each project.

“The commercial scale demonstrations we conducted were successful in recovering the native oil from the oil sands processed which had been delivered from several areas throughout the United States. We believe that the Arrakis technology is the most advanced, cost-effective and eco-friendly processing technology available for recovering bitumen from tar and oil sands,” Jeffrey T. Wilson, President of Imperial said.

“On the heels of the President’s newly announced energy policy, we believe that the Arrakis process will begin to unlock the potential of some 20 billion barrels of recoverable oil sands located in the United States. Upon completion of definitive agreements later this month with each of the parties, we will deploy the commercial unit located in Houston to the field while we build a second and possibly a third unit for separate project sites. We expect to be operational with the first unit later this summer. Since our process has no air, water or hydrocarbon emissions issues and uses a non-toxic, biodegradable chemical under low dosage rates in a recycled operation, we do not expect to encounter any significant permitting issues at any of the proposed sites.”

Forest Fires Causing Problems for Cenovus at Pelican Lake Project

Cenovus Energy Inc. may have to halt oil production at its Pelican Lake pool if wild fires continue to wreak havoc in northern Alberta.

The wind-fuelled blaze that partially destroyed the town of Slave Lake, Alta., does not pose a threat to those facilities at the moment, company spokeswoman Rhona DelFrari said May 16.

The site is currently producing at its full 22,000-barrel-per-day capacity.

However, Plains Midstream's Rainbow pipeline has been shut down because of the fire, which means Cenovus has been putting its oil into storage tanks for now.

"We're thinking we may have to shut in production at Pelican Lake sometime later (today) or tomorrow if the pipeline doesn't re-open," DelFrari said.

Another portion of the pipeline suffered a major oil spill last month near Peace River. Cleanup efforts have been suspended because of the fires.

The fires have not affected Cenovus operations elsewhere in the province, like the Christina Lake and Foster Creek oilsands projects.

A third phase of Cenovus' Christina Lake oilsands project is nearing completion, with the company preparing to start pumping steam underground in the next day or so.

"That project's done really well. We're about five per cent below cost and we're a few months ahead of schedule," Harbir Chhina, executive vice-president of oilsands, said at a conference on May 16.

Christina Lake Phase C is designed to produce 40,000 barrels of oil per day. Construction on an identically sized fourth phase is underway and production is set to begin in 2013. Christina Lake is about 120 kilometers south of Fort McMurray, Alta.

Christina Lake and the nearby Foster Creek development are part of a 50-50 joint-venture with ConocoPhillips.

The oil in that area is too deep underground to use traditional open-pit mining methods. Instead, Cenovus pumps high-pressure steam underground to soften the bitumen and then draw it to the surface through a pipe.

Last month, Cenovus received regulatory approval to build another three 40,000-barrel-per-day phases at Christina Lake. That would bring gross production at Christina Lake to 218,000 barrels per day once complete.

"Things are going really well and we're achieving all the milestones that we're setting," Chhina said.

Also, part of the ConocoPhillips joint-venture, are refineries in Borger, Texas, and Wood River, IL.

An expansion to the Wood River refinery — estimated to cost between $3.6 billion and $3.8 billion — is expected to be completed later this year.

"We're running a little bit behind because of weather issues on that project, but basically within 10 per cent of cost," Chhina said.

Cenovus shares were down 34 cents at $32.55 in late Monday trading on the Toronto Stock Exchange.

Canadian Energy Research Institute Predicts $2.077 Trillion in Oil Sands Investments

The recession that clouded the future of oilsands development two years ago has lifted and trillions of dollars of investment are on the horizon, according to a report released May 16.

Over the next 25 years, through 2035, $2.077 trillion will be invested in building and maintaining the oilsands, according to the Canadian Energy Research Institute.

That includes $253 billion in initial capital for construction and $1.8 trillion for operation, maintenance and sustaining capital.

“The projects ... that were delayed are now back being developed again, there are more projects, some projects have moved forward in time,” said CERI president and chief executive Peter Howard in an interview.

“The net result is there is the potential for more money to be invested than what we had suggested in 2009.

“And with more money comes more jobs more gross domestic product, etc.”

Under its “realistic scenario,” oilsands production capacity will ramp up from about 1.7 million barrels per day now to 2.1 million bpd by 2015, 4.8 million by 2030 and 4.9 million by 2035.

In situ bitumen production volumes will catch up to mined output by 2025, and will account for 57 per cent of total production, or 2.8 million bpd, by 2035.

India’s ONGC Close to $4 Bln for Stake in Canada Oil Sands Project

ONGC is close to acquiring equity stakes in oil sand projects in Canada for up to $4 billion (Rs 17,776 crore).

“We are looking for these type of opportunities (investing in oil sands). Canada has huge reserves of oil sands,” ONGC group chairman and managing director AK Hazarika told Financial Chronicle on May 4.

Hazarika said investment in oil sands exploration would be huge: “It will be in billions. Volumes are very big. It may go to anything between $2 billion and $4 billion.” Canada and Venezuela have large deposits of oil sands.

Hazarika did not divulge the names of companies with whom ONGC is engaged in advanced talks. Only a few global companies such as Total, Royal Dutch Shell, Devon Energy, Husky Energy and Suncor Energy, among others, have invested in oil sand projects in Canada. ONGC has cash reserves of about Rs 14,000 crore, the PSU’s director (finance), DK Sarraf, told FC. “If we get a good opportunity, we can spend in multiples of our cash reserve. We do not have any borrowings,” he added.

Canada started exploiting oil sands in 1999. Reports suggest that crude oil output from oil sands in Canada is expected to touch 2.7 million barrels per day (mbpd) by 2015 from 1 mbpd in 2004.

“Exploitation of oil sands becomes economically viable if global crude oil price remains above $80 a barrel. Since crude oil price is hovering above $120 a barrel and if it stays at these levels, crude oil extracted from oil sands will generate additional revenue for companies,” said Kalpana Jain, senior director at international consulting firm Deloitte Touche Tohmatsu India.

ONGC has already invested in an oil sand project in Carabobo in Venezuela and expects to drill oil from the acreage by 2014-15, Hazarika said.

Last year, the government allowed ONGC Videsh, the overseas subsidiary of the government-run firm, to spend $1.33 billion on exploration of hydrocarbon resources in Carabobo-1 project. Its partners Indian Oil Corporation and Oil India would also invest $424 million in the project.

U.S. / CANADA

Precision Drilling Announces Additional New Build Rigs and Capital Expenditures

Precision Drilling Corporation announced May 11, that capital expenditures plans have increased again this year due to the strong demand for Precision's new Super Series drilling rigs. Precision has increased its 2011 new build rig program to 28 rigs, which includes the May 11 announcement of 16 new Super Series rigs added to the 12 Super Series rigs previously announced. These 16 rigs consist of three Super Single rigs for Canada and 13 Super Triple rigs for the United States. Of the total 28 rigs in the 2011 program, Precision expects to deliver 21 in 2011 and the remaining seven in 2012. Precision has committed to 37 new build rigs since the beginning of 2010.

For the 28 new build rigs in the 2011 program, Precision has signed term contracts for 17 rigs to date with an average term over three years. Precision has firm commitments from customers for the majority of the remaining 11 rigs and Precision fully expects to complete contracts for all 11 of these rigs in the next couple of months on terms similar to the term contracts already in place.

Precision now estimates that capital expenditures for 2011 will total $790 million. To complete the 2011 new build rig program and rig upgrades, Precision expects there will also be an additional $152 million of capital expenditures in 2012. The total 2011 capital expenditure plan includes $121 million for sustaining and infrastructure expenditures and is based upon currently anticipated activity levels for the year. Additionally, $458 million is slated for expansion capital for the 2010 and 2011 new build rig programs. The total capital expenditures also include the cost to upgrade eight to twelve rigs and to purchase long lead time items for future new build rigs or upgrades at an anticipated cost of $211 million. Certain rig upgrades will depend upon the successful completion of term contracts prior to incurring the planned capital expenditures. Precision expects the $790 million will be split $718 million for the Contract Drilling segment and $72 million for the Completion and Production Services segment.

Kevin Neveu, President and Chief Executive Officer stated, "The continued strong demand for Precision's Super Series rigs is indicative of the long term confidence our customers have in the High Performance, High Value capabilities our rigs are well known for. I am particularly pleased to see the strong market demand for the Super Triple rig in the Bakken and Eagle Ford plays with 13 of today's announced new builds slated for those oil and natural gas liquids rich plays."

"With the strength of Precision's balance sheet and cash flow generated from ongoing operations, coupled with our outstanding engineering and manufacturing divisions, Precision is in a great position to take advantage of these new build rig opportunities. Our increased capital commitment underscores Precision's confidence in the drilling market and our ability to deliver new build rigs on time and on budget. We are highly confident that the firm customer commitments for the new build rigs will be converted to term contracts over the coming weeks. Precision will, however, continue to be disciplined in our capital expenditures by not completing new build rigs or major rig upgrades unless they are secured by term contracts that provide acceptable financial returns", concluded Mr. Neveu.

ASIA

CHINA

Sasol Considers Plans to Produce Fuel from Shale Gas, Coal in China

Sasol Ltd. (SOL), the world’s largest maker of motor fuels from coal, is open to adding plants to convert coal to fuels in regions of China such as Xinjiang, said John Armstrong, company president for the country.

The Johannesburg-based company will also consider projects to turn shale gas into liquid fuels should the nation allow access to such an industry in the future, Armstrong said in an interview in Tianjin May17.

Sasol is trying to gain a foothold in China with a $10 billion joint venture coal liquefaction facility in the Ningxia Hui autonomous region with Shenhua Ningxia Coal Industry Group Ltd., a unit of the nation’s biggest coal producer. Sasol has halted development of the plant pending state approval, the company said in February.

“We are alert to other opportunities,” Armstrong said. “But the focus remains on Ningxia and we will not do anything to detract from this,” he said.

Sasol, South Africa’s second-biggest company by market value; uses its Fischer-Tropsch technology to transform gas from below the ocean floor and coal into liquid fuels such as gasoline and diesel in South Africa and Qatar.

“We have that one project on the go and it’s still our best entree into business in China,” Armstrong said, referring to the Ningxia project. “But maybe it won’t be the only one. Maybe there’ll be other partners or a different region. It’s hard for anyone to say no to a project in Xinjiang,” he said.

China is developing poorer provinces in the west including resource-rich Xinjiang, which contains 40 percent of the nation’s proven coal reserves, according to government data.

The country has tapped foreign companies including Royal Dutch Shell Plc (RDSA) and Chevron Corp. (CVX) to help explore and extract shale gas reserves, estimated to be 12 times higher than conventional gas reserves, according to the U.S. Energy Department last month.

“Right now, China places quite a bit of restriction on what you can do with gas and at the moment, gas to liquid isn’t too much on the radar screen,” Armstrong said. “Depending on what happens to shale gas that might change.”

Coal-to-liquids and coal-to-gas projects were removed from the Chinese government’s list of industries whose development it plans to encourage, according to an April 26 report on the website of the National Development and Reform Commission, China’s top economic planning agency.

Sasol hasn’t set a deadline for getting government approval for the Ningxia project, Armstrong said.

“We still think we are moving in the right direction although that’s moving slower than we’d like,” he said.

Sasol submitted an application with Shenhua to the NDRC in 2009 and expected recommendations by the end of 2010, the company said last August.

It said in March 2010 it may decide on whether to go ahead with the 3.85 million metric ton-a-year Ningxia plant, about 810 miles (1,300 kilometers) southwest of Beijing, by the end of that year.

The company is cutting costs at its China operations to be “in the game for longer,” Armstrong said. Sasol has reduced its China-based staff to around 20 compared with a crew of 50 people at the peak, he said.

“Given what we’ve invested in the project so far, Sasol would be very cautious to walk away earlier than is required,” he said, declining to provide details on the company’s investments in the China business.

Shares of Sasol, which converts more than 40 million tons of coal annually at the world’s largest plant in Secunda, South Africa, gained 27 percent in Johannesburg in the past 12 months as rising oil prices increased the value of alternative fuels. The stock fell 0.9 percent to 357.5 rand at 12:18 p.m. local time today.

Armstrong said he isn’t planning to reduce Sasol’s China headcount further if delays to the Ningxia project continue.

“On the contrary, I’m thinking of how I’m going to remobilize, on which guys I should bring back to make sure we’ve got a strong team so that when somebody pushes the button and says go, I can go,” he said.

EUROPE

BULGARIA

Chevron Wins Tender to Explore for Shale Gas in Bulgaria

Chevron has been awarded a contract to carry out shale gas exploration in northeastern Bulgaria, outbidding Canadian sector player BNK Petroleum, the country's Economy Minister Traicho Traikov said.

The agreement is now subject to approval by the Cabinet, he said.

According to preliminary estimates, the field near the town of Novi Pazar has reserves of about one trillion cu m of shale gas, which would ensure the country's gas consumption in the next 300 years.

Chevron has said it would invest 30 million euro in exploration works at the field, which covers 600 km.

Alternative natural gas sources in Bulgaria are expected to help the country negotiate more favorable terms for gas deliveries with Russia after 2012, the Economy Ministry said. In addition, the country plans to expand the capacity of its natural gas storage in Chiren by September, which will boost the maximum daily consumption rate to 5.5 million cu m from 4.3 million cu m currently.

The country could also take advantage of the planned roll-out of interconnection gas links with neighboring countries. The gas inter-connectors with Greece are expected to be completed by the end of 2014, although the country initially intended to build the link by 2013, Traikov said.

POLAND

Shale Gas Exploration Projects in Poland to Get Impetus

Polish and foreign firms will likely carry out about 100 shale gas exploration drillings in Poland within the coming 2-3 years, and the number will be even higher after the period, Polish gas giant PGNiG's oil and gas exploration unit CEO Maciej Zalubski told Parkiet daily.

The first 100 drillings will show, which projects should be dropped and which should be pursued, Zalubski said, adding that the current discussion of the topic is held in the sphere of scientific reports, and not local, on-the-site tests.

So far seen 7 shale gas drillings have been made, while companies searching for the resource have obliged themselves to conduct another 122 such drillings until 2017, the daily adds.

McIlvaine Company,

Northfield, IL 60093-2743

Tel: 847-784-0012; Fax: 847-784-0061;

E-mail: editor@mcilvainecompany.com