The one-hour health standard reportedly will protect millions of Americans from short-term exposure to SO2, which is primarily emitted from power plants and other industrial facilities. Exposure to SO2 can aggravate asthma and cause other respiratory difficulties. People with asthma, children, and the elderly are especially vulnerable to the effects of SO2.

"We're taking on an old problem in a new way, one designed to give all American communities the clean air protections they deserve. Moving to a one-hour standard and monitoring in the areas with the highest SO2 levels is the most efficient and effective way to protect against sulfur dioxide pollution in the air we breathe," said EPA Administrator Lisa P. Jackson. "This is one of many pollutants we've been able to significantly reduce through the Clean Air Act, keeping people healthy, protecting our environment and growing our economy. This new standard -- the first in almost 40 years -- will ensure continued success in meeting these challenges."

EPA is setting the one-hour SO2 health standard at 75 parts per billion (ppb), a level designed to protect against short-term exposures ranging from five minutes to 24 hours. EPA is revoking the current 24-hour and annual SO2 health standards, claiming that the science indicates that short-term exposures are of greatest concern and the existing standards would not provide additional health benefits.

EPA is also changing the monitoring requirements for SO2. The new requirements assure that monitors will be placed where SO2 emissions impact populated areas. Any new monitors required by this rule must begin operating no later than Jan. 1, 2013. EPA is expecting to use modeling as well as monitoring to determine compliance with the new standard.

The final rule also changes the Air Quality Index to reflect the revised SO2 standard. This change will improve states' ability to alert the public when short-term SO2 levels may affect their health.

EPA estimates that the health benefits associated with this rule range between $13 billion and $33 billion annually. These benefits include preventing 2,300 to 5,900 premature deaths and 54,000 asthma attacks a year. The estimated cost in 2020 to fully implement this standard is approximately $1.5 billion.

The first National Ambient Air Quality Standards for SO2 were set in 1971, establishing both a primary standard to protect health and a secondary standard to protect the public welfare. Annual average SO2 concentrations have decreased by 71 percent since 1980.

The final rule addresses only the SO2 primary standards, which are designed to protect public health. EPA will address the secondary standard -- designed to protect the public welfare, including the environment -- as part of a separate review to be completed in 2012.

EPA expects to identify or designate areas not meeting the new standard by June 2012.

More information: http://www.epa.gov/air/sulfurdioxide

MarkWest, Sunoco Logistics Plan Marcellus Ethane Pipeline

MarkWest Liberty Midstream & Resources, LLC, a partnership between MarkWest Energy Partners, L.P. and The Energy & Minerals Group, and Sunoco Logistics Partners L.P. on June 2 announced a combined pipeline and marine project for ethane produced in the Marcellus Shale Basin.

The Mariner Project is anticipated to have initial capacity to transport up to 50,000 barrels per day of ethane to Gulf Coast markets as soon as the second quarter of 2012 and could be scaled to transport higher volumes to support additional ethane production in the Marcellus region. MarkWest Liberty has been working with key producers and petrochemical consumers since late 2009 and the project is supported by key producers including Range Resources Corp. and Chesapeake Energy Corp.

The Mariner Project includes MarkWest Liberty making minor modifications to its processing facilities to recover sufficient ethane to allow the residue gas to meet interstate gas pipeline specifications and installing additional facilities at its Houston, Pennsylvania processing and fractionation complex to separate the ethane for delivery to downstream Mariner Project facilities. MarkWest Liberty will also construct a 45-mile pipeline from the Houston complex to an interconnection with an existing Sunoco Logistics pipeline at Delmont, Pennsylvania. The ethane will be transported to an existing East Coast facility where Sunoco Logistics will construct refrigerated ethane storage facilities. The ethane will then be transported via marine vessel to premium markets in the Gulf Coast. In addition, the existing Sunoco Logistics pipeline crosses many of the large pipelines transporting natural gas into the northeast, which will provide multiple ethane blending options.

"We are excited to be able to participate in the Mariner Project and we are especially pleased to partner with MarkWest Liberty due to their extensive experience in the Marcellus Shale Basin," said Deborah M. Fretz, President and Chief Executive Officer of Sunoco Logistics. "Our existing Pennsylvania active and idle pipeline infrastructure is well-positioned to provide an efficient solution for producers to move ethane across Pennsylvania to a Delaware River marine port to access multiple markets. The combination of MarkWest Liberty's fractionation complex and Sunoco Logistics' transportation system offers producers a higher value for their natural gas liquids by transporting only the ethane portion of the liquids and allowing the heavier liquids to remain in the northeast marketplace."

Frank M. Semple, Chairman, President and Chief Executive Officer of MarkWest stated, "We have been working with Sunoco Logistics and our producer customers for a number of months and we believe the Mariner Project provides the most efficient solution to maximize the value of Marcellus ethane, supports the development of more than 2 BCF per day of Marcellus rich gas, and significantly accelerates the in-service date to transport ethane compared to other pipeline projects. MarkWest and The Energy & Minerals Group are very pleased to partner with Sunoco Logistics because of their strong set of assets and significant experience in the storage and transportation of liquefied petroleum gas."

ETP to Build E. Texas Pipeline in Haynesville Shale

Energy Transfer Partners, L.P. (ETP) on June 2 announced the construction of a 63-mile natural gas pipeline that will provide its customers additional transportation, gathering, and treating services in the rapidly expanding Haynesville Shale in East Texas.

The pipeline project, which will originate in southeast Shelby County, Texas, traverse San Augustine County and terminate in Nacogdoches County, Texas, will consist of predominately 20 and 24-inch pipe and will have an initial capacity of 645 million cubic feet per day. The pipeline is supported by natural gas production from multiple 10-year agreements that encompass approximately 264,000 acres in the East Texas area.

The pipeline will interconnect with two interstate pipelines in addition to the Partnership's Houston Pipeline System, which provides producers the option to access numerous other interstate and intrastate markets including the Carthage, Waha, Katy and Houston Ship Channel hubs in Texas. Partial service is expected to begin on the pipeline in the third quarter of this year and the full in-service date is expected to be in the fourth quarter 2010.

"This project shows our continued emphasis on developing organic growth projects and providing producers unparalleled access to markets throughout the country," said Energy Transfer Partners' Tim Dahlstrom, Senior Vice-President. "Our partnership is excited about this new opportunity to expand our pipeline network into a rapidly growing area of James Lime, Bossier and Haynesville production."

Energy Transfer Partners, L.P. is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Colorado, Louisiana, New Mexico, and Utah, and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include more than 17,500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas.

Willbros Awards AUT Fayetteville Express NDT Project

AUT Specialists has been awarded spreads 3 and 4 of the Fayetteville Express Project (FEP) by Willbros Construction of Houston, Texas. The project start date was mid-March 2010.

The 185-mile natural gas pipeline will originate in Conway County, Arkansas, continue eastward through White County, Arkansas, and terminate at an interconnect with Trunkline Gas Company in Panola County, Mississippi. FEP will deliver clean-burning natural gas supplies from the Fayetteville Shale in Arkansas to communities along the route. In addition, it will provide an alternate route for natural gas when hurricanes and tropical storms disrupt offshore and coastal supplies.

FEP is a joint venture between Energy Transfer Partners, L.P. and Kinder Morgan Energy Partners, L.P. Willbros' scope of work includes 120 miles of 42-inch pipeline with wall thicknesses ranging from .555" to .888" wall. It originates near Bald Knob, Arkansas and ends at the Trunkline interconnection. The project is expected to begin construction in April 2010 and be completed in October 2010.

AUT Specialists LLC provides a worldwide service in the non-destructive testing industry. It specializes in the highly effective use of automated ultrasonic testing to inspect pipeline girth welds in the construction phase of oil and gas pipelines. Other offered services include radiography, magnetic particle, and dye penetrant testing.

Union Drilling in West Virginia Blast has History of Violations

The Texas gas-drilling company that struck methane in an abandoned West Virginia coal mine and triggered an explosion that hurt seven workers has paid more than $226,000 in fines for federal safety violations over the past five years.

In every case, records show the original fines the Occupational Safety and Health Administration recommended for Fort Worth-based Union Drilling Inc. were later reduced, either through informal settlements or proceedings with an administrative law judge.

OSHA has done 20 inspections of Union Drilling operations around the country since February 2006, and 13 of those resulted in violations, said Leni Uddyback-Fortson, spokeswoman for Region 3 in Philadelphia.

She could not comment on whether the violation rate is unusual for the industry.

"The inspections and the citations that have resulted sort of speak for themselves," she said. "It shows that there is a history there."

Union has not responded to repeated telephone messages. It has not commented on the June 7 explosion near Moundsville except to say it's cooperating with investigators.

All the workers hurt in the blast are expected to recover.

A team from Texas-based rig-fire expert Wild Well Control has been moving damaged equipment as the venting methane burns off and will try to cap the well when the team can safely approach it. Union crews had drilled through the mine before without incident, and it's unclear what might have ignited the methane.

The state Department of Environmental Protection says the mine had been inactive since 1977.

Union was drilling the well for Chief Oil & Gas LLC of Dallas, Texas, which has a participation interest in the well with permit holder AB Resources of Brecksville, Ohio. The Union crew from Buckhannon had drilled only 1,000 feet toward the mile-deep Marcellus shale gas field when it hit the methane.

The DEP has no record of any violations in West Virginia by either Chief or AB Resources, spokeswoman Kathy Cosco said. Union was not listed as a responsible party, so it would not have been cited, but any violations would have been recorded against AB Resources.

But federal records show safety problems are common at Union sites.

In one pending case from August 2009, 22 violations were cited at a well in New Salem, Pa. OSHA has recommended more than $54,000 in fines, the largest a $15,000 penalty for failing to guard holes and floor or wall openings.

That violation, a common industry hazard, routinely shows up in OSHA's records for Union.

"The rigs are mobile and can be taken from site to site, and often the safety railing and walkways are not put in properly," Uddyback-Fortson said.

Union was also cited in the New Salem case for deficiencies in medical services and first aid, for exposing workers to falling objects by improperly modifying a wire rope hoist and for general safety infractions.

In more than half of the inspections that resulted in violations since 2006, OSHA recommended fines of more than $25,000, indicating either the number or severity of infractions, or the fact that it was a repeat or willful violation.

It is not uncommon to reduce those fines as part of a settlement package, Uddyback-Fortson said. Companies are also often required to correct problems by installing equipment or taking some other action.

"The most important thing is that the hazard is removed, that the workers are safe on the job," she said.

One of the highest fines - $31,000 for February 2008 violations in Smyrna, N.Y. - was later reduced to $9,000, OSHA records show. An April 2007 fine of $32,000 for violations in Rose Bud, Ark., was reduced to $7,000.

Three $25,000 fines in the Pennsylvania towns of Otter Creek, Meadville and Pymatuning were reduced to either $22,000 or $17,500.

Federal court records also show Union settled a 2008 negligence lawsuit in Arkansas earlier this year.

Senate Resolution Would Overturn EPA's 'Endangerment' Finding

A group of 24 trade associations representing a broad range of employers that provide jobs to millions of Americans is urging U.S. senators to bar the Environmental Protection Agency from going around Congress to regulate greenhouse gas emissions under the Clean Air Act.

The group has sent a letter to all senators urging them to support Senate Joint Resolution 26, a bipartisan measure introduced by Sen. Lisa Murkowski (R-Alaska).

The resolution would overturn EPA's 2009 "endangerment" finding, which concluded that greenhouse gas emissions endanger public health and welfare. The finding paved the way for EPA to regulate car and light-duty truck emissions of greenhouse gases, which in turn has triggered subsequent EPA regulation of greenhouse gas emissions from other commercial and industrial sources.

"Massive and rapidly imposed restrictions on greenhouse gas emissions would harm the American economy and hit every American in his or her wallet," said Charles T. Drevna, president of the National Petrochemical & Refiners Association, one of the groups signing the letter.

"If EPA's aggressive campaign to regulate greenhouse gases under the Clean Air Act is successful, it will add billions of dollars to the cost of doing business in the United States, raise the cost of energy and other products for American families, wipe out the jobs of millions of American workers, and simply shift greenhouse gas emissions from the United States to other nations without any increase in environmental protection," Drevna added.

"Restrictions on greenhouse gas emissions were never authorized or contemplated by members of Congress when they enacted the Clean Air Act," Drevna said. "Sen. Murkowski's resolution simply recognizes this truth and calls a halt to EPA's greenhouse gas campaign before it harms the American economy, destroys American jobs, and costs families and farmers billions of dollars."

The letter's signatories also urged senators to reject any effort to codify the EPA's recently released "tailoring" rule into law. That rule would subject only stationary sources of greenhouse gas emissions of 100,000 tons or more annually to state government permitting requirements under the Clean Air Act. The Clean Air Act, however, sets a permitting threshold of 250 tons annually for emissions from major sources.

Groups signing the letter are: American Coke and Coal Chemicals Institute; American Iron and Steel Institute; American Health Care Association; American Petroleum Institute; Associated General Contractors of America; The Center for North American Energy Security; Corn Refiners Association; Industrial Energy Consumers of America; Industrial Minerals Association - North America; International Warehouse Logistics Association; Metals Service Center Institute; National Association of Convenience Stores; National Association of Manufacturers; National Cattlemen's Beef Association; National Center for Assisted Living; National Mining Association; National Petrochemical & Refiners Association; Natural Gas Supply Association; Portland Cement Association; Society of Independent Gasoline Marketers of America; Small Business & Entrepreneurship Council; The Fertilizer Institute; U.S. Chamber of Commerce; and U.S. Oil and Gas Association.

EPA Pulls ECF Rule

The U.S. Environmental Protection Agency (EPA) has withdrawn the Emission Comparable Fuels (ECF) Rule, a rule that was finalized in December 2008. The agency stated the rule sought to remove regulatory costs by reclassifying fuels that would otherwise be regulated as hazardous waste, but generate emissions similar to fuel oil when burned.

EPA has now withdrawn the rule due to difficulty of ensuring that emissions from burning ECF are comparable to emissions from burning fuel oil.

The ECF rule was criticized for potentially allowing hazardous waste to evade the hazardous waste regulatory system, and for being difficult to administer. Industry members have also criticized it because of the detailed conditions for reclassification, which they believe will limit the rule's use.

More information on the rule: http://www.epa.gov/epawaste/hazard/tsd/td/combust/compfuels/exclusion.htm

Boardwalk Pipeline, Southcross Energy to Serve Eagle Ford Producers

Boardwalk Pipeline Partners, LP and Southcross Energy, LLC, with its affiliates, on June 15 announced that they will work together to provide infrastructure solutions to natural gas producers in the Eagle Ford Shale production area located in South Texas.

Boardwalk plans to modify an existing section of its subsidiary Gulf South Pipeline's 30-inch pipeline from Refugio, Texas to Fort Bend County, Texas, so that condensate-rich Eagle Ford Shale gas can be accepted into that pipeline segment. Southcross Energy will connect its existing gathering facilities in South Texas to the newly modified Gulf South pipeline segment so that condensate-rich Eagle Ford gas can then be transported to four Gulf Coast processing plants currently served by Southcross Energy including its Gregory Plant, located near Corpus Christi, Texas.

Rolf Gafvert, Chief Executive Officer for Boardwalk and David Biegler, Chairman of Southcross, said, "By leveraging existing assets from both companies, Boardwalk and Southcross Energy are well positioned to offer Eagle Ford Shale gas producers the infrastructure needed to gather, transport and process their condensate-rich gas. We anticipate that portions of our newly proposed solution could be operational later this year and that both companies will seek to expand their pipeline capacity in this region."

Boardwalk Pipeline Partners, LP, is a limited partnership engaged, through its subsidiaries, Gulf Crossing Pipeline Company LLC, Gulf South Pipeline Company, LP, and Texas Gas Transmission, LLC, in the interstate transportation and storage of natural gas. Boardwalk's interstate natural gas pipeline systems have approximately 14,200 miles of pipeline and underground storage fields having aggregate working gas capacity of approximately 163 Bcf.

Southcross Energy GP LLC is a midstream natural gas company engaged in the purchase and sale, pipeline transportation, gathering and processing of natural gas. It operates in South Texas, Mississippi and Alabama with a total of more than 2,100 miles of pipeline and gathering assets.

Energy Transfer Applies to FERC for Expansion of Tiger Pipeline

Energy Transfer Partners, L.P. (ETP) on June 17 announced that it has filed an application with the Federal Energy Regulatory Commission (FERC) requesting a certificate of public convenience and necessity that would authorize construction and operation of the ETC Tiger Pipeline Expansion Project, Phase I (Tiger Expansion). The Tiger Expansion is expected to add 400 million cubic feet per day of capacity to the ETC Tiger Pipeline system, bringing total capacity to 2.4 billion cubic feet per day, all of which is sold out under long-term contracts ranging from 10 to 15 years.

"This expansion of the Tiger System will provide vital take away capacity from the Haynesville Shale and Middle Bossier shale production areas in Louisiana and East Texas, to markets in the eastern half of the US," said Luke Fletcher, vice president, Energy Transfer Partners Interstate Pipeline Division.

Construction began earlier this month on the original 42-inch Tiger Pipeline, an approximately 175-mile interstate natural gas pipeline originating in Panola County, Texas and terminating in Richland Parish, Louisiana. The Tiger Pipeline will interconnect to seven interstate pipelines and one intrastate pipeline for ultimate delivery to markets across the Northeast, Southeast, Mid-Atlantic and Midwest.

The Tiger Pipeline, which will have an initial capacity of 2 billion cubic feet per day, is expected to be in service in the first quarter of 2011. The Tiger Expansion is expected to be in service in the last half of 2011. Energy Transfer Partners, L.P. is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Colorado, Louisiana, New Mexico, and Utah, and owns the largest intrastate pipeline system in Texas. ETP currently has natural gas operations that include more than 17,500 miles of gathering and transportation pipelines, treating and processing assets, and three storage facilities located in Texas. ETP also is one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.

Dominion Announces 15-year Contract for Marcellus Project

Dominion on June 14 announced that its natural gas transmission and storage subsidiary, Dominion Transmission, has reached a 15-year agreement with the gas subsidiary of CONSOL Energy Inc. for firm transportation of CONSOL's Marcellus shale natural gas production.

The project, capable of transporting 200,000 dekatherms per day, will move supplies from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Clinton County, Pa.

"Dominion is pleased to provide CONSOL with year-round access to growing Northeast markets and to provide another supply alternative for market area customers," said Gary Sypolt, chief executive officer of Dominion Energy.

Earlier this year Dominion sold its natural gas exploration and production business to CONSOL so that the company could concentrate on its regulated businesses, including increased transportation and storage infrastructure opportunities resulting from Marcellus shale discoveries.

Dominion plans to file for a FERC certificate in December. If the project is approved, construction is planned to begin in March 2012, and it would enter service in November 2012. Construction plans include new compression facilities at three existing compressor stations in central Pennsylvania.

Dominion Transmission provides gathering, processing, transportation and storage services, operating in the heart of the Marcellus shale production area.

CONSOL Energy, the leading diversified coal and gas producer in the Appalachian Basin, is a member of Standard & Poor's 500 Equity Index and the Fortune 500. At year-end 2009, it had 11 bituminous coal mining complexes in six states and reports proven and probable coal reserves of 4.5 billion tons. It is also the leading Appalachian gas producer, with proved reserves of 2.9 trillion cubic feet.

Congressmen Seek to Delay TransCanada Keystone Pipeline

A group of U.S. representatives has asked the State Department not to approve a TransCanada Corp. oil-sands pipeline until the oil’s effect on greenhouse-gas emissions is studied.

Representatives Jay Inslee of Washington, Peter Welch of Vermont and Dennis Kucinich of Ohio joined at least 46 other House Democrats signing the letter June 23 to Secretary of State Hillary Clinton, asking for the study before the State Department issues its presidential permit for the project. The pipeline, which would stretch from oil-sands formations in Alberta to the Texas Gulf Coast, needs the permit because it crosses the U.S. border.

The Keystone XL pipeline expansion would add 500,000 barrels a day of crude oil capacity to the system, which Calgary-based TransCanada estimates will cost $12 billion in total. The 1,980-mile (3,185-kilometer) XL project extends the company’s existing Keystone pipeline, which runs through Canada to the central U.S. and begins operating this year.

“The issuance of a presidential permit to build this pipeline would have significant energy and environment implications for our nation for many years to come,” the representatives wrote. “Building this pipeline has the potential to undermine America’s clean energy future and international leadership on climate change.”

Studies have found extracting oil from the sands emits three times more greenhouse gases than conventional petroleum production, according to the letter. The letter asks Clinton to study how greenhouse gases, which contribute to climate change, may change over the life cycle of the pipeline.

The 327-mile Canadian portion of the Keystone XL pipeline will run from Hardisty, Alberta, to the U.S. border at Monchy, Saskatchewan. From there the 36-inch diameter line will cut across Montana, South Dakota and Nebraska before joining the existing Keystone pipeline. The XL expansion will also extend the pipeline from Cushing, Oklahoma, to Houston and Port Arthur, Texas.

“We disagree that there is a requirement to expand” the permitting process, Robert Jones, TransCanada’s Keystone Pipeline vice president, said during a telephone interview from the company’s Calgary headquarters. “It’s very obvious and quite transparent that the individuals that signed this letter don’t represent any of the states of which the Keystone pipeline system will run through and runs through.”

TransCanada owns Canada’s largest pipeline system. The company became the sole owner of Keystone in August, buying ConocoPhillips’s 20.1 percent stake for about $550 million. The company cited increasing oil-sands production in its decision to buy out its partner. ConocoPhillips had owned as much as 50 percent of the line.

TransCanada began filling part of the Keystone pipeline with oil earlier this year. The Keystone XL expansion is supposed to start operating in 2012, according to TransCanada’s website.

Shale Gas Pollution Fears Give U.S. another Energy Controversy

After BP’s giant Gulf of Mexico spill, it couldn’t be a worse time for America’s oil giants to find themselves in another environmental firestorm.

But a new controversy has been born, emanating from the drinking water of people living near so-called “shale gas” fields.

A controversial documentary, Gaslands, which was aired on television channel HBO in June, shows one Colorado homeowner bending over his tap, holding a lighter with outstretched arm and igniting his chemical-laden water.

The film – openly controversial– alleges shale gas drillers, using a process to release gas known as hydraulic fracturing, which involves blasting millions of gallons of water, sand and diluted chemicals into shale rock, breaking it apart to free the gas, have allowed pollutants to affect local drinking water in multiple locations.

Its director, Josh Fox, interviewed people in Colorado, Texas, Wyoming, Utah, New Mexico and Pennsylvania. Cloudy, smelly, gassy water is flowing out of their pipes. Rivers are catching fire. Some claim – which is hard to prove – that they have been made sick. And the gas companies in many places are allegedly trucking in clean drinking water in return for non-disclosure agreements.

Fox, a Pennsylvania playwright, calls the industry's contention that such drilling is harmless too good to be true. He started asking questions when his family was offered $100,000 plus royalties to allow hydraulic fracturing, also known as "fracking," on their property.

"I don't think it's a gold mine. I think it's a trap," Fox said. He turned down the offer but many neighbors took the money.

The documentary which traces Fox's cross-country journey; includes interviews with families who signed leases with the gas industry and now regret it.

The industry, particularly a website called Energy In Depth, is furious at the implications.

It quickly issued a point-by-point rebuttal, saying any pollution has been due to the bad practices of individual companies rather than industry-wide problems and accusing Fox of factual inaccuracies. The director counters that the footage and testimony in his film speak for themselves.

It is hard to work out exactly who or which organization is behind the collective of oil and gas pressure groups at Energy in Depth, which says it is “working to keep energy affordable here at home, creating new jobs and minimizing our dangerous dependence on foreign oil”.

The only clue is its registration at the address of the powerful PR and lobbying firm Financial Dynamics (FD) Americas.

It is clear that the big corporate spinners and lawyers have come out against this film, which is currently riding high on the wave of popular anger against the oil industry’s perceived neglect of safety in the pursuit of profit.

Energy companies, including BP, have been involved in lobbying against tighter shale gas regulation, asking that decisions are taken at state level, rather than being left to the Environmental Protection Agency (EPA).

Of course, they have a huge amount to lose if the U.S. suddenly loses its focus on shale.

The London-listed companies are exposed to the tune of billions: Shell bought up $4.7bn of assets in Marcellus last month, BG Group has a $2bn joint venture with Exco and BP has a $2.5bn partnership with Chesapeake.

They have all come over to shale drilling in the last couple of years, touting the technology as the answer to America’s energy thirst.

Since energy sources are trying to wean themselves off oil and coal, which have high carbon dioxide emissions, gas has been proposed as a more climate-friendly replacement fuel.

But the best thing about shale is its abundance. It’s been hailed as a “complete game changer” (by BP’s Tony Hayward) and “a huge deal” (by Shell’s Peter Voser).

In fact, the newly discovered resource could provide up to 100 years of U.S. needs and leave it less dependent on foreign supplies.

As a result, shale has been looking like an increasingly attractive option at a time when the oil industry is facing the prospect of a U.S. retrenchment from deepwater drilling activity in the wake of BP’s spill.

However, to say that goodwill towards energy companies is at a low point is an understatement. BP’s Gulf of Mexico leak has put the entire U.S. energy industry under a cloud of suspicion and mistrust. The calls for a suspension of shale drilling pending more environmental research are getting stronger.

Furthermore, twice in recent weeks, there have been accidents in the Marcellus fields, including a leak in Pennsylvania that expelled 35,000 gallons of gas and a blast in West Virginia that sent at least seven workers to the hospitals with burns.

Like the BP oil spill, it’s become an election issue. “I think it’s extremely critical that we take a step back from the ongoing drilling in Marcellus Shale fields for at least one year,” urged state senator Jim Ferlo of D-Pittsburgh this month.

Whatever the truth behind some of the claims in the Fox film and fresh safety fears; Americans will soon be forced into a national debate that balances the dangers of exploration and drilling against rampant energy consumption.

There’s already an inquiry into the safety of gas fracturing currently being conducted by the Environmental Protection Agency.

Given President Obama’s current hostility toward the energy giants, the authorities are going to be under pressure to make regulations watertight, or put aside the gas industry’s shale ambitions for the time being.

Study Says Two-thirds of Marcellus Gas could be Exempted from Taxes

Even if Pennsylvania adopts a tax on gas extracted from the Marcellus Shale, two-thirds of it would be exempt under proposals being considered, says a Pennsylvania Budget and Policy Center study released June 24.

Lawmakers want to exclude low-producing wells from the tax, which would protect existing shallow wells as well as the deeper Marcellus wells during the later years of their production. A well usually produces the most gas immediately after drilling, then drops sharply the next two years and tapers off more gradually over the remaining life of the well, according to the study.

The gas industry is pressing for a tax exemption in the first, most productive years as well, saying it would allow them to recoup some of the costs of drilling.

The Budget and Policy Center study looked at the tax laws in Texas and Arkansas as well as gas production data from the Barnett Shale formation, similar to the Marcellus but drilled earlier. The study suggests that the "back-end" exemption for low-producing wells would exclude 22 percent of a typical well’s production from taxation, while the "front-end" exemption would exclude another 42 percent from taxation.

Pennsylvania Budget and Policy Center Director Sharon Ward said that as lawmakers craft a tax on the burgeoning industry, they "are negotiating for a client, and that client is the citizens of Pennsylvania."

"We ask they negotiate well," Ward said, and "we urge them not to give away the store."

David Levdansky, D-Allegheny and co-sponsor of the leading gas tax bill, said he does not accept the industry’s claim that an exemption in the early years is needed to recoup costs and make Pennsylvania competitive with other states.

Pennsylvania gas wells are not subject to property tax, he said, unlike in Texas, where the property taxes on wells is often higher than the severance tax.

Taxation of mineral rights was halted by a 2002 Pennsylvania Supreme Court ruling, and the Legislature has not changed the language in the law to allow the taxation to resume. What’s more, said Levdansky, over two-thirds of the Marcellus Shale wells drilled in Pennsylvania last year were drilled by businesses that do not pay corporate net income tax because they are registered as limited liability companies.

"We certainly don’t want to discourage investment," Levdansky said, but "Why do we have to give the gas drilling industry any more incentive than they already have?"

Kathryn Klaber, president of the Marcellus Shale Coalition, which represents the gas industry, said Marcellus Shale gas development is creating thousands of jobs and is generating "millions in state and local tax revenues." Klaber said, "It’s remarkable that organizations and individuals that claim they support working Pennsylvanians can also discourage the very investment that make those jobs possible."

India’s Reliance Pays $1.3 Bln for Pioneer's Texas Shale Gas

Reliance Industries said June 24 it has agreed to pay $1.3 billion for a stake in the shale gas assets of Texas-based Pioneer Natural Resources Co. as the Indian oil and gas major expands its upstream business in North America.

Reliance subsidiary Reliance Eagleford Upstream LP will pay $263 million upfront for a 45 percent interest in Pioneer's Eagle Ford shale acreage in south Texas, representing 118,000 acres of the 263,000 acre field, which Reliance says holds about 10 trillion cubic feet of gas equivalent.

It is the second such deal this year for Reliance as it chases resources and expertise in promising unconventional gas reserves in North America.

"This transaction represents another significant milestone in Reliance's efforts to grow its North American shale gas operations," executive director PMS Prasad said in a statement.

In April, Reliance agreed to pay $1.7 billion for a 40 percent stake in Atlas Energy's Marcellus shale acreage in West Virginia, Pennsylvania and New York States. Reliance says the 343,000 acres hold an estimated 13 trillion cubic feet of gas.

Recently, chairman Mukesh Ambani told shareholders that Reliance would continue to use its considerable cash holdings to "build a substantial upstream business in North America."

Reliance is India's largest private sector company, with a market capitalization of $75.3 billion on the Bombay Stock Exchange and net profit last fiscal year of $3.6 billion on sales of $44.6 billion.

KKR to Invest $400 Million to Develop Shale Gas in Texas

KKR is investing $400 million in a joint venture with Hilcorp Energy Co. to develop the Eagle Ford Shale in South Texas, according to people familiar with the deal.

The transaction, expected to be announced June 14, is the latest transaction spotlighting intense interest in North American shale-gas, which is transforming the energy industry. In recent months both private-equity firms and foreign investors have invested billions of dollars in shale-gas production across the U.S.

For example, BP PLC, the oil company plagued by the oil spill in the Gulf of Mexico, announced an expansion of its U.S. shale-gas operations through a joint-venture deal in the Eagle Ford Shale with closely held Lewis Energy Group valued at least $160 million. And India's Reliance Industries Ltd. invested $1.7 billion for a 40% stake in a joint venture with Atlas Energy Inc., a company that controls acreage in the Marcellus Shale, a region stretching from New York to West Virginia.

Earlier this month, KKR was part of a large natural-gas deal expected to yield major profits for the firm. Royal Dutch Shell PLC agreed to buy East Resources Inc., a closely held U.S. natural-gas explorer in the Marcellus, for $4.7 billion. KKR paid $325 million for a roughly one-third stake in East Resources only one year ago.

KKR partner, Hilcorp, is one of the country's largest privately held oil-and-gas companies. The Houston-based Hilcorp will run the control 60% of the joint venture and run its operations, as well as contribute about 100,000 acres to the partnership, say people familiar with the deal.

Statoil Seeks to Build Up Presence in Marcellus Shale

Statoil ASA, Europe’s second-biggest gas exporter, is seeking to build up its presence in the Marcellus Shale formations in the eastern U.S. using the same strategy adopted at home, Chief Executive Helge Lund said.

In Europe, Statoil developed a portfolio of production assets, processing facilities, pipelines and storage capacity. Now its sights are focused on the natural-gas reserve underneath parts of New York, Pennsylvania and West Virginia.

“What’s most important when developing a gas position is to have upstream projects and good assets,” Lund said in an interview June 7 in Hammerfest, Norway. “We’ve done that in Europe for a long time and especially in Norway, and now we’re working on that at Marcellus.”

In March, Statoil added 59,000 net acres at Marcellus Shale to the 600,000 acres it acquired through an agreement with Chesapeake Energy Corp. in 2008. The company signed an agreement in May with National Fuel Gas Supply Corp. to deliver gas from the U.S. to Canada and in March to transport and deliver gas from Northern Marcellus to New Jersey and New York.

“To acquire midstream positions such as pipelines and storage possibilities can give us the opportunity to add value beyond just the raw sale of hydrocarbons,” Lund said. “So we’re working on building more flexibility.”

Statoil has a gas trading unit in Stamford, Connecticut, as well as two positions in a pipeline network, he said.

Producers such as Statoil, which operates 80 percent of Norway’s petroleum production, and BP Plc are tapping unconventional sources to stem a decline from fields in the North Sea and other maturing areas. Statoil is seeking to boost its reserve-replacement ratio, which hasn’t been above 100 percent since 2005. It rose to 73 percent last year from 34 percent in 2008, buoyed by the Marcellus acreage.

The company is on the hunt for further acquisitions, the CEO said.

“It’s our job to be on the look-out for opportunities in this area and others and we’ve shown in the last few years that we’re active,” Lund said. “There are other opportunities we have seized -- we took a small position with Chesapeake in South Africa and we’re doing a screening on a global basis.”

Lund declined to comment on whether Statoil is in talks with Pioneer Natural Resources Co. regarding a joint venture in the Eagle Ford Shale. The Irving, Texas-based company plans to make an announcement on the joint venture in the second quarter.

Statoil in February cut its output target for 2012 to between 2.1 million to 2.2 million barrels of oil equivalent a day, from 2.2 million a day, because of a weak gas market. The company said last month it expected conditions to “be challenging in the near term” after reporting a 35 percent slump in its gas prices in the first quarter.

Although gas prices are “pretty weak” at the moment due to increased supply of liquefied natural gas and shale gas production in the U.S. and weak demand, Lund expects the global market “to tighten in one to three years.”

Choking Back Gas Wells Signals Change in Haynesville Shale-Field Operations

Natural gas producers are choking back production from wells in the Haynesville Shale, in Texas and Louisiana, as a way of boosting the overall efficiency and life span of those wells.

The technique represents an important shift in the exploitation of gas from the dense sedimentary rock formations known as shales. Frenzied development flooded the natural gas market last year with, shale gas and the recession cut deeply into natural gas demand, pushing prices to a 7 1/2-year low last September. Now more measured growth from shales could help mitigate future gas gluts and allow for more orderly development of these gas-rich assets.

The progression could help support a recent upswing in prices, which have more than doubled from last year's lows due, in part, to the prospect of hot summer weather, which increases demand for gas-fired electricity, and a busy storm season, which increases the potential of supply disruptions.

Natural gas producers such as Petrohawk Energy Corp. (HK) and Devon Energy Corp. (DVN) have begun limiting initial production from their Haynesville wells. Petrohawk has cut its average initial production rate in half to about nine million cubic feet of natural gas a day. The Houston-based energy company will constrain production on all 110 operated wells it drills in the Haynesville shale this year, ultimately increasing the life and output of each well. However, the company hasn't yet provided an indication of how much more gas each well will eventually produce.

"Production management practices are one of the efficiencies to be gained in the development of an asset, and it's the one we are focused on at this time," Joan Dunlap, vice president of investor relations at Petrohawk, said in an interview.

Shale gas wells can produce huge amounts of gas initially, but the wells decline quickly. In some cases, the rate of production can fall by 80% or more in the first year. The rapid decline rates require producers to drill more wells to keep up the pace of production. Shale wells involve drilling into the formation and then sideways through the rock. A mixture of water, sand and chemicals is then injected into the well under high pressure--breaking the rock apart and releasing the gas trapped within.

By choking back the well, producers are extending the life of those fractures, which will close more rapidly when gas is produced at higher rates. Shales as a relatively new source of natural gas; had big initial production rates that were commonplace as these companies attempted to understand the formation and demonstrate the worth of their assets to investors.

Greg Kelleher, senior vice president of Devon Energy Corp's (DVN) southern division, said the company has been experimenting with producing gas at lower initial rates as part of evolving practices at its East Texas Haynesville acreage.

"We are trying to optimize the reservoir," Kelleher said, noting that the company is trying to come up with the best "economic case" for the Haynesville shale. Devon will drill as many as 30 shale wells in the Haynesville area this year.

Companies have used other techniques to slow production from these fields such as drilling wells without completing them so they can bring production online at a later date and, perhaps, at better commodity prices.

"Producers are starting to think about using these producing assets as a surrogate for storage," said Rusty Braziel, managing director for BENTEK Energy, which tracks energy-market data. Braziel notes that these techniques have an added advantage of allowing companies to manage through volatile swings in natural gas prices.

Arkansas in Nation’s Top 10 Natural Gas producers

Two of the top 10 companies producing in Arkansas are Fort Smith-based Stephens Production (4th) and Fort Smith-based Hanna Oil & Gas (9th).

Arkansas leapfrogged states such as California, Utah and Alaska to jump into the nation's top 10 in 2008, and has remained strongly in the position in 2009 and throughout 2010. The surprising ranking comes from recent annual reports compiled by the Energy Information Administration, housed in the U.S. Department of Energy, and requested information from the Arkansas Oil and Gas Commission (AOGC).

According to the EIA ranking, Arkansas' annual production of marketed natural gas jumped nearly 140 percent from 187 billion cubit feet (bcf) to 446.5 bcf between 2004-2008. Sales of Arkansas natural gas continued to grow in 2009, spiking 53% to 683 bcf of production, according to the most recent figures from AOGC. Many companies — including Arkansas' top producer, Southwestern Energy — have warned that production could slow in 2010 due to depressed natural gas prices. (Marketed production is the total gross withdrawals from Arkansas wells, less the output used for repressuring, quantities vented and flared, and non-hydrocarbon gases removed in treating or processing operations.)

Today, more than two-thirds of the state's natural gas drilling and production operations are located within the Fayetteville Shale, the unconventional gas reservoir that covers several counties in central and eastern Arkansas. Fayetteville Shale leaders Southwestern Energy, Chesapeake Energy and other independent drillers have driven billions of dollars of investment into the Arkansas shale play.

Although current data shows Arkansas' natural gas production continues to grow in 2010, the state still lags well behind the top six natural gas-producing states in the U.S. — each generating over a trillion cubit feet (tcf) of output annually.

Overall, Texas produces 6 tcf of natural gas each year, about 30 percent of the nation's total production. Second-place Wyoming produces 2.2 tcf, while the remaining top-producing states range between 1.4 and 1.9 tcf.

Altogether, U.S. marketed production in 2009 totaled 21.8 tcf. Utah, Alaska and Kansas round out the top ten after Arkansas.

According to the AOGC, the list of top natural gas producing companies in Arkansas in 2009 ranks as follows:

1. SEECO (subsidiary of Southwestern Energy)

2. Chesapeake

3. XTO Energy

4. Stephens Production

5. Forest Oil

6. One Tec

7. Petrohawk

8. KCS Resources

9. Hanna Oil & Gas

10. Sedna Energy

Crosstex Adds New Supply to N. Texas System

The Crosstex Energy companies, Crosstex Energy, L.P. (the Partnership) and Crosstex Energy, Inc. (the Corporation), announced June 21 that the Partnership has entered into a 10-year firm transportation agreement with a major Barnett Shale producer for an additional 50 million cubic feet of natural gas per day on its North Texas gathering system. Crosstex is constructing a compressor station on an existing gathering line to accommodate the customer's transportation requirements.

The project is scheduled to be completed and operational in the first quarter of 2011. Incremental investment required for the project is estimated to be less than $10 million and the annual cash flow from the agreement is expected to be approximately $8 million.

"This agreement is a prime example of how our strategic position in the Barnett Shale adds value. We are able to make relatively low-cost, incremental investments that generate high returns and enhance the utilization of our core assets," said Barry E. Davis, Crosstex President and Chief Executive Officer. "We will continue to look for opportunities in North Texas where our operations are located in the heart of the Barnett Shale, one of the most significant shale plays in the U.S."

DEP Submits List of Potentially Harmful Chemicals Used in PA “Fracking”

Compounds associated with neurological problems, cancer and other serious health effects are among the chemicals being used to drill natural gas wells in Pennsylvania, although state and industry officials said June 28 the practice is not polluting drinking water.

The Associated Press obtained the list from the state Department of Environmental Protection, which assembled, what is believed to be the first complete catalog of gas drilling chemicals being used in Pennsylvania. It hopes to post it online soon..

The department counts more than 80 chemicals being used by the rapidly growing drilling industry in hydraulic fracturing, or "fracking," as it pursues the rich Marcellus Shale reserve.

Many of the compounds are also present in consumer products, such as salt, cosmetics, gasoline, pesticides, solvents, glues, paints and tobacco smoke.

Environmental advocates worry that the chemicals are poisoning underground drinking water sources. However, environmental officials say they know of no examples in Pennsylvania or elsewhere.

"If we thought there was any frack fluid getting into fresh drinking water ... I think we'd have to have a very serious conversation about prohibiting the activity completely," said Scott Perry, the director of the department's Bureau of Oil and Gas Management.

Conrad Volz, who directs the University of Pittsburgh's Department of Environmental and Occupational Health, said state and federal agencies haven't done enough research to come to that conclusion.

The Department of Environmental Protection assembled the list from information the industry is required to disclose.

Industry officials say the chemicals pose no threat because they are handled safely and are heavily diluted when they are injected under heavy pressure with water and sand into a well. Industry officials say the chemicals account for less than 1 percent of the fluid that is blasted underground.

The mixture breaks up the shale some 5,000 to 8,000 feet down and props open the cracks to allow the gas trapped inside to flow up the well to the surface.

Approximately 1,500 Marcellus Shale wells have been drilled in Pennsylvania in the past three years, and many thousands more are expected in the coming years. Hydraulic fracturing has been heavily used in Texas, Louisiana, Colorado and Wyoming in the past decade.

The chemicals are used to reduce friction, kill algae and break down mineral deposits in the well. Various well services firms make different proprietary blends of the solutions and supply them to the drilling companies, which blend them with water at the well site before pumping them underground.

In recent years, the makers of the solutions have sought to replace toxic ingredients with "green" or food-based additives.

One compound, naphthalene, is classified by the federal Environmental Protection Agency as a possible human carcinogen.

The EPA said central nervous system depression has been reported in people who get high levels of toluene by deliberately inhaling paint or glue.

In its online guidelines on xylene, the U.S. Occupational Safety and Health Administration cites an industrial hygiene and toxicology text that says chronic exposure to xylene may cause central nervous system depression, anemia, liver damage and more.

DEP Orders EOG Resources to Cease Gas Drilling in Pennsylvania

A Texas company must halt its natural gas drilling in Pennsylvania and likely will pay fines because of a blowout at a Clearfield County well, state Department of Environmental Protection Secretary John Hanger said June 7.

As officials in West Virginia tried to extinguish a gas well that exploded, Pennsylvania leaders said they were examining delays in the response to the blowout at the Clearfield well, one of 278 that EOG Resources operates in the state.

"We want to minimize the risk of drilling. We know we can minimize, not eliminate all the risk," Hanger said. "We want to know what went wrong and fix it, and I'm glad the company isn't challenging our order."

Gas pressure broke through a nearly completed well, sending a geyser with more than 35,000 gallons of gas and chemical-laden wastewater into the forest, Hanger said. EOG contractors contained most of the toxic discharge, but state officials are monitoring one stream that shows signs of pollution.

"So far, the environmental impact isn't zero, but it's relatively modest," Hanger said. "Gas drilling is an industrial activity, and there is an inevitable cost associated with hosting an industrial activity, like mining or oil and natural gas drilling."

Houston-based EOG, formerly Enron Oil & Gas Co., is cooperating with the state's decision to stop it from drilling or completing any wells, company officials said in a statement. The company is paying an "independent expert" to work with DEP staff to study the accident and company drilling operations throughout Pennsylvania.

Environmentalists urged a moratorium on all drilling, saying many emergency responders, especially in rural areas, are unprepared for the risks that come with deep shale drilling.

"You can't have bottlenecks in emergency response," said Conrad Dan Volz, director of the University of Pittsburgh's Center for Healthy Environments and Communities. "It needs a top-to-(bottom) procedural evaluation, and I don't know how that can be done without an immediate moratorium on drilling ... Both of these incidents on top of one another points out these gas-drilling procedures have inherent risk that make them an immediate danger to life and health."

The blowout was the first of its kind in the state's exploration of the gas-rich Marcellus shale, parts of which are more than 8,000 feet below the surface. A blowout preventer failed, according to the department's preliminary investigation, but state officials aren't certain whether that was the main cause of the accident.

Explosions and blowouts are uncommon, according to experts, but at least two workers died this spring at Pennsylvania drilling rigs.

Such accidents are not unique to the natural gas exploration-production industry, said Penn State professor Robert Watson. Most happen because of human error and not equipment failure, he said.

"A worker may cross a thread on the blowout preventer, and that's all it takes to cause an accident," said Watson, associate professor emeritus of petroleum and natural gas engineering and geo-environmental engineering.

At the Clearfield County well, about 10 miles north of Interstate 80 just outside Moshannon State Forest, EOG workers tested the blowout preventer the morning before the accident and found no problems, Hanger said. State inspectors visited the site three times this year — Jan. 20, Feb. 18 and March 3 — and found no problems, he said.

The explosion happened about 8 p.m. June 3; it took more than two hours for the company to alert emergency responders, and seven hours for it to get a contractor on site to control the well, one of the reasons fines are likely, Hanger said.

"What happened here, we were lucky no lives were lost, no water that we know of was polluted, but it is certainly a signal to all of us that we have to proceed with caution and be careful about this," Gov. Ed Rendell said.

Most of EOG's Pennsylvania wells are in Clearfield County, DEP records show.

Records show EOG Resources violated environmental and safety regulations only once in Pennsylvania, failing to minimize erosion at a site in 1996. It has 15 workplace safety violations from two inspections in 2006 and 2007 in California and Texas, but passed six other completed inspections nationwide since 2001 without problems, according to records from the Occupational Safety & Health Administration.

CANADA

Shell Canada Completes Athabasca Turnaround

The turnaround at Shell Canada's Muskeg River Mine and Scotford Upgrader has come to a successful close with both operations now officially back online, Shell Canada reported June 7.

"This was a huge undertaking for Shell and we are proud of what the teams at our heavy oil sites accomplished," said Shell Executive Vice President Heavy Oil, John Abbott.

The Muskeg River Mine and Scotford Upgrader, which started operation in late 2003, had their first large turnaround in 2006.

"The complexity of safely and efficiently managing such a large scope of work between two distinct but integrated facilities is a major undertaking," said Abbott, adding that about 4,500 contractors from all major skills and trades were required for the work.

Planning for the event had been underway since early 2007. Maintenance work was completed in just over two months, on time and within budget. Several important projects were completed during the shutdown, including replacing more than 250 valves at the Upgrader, as well as replacing the surge feed conveyor belt and installing new feed wells for the Primary Separation Cells at Muskeg River Mine. In addition, the shutdown allowed for the commissioning of a new 42-inch pipeline between Muskeg River Mine and Scotford ahead of the start-up of our 100,000 barrels per day expansion project which is scheduled to be fully online in early 2011.

Shell's customers were unaffected by the shutdown having been informed well in advance as part of the planning process and made arrangements during the outage period, which began in March of 2010.

Shell Canada Energy is 60% owner with Chevron Canada Limited (20%) and Marathon Oil Sands L.P. (20%) of the Athabasca Oil Sands Project (AOSP), including the Muskeg River Mine and Scotford Upgrader, with a capacity of 155,000 barrels per day.

Shell has been operating in Canada since 1911 and employs approximately 8,000 people across the country. A leading manufacturer, distributor and marketer of refined petroleum products, Shell produces natural gas, natural gas liquids and bitumen, and is Canada's largest producer of sulfur. Shell is one of Canada's oil sands developers and operates the Athabasca Oil Sands Project on behalf of the joint venture partners.

Suncor Receives Regulatory Approval from ERCB for Tailings Management Plan

Suncor Energy has received approval for its tailings management plan from the Energy Resources Conservation Board (ERCB). The plan proposed the expansion of a new approach to tailings management called TROTM.

"This is great news and a significant milestone in addressing one of the greatest reclamation challenges in oil sands mining," said Kirk Bailey, executive vice president, Oil Sands. "We are confident that our TROTM technology will help us meet the expectations of stakeholders around accelerating the pace of reclamation, while also reducing our costs over the long term."

Suncor has been researching, developing and testing the TROTM technology since 2003. The company will rapidly accelerate the implementation of this technology across its existing operations.

"We expect to invest more than CAN$1 billion to implement our new TROTM technology, potentially reducing tailings reclamation time by decades," said Bailey. "Suncor's commitment to restoring natural habitats is also illustrated by our plans to complete the reclamation of our first tailings pond to a solid surface later this year."

Tailings are the mixture of fine clay, sands, water and residual bitumen produced through the oil sands extraction process. As tailings settle, a portion will eventually form mature fine tailings (MFT), a substance that has historically taken many decades to firm up sufficiently for reclamation. During the TROTM process, MFT is mixed with a polymer flocculent and then deposited in thin layers over sand beaches with shallow slopes. This drying process occurs over a matter of weeks, allowing more rapid reclamation activities to occur. The resulting product is a dry material that can be reclaimed in place or moved to another location for contouring and replanting with native vegetation.

Suncor will continue to work closely with stakeholders to ensure they understand the new technology and that the company understands any concerns they may have.

Connacher Set to Produce Bitumen from Algar Oilsands Project in August

Connacher Oil and Gas Ltd. is on track to see first production from its steam-driven Algar oilsands project in August.

Algar, Connacher's second 10,000-barrel-per-day development in northeastern Alberta, came in slightly under budget with a final price tag of $370 million.

The company managed costs by tackling the project in small chunks, chief operating officer Pete Sametz said June 23.

"A lot of it becomes logistics in terms of how you get everything to the site and put together. It's almost like Lego or Meccano, the approach we take," he said in an interview after a ceremony to formally open Algar.

The Algar project was one of many oilsands projects to be put on the shelf when the recession struck in late 2008, but the company dusted off the project last year.

Construction wrapped up in April and steam is now circulating to reach bitumen deep underground so it can be pumped to the surface.

The company is aiming to get regulatory approval late next year for a third expansion phase that would add another 24,000 barrels per day of production capacity, with a 2013 startup.

Connacher will apply lessons learned from the first two phases when it begins working on its third.

It will likely be the small things that make the difference, said Sametz.

"It's all about executing on those details, because that's where you save the money."

Cenovus Says New Narrows Lake Project Application to be Filed within Weeks

Cenovus Energy Inc. has ambitious plans to grow its oilsands holdings beyond its well-established Foster Creek and Christina Lake holdings.

"We have set lofty goals for ourselves. But I believe they are achievable," chief executive Brian Ferguson told the firm's first investor day since splitting off from natural gas giant Encana Corp. late last year.

Calgary-based Cenovus plans to file a regulatory application within weeks for Narrows Lake, near its Christina Lake holdings in northeastern Alberta.

The firm anticipates an 18-month to two-year regulatory process for Narrow's Lake, with startup expected around 2016.

Narrow's Lake, part of a 50-50 joint venture with ConocoPhillips, would have a production capacity of about 130,000 barrels per day.

Cenovus plans to next look at developing some land to the northeast, called Grand Rapids. That development would not be part of the ConocoPhillips joint-venture, through which each partner gets a half-stake in some of the U.S. energy giant's U.S. refineries and Cenovus' oilsands assets.

"The one thing I really like about this play is you don't have to divide it by two," executive vice-president Harbir Chhina said.

Cenovus has already started putting together its environmental impact assessment for Grand Rapids and aims to file a regulatory application toward the end of next year. Start up of the first 60,000 barrel-per-day phase is set for in 2017.

Next up would be an asset called Telephone Lake, a chunk of the company's Borealis holdings north of Christina Lake. Cenovus is looking for approval of that property around 2013.

Chhina cautioned that the current schedule was not set in stone.

"You will see all these plays, but the timing of regulatory construction development might change year-to-year depending on which one we feel more comfortable with," he said.

Cenovus said June 23 it aims to bump up its current bitumen production five-fold to 300,000 barrels per day by 2019.

An external evaluation by McDaniel & Associates Consultants Ltd. said the best estimate of Cenovus' total bitumen initially in place is 137 billion barrels. That estimate includes the resource that can't be exploited with today's technology.

Of that, 56 billion barrels is considered to be "discovered bitumen initially in place." Usually there must be at least one well drilled per section for the bitumen to be considered "discovered."

A McDaniel estimate in April found Cenovus can economically develop around 5.4 billion barrels based on its commodity price outlook.

Suncor Oil Sands Output up despite Upgrader Work

Suncor Energy Inc said on June 3 that output from its oil sands operations rose last month, despite the shutdown of its largest upgrader for planned maintenance.

Suncor, Canada's largest oil and gas company, said that output from its oil sands operations averaged 304,000 barrels per day in May, up 2.7 percent from the same month last year.

However, May production was down 8.7 percent from April's 333,000 bpd average output as the company began scheduled maintenance on its Upgrader 2 unit on May 17.

Work on the upgrader is expected to last six weeks.

Sneh Seetal, a spokeswoman for Suncor, said the maintenance shutdown is cutting output from the company's Fort McMurray, Alberta, operations by 85,000 barrels per day.

The company said its year-to-date oil sands output has averaged 250,000 bpd and it is targeting full-year average production of 280,000 bpd.

Encana and CNPC Sign MOU to Develop Canadian Unconventional Gas

Encana Corporation and China National Petroleum Corporation (CNPC) signed a memorandum of understanding outlining a framework for the two companies to negotiate a potential joint-venture investment in the development of certain lands in Encana's natural gas plays in Horn River, Greater Sierra (Jean Marie formation) and Cutbank Ridge (Montney formation) in northeast British Columbia, Encana reported in a news release.

"Given the depth of our enormous unconventional natural gas resource portfolio, we are accelerating our organic growth rate and targeting a doubling of our production per share over the next five years. Beyond our internally-funded capital investments, we have an extensive joint-venture program that helps accelerate value recognition across our North American resource portfolio. With this potential CNPC joint venture, we would expect, upon successful completion of a transaction, to lower costs, reduce risks, increase our capital efficiencies, improve project returns, optimize production techniques and tap natural gas opportunities that would otherwise remain dormant for some time," said Randy Eresman, Encana's President & Chief Executive Officer.

"Recent breakthrough technologies are transforming North America's energy future by opening vast new supplies of clean burning natural gas, particularly in U.S. shale gas plays. This initiative with CNPC has the potential to significantly benefit Canada's economy through increased investment in our three British Columbia natural gas plays. New investments of this nature hold considerable promise for creating jobs and new markets, expanding resource revenues for governments and substantially enhancing the competitiveness of Canadian natural gas in North America," Eresman said.

In the past three years, Encana has attracted commitments of more than US$4 billion of joint-venture capital through multiple agreements in Canada and the United States, of which about $900 million is to be invested in 2010. Encana is targeting annual joint-venture investments of between $1 billion and $2 billion. A joint venture with CNPC could contribute significantly towards achieving that investment target.

In the agreement signed at the Fairmont Chateau Laurier in Ottawa, Encana and CNPC stated that they "believe the full-scale partnership and cooperation will bring a win-win situation and help to realize the business goals of each" company and they "intend to jointly and comprehensively develop the natural gas value chain business in Canada."

Under a potential joint venture, Encana would be the operator of all developments, meaning it would drill and complete the wells, build the processing facilities and pipelines and conduct all field work for the joint venture. CNPC would invest capital to earn an interest in the assets and gain an advanced understanding of unconventional natural gas development through an ongoing sharing of technical knowledge. The companies expect that it will take several months to negotiate a potential joint venture, which would be subject to typical conditions precedent, including the negotiation of acceptable terms and conditions, receipt of the Encana Board of Directors' approval of the final terms of the proposed joint venture and receipt of any necessary regulatory approvals.

ASIA

AUSTRALIA

New Standard Energy to Increase Goldwyer Shale Gas Footprint in W Australia

New Standard Energy has secured additional exploration to increase its shale gas exploration footprint over the Goldwyer shale in the Canning Basin, Western Australia in excess of 48,000sqkm or 11.9 million acres.

The additional Canning Basin acreage awarded to New Standard is prospective for shale gas and comprises two awarded application areas. In addition, New Standard has been notified it is the preferred bidder for acreage release area L08-8. These areas lie adjacent to existing granted permits within the New Standard portfolio and form an integral part of the prospective Goldwyer shale exploration area in which New Standard has a 100% working interest.

New Standard received a report it had commissioned from specialist shale gas consultants, Netherland and Sewell and Associates (NSAI), to review the prospects of New Standard's Goldwyer shale exploration acreage.

NSAI concluded that the Goldwyer shale in the Canning Basin appeared to contain the requisite geological indicators for shale gas, providing New Standard with the confidence to increase it acreage holding and accelerate its shale gas exploration program. On the back of the NSAI report New Standard also engaged Euroz Securities to assist assess alternatives to progress the Goldwyer project.

In addition to its Canning Basin exploration permits, New Standard has secured an acreage holding in excess of 8,500sqkm in the onshore Carnarvon Basin, Western Australia.

CHINA

Sinopec to Search for Shale Gas in China’s Sichuan Basin

China Petroleum & Chemical Corp., (Sinopec) has announced that its Sinopec Exploration Southern Company business unit will explore for shale gas in China's Sichuan Basin. Sinopec previously said it would search for shale gas in China's Guizhou province through a partnership with oil giant BP.

China Petroleum & Chemical Corp. will not work with a partner on Sichuan Basin projects. The company is expected to build 2.5 billion cubic meters of shale gas production capacity, according to China Business News. Shale gas is viewed as an unconventional resource and has become increasingly more sought after by the world's oil majors as the exploration costs for crude rises and the availability of oil declines.

PetroChina, China's largest oil company expects China's natural gas consumption to reach 300 billion cubic meters by 2020. China Petroleum & Chemical Corp. shale gas could meet 5% to 10% of that demand.

EUROPE / AFRICA / MIDDLE EAST

POLAND

Poland to Consider Replacing Russian Gas with Shale Gas

Poland could stop buying Russian gas if it finds enough shale gas reserves at home, Polish presidential candidate Bronislaw Komorowski said, according to Reuters. Poland agreed with Russia to buy 10 billion cubic meters of gas per year through 2037, but the final agreement has not been signed. Earlier a representative of the Russian Economy Ministry warned Poland that if the country did not sign the agreement soon, it could end up with no gas in October.

However, Komorowski, who won a majority of votes in the first round of the Polish presidential election in June, is skeptical about the deal.

"It is very risky to sign an agreement for more than 20 years", he said, adding that shale gas produced in Poland could be an alternative to imported Russian gas. "If we see that we have enough shale gas, we want to have the right to discuss the agreement with Russia and possibly to reject it", he said.

He said the first shale gas well in Poland would be ready in a few months and an estimation of shale gas reserves would take a few years. Poland needs 14 billion cubic meters of gas a year and currently imports two-thirds of that volume from Russia.

UNITED KINGDOM

Subsea Wins $135 Mln EPIC Contract to Install Pipeline Bundle System for BP in North Sea

Subsea 7 has been awarded an engineering, procurement, installation and commissioning (EPIC) contract by BP Exploration Operating for the Andrew Area Development Project in the UK sector of the North Sea. The contract is valued in excess of $135 million.

The Subsea 7 work scope is to engineer, procure, fabricate, install and commission a 28km pipeline bundle system consisting of production, gas lift and methanol pipelines. Also included is the installation of a 28km electro-hydraulic control umbilical, tie-ins of integrated subsea towhead structures, field testing and pre-commissioning works.

The pipeline bundle system will be installed using the controlled depth tow methodology (CDTM) to tie-back BP's Arundel and Kinnoull developments to the Andrew platform.

Subsea 7's Vice President for the UK Region, Steph McNeill, commented, "We are extremely pleased to be awarded this major pipeline bundle project by BP, which builds upon our strong track record of successful bundle design, fabrication and installation. We look forward to helping bring on-stream the Andrew Area development in an efficient, timely and safe manner."

The pipeline bundle system consists of 4 daisy chain pipeline bundles (totaling approx. 28km). It represents a step change in the Subsea 7 pipeline bundle tie-back range in that it will be the longest bundle Subsea 7 has produced and installed to date.

The pipeline bundle technology is unique to Subsea 7; the product allows efficiencies to be generated by neatly incorporating all the structures, valve work, pipelines and control systems necessary to operate a field in one single product. Subsea 7 has successfully produced 60 bundles in the last 30 years, including several BP projects, the most recent example being for its Valhall field in the Norwegian sector of the North Sea in 2009.

Engineering has commenced in Subsea 7's offices in Aberdeen. The offshore phase will commence in early 2011.

The Andrew development is located 230km North East of Aberdeen in blocks 16/27a & 16/28, Central North Sea. The water depth is between 100 and 120 meters.

SOUTH AFRICA

Shell Awarded a Shale Gas Permit with Sasol, Anglo American in Application Process

South Africa's exploration regulator Petroleum Agency SA has issued shale gas permits to Shell International and oil and gas company Falcon, with Sasol and Anglo American still in the queue.

Petroleum Agency SA - headed by CEO Mthozami Xiphu and entirely separate from PetroSA - is designated by the Mineral and Petroleum Resources Development Act to regulate and promote oil and gas exploration in South Africa.

Petroleum Agency SA technical compliance manager Stephen Mills tells Engineering News Online that the permits for Falcon Oil & Gas and for Shell have been issued, and that the applications from Sasol and Anglo are in process.

"This is not to say that they are going to be issued or that they are not going to be issued, but that we haven't got around to deciding yet. We would hope to issue a permit of this type easily within 12 months, and hopefully less," Mills says.

Sasol's application to search for shale gas in the Karoo went in late last year, in partnership with Chesapeake of the U.S. and Statoil of Norway.

Mills believes that Petroleum Agency SA is close to issuing a permit to BHP Billiton for exploration offshore of South Africa's West Coast.

"We understand that Treasury has agreed a template for the kind of guarantees that BHP Billiton is looking for," Mills tells Engineering News Online.

The concept is that the South African Finance Minister guarantees that the provisions of the tenth schedule to the Income Tax Act will pertain for as long as an exploration right exists and any production rights that flow from it, regardless of any subsequent changes to schedule ten.

BHP Billiton owns the lead percentage interest in the right to explore block 3A/4A, in which Sasol and PetroSA also own percentage interests. The water depth of block 3A/4A, where gas is the likely target, is typically 100 m.

BHP Billiton also has the lead percentage of the block 3B/4B right, together with U.S. company Global Offshore Oil Exploration South Africa. The water depth of this block, where oil is the likely target, is from 1 500 m to 2 000 m.

BHP Billiton will almost certainly act as operator in both blocks.

Although companies will require a black economic-empowerment (BEE) partnership should production eventuate, BEE status is not mandatory during the risky exploration phase.

In the nearby Ibhubesi gas field, a production right has been issued to Forest Exploration, which is securing gas sales agreements prior to committing to large capital expenditure.

Forest also has a major interest in the 2C deep-water block and PetroSA has the right to block 1, on the Namibian border, and a technical cooperation permit over the 5/6 area, which is further south.

As Engineering News Online reported earlier this year, the southern part of South Africa is the area of shale gas pursuit.

Shale, which hosts the shale gas, was considered too difficult to drill, until a recent horizontal-drilling and hydraulic-fracturing breakthrough led to the so-called "shale gale".

Shale gas, like coalbed methane, is one of a number of "unconventional" sources of natural gas and the breakthrough has more than doubled North America's discovered gas resources to 85-trillion cubic feet.

McIlvaine Company,

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