Companies eager to capitalize on the shale revolution are buying up other companies that have deeds to land with access to reserves. Two multibillion-dollar deals in the first quarter show the interest companies have in scooping up shale plays for the resources and technology. Below are major shale gas and oil acquisitions:

APRIL 2011:

-- Marubeni Corp (8002.T) will pay Marathon Oil Corp (MRO.N) about $270 million for a 30 percent stake in a U.S. shale oil project. [nWNAB2649]

FEBRUARY 2011:

-- PetroChina (0857.HK) pays Encana Corp (ECA.TO) $5.4 billion for half of a shale gas project. [ID:nN09296031]

-- BHP Billiton (BHP.AX) pays Chesapeake Energy Corp (CHK.N) $4.75 billion for gas reserves in the Fayetteville Shale in Arkansas. [ID:nLDE71L1M0]

DECEMBER 2010:

-- South Africa's Sasol (SOLJ.J) pays $1.03 billion for a half share in Talisman Energy Inc (TLM.TO) shale gas property. [ID:nLDE6BJ04G]

OCTOBER 2010:

-- CNOOC Ltd (0883.HK) (CEO.N) agrees to pay Chesapeake Energy $1.08 billion in cash for one-third of its Eagle Ford shale in South Texas. [ID:nN10263769]

JUNE 2010:

-- India's largest listed company Reliance Industries (RELI.BO) will invest $1.36 billion in the U.S. shale gas assets of Pioneer Natural Resources (PXD.N). [ID:nSGE65N06C]

MAY 2010

-- Royal Dutch Shell (RDSa.L) says it will pay $4.7 billion cash to buy privately held East Resources Inc, which controls 650,000 net acres (2,600 square kilometers) in the Marcellus Shale. [ID:nLDE64R0AX]

APRIL 2010:

-- British gas producer BG Group (BG.L) said it would pay $950 million to buy a 50 percent interest in shale gas assets in Appalachia from EXCO Resources (XCO.N).

FEBRUARY 2010:

-- S.Korea's KOGAS (036460.KS) invests $1.1 billion in developing Encana Corp's natural gas fields. [ID:nTOE61R013]

-- Canada's Progress Energy Resources Corp (PRQ.TO) agreed to buy certain northeast British Columbia Foothills assets for about C$390 million ($366.2 million) from Suncor Energy (SU.TO). [ID:nSGE6180KX]

DECEMBER 2009:

-- Exxon Mobil Corp (XOM.N) announced its plan to buy XTO Energy Inc XTO.N for about $30 billion in stock. XTO's resource base is the equivalent of 45 trillion cubic feet of gas and includes shale gas, tight gas, coal bed methane and shale oil. [ID:nN14126206]

-- Ultra Petroleum Corp (UPL.N) said it would pay about $400 million to an unnamed private company to buy 80,000 net acres in the burgeoning U.S. Marcellus Shale region, giving it about 250,000 net acres and a potential for 1,800 net drilling sites. [ID:nSGE5BK0EU]

NOVEMBER 2009:

-- Denbury Resources Inc (DNR.N) said it would buy Encore

Acquisition Co for $3.2 billion, creating a company with 426 million barrels of oil equivalent in proved reserves. [ID:nN01400606] The acquisition would allow Denbury to leverage its enhanced-oil-recovery business into Encore's properties in Wyoming, Montana, and North Dakota, and would give it a large stake in the Bakken shale on the U.S.-Canada border.

JUNE 2009:

-- British gas producer BG Group paid Dallas-based Exco Resources Inc (XCO.N) $1.3 billion for an interest in shale gas resources in Texas and Louisiana. [ID:nLU618520] The companies said each would own 50 percent of a venture to which EXCO is contributing 120,000 acres of land in the Haynesville shale gas area and associated gas infrastructure.

MAY 2009:

-- Talon Oil & Gas LLC bought 60 percent of Denbury Resources Inc's (DNR.N) natural gas assets for $270 million.

-- Independent oil and gas company Quicksilver Resources Inc (KWK.N) agreed a joint venture with Italian energy giant Eni (ENI.MI) to develop its Barnett shale properties in Texas. [ID:nBNG161361] As part of the deal, Eni agreed to buy a 27.5 percent stake in Quicksilver's Alliance leasehold interests in the Fort Worth basin for $280 million.

MARCH 2009:

-- Independent Canadian oil exploration firm TriStar Oil & Gas and Crescent Point Energy Trust agreed to buy Talisman Energy Inc's lands in the prolific Bakken shale region of Saskatchewan and Montana for C$720 million ($567 million). TriStar was later acquired by Petrobank Energy and Resources Ltd (PBG.TO), which combined its own conventional oil assets with TriStar to create a new company called PetroBakken Energy Ltd (PBN.TO).

AMERICAS

U.S.

NuStar, TexStar Plan Pipeline and Storage System for Eagle Ford Crude

NuStar Logistics, L.P. and TexStar Midstream Services, LP on April 5 announced that they have signed a letter of intent to develop a new pipeline system to transport Eagle Ford Shale crude and condensate to Corpus Christi.

TexStar will build and operate a new 65-mile, 12-inch pipeline that will have the capacity to move 120,000 barrels per day of crude and condensate from Frio County to Three Rivers. TexStar will build at least two truck unloading facilities which will be located along the pipeline to gather crude oil produced in Atascosa, Frio, LaSalle, McMullen, and Live Oak counties. At Three Rivers, the TexStar pipeline will be interconnected with a new storage facility to be constructed by NuStar. That storage facility will be connected to NuStar's existing 16-inch pipeline that will have the capacity to transport 200,000 barrels per day into NuStar's Corpus Christi North Beach Terminal. That terminal has approximately 2 million barrels of storage capacity, and the Port of Corpus Christi Authority recently approved a land lease option agreement for 15 acres contiguous to the existing property, which will provide terminal expansion capabilities. TexStar and NuStar expect to complete construction and begin service on the projects in the second quarter of 2012.

"We are excited to partner with NuStar on this project, and our combined facilities will provide South Texas producers with an open access, reliable, and low cost outlet for their oil," said Phil Mezey, TexStar's co-CEO and Chief Operating Officer. "Use of NuStar's existing pipeline and terminal infrastructure in Corpus Christi will assure producers of a secure and reliable solution for getting their oil to market in the near future."

NuStar President and CEO Curt Anastasio also discussed the benefits of the project, and noted that it is part of a concentrated effort in which NuStar expects to significantly expand and modify its pipeline and terminal infrastructure to transport and store even greater volumes of Eagle Ford Shale crude and condensate.

"TexStar is an ideal partner for NuStar in this project because they are a very well managed company and they have a proven ability to complete projects like this quickly and efficiently, which is a win for both of our companies and our customers," said Anastasio. "And this project is part of a larger strategy to give our customers even greater logistical flexibility by moving the crude and condensate from the Eagle Ford region to Corpus Christi, which gives them greater access to major refining and trading hub markets since Corpus Christi has waterborne capabilities for loading vessels.

"NuStar's existing pipeline and terminal infrastructure in South Texas provides the foundation to pursue and develop these and other logistics opportunities in the Eagle Ford Shale region," Anastasio added. "These projects will strengthen NuStar's position in South Texas, and our ability to provide logistics services to oil and gas producers, gas processors, refiners, and other stakeholders."

NuStar Energy L.P. is a publicly traded, limited partnership based in San Antonio, with 8,417 miles of pipeline; 90 terminal and storage facilities that store and distribute crude oil, refined products and specialty liquids; and two asphalt refineries with a combined throughput capacity of 104,000 barrels per day. The partnership's combined system has over 94 million barrels of storage capacity.

TexStar has owned and operated over 1,500 miles of pipeline and two large gas processing plants and is in the process of rapidly expanding its existing gathering assets in the Eagle Ford shale area and is currently working to install additional gas and crude oil pipelines.

Tesoro Disagrees with CSB over Anacortes Conclusion and $2.4 Mln Fine

Tesoro Corp said April 5 it disagrees with a government agency's preliminary findings that the company was responsible for a fatal explosion at its Anacortes refinery in 2010.

Tesoro was responding to a U.S. Chemical Safety Board April 1 announcement that the company "did not adequately maintain" the refinery's 40-year-old heat exchanger, the source of the April 2010 explosion that killed seven people. The board made the statement while reporting the preliminary findings of its investigation into the accident.

"We disagree with (the agency') characterization of Tesoro's operations at Anacortes," Tesoro spokesman Mike Marcy said. "We look forward to clarifying the facts as the Board completes its investigation and prepares its final report."

The CSB's findings echo those made by Washington state regulators in October. State regulators fined the company $2.4 million, saying adequate inspection and maintenance of the exchanger would have prevented the explosion. Tesoro is appealing the citations.

The CSB is an independent federal agency charged with investigating serious chemical accidents. The board doesn't issue citations or fines, but does advise regulatory agencies such as the U.S. Environmental Protection Agency and the Occupational Safety and Health Administration.

Koch Plans to Complete another Eagle Ford Pipeline by Mid-2012

Koch Pipeline Company, L.P. plans to build a crude oil pipeline from Pettus, Texas, to Corpus Christi, Texas, to move more Eagle Ford production. Current plans include a 20-inch line, which is currently in the permitting and right-of-way acquisition phase and should be complete in mid-2012.

"With this large-diameter line in operation, Koch Pipeline will have increased its system capability from Karnes County to the Corpus Christi-area to about 250,000 barrels per day," said Kim Penner, president of Koch Pipeline.

The completion of the line is timed with affiliate Flint Hills Resources' updates to an Ingleside terminal that will have the capacity to ship up to 200,000 barrels per day of production via barge to other Gulf Coast markets.

Koch Pipeline is constructing a station near Helena in Karnes County along with connections to tank batteries in Karnes and DeWitt counties as well as a 16-inch pipeline from Helena to Pettus. The 16-inch pipeline will connect to the new line announced today at Pettus.

"With several new lines, our legacy system and arrangements with Arrowhead Pipeline and NuStar Logistics, we are addressing producer's needs to move crude oil and condensate to market," Penner said. "We continue to evaluate major South Texas pipeline projects, including a project to connect producers in Western counties."

The company is the largest transporter of South Texas crude oil with about 540 miles of active crude oil transportation lines in Texas. The company also has ongoing relations with other crude distribution systems that further its ability to provide services in this growing production area.

Koch Pipeline Company, L.P. has earned numerous local, state and national level safety awards. Koch Pipeline operates about 4,000 miles of pipelines that transport crude oil, refined products, natural gas liquids and chemicals. Koch Pipeline Company, L.P. is an indirect, wholly owned subsidiary of Koch Industries, Inc.

Williams Set to Begin Work on Transco Project in PA

Work should begin this spring on a new natural gas pipeline system that will connect Marcellus Shale wells in the northeast with a route to major metropolitan markets.

Three Williams’ representatives -- Ryan Savage, general manager for Appalachian Midstream Operations; Tunkhannock-based Manager of Operations Mike Dickinson and Communications Specialist Helen Humphreys -- met with The Citizens' Voice recently to outline details of the Springville Gathering System project.

"It's clear that a lot of residents don't have a good idea about our projects, and also don't have all of the facts," Humphreys said. "We think it's important that the Springville project, which is Williams' pipeline project, be evaluated on its own merits, and that Williams be evaluated on its own merits."

Tulsa, OK-based Williams owns the Transco interstate pipeline that Savage said starts in south Texas and supplies 60 percent of the gas to cities like Philadelphia and New York. The Transco has been in Luzerne County since 1958, and there are currently four metering stations in the county, Savage said.

The company plans to run a new 24-inch diameter gas gathering pipeline that will run approximately 33.5 miles from the Lathrop compressor station at Springville in Susquehanna County to a new compressor station outside Tunkhannock. From there it will connect to the Transco by way of a new metering station in Dallas Township, to be located on private property about half a mile from the Dallas schools.

Williams plans to use the line for natural gas from its own wells, and has an agreement with Cabot Oil & Gas to transport gas from Susquehanna County. Williams also has been talking to other companies about using the new pipeline, Savage said.

Williams planned a hearing May 16 in Dallas Township for the proposed metering station.

For the pipeline itself, the company has already started designing the route, buying pipe and lining up contractors, Savage said.

Most requirements, including permits and an archaeological survey, have been fulfilled. After a permit from the state Department of Environmental Protection is granted, work can start in May or June and will be a three- to four-month process, he said.

"It takes a long time to get to this point, and we're in the last throes," Savage said. "Construction's really the short period. It takes a long time to get your right-of-way, and get all your permit applications in, and do all of your endangered species testing and all your other environmental protection work."

Williams' compressor station in Tunkhannock, which is under construction, will be located in a rural area away from the road, he said.

"You'd never know where it was unless somebody pointed it out to you," Savage said.

He said the same will go for the metering station. Williams will build a private, padlocked road to it. Truck traffic will not come near the school during construction, Humphreys said.

The metering station will be constantly monitored at a facility in Tulsa, Dickinson said. If there is anything outside normal operating parameters, an alarm goes off and a local operator can be called or the station can be shut down remotely, he said.

Savage said a metering station is one of the most innocuous natural gas facilities, comparing it to a gas meter on a home, but larger.

"On the scale of things, these aren't dangerous facilities," he said.

Blackstone Joins Alta Resources in $1 Bln Shale Venture

Blackstone Group is investing in the lucrative area of shale, following rivals such as Kohlberg Kravis Roberts & Co (KKR).

North American shale fields are drawing billions of dollars from companies that are eager to learn the techniques to tap into the difficult geological formations.

Blackstone said April 12 it has teamed up with shale gas developer Alta Resources to form Alta Energy Partners and they are committing to invest up to $1 billion via this entity to acquire and develop unconventional oil and gas assets in North America.

Unconventional assets include shale rock fields that may hold vast quantities of oil and gas but are more expensive to tap than traditional energy reservoirs.

To access the resources, energy producers use a technique called "hydraulic fracturing," in which large quantities of water and sand are mixed with chemicals and pumped under high pressure into the wells to break apart the brittle rock and release oil or gas.

That "fracking" has led to a backlash in some areas, where residents and evironmentalists blame it for contaminating drinking water supplies and fouling streams and rivers.

Texas' Barnett Shale was among the first of these giant fields to be developed, and energy companies have swarmed to other similar energy fields, including the Fayetteville shale in Arkansas and the Marcellus shale in Pennsylvania.

High oil prices have rekindled interest in oil and liquids-heavy fields, such as the Eagle Ford and Bakken shales, prompting energy producers to shift their investments away from fields that primarily produce natural gas.

Alta is run by CEO Joseph Greenberg and has as a partner George Mitchell, one of the industry's first to regonize the potential in shale fields.

KKR has also been investing in shale. It created a partnership KKR Natural Resources with Premier Natural Resources, to pursue investments in North American oil and gas properties.

Heckmann Water Buys 200 LNG Powered Peterbilts to Haul Disposal Water from Shale Gas Wells

Encana Natural Gas will provide LNG from new mobile refueling stations for Heckmann Water Resources of California. To transport disposal water from shale gas wells in the Haynesville and Eagle Ford, Heckmann plans to convert its fleet to LNG from diesel. Peterbilt of Denton, Texas will supply the trucks powered by Westport HD Systems from Westport Innovations of Vancouver, BC. LNG costs from 20-40% less than gasoline or diesel and carbon dioxide emissions can be up to 30% lower.

Analysis: The above is an extract from an article that appeared in the April 11 issue of the Oil & Gas Journal. Royal Dutch Shell's Malcolm Brinded, chief of the company's China and Europe unit recently noted that consumption of LNG was growing worldwide at a rate of between 6 and 10%/year. Recent news announcements suggest that in the U.S., total natural gas growth is closer to 10% with LNG becoming a larger component.

Apache Corp, Chesapeake Energy and Questar have all announced expansions to their compressed natural gas (CNG) refueling stations. But for long distance hauling, LNG is by far the preferred fuel. The announcement by Heckmann suggests that they will continue to expand their LNG fleet as more and more capacity is needed to transport disposal water from wells completed in the several shale gas plays of the U.S. and Canada. Heckmann is also involved in a joint venture with Energy Transfer Partners to move disposal water by pipeline from both the Marcellus and the Haynesville fields. State regulators, particularly in Pennsylvana and New York are concerned both about leakage of water from trucks as well as increased carbon dioxide emissions. This move by Heckmann is an indication of the steps the major disposal water carriers are taking to improve efficiency and thus gain credibility with the regulators. With demand for all types of natural gas increasing because of its environmental virtues, shale gas drilling will be around for many years and profits will accrue to companies willing to meet the challenges of safe water disposal with low carbon dioxide emissions.

PA Drillers Told to Stop Sending Wastewater to Treatment Plants

Pennsylvania regulators on April 20 called on Marcellus Shale natural gas drillers to stop sending wastewater to 15 treatment plants, citing an increased risk of contaminating public drinking water.

The Department of Environmental Protection's action, while voluntary, will likely set the stage for a formal ban on the discharge of inadequately treated wastewater into the state's rivers.

"Now is the time to take action to end this practice," acting DEP Secretary Michael Krancer said in a statement.

DEP's action comes as the U.S. Environmental Protection Agency and activists step up pressure on Gov. Corbett to increase regulation of the shale-gas boom, including the massive volumes of toxic wastewater produced by hydraulic fracturing.

"Amid growing concern by the public and increased scrutiny by the media, we are happy to see DEP finally take these critical steps to once and for all stop dangerous, undertreated Marcellus Shale wastewater from entering our waterways and drinking-water supplies," said Erika Staaf, a spokeswoman for the PennEnvironment advocacy group.

DEP's announcement came the day after Corbett, who has been criticized for his close ties to drillers and his refusal to support a gas-production tax; assured local officials he would not allow the industry to "poison the water."

"We need to protect the water," the governor, a Republican, said at a meeting of the Pennsylvania State Association of Township Supervisors. "But we must do it based on science, not emotion."

The Marcellus Shale Coalition, an industry trade group, said it welcomed DEP's announcement.

Kathryn Z. Klaber, the coalition's president, said that the industry was already recycling much of its wastewater and that drilling operators were "very confident they can in fact meet these additional limits."

Klaber said that the DEP's action was "timely" and that it was a "perfectly reasonable assumption" that the state would eventually put its voluntary order into enforceable regulations.

The DEP and the industry appear to have been influenced by complaints from public water suppliers in Western Pennsylvania, which say they are challenged by bromide levels whose concentrations have increased concurrently with the drilling boom.

The bromides themselves are not a public health risk - they account for a tiny part of the salty dissolved solids that create an unpleasant taste in water at elevated levels.

But bromides react with the chlorine disinfectants used by drinking water to form brominated trihalomethanes (THMs), a volatile organic compound. Studies have linked the prolonged ingestion of high levels of THMs to several types of cancer and birth defects.

Officials at several water authorities in the Pittsburgh area say their facilities have failed several tests for trihalomethanes in recent years.

Researchers at Carnegie Mellon University in Pittsburgh, who are in the final stages of a two-year study of trihalomethanes in the Monogahela River, have shared their preliminary data with federal and state regulators.

Bromide levels had been in the low to moderate level until last July, when the rates inexplicably spiked, said Jeanne M. VanBriesen, an engineering professor who heads the university study.

Since the spike, bromide levels have steadied at "slightly elevated" levels, she said.

She said the signature of the bromide concentrations suggests that the source is either water, produced from oil and gas wells, or wastewater from pollution-control equipment of coal-fired power plants.

The level of trihalomethanes in public drinking water has also increased, she said, though she said that none has exceeded EPA limits of 80 micrograms per liter in a three-month average.

"I can't say the plants are in noncompliance," VanBriesen said. "But we saw levels that, if they persisted over a long period, would amount to violations."

VanBriesen said she was encouraged by the state's asking drillers to stop taking wastewater to treatment plants after May 19. "It's always nice to see science being used for something," she said.

Researchers expect bromide levels to decline after that date, reinforcing the presumption that gas drilling is responsible for the elevated levels.

"While there are several possible sources for bromide other than shale-drilling wastewater, we believe that if operators would stop giving wastewater to facilities . . . bromide concentrations would quickly and significantly decrease," the DEP's Krancer said.

Bromides, chlorides, and some heavy metals occur naturally in deep rock formations such as the Marcellus Shale, the massive deposit that underlies much of Pennsylvania and parts of several surrounding states.

In other regions where shale production has taken off, operators dispose of the wastewater in deep, federally regulated injection wells. But Pennsylvania's geology is insufficiently porous to accept large volumes of wastewater.

Copano Energy Plans $145 Mln Houston Processing Facility Expansion

Copano Energy LLC plans to expand its Houston Central processing facility, located in Colorado County, Texas.

Houston-based Copano said the $145-million project was in response to producer demand in the Eagle Ford shale. The expansion will bring a new 400,000 million cubic foot per day cryogenic processing plant, giving the facility to a total processing capacity for natural gas liquids of 1.1 billion cubic feet per day.

Construction is set to be completed by 2013.

In February, Copano inked a deal with midstream oil & gas company Kinder Morgan Energy Partners LP to provide natural gas gathering, transportation and processing services to Houston-based Anadarko E&P Company LP, a subsidiary of The Woodlands-based Anadarko Petroleum Corp..

BLM to Conduct New Study of Acreage for Oil Shale, Tar Sands

The Bureau of Land Management will conduct a “fresh” study to determine how much public acreage to open to potential oil shale and tar sands development, the agency announced April 13. .

In 2008, under the Bush administration, the agency amended eight area management plans in Utah, Colorado and Wyoming to open about 1.9 million acres for oil shale development and more than 430,000 acres for tar sands.

With technological issues still leaving development of the resources in question, industry has taken little action since then. The BLM called its new environmental study “a fresh look at what public lands are best suited” for development.

“The BLM remains committed to a thoughtful, orderly and responsible oil shale development program,” BLM Director Bob Abbey said in a statement.

The government will take public comments about the program and is conducting seven scoping meetings in the three states. The first three are in Utah, starting with an April 26 meeting in Salt Lake City.

Dow Chemical to Further Integrate Shale Gas Liquids with It’s Businesses

Dow Chemical Co. (DOW) said it plans to further integrate the company's North American performance businesses with shale gas liquids, actions the company said will strengthen its competitive position.

The U.S. chemical producer said the moves would strengthen its performance plastics, performance products and advanced materials businesses.

"The improved outlook for U.S. natural gas supply from shale brings the prospect of competitively priced ethane and propane feedstocks to Dow," said Dow executive Jim Fitterling.

Dow is currently finalizing plans to increase the company's supply of ethylene, which is used for plastics and other products. It intends to restart ethylene operations at a site near Hahnville, La., by the end of next year, among other moves.

The company also intends to increase supply of propylene, an industrial chemical that is a building block for an array of chemical and plastic products, by constructing a new production facility in Texas and exploring an option to commercialize its own technology to produce propylene from propane.

"As the largest consumer of propylene in North America, Dow has a unique opportunity to invest aggressively for on-purpose propylene production from propane," said Fitterling.

Dow has seen sales rebound in recent quarters on volume growth in basic chemicals, agriculture products and other units. The company's chemicals are used in a wide range of products including diapers and products in the auto industry.

Chesapeake Energy Well Blowout in PA Highlights Fracking Concerns

A blowout at a Pennsylvania natural gas well has fueled increased concerns about the already controversial practice of hydraulic fracking.

The well, owned by Chesapeake Energy Corp., experienced an equipment failure April 19, sending chemical-laced water over the drilling site in Bradford County, Pa. and into nearby waterways, including Towanda Creek, which feeds into the Susquehanna River.

"There have been no injuries and there continues to be no danger to the public," Brian Grove, senior director for corporate development at Chesapeake, said in a statement.

The company stopped all operations in the state and said April 21 that it had successfully sealed the leaking gas well.

The accident comes one year after an explosion sunk the Deepwater Horizon oil rig in the Gulf of Mexico, resulting in 11 deaths and the worst offshore oil spill in U.S. history, and at a time when hydraulic fracturing, or "fracking," is coming under increased scrutiny from state and federal officials.

The technique, used to release vast reserves of natural gas buried underground, involves massive amounts of water, sand and chemicals injected at high pressures to fracture rock and release the stored gas.

A report released by Democratic members of Congress earlier in April said that more than 650 of the chemicals used in fracking were carcinogens.

In the fracking process, anywhere from 10 to 40 percent of the water injected into the well returns to the surface carrying drilling chemicals, high levels of salts and sometimes naturally occurring radioactive material. The state of Pennsylvania has allowed drillers to discharge much of the waste through sewage treatment plants into rivers, The New York Times reports.

An investigation by the Times found that more than 1.3 billion gallons of wastewater was produced by Pennsylvania wells over the past three years. But treatment plants to which the wastewater was sent weren't equipped to remove many of the toxic materials contained in the drilling waste.

Environmental group American Rivers has called on Congress to push for the restoration of the Environmental Protection Agency's ability to regulate hydraulic fracturing under the Safe Drinking Water Act, removed in a 2005 energy bill referred to as the "Halliburton loophole."

"In case last year's BP oil spill wasn't enough of a wake-up call, now we have another disaster, this time in Pennsylvania. The American people have had it with the industry's false assurances," said Andrew Fahlund, senior vice president for conservation at American Rivers.

Pennsylvania's massive Marcellus Shale reserve is believed to hold enough gas to supply the country's energy needs for heat and electricity, at current consumption rates, for more than 15 years. Some 3,300 Marcellus gas-well permits were issued to drilling companies last year, compared to 117 in 2007.

ETP to Expand Eagle Ford Mainline, Build Processing Plant

Energy Transfer Partners, L.P. (ETP) announced it has entered into long-term fee-based agreements with multiple producers, including Rosetta Resources Operating LP, SM Energy Co., and a subsidiary of Anadarko Petroleum Corp., to provide natural gas gathering, processing, and liquids services from the prolific Eagle Ford Shale.

To facilitate these agreements, which include volume commitments in excess of 540,000 MMBtu per day of natural gas, ETP will significantly expand the previously announced Rich Eagle Ford Mainline (REM) pipeline in South Texas and will construct a new processing facility in Jackson County, Texas.

The REM pipeline expansion, which will extend from the Partnership's Chisholm Pipeline in DeWitt County east into Jackson County, Texas, will add roughly 70 miles of 36-inch pipe to the initial 160-mile, 30-inch REM pipeline that was announced in February 2011. When fully constructed, the Partnership's REM pipeline will consist of approximately 230 miles of 30-inch and 36-inch pipe with a capacity of at least 600 million cubic feet per day (MMcf/d). Completion of the initial phase of REM remains scheduled for the fourth quarter of 2011 and completion of the REM expansion is scheduled for the first quarter of 2013.

The Jackson County gas processing plant will have approximately 600 MMcf/d of capacity and can be expanded to 800 MMcf/d. The plant is scheduled for completion in the first quarter of 2013. Total cost of the REM expansion and Jackson County processing facility are expected to be approximately $450 million.

"The REM expansion will materially increase the Partnership's extensive midstream infrastructure in the Eagle Ford," said Brian Beebe, Energy Transfer's senior vice president. "Along with our recently completed Dos Hermanas Pipeline, the Chisholm Pipeline scheduled for completion in the second quarter of 2011, and the recently announced acquisition of LDH Energy Asset Holdings, the Partnership's ability to provide its shippers with the full array of gas transportation, processing and NGL handling services demonstrates our commitment to deliver the services desired by our customers for Eagle Ford Shale development."

CANADA

Penn State’s Liquid Salt Process Could Clean Up Canadian Tar Sand’s Toxic Sludge

The tar sand extraction fields in Alberta, Canada export over one million barrels of oil each day - mostly to the U.S. Greenpeace, National Geographic, and Canada's own governmental agencies consider Alberta's tar sands to be serious environmental threats, and it would be hard to find a reasonable person who has a lot of positive things to say about the tar sand oil's overall impact on the environment ... but that may be about to change.

A new technique being pioneered at Penn State University may serve to dramatically reduce the environmental impact of the oil extraction processes being used in Alberta. Currently, separating the "usable" oil from the tar sands involves mixing them with warm water, then agitating the mixture until it separates. This process requires literally tons of water, however, which is diverted from nearby rivers before being pumped into open-air "tailings ponds", where the toxic sludge can leach its way back into the water table.

Instead of using warm water from diverted rivers and streams, the new method would make use of room temperature ionic liquids (ILs), which consist of salt in a liquid state. When these ILs are introduced to a tar sand mixture and agitated, the resulting combination settles into three distinct layers (below).

As you can see, the process leaves a top layer of bitumen (tar) can be easily removed and refined.

Once the process is complete and the tar is removed, the the ILs - unlike the water being used currently - can be reused, while the now tar-free sands can be returned to the environment. The good news doesn't end there, though: because the process can make use of ILs at much lower temperatures, there are significant energy savings that come from not heating thousands of tons of water.

It will be interesting to see how many Albertan oil companies "pick up" on the idea, but it would certainly go a long way towards greening up the region's care-free, "petro-dollar" image.

Total Signs Deal with E-T Energy for Calgary Oilsands Technology

Privately-held E-T Energy, a small Calgary technology firm said April 13 that it has signed a deal with Total Canada for use of a proprietary method of producing oilsands that reduces emissions and the need for water in thermal operations.

E-T said Total will participate in the next two stages of field testing a unique electrical production technique as it prepares for a proposed 10,000 barrel per day development at Poplar Creek in northeast Alberta.

Financial terms of the deal were not disclosed but Total will provide financial and technical support in exchange for an option for future co-operation in the development of the technology, including a global license of the technology, as a limited working interest in the Poplar Creek project.

In a news release, E-T said it expects to start production from the current two test patterns before the end of April and will commence work on the third phase immediately after.

Bruce McGee, E-T Energy’s president and CEO, said the deal with Total was more than four years in the making and represents efforts to take the technology from the lab into the commercial realm.

Total has published scientific papers on the technique and the co-operation efforts will attempt to work out practical considerations in scaling it up.

“There are some commercial issues that need to be resolved,” he said. “We know the technology works, we’ve done it on a pilot scale, but to do it on a commercial scale, it’s easier said done.”

The technique sees electrodes placed into the ground and uses electricity to mobilize bitumen into production wells. According to a presentation on the company’s website, the end product is a partially improved bitumen free of sand and produced water.

Total Canada CEO Jean-Michel Gires said the deal reflects Total’s commitment to finding environmentally friendlier ways of developing oilsands, which are considered the second-largest oil reserves on Earth. “We are looking forward to seeing where this new technology can go and how it can be used on a commercial scale,” he said.

Although it won’t initially lead to production, Total spokeswoman Saphina Benimadhu said the move is part of the company’s greater research and development efforts.

“We believe strongly in innovation and this is an opportunity to support new technology.”

In a second announcement, E-T said is has secured $6.8 million in co-funding from Alberta’s Climate Change and Emissions Management Corporation for the third and fourth phases of field testing the technology at Poplar Creek.

“This project is one way that CCEMC is advancing clean technology and exploring the impact that technology can have on reducing greenhouse gas emissions in the oilsands,” CCEMC chairman Eric Newell said in a statement.

Sunrise OTSG Order Goes to Technip’s KTI Corp

Technip's wholly owned subsidiary, KTI Corporation, was awarded a purchase order by Snamprogetti Canada to design and supply ten Once through Steam Generation (OTSG) units for the first phase of the Sunrise Energy Project. The OTSG units are an integral part of the Steam-Assisted Gravity Drainage (SAGD) process being applied at Sunrise for the extraction of bitumen.

Sunrise, a SAGD Oil Sands Project, operated by Husky Energy; is being constructed approximately 60 kilometers northeast of Fort McMurray, Alberta, Canada. Upon completion of Phase 1 of the project, the facility is expected to produce approximately 60,000 barrels per day of bitumen.

Snamprogetti Canada is the prime contractor for engineering, procurement and construction of the Central Plant Facility for Sunrise Phase 1 where the OTSGs will be used.

KTI's engineering center in Houston, Texas will execute the OTSG contract. Final fabrication and assembly of the OTSGs will occur in Tofield, Alberta. Final delivery and completion of these units is scheduled for the second half of 2012.

CB&I Awarded $45 Mln Contract to Build Tanks for Oil Sands Project

CB&I on April 26 announced that it has been awarded a project, valued in excess of US$45 million, for storage tanks at an oil sands project near Fort McMurray, Alberta, Canada. This was a first quarter award.

CB&I's scope of work includes the engineering, procurement, fabrication and construction of 12 cone roof tanks at the oil sands project. CB&I's contract is scheduled for completion in 2013.

Cenovus to Expand Christina Lake Operation

Cenovus Energy Inc. has received approval from the Alberta Energy Resources Conservation Board (ERCB) to move forward with a major expansion at its Christina Lake oil sands operation. The approval covers three expansion phases (E, F and G) of 40,000 barrels per day (bbls/d) each, which would bring gross production capacity to 218,000 bbls/d once it is complete.

"The regulatory approval at Christina Lake is a significant step in our plan to increase the company's net asset value," said Brian Ferguson, President & Chief Executive Officer of Cenovus. "This is a major milestone that allows our expansion plans at Christina Lake to remain on schedule. Additionally, as a result of this approval and the expansion of the development plan area, we expect to add substantially to our Christina Lake proved reserves at year end."

Christina Lake is a major part of the company's plan to grow oil sands production five-fold by 2019. With this approval, Cenovus has oil sands expansions totaling 290,000 bbls/d of gross production capacity either under construction or approved by the regulators. That is in addition to its current combined gross production capacity of 138,000 bbls/d at Christina Lake and Foster Creek.

Engineering and equipment fabrication for Christina Lake phase E is already underway with first production planned for 2014. Phase F is expected to begin production in 2016 and phase G the following year. The first phase of the expansion is expected to be sanctioned by Cenovus and its partner by the end of 2011.

"We are especially proud of our ability to deliver industry-leading capital efficiencies as we expand our oil sands projects," said John Brannan, Executive Vice-President & Chief Operating Officer of Cenovus. "We are currently building our Christina Lake expansions at a capital efficiency of about $22,500 per flowing barrel. This is largely thanks to our manufacturing approach for constructing expansions and the improvements our staff are able to identify and implement with each new phase."

Cenovus's Christina Lake operation located near the community of Conklin in northeast Alberta, about 120 kilometers south of Fort McMurray began as a pilot project in 2000 and is currently producing about 18,000 bbls/d gross from 19 wells. Christina Lake is one of the company's premier growth assets with more than 700 million barrels of proved plus probable reserves and 800 million barrels of best estimate economic contingent resources. The operation currently has an industry-leading steam to oil ratio (SOR) of less than 2.0, which means less than two barrels of steam are needed to produce each barrel of oil. The low SOR contributed to low average operating expenses of $16.47 per barrel at Christina Lake in 2010.

Christina Lake currently has two additional phases of 40,000 bbls/d of gross production capacity each under construction. Phase C is almost complete, with final testing and commissioning adjustments now taking place. The plan is to start injecting steam by the end of this quarter, with first production expected in the third quarter of this year. Construction is also progressing well on phase D with more than half of the work complete. Most of the larger pieces of infrastructure are already at site and the final modules are being completed at the company's assembly yard in Nisku, Alberta. Steam injection at phase D is expected in the first quarter of 2013 with production starting in the second quarter. Construction for both phases is on schedule and on budget. An application for an additional 40,000 bbls/d expansion, phase H, at Christina Lake is expected to be submitted for regulatory review in 2013. That would bring the project's total gross production capacity to 258,000 bbls/d by 2019.

Cenovus is also moving forward with three approved expansion phases at its Foster Creek operation, which are expected to increase gross production capacity to 210,000 bbls/d from the current 120,000 bbls/d. A regulatory application for the Narrows Lake project, located in the Christina Lake Region, is under review. Narrows Lake is expected to have gross production capacity of 130,000 bbls/d. In addition, Cenovus is doing preliminary assessment work on nine other emerging oil sands projects, including Grand Rapids in the Greater Pelican Region and Telephone Lake in the Borealis Region. The company believes several of the emerging projects could be of the same scale as Foster Creek and Christina Lake.

Cenovus has a 50% ownership of Christina Lake, Foster Creek and Narrows Lake with ConocoPhillips.

ASIA

CHINA

Senior Expert at Conference Warns Australia on Shale Gas Production in China

Pedro Haas, a senior expert with consultants McKinsey and Company, told the Australian Petroleum Production & Exploration Association conference in Perth April 11 that if shale gas production in China takes off as it has in the U.S., domestic production could provide as much as a quarter of the country's total gas demand within four years.

Such a seismic shift could be significant for Australia because, although Japan and South Korea are the traditional buyers of Australia's LNG, China and India have more recently emerged as growth markets.

"U.S. (shale gas production) has gone from 20 billion cum to 100 billion cum in the past five years," Mr Haas said.

"If you expect a similar growth pattern replicated in China, China would be producing 50 billion cum by 2015 and almost 100 billion by 2025."

Total Chinese gas demand was forecast to hit 200 billion cum by 2015 and 284 billion by 2020.

However, Mr Haas said it was too early to tell if this potential surge in shale gas production would be more of a challenge to coal production or LNG imports.

"The key question is: what will these uncertainties do to the pricing relationship," Mr Haas said.

"And of course whether gas in China competes with coal or competes with imported LNG will have an impact on the pricing of that gas."

Shale gas has only recently become economic because of technological advances. In the U.S., it has proved to be a game changer and now accounts for about 15 per cent of gas production, tipped to rise to 45 per cent by 2035.

China is estimated to have twice the shale gas reserves of the U.S.

Woodside Petroleum chief executive Don Voelte struck a more bullish note on the prospects for Chinese demand, although he said the likes of Japan, South Korea and Taiwan would remain the "core" markets for LNG.

"When you consider that Japan has been importing LNG for decades, it seems remarkable that China only received its first shipment in 2006," he said.

"With more regasification terminals scheduled to start up this year, demand is set to grow by about 17 per cent a year to 24 million tonnes in 2016."

With growing economies like Thailand, Singapore and Vietnam in mind, Mr Voelte said new LNG supply of about 60 million tonnes per annum would be needed to meet growing Asian demand from 2020.

The key is what this will do to pricing.”

China Ready to Unlock It’s Shale Energy

China has spent tens of billions of dollars buying into energy resources from Africa to Latin America to satisfy the thirst for fuel from its growing industry and burgeoning cities. But China may have more energy riches under its own soil than policy makers in the world's second-largest economy ever dared imagine.

Just over a year ago, Beijing awakened to a technology revolution that has unlocked massive reserves of gas trapped within shale rock formations in the United States. Once deemed too costly to extract, shale gas has turned around U.S. dependence on foreign gas imports. Just a few years ago, the United States was building scores of expensive facilities to import liquefied natural gas (LNG), looking at booming long-term demand forecasts and wondering which countries would supply the huge volume of imports it needed.

Instead, the United States is turning import facilities into export terminals, because its shale gas reserves are estimated to be big enough to meet domestic demand for 30 years. This is an American dream that China wants to emulate. "America's shale gas production alone has exceeded that of total Chinese gas output. That gives us a lot of confidence," said Zhang Dawei, deputy director of the Strategic Research Centre for Oil and Gas in the Ministry of Land and Resources(MLR).

China's confidence has been increased by a new report of its estimated reserves of shale gas, which shows them to be, by far, the largest in the world.

The U.S. Energy Information Agency in a report last month estimates China holds 36.1 trillion cubic meters (1,275 trillion cubic feet) of technically recoverable shale gas reserves -- significantly higher than the 24.4 tcm (862 trillion cubic feet) in the United States, which has the second-most.

Industry estimates in China peg shale gas resources slightly lower -- but still huge -- at 26 trillion cubic meters (tcm), although they have yet to give their own forecasts of how much of that is recoverable. China's imminent shale rush comes at a critical point. It will soon overtake the United States as the world's top energy user and is already the world's biggest coal burner. China also pumps more carbon dioxide into the atmosphere than any other country.

Beijing thus faces the daunting challenge of how to clean up its brown skies while meeting the world's fastest growing energy demand. Natural gas burns more cleanly than other fossil fuels and installing gas-fired power generation is cheaper and easier than building nuclear plants. The problem is China cannot meet its rising demand for gas with its limited reserves of conventional gas. It faces the prospect of becoming as dependent on international markets for gas as it is for oil, where China is the world's second-largest importer.

But shale gas may not be as clean as advertised, according to a study released in April by Cornell University. This study argues that significant amounts of methane -- a potent greenhouse gas -- escape into the atmosphere during production in wells and distribution in pipelines. Regardless, China is racing to find out how much shale gas it can exploit -- and how quickly it can get the technology and build the infrastructure it needs to pump it to market -- to reduce its dependence on foreign sources of gas. That race is about to begin any day now.

The MLR said it would hold the first auction of shale gas blocks by the end of the first quarter of this year, so it is already overdue. The ministry had previously delayed the auction, initially scheduled last November, to open up the bidding to more domestic companies -- inject more competition into the process and quicken the pace of shale development. The auction is for eight exploration blocks covering 18,000 square kilometers in four inland provinces: southwest Sichuan, Chongqing and Guizhou, and central Hubei province. "We are aiming for major breakthroughs in locating the reserves in five years, and in eight years shale gas should take a significant position in China's energy mix," said Zhang at the the land ministry. He talked of having shale gas account for one-tenth of China's total gas output by 2020.

China has identified shale gas as one of the country's top targets for technological breakthroughs in the 2011-2015 five-year plan, which means that Beijing will be opening the funding faucets for shale gas research. China's National Energy Administration is setting up a shale gas laboratory in Langfang, near Beijing, to be financed mostly by PetroChina, and that will become China's national shale gas research center, officials say.

Experts say shale, which needs intensive drilling and many wells, plays to China's strengths. "Shale gas projects are sometimes referred to as manufacturing operations. Which countries globally are particularly good at manufacturing?" said Robert Clarke, global head of unconventional gas research for Wood Mackenzie. "China certainly comes to the forefront of your mind -- good in controlling costs, looking at efficiencies, and continually learning from earlier mistakes."

PetroChina, which produces nearly 80 percent of China's total gas output, last month completed its first horizontal shale gas well in the Weiyuan block of Sichuan province. Its parent company and China's biggest oil and gas firm, China National Petroleum Corporation (CNPC), said it aimed to have unconventional gas, mostly shale, account for about a fifth of total gas production by 2030.

CNPC predicts that China's overall gas production will more than triple to 300 billion cubic meters by 2030 from 94 bcm in 2010. That would put shale gas output up near 60 billion bcm in 20 years, or more gas than India currently consumes.

Right now, China is pumping nothing at all from its shale gas reserves.

The shale rush only really began in China when President Barack Obama signed a cooperation pact on shale gas in November 2009 during a state visit to Beijing, just weeks before the Copenhagen climate talks. Washington thought that if China could increase gas usage at the expense of dirty coal, it would reduce the carbon footprint of the world's biggest greenhouse gas polluter.

U.S. firms had hoped the pact would help them leverage their technology to gain rare access to China's tightly controlled oil and gas reserves. China may have hoped to acquire some of that technology to help develop its fledgling shale industry. Neither has materialized to any great extent so far. But the pact has undoubtedly helped smooth out any political objections to acquisitions by cash-rich Chinese energy giants of stakes in North American shale assets. In a flurry of recent deals, they have effectively purchased the technology and expertise they lack back home.

China's third-largest oil and gas firm CNOOC struck two deals with leading U.S. shale gas player Chesapeake over the last several months, giving it access to drilling leases in Texas, Wyoming and Colorado. The deals marked CNOOC's successful entry into the United States after its 2005 bid for Unocal Corp was ended by strident political opposition over the involvement of Chinese state companies in the U.S. energy sector. Chevron later acquired the U.S. oil firm instead.

EUROPE / AFRICA

FRANCE

Shale Gas Drilling Likely to be Banned in France

The French government has backed a draft bill that would ban shale gas drilling in the country, citing fears that the extraction method is a risk to water quality. However, for other countries like Poland, shale gas has become a national priority to win independence from Russian imports. EurActiv France reports.

To proponents, shale gas represents a hitherto untapped and welcome alternative energy source to traditional fossil fuels. At the moment the continent depends on gas imported from Russia, and disputes between that country and Ukraine have disrupted winter supplies in recent years.

In the U.S., shale gas already accounts for over 10% of US natural gas production and some analysts predict that could rise to 50% within 20 years. BP's former chief executive Tony Hayward has described shale gas as a "game changer".

MPs from the ruling centre-right UMP party tabled the bill in the National Assembly using an accelerated procedure. As a result, it will only be examined in a single reading in the Assembly and the Senate.

If adopted, the text would suspend drilling permits granted in March 2010 to Total, GDF Suez, and Schuepbach Energy by former Environment Minister Jean-Louis Borloo.

A shale gas drilling ban is also supported by the opposition Socialist Party, which presented its own alternative text with the same aim.

In March, the French government had prolonged a moratorium on shale gas drilling until June.

This had followed protests opposing the drilling method, notably in the village of Villeneuve-de-Berg in southern France, with over 20,000 people voicing their opposition chanting "No gazaran!" Shale gas drilling near the town had been planned for the end of 2011.

Scientists relieved, oil business fears red tape

After the announcement of the suspension of drilling, researchers at the hydro-science center at the University of Montpellier said they were reassured. In the event of shale gas drilling, Montpellier's region "and all the water reserves close to the drilling area would have been seriously threatened," said researcher Françoise Elbaz.

"There is always a technological risk. In going back up, the drill can release toxic gases such as the radioelements naturally contained in the rocks," she said. "And the authorities would have to cut off the water supply."

No such drilling has yet taken place in France, but researchers cite the example of the city of Pittsburgh in the United States. Elbaz says that following the use of chemicals to fracture the rock and ensure permeability, the waters of the city have reached a salinity level inappropriate for consumption.

During a presentation of his company's annual results last February, the director-general of Total, Christophe Margerie, said he was "annoyed by the noise" surrounding shale gas. He expressed frustration with excessive concern about the safety of drilling, saying "it's good to talk about the problems this can pose – if one day there are some – but today, there are none".

Margerie also raised fears that red tape could hinder production. "[If] we need to ask the authorization to one day ask for authorization, we're going to start falling into useless paperwork," he said.

If the law is passed, the French debate on shale gas should be closed, but the discussion continues at the European level.

Last February, European leaders agreed that "Europe's potential for sustainable extraction and use of conventional and unconventional (e.g. shale gas, oil shale) fossil fuel resources should be assessed".

A report by the consultancy firm McKinsey – commissioned by major gas giants Gazprom, Centrica and others – claimed that shale gas could meet the continent's energy needs for 30 years.

Cuadrilla Resources, a British energy company, has begun exploratory drilling near Blackpool, Lancashire. Drilling of shale gas is already taking place near Gdansk, Poland.

For certain European countries, Poland in the lead, the drilling of shale gas is seen as an alternative to Russian gas, which would allow for greater energy independence.

POLAND

Poland May Be Sitting on More Shale Gas Reserves than Earlier Estimated

A new estimate suggests the nation of Poland may have nearly twice as much shale gas as previously thought.

Enthusiasm for shale gas could make drilling rigs a common sight. It is already common knowledge that Poland’s potential shale gas reserves could be a game-changer for the country, but a new estimate from the United States’ Energy Information Administration (EIA) has raised the bar again.

Unconventional resources consultancy Advanced Resources International had previously put Poland’s maximum shale gas reserves at three trillion cubic meters, but the EIA’s most recent analysis suggests 5.3 trillion cubic meters of shale gas could be present beneath the country.

Poland’s annual gas consumption amounts to 14 billion cubic meters at present, meaning the reserves could supply the country’s needs for 300 years.

But Henryk Jacek Jezierski, Poland’s chief national geologist, has warned against over-optimism. He emphasized that the American study was still preliminary.

“The next step in determining the size of Polish [reserves] are the results of the U.S. Geological Survey and the Polish Geological Institute, which will probably be published in September,” Mr Budzanowski said in a statement published on the Polish Environment Ministry’s website. And even those figures will be an approximation, he added. Reliable data can only be gathered on the basis of exploration, a broad picture of which will not be clear for a few more years.

Nonetheless, the EIA’s report places Poland as a clear leader when it comes to shale gas reserves in Europe, with only France estimated to possess similar levels.

And given Poland’s concerns regarding energy security (it is currently dependent on Russian gas) and public opinion’s generally positive view of mining, the country has a much friendlier social and political environment for the development of the shale gas industry, noted Ernest Wyciszkiewicz, an economic relations and energy security expert at the Polish Institute of International Affairs (PISM).

“Undertakings relative to shale gas in Europe are still quite risky, and any kind of news that the potential shale reserves are bigger than expected is great news for investors, as well as for the Polish administration and policymakers,” said Mr Wyciszkiewicz.

On the one hand, reports of potentially larger reserves are likely to influence the investment strategies of companies interested in the Polish market. On the other hand, it might provide an incentive for the government to accelerate the building of a proper regulatory and legal framework for this potential new sector, Mr Wyciszkiewicz suggested.

Other steps needed to encourage investment include the improvement of access to exploration equipment such as drilling rigs, the establishment of interconnectors to other national gas pipeline systems and, eventually, deregulation of the energy market so that new players can get direct access to end consumers.

“For now we are still in the exploration phase, but it is important that companies interested in investing be sure that the market will be accessible for them,” commented the PISM expert.

The EIA report singles out three regions in Poland that appear favorable for shale gas exploration: the Baltic region in the north, Lublin in the south, and Podlasie in the east.

The Environment Ministry has so far granted 85 concessions for shale gas exploration.

Polish gas monopolist PGNiG and U.S. firm Lane Energy have recently made promising progress in the Pomorze region in the north.

ALGERIA

Eni and Sonatrach Sign Cooperation Agreement for Development of Unconventional Gas in Algeria

Eni and Sonatrach on April 29 signed a cooperation agreement for the development of unconventional oil, with particular focus on shale gas reinforcing the close relationship between the two companies.

With extensive experience in exploration and production of unconventional oil, Eni and Sonatrach will jointly implement activities to assess the technical and commercial feasibility of exploration and operational initiatives in shale gas.

Based on previous assessments, Eni confirms the significant shale gas reserves in Algeria which Eni and Sonatrach wish to explore and develop. This will enable both companies to make important discoveries which will enhance the gas potential of the country.

Eni has been in Algeria since 1981. Eni's equity production is currently 75,000 barrels per day. In Algeria, Eni holds 24 licenses in production, 8 licenses under development and an ongoing exploration license.

Last month, Algeria's energy minister, Youcef Yousfi, said the potential for unconventional natural gas in the North African country may be bigger than in the U.S., based on early indications.

The interest is also part of a broader strategic diversification within Eni. In December, it entered the European shale gas market with an acquisition in Poland.

McIlvaine Company,

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