There is a growing interest in the world’s biggest integrated oil companies in gaining exposure to and operational experience in North America’s unconventional gas reserves.

ExxonMobil Corp’s acquisition of shale-gas producer XTO Energy in a transaction worth $41 million--the energy’ giant’s biggest takeover in a decade--underscores the near-term and long-term opportunity in this segment.

In the near term, many of the nation’s hottest shale plays remain economic to produce even with depressed natural-gas prices.

For example, producers have ramped up drilling activity in the Eagle Ford Shale and other basins that contain ample amounts of natural gas liquids (NGL) and condensates, higher-priced commodities that boost margins. And the northern reaches of the shale deposit primarily produce oil.

At the same time, oil- and liquid-rich shale plays aren’t the only economic options in a weak market; parts of the Haynesville Shale, which extends from Louisiana into East Texas, are so prolific that production costs are among the lowest in North America. Even in a weak pricing environment, producers in the Haynesville still generate solid returns.

ExxonMobil’s management acknowledged these trends in the company’s second-quarter conference call, noting that the firm’s near-term focus would be on ramping up gas production in the most economically attractive shale plays.

Over the long term, ExxonMobil expects global consumption of natural gas to increase 55 percent between 2005 and 2030, thanks to an abundance of supply from unconventional fields, the West’s push for energy independence and efforts to reduce carbon dioxide emissions. Moreover, ExxonMobil’s acquisition of XTO nearly tripled the energy giants’ U.S. natural gas output; such production growth is hard to come by in the oil business after the rise of national oil companies.

But as Elliott Gue has noted on numerous occasions in his paid advisory, The Energy Strategist, services industry names tend to benefit handsomely from producers’ frenzied drilling in unconventional fields; although many of the hottest plays offer attractive economics, the complexities of drilling in these regions require two to five times the amount of services works as a conventional well.

Not surprisingly, the takeover bug has also bitten the services industry, and participants are bolstering their product portfolios by scooping up smaller names with attractive business lines or promising technologies. Of late, much of this interest has centered on the pressure pumping space, the muscle behind the huge fracturing (fracking) operations that unlock the gas trapped in shale deposits.

Whereas horizontal drilling enables producers to increase the well’s exposure to productive zones, fracking increases the permeability of the reservoir rock that enables natural gas to flow into the well. Fracturing, or stimulation, involves pumping large quantities of water and a small percentage of chemicals into the rock formation at high pressure, a process that produces a network of cracks. The inclusion of a proppant--typically sand, sand coated with ceramic material or ceramic material--ensures that these passages remain open. This key service often accounts for about half of production costs at unconventional plays.

Services giant Baker Hughes made the first splash in this critical business segment with its $5.5 billion deal for BJ Services, the third-biggest pressure-pumping outfit behind Halliburton and Schlumberger. When the deal was announced in August 2009, management noted that the new business line would enable Baker Hughes to compete more effectively in the North American natural gas market and for bundled contracts overseas.

Two more deals have closed in the past two months.

Patterson-UTI Energy owns and operates a fleet of roughly 350 land-based rigs in the U.S. and boasts a long history of operation in Appalachia, including the Marcellus Shale. In early July the firm agreed to purchase Key Energy Services’ pressure-pumping and wireline assets for $237 million. In the company’s second-quarter conference call management noted that its existing pumping business in the Appalachian Basin remains in high demand, prompting the company to invest in additional horsepower. The acquisition will increase the total horsepower of its pumping operations to 470,000 and provide exposure to the Barnett, Eagle Ford and Permian Basins.

More recently, Nabors Industries, the world’s leading land-rig contractor, announced that it will acquire Superior Well Services in an all-cash deal worth $900 million. Superior boasts 530,000 horsepower in pressure-pump capacity, 98 percent of which dates from after 2003. Although Superior has operations in all of the major basins, the deal will boost Nabors’ presence in the Marcellus Shale. Price increases amid higher demand for pumping services enabled Superior to more than double its revenue in the second quarter.

What are the implications of this spate of deals? For one, this uptick in acquisitions confirms that demand for pumping remains robust in North American shale plays--hardly a surprise given that the horizontal, gas-directed rig count continues to account for roughly 54 percent of all units targeting natural gas.

Moreover, pricing dynamics also appear robust; many pumping outfits slashed prices at the height of the downturn and now have scope to raise prices. Given significant cost reductions, profits remain impressive.

David Dittman, associate editor Canadian Edge, has suggested shares of Canadian pressure-pumping outfits, especially those with leverage to the Horn River Basin in northeast British Columbia. EnCana Corp's recent joint ventures in the region suggest that activity will pick up. And given the play’s geology, horsepower is particular important.

Investors should also consider a handful of names that produce valves and other replacement parts for the advanced rigs and pumping systems; with operators increasingly producing larger horizontal areas, wear and tear on drilling and fracturing equipment ensures a growing stream of demand.

AMERICAS

U.S.

Marcellus Shale Drillers Amass 952 Violations Likely to Harm the Environment

The Pennsylvania Land Trust Association has reviewed environmental violations accrued by Marcellus Shale drillers working in Pennsylvania between January 2008 and June 25, 2010. The records were obtained via a Right to Know Request made to the Department of Environmental Protection.

DEP records show a total of 1,435 violations of state Oil and Gas Laws due to gas drilling or other earth disturbance activities related to natural gas extraction from the Marcellus Shale in this 2.5-year period.

The Association identified 952 violations as having or likely to have an impact on the environment. 483 were identified as likely being an administrative or safety violation and not likely to have the potential to negatively impact the environment.

The report breaks the violations down by type. For example, of the 952 violations:

-- 268 involve improper construction of waste water impoundments;

-- 10 involve improper well casing;

-- 154 involve discharge of industrial waste; and

-- 16 involve improper blowout prevention.

The report lists the 25 companies with the most violations as well as the 25 companies with the highest average number of violations per well driller.

DEP Fines Talisman Energy $15,506 for Bradford County Drilling Wastewater Spill

The Department of Environmental Protection has fined Talisman Energy USA Inc., of Horseheads, N.Y., $15,506 for a spill of used natural gas drilling fluids last November at its Klein gas well pad in Armenia Township, Bradford County that polluted a small, unnamed waterway.

The spill involved hydraulic fracturing flowback fluid, which is the substance that returns to the surface after a company injects the pressurized fluid underground to fracture, or “frack,” a geologic formation and extract natural gas.

“DEP’s investigation in late November 2009 determined that Talisman spilled between 4,200 to 6,300 gallons of fracking flowback fluids when a pump failed and sand collected in a valve,” said DEP Northcentral Oil and Gas Program Manager Jennifer Means.

The fluids flowed off the well pad and toward a wetland, and a small amount ultimately discharged to an unnamed tributary to Webier Creek, which drains into the upper reaches of the Tioga River, a cold water fishery.

Talisman successfully completed DEP’s Act 2 process for spill cleanup activities.

The fine will be deposited into the fund that supports DEP’s oil and gas permitting and enforcement programs.

NiSource, UGI to Build New Marcellus Pipeline

NiSource Inc. and UGI Corp. have announced that NiSource's NiSource Gas Transmission & Storage (NGT&S) unit and UGI's UGI Energy Services, Inc. unit, are partnering to develop a new natural gas pipeline to provide Marcellus Shale producers in Pennsylvania improved access to high-value markets.

An estimated 500,000 Dth/day of transportation capacity will be made available for increased production along NiSource's Columbia Gas Transmission pipeline system in Clearfield, Centre and Clinton counties to interconnections with Transcontinental Gas Pipeline Corp., Tennessee Gas Pipeline Company, Dominion Gas Transmission, Inc., and Millennium Pipeline Company in north central Pennsylvania and southern New York, as well as connections to UGI's Tioga/Meeker natural gas storage facilities and extensive gas distribution network.

"With the significant increase in drilling and deliverability of natural gas in the Marcellus Shale, there is a growing need for capacity to facilitate the movement of producers' gas to downstream markets," said Christopher A. Helms, executive vice president and group CEO for NGT&S. "Providing solutions to deliver this exciting new supply source to high-value markets is a key focus area for NGT&S. With this and other projects, we are working diligently to advance the NGT&S strategic plan to meet customer needs through thoughtful infrastructure investment."

Bradley C. Hall, president of UGI Energy Services, said, "This joint marketing agreement brings together two major players with strategic assets, supplier relationships, and customers in and near the Marcellus Shale region. UGI has a large appetite for natural gas and we believe this project will provide our utility and transportation service customers with cost effective and reliable gas supply. We look forward to working with NGT&S on this important new supply initiative, especially given its operating and construction expertise with transmission and gathering pipelines."

The joint marketing and development agreement is the first step in the planned development, construction and operation of a natural gas transmission pipeline with multiple points of access for producers and customers. The collaboration of the two companies will leverage the considerable Marcellus development efforts of each company, along with their extensive asset bases in Pennsylvania.

Development and construction costs are expected to be shared equally by the partners. Based on extensive work completed to date, the parties expect to file preliminary plans with the Federal Energy Regulatory Commission (FERC), and to hold an open season for the project's capacity, by the end of the year. The project is targeted to be in-service in the fourth quarter of 2012. The partners anticipate additional expansions in the future as producers carry out their drilling plans.

The NGT&S companies include Columbia Gas Transmission, Columbia Gulf Transmission, Hardy Storage, Millennium Pipeline and Crossroads Pipeline. Combined, the companies operate about 15,000 miles of interstate natural gas pipeline and 37 storage fields, delivering over 1 trillion cubic feet of natural gas per year.

UGI Energy Services, the midstream and energy marketing unit of UGI, markets natural gas, electricity, and fuel oil to over 8,000 commercial and industrial customers at over 25,000 locations throughout the mid-Atlantic region, owns and operates natural gas storage in the Marcellus Shale region and peaking plants for utility clients, and owns 112 megawatts of electric generation capacity, as well as another 125 megawatts of gas fired generation under construction. UGI Utilities, Inc., a unit of UGI, serves much of the Marcellus Shale geography in northern and eastern Pennsylvania with 625,000 customers and 12,000 miles of pipeline in 45 Pennsylvania counties.

UGI to Spend $300 Mln over Next Two Years on Marcellus Midstream Projects

UGI Corp. announced August 12 that it plans to invest approximately $300 million over the next two years on midstream projects to support the development of natural gas infrastructure in the Marcellus Shale region.

Lon R. Greenberg, chairman and chief executive officer of UGI, said, "The natural gas in the Marcellus Shale region of Pennsylvania is in areas in which we have a significant amount of assets, including much of our utility and gas marketing service territories. We believe these and future projects will provide our utility and transportation service customers with cost effective and reliable gas supply. Our ultimate investment will depend on many factors, but given our strategic assets, supplier relationships, customer base and expertise in energy logistics, we are confident in our ability to invest wisely for the benefit of our stakeholders."

Among these investments are the recently announced agreement between UGI's midstream and energy marketing unit, UGI Energy Services, Inc., and NiSource Gas Transmission and Storage (NGT&S) to market and develop a major pipeline project to provide Marcellus Shale producers in Pennsylvania improved access to high-value markets. This project would be subject to approval by the Federal Energy Regulatory Commission (FERC) and is planned to be available for service in late 2012.

In addition, UGI plans to enhance the delivery options from its Meeker and Tioga storage fields located in north central Pennsylvania by drilling additional storage wells and adding dehydration and compression capacity. UGI's storage fields are ideally situated to enable Marcellus gas to efficiently serve temperature sensitive end-use markets. In addition, the fields are connected to UGI's gas utility distribution system, as well as to the Dominion Gas Transmission, Inc. and Tennessee Gas Pipeline Company interstate pipeline systems. The proposed pipeline by NGT&S and UGI also would connect to these storage fields. This storage enhancement project, which would be subject to regulatory approval, is planned to be available for service in 2013.

Additional projects to construct gathering facilities and purchase gas from Marcellus producers would bring locally produced gas to Pennsylvania and interstate markets during 2012. These projects would not be subject to FERC approval.

UGI a holding company with propane marketing, utility and energy marketing subsidiaries owns 44% of AmeriGas Partners, L.P., the nation's largest retail propane marketer, and also owns Antargaz, one of the largest LPG distributors in France.

Dominion Announces New Marcellus Project with Tennessee Gas Pipeline

Dominion announced August 9 that its natural gas transmission and storage subsidiary, Dominion Transmission, has reached a 10-year lease agreement with Tennessee Gas Pipeline Company for firm capacity to move Marcellus shale natural gas supplies.

The Ellisburg-to-Craigs project, with capacity of 150,000 dekatherms per day, will move natural gas from Tennessee's 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York.

"Dominion Transmission's hub-and-spoke network crisscrossing the Marcellus shale producing area provides many opportunities to help transport new natural gas supplies to market," said Thomas F. Farrell II, chairman, president and chief executive officer of Dominion. "This agreement with Tennessee for new capacity is an excellent example."

Dominion plans to file for a FERC certificate in December. Once the project is approved, construction will commence in March 2012, with a planned in-service date of November 1, 2012. Construction plans include additional compression facilities and a new measurement and regulating station at the Craigs interconnect with Tennessee in New York. Dominion will also add regulating facilities on its system in northern Pennsylvania.

NY Governor Says No Gas Drilling unless Fracking Proves Safe

Gov. David Paterson says hydraulic fracturing of natural gas wells in New York's part of the four-state Marcellus Shale region won't be allowed without "overwhelming evidence that nothing will happen" to harm clean water supplies.

In an interview August 13 on Syracuse radio, Paterson said the controversy over natural gas drilling is "obviously a clash between a very lucrative profit-making opportunity and a very serious public safety hazard."

He said a decision on issuing gas drilling permits will be based on scientific evidence showing hydraulic fracturing is safe. Permits have been on hold for two years in New York while regulators complete a review.

While opponents say hydraulic fracturing, which uses chemical-laced water at high pressure to fracture gas-rich shale, threatens water supplies, the industry says it's been used safely for decades.

Reliance Industries Spends $392 Mln for Third U.S. Shale Gas Stake with Carrizo Oil & Gas

India's Reliance Industries will pay $392 million for a 60 percent interest in a shale gas joint venture with U.S.-based Carrizo Oil & Gas, the company said August 5.

This is the third such deal this year for Reliance as it chases resources and expertise in promising unconventional gas reserves in North America. Reliance has been keen to play a stronger role in the U.S., the world's second-biggest energy consumer.

"The proposed joint venture will supplement strengths achieved through our recent joint ventures and further expands our footprint in North American shale gas operations," Walter Van de Vijver, Reliance's president of international exploration and production, said in a statement.

Under the terms of the deal, Reliance will buy out the interest of Avista Capital Partners to form a new joint venture with Carrizo to explore 104,400 net acres in Pennsylvania's Marcellus Shale area.

New extraction technology has helped create a boom in shale gas, which is geologically difficult to extract.

Reliance estimates the potential resource at 3.4 trillion cubic feet equivalents of gas and said it expects to drill 1,000 wells in the area over the next decade.

The transaction is expected to close in September.

Since April, Reliance has agreed to pay $3 billion for significant stakes in Atlas Energy and Pioneer Natural Resources, two other U.S. companies with shale gas holdings.

Cubic Energy Participates in Additional Horizontal Haynesville Shale Well

Cubic Energy, Inc. announced August 16 that the Crow 8 No. 1 spud on August 10, 2010 and surface casing was set at 1,925 feet on August 11, 2010. Cubic has a 24% working interest in this well.

Richard Sepulvado, Cubic's Vice President of Exploration and Production states, "This is the third well to be drilled under our existing drilling credit and we look forward to continued development of our Haynesville Shale acreage."

The Crow 8 No. 1 is currently drilling its vertical portion of the well. This well is located in Section 8, Township 14 North -- Range 15 West in Caddo Parish, Louisiana which is located in Cubic's Bethany Longstreet acreage. Cubic Energy, Inc. is an independent company engaged in the development and production of, and exploration for, crude oil and natural gas. The Company's oil and gas assets and activity are concentrated primarily in Louisiana and Texas.

EOG Selling 180,000 U.S. Shale Acres to Increase Oil Exploration Funds

EOG Resources Inc said August 6 it plans to sell about 180,000 acres in U.S. shale plays as part of the oil and gas company's effort to increase funds for oil exploration.

EOG will sell 117,000 acres in the Eagle Ford Shale in South Texas; 51,000 acres in the Marcellus Shale in Pennsylvania; in 15,000 acres in the Haynesville Shale, Mark Papa, the company's CEO, told analysts on a conference call.

"We're so long on acreage relative to what we can logically develop in a reasonable period of time," Papa told analysts.

EOG, based in Houston, also plans to sell Canadian shallow gas assets that produce 170 million cubic feet per day.

On August 5, EOG reported a second quarter profit that fell short of Wall Street estimates. The company also said it would boost 2010 spending by $500 million.

Capstone Turbine Receives Order for Eagle Ford Shale Play

Capstone Turbine Corporation has received an order for 18 C65 microturbines for one of the world's largest independent oil and natural gas companies.

Capstone distributor Pumps & Service received its second order in the past eight weeks from a major oil and gas company exploring large shale reserves in the U.S. The market for Capstone turbines and microturbines in this industry is vast. The market is expected to grow substantially, especially since the U.S. Environmental Protection Agency's (EPA) Clean Air Act has strict requirements for emissions levels at natural gas sites.

The 18 low-emission C65 microturbines will provide prime power to central processing facilities and metering stations at remote well sites in the Eagle Ford shale play in South Texas. The Eagle Ford play is expected to emerge as a major oil and gas play in the United States over the next decade. Experts estimate it will rank sixth in size among the all-time giant oil fields in the U.S.

"Many of these sites are extremely remote and unmanned, which means 24x7 distributed power is paramount," said Jim Crouse, Capstone's Executive

Vice President of sales and marketing; "Even more important; producers must meet tough EPA air-permitting requirements; which makes Capstone's clean and green, low-emission microturbines attractive."

"The reliability of Capstone microturbines, along with their low emissions, low cost of ownership, and Pumps & Service's ability to deliver the total

solution; all contributed to the company's decision to select Capstone," said Bryan Hensley, Vice President of Sales and Marketing, Pumps & Service.

The order Pumps & Service received two months ago from North America's largest gas producer featured a Capstone C600 microturbine that will be installed at a site pumping gas from the Marcellus Shale Play that spans West Virginia, Pennsylvania and Southern New York.

N.Y. Overseeing $1.5 Mln Research Project into Carbon Storage in Shale Formations

New York's gas-rich underground rock formations have sparked a contentious fight over drilling safety, but they're also being studied as potential tombs for the greenhouse gas emissions that fuel global warming.

The New York State Energy Research and Development Authority is overseeing a $1.5 million research project, also supported by the U.S. Energy Department, into the Marcellus Shale as well as other shale formations in New York, Vermont and Kentucky.

Researchers hope to learn whether wells drilled a mile or more underground into the Marcellus, which contains lucrative deposits of natural gas, could be used to contain power plant emissions of carbon dioxide, a greenhouse gas released by burning of fossil fuels.

The two-year project is linked "to the current boom in development from eastern gas shales, namely hydraulic fracturing and horizontal drilling," according to research plans filed in April with the U.S. Energy Department.

Also called hydrofracking, the drilling technique -- which relies on a high-pressure blend of water, chemicals and sand to crack apart gas-bearing underground rocks -- is in widespread use in states such as Pennsylvania, Texas and Colorado.

But it has not started in New York, where companies over the past two years bought up drilling rights on thousands of acres in the gas-laden Marcellus Shale, which stretches from the western Catskills through the Southern Tier.

The state Department of Environmental Conservation is still crafting a set of rules for hydrofracking, although the state Senate recently passed a bill to delay rules until mid-May. That moratorium has not yet been taken up in the Assembly.

Opponents have linked hydrofracking to groundwater contamination in other states. The gas industry insists the process is safe.

NYSERDA is providing $250,000 toward the research, which also will determine whether CO2 injections could help push out more gas to drillers as hydrofracked wells begin to play out, boosting profits and making CO2 injection less expensive.

"If we are moving more product out of the ground that is being sold, that can make CO2 injection more economical," said Mark Torpey, NYSERDA director of research and development. "We will also be asking whether CO2 can be used as a fracking method."

Removing CO2 from power plant emissions, which account for about 40 percent of the nation's carbon emissions, and storing the gas underground -- a concept called carbon capture and sequestration -- is part of the Obama administration's plan to fight climate change.

Capture and sequestration would allow continued widespread burning of coal, which supplies half the nation's electricity but releases much more CO2 than natural gas does. New York gets about 20 percent of its electricity from coal.

In August, the Energy Department funded 15 underground storage research projects, including the one in New York, at a total of $21.3 million.

For this project, plans call for a test CO2 injection well at a Kentucky shale field, and a second well at an as-yet-unidentified location, said Michael Godec, vice president of Advanced Resources International, an Arlington, Va.-based energy consulting company that is spearheading the two-year project.

"The biggest benefit, if this works, is that shales happen to coexist in areas where many coal-fired power plants already are," Godec said. This would reduce the need for expensive piping networks to carry CO2 to underground storage.

Godec said it was too early to tell if the second CO2 injection well will be built in New York. He said contentious nature of hydrofracking in the state might slow down needed permits for such a well beyond the project's timetable.

At Cornell University, researchers will study special chemical markers introduced into gas wells to track water flow pushed by the pressure from CO2 injection through underground cracks. Researchers from the University at Buffalo will examine the Marcellus and other New York shales for promising underground sites.

NYSERDA has spent two years looking for such sites in the Southern Tier counties of Broome, Chenango, Cayuga, Steuben, Yates, Schuyler and Tompkins, plus Erie, Chautauqua and Cattaraugus counties in the western edge of the state.

Torpey also could not say whether a CO2 injection well will be tested in New York. Further research on shale formations will be supplied by the Vermont Geological Survey, Kentucky Geological Survey, and HTC Purenergy.

If CO2 can be used to harvest more natural gas from shale while at the same time being locked away underground to reduce climate change, the beneficiaries would be "those currently developing and producing natural gas from shales today; power generators that would like to find cost-effective CO2 storage options nearer to their facilities in the east; and states, landowners and other parties that could economically benefit from further economic production and utilization of the eastern gas shale resource," according to the research plan.

The research includes a "number of industrial partners, including several oil and gas operators that are currently drilling in eastern shale wells ... some commitments of data for wells in each of the target formations have already been made," the plans stated.

Godec declined to identify the companies, saying he did not yet have signed agreements.

Today, the cost of carbon storage appears prohibitively expensive at up to $300 per ton, according to the U.S. Department of Energy. That would greatly increase the cost of electricity generated by coal, likely making it more expensive than alternative energies like wind and solar.

The government's goal is to reduce storage costs to less than $10 per ton by 2015.

DOE estimates underground saline formations, which are different from shale, could store up to 500 billion tons. That's equivalent to about 300 years of the U.S. total CO2 emissions.

The storage method does have risks. One danger could be the sudden and unintended release of CO2 gases into the atmosphere if an underground storage area were to crack or rupture.

U.S. / CANADA

Enbridge to Add Bakken Pipeline Capacity

Enbridge Energy Partners L.P. (EEP) and Enbridge Income Fund (ENF) announced August 24 that they are proceeding, subject to customary regulatory approvals, with a joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota, Manitoba and Saskatchewan. The Bakken Expansion Program will increase takeaway capacity from the Bakken play by 145,000 barrels per day (bpd), which can be readily expanded to 325,000 bpd at low cost. EEP and ENF are affiliates of Enbridge Inc. (collectively "Enbridge").

"This latest in a series of expansions will provide shippers with favorable tolls, diverse market alternatives and batch quality maintenance for this high quality light sweet crude. Further, the Bakken and Three Forks formations represent an area of tremendous opportunity for both Enbridge Energy Partners and Enbridge Income Fund," said Stephen J. Wuori, Executive Vice President, Liquids Pipelines, Enbridge Inc. "We anticipate substantial further production growth based on discussions with producers, and our own regional supply analysis. We are well positioned to provide shippers with attractive transportation options based on our extensive existing operations in the region."

Enbridge's Bakken Expansion Program will involve U.S. projects which will be undertaken by EEP at a cost of approximately US$370 million; and Canadian projects which will be undertaken by ENF at a cost of approximately Cdn $190 million. The expansion program will originate at Beaver Lodge Station near Tioga, North Dakota, in the heart of the Bakken, and will follow existing EEP and ENF rights of way to terminate at and deliver to the Enbridge mainline terminal at Cromer, Manitoba. In addition, EEP has proposed a separate project to expand its pipeline system south of the Missouri River, connecting to Beaver Lodge Station and providing increased access to the expanded North Dakota System. Once on the Enbridge mainline, Bakken production will have access to the multiple markets accessible from the mainline and connected pipeline systems. The Program is a series of pipeline expansion projects that will provide approximately 145,000 bpd of incremental capacity from North Dakota into the Enbridge Mainline at Cromer, Manitoba by Q1 2013.

EEP and ENF have received sufficient long-term shipping commitments from anchor shippers to enable the Bakken Expansion Program to proceed. A binding Open Season is planned to provide other shippers with the opportunity to make shipping commitments between Berthold and Cromer on the same terms as provided to anchor shippers, as well as to provide an opportunity to commit to capacity on the proposed expansion of EEP's pipeline system in northwestern North Dakota. Details on the Open Season will be announced separately.

The Bakken Expansion Program follows a series of expansions that have been undertaken by EEP and ENF to economically respond to growing crude oil transport needs from this region. EEP's North Dakota System completed a 51,000 bpd expansion to reach a total annual capacity of 161,500 bpd on January 1, 2010. That capacity was immediately fully utilized, and operational fine tuning is being undertaken to further enhance the capacity of this system between North Dakota and the Enbridge mainline system at Clearbrook, Minnesota. ENF's Saskatchewan System is currently undertaking three separate expansions, expected to be in service late this year that will collectively increase upstream capacity of the gathering systems by 125,000 bpd. Total capacity into Cromer following the current (Phase II) and the previously completed Phase I expansion will be 230,000 bpd.

"We are confident that this series of expansions will relieve much of the current demand for pipeline capacity out of the Bakken and Three Forks production areas as well as provide the foundation for timely future expansions to meet the needs of the region", said Wuori. "The suite of projects we're proposing will provide firm access from North Dakota oilfields to the 2 million barrel per day Enbridge Mainline System. Along with ongoing reliable service for existing shippers on EEP's North Dakota System and ENF's Saskatchewan system, the expanded systems optimize segregated light sweet pipeline capacity serving the Great Lakes region of the Upper Midwest and the Midcontinent refinery markets connected to Cushing, Oklahoma.

"By providing shippers with timely, cost-effective, long-haul and long-term transportation solutions, Enbridge's Bakken Expansion Program will give them the best options and greatest connectivity into North American refinery and marketing hubs."

Enbridge Inc. has a 27% ownership interest in EEP, and a 72% economic interest (41.9% voting interest) in ENF. Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

Enbridge Energy Partners, L.P. owns and operates a diversified portfolio of crude oil and natural gas transportation systems in the United States, including the Enbridge North Dakota System. Its principal crude oil system is the largest transporter of growing oil production from western Canada. The system's deliveries to refining centers and connected carriers in the United States account for approximately 11 per cent of total U.S. oil imports; while deliveries to Ontario, Canada satisfy approximately 60 per cent of refinery demand in that region. EEP's natural gas gathering, treating, processing and transmission assets, which are principally located onshore in the active U.S. Mid-Continent and Gulf Coast area, deliver approximately 3 billion cubic feet of natural gas daily.

Enbridge Energy Management, L.L.C. manages the business and affairs of EEP and its sole asset is an approximate 14 per cent interest in EEP. Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc. of Calgary, Alberta, is the general partner and holds an approximate 27 percent interest in EEP.

Enbridge Income Fund is an unincorporated, open-ended trust created to provide a stable and sustainable flow of distributable cash to unit-holders. ENF is a premier income fund in Canada with a low-risk profile focused on energy infrastructure assets. It owns a 50% interest in the Canadian segment of the Alliance Pipeline, a 100% interest in Enbridge Pipelines (Saskatchewan) Inc., and a 50% interest in NRGreen Power Limited Partnership, which operates electrical generation facilities using waste heat, and holds interests in three wind power projects in Western Canada.

U.S. / AUSTRALIA

Oil India Gears up for Overseas Shale Assets Acquisition

State owned oil major, Oil India Ltd (OIL), is in talks with several U.S. shale gas companies to jointly acquire shale gas properties in the U.S. and Australia worth Rs1 billion in 2010.

N M Borah, chairman of OIL told PTI that the company is currently talking with some U.S.-based shale gas companies to form a JV to acquire shale gas assets globally since U.S. shale gas companies have the expertise and the technology for the extraction of shale gas.

Oil India, which has earmarked a budget of Rs1 billion for potential shale asset acquisitions in 2010, is reported to have hired seven investment banks including Citigroup, Morgan Stanley, Bank of America Merrill Lynch and Deutsche Bank to identify and advise on potential shale gas assets that could be acquired in the U.S. and Australia.

The public sector exploration company may even team up with two other state run energy firms, GAIL India and oil marketing company Indian Oil for joint acquisitions of shale gas properties overseas, according to T K Ananth Kumar, Oil India director of finance.

Oil India also plans to invest around Rs300-Rs500 crore in shale gas exploration over the next three to four years, said Borah.

Meanwhile, Washington has offered India its expertise in exploring and exploiting shale gas resources - a move that is aimed at helping India reduce its dependence on oil and gas imports.

Briefing media representatives at the August Global Shale Gas Initiative Conference in Washington, David Goldwyn, the Obama administration's coordinator for International Energy Affairs, had said, ''Coincident with prime minister Singh's visit to the US, we launched a memorandum of understanding with India on shale gas. And we have proposed... that the US Geological Survey (USGS) do a resource assessment of certain shale basins in India.''

Goldwyn said that the USGS would also train Indian geophysicists to enable them to professionally assess shale resources.

Shale gas has become an important source of energy in a few countries which have been able to commercially exploit this resource.

India has so far only explored on-land and offshore oil and gas blocks and preliminary estimates show India's shale-gas reserves may be larger than its proven conventional gas deposits, according to P K Bhowmick, president of the Association of Petroleum Geologists.

Several basins in India are known to hold shale gas resources, particularly in three basins - Cambay (in Gujarat), Assam-Arakan (in the North-East) and Gondwana (in central India.

India plans to join the booming shale-gas exploration business that has fuelled more than $39 billion of acquisitions in the U.S. by companies, including Exxon Mobil, Royal Shell and Reliance Industries Ltd.

India also plans to change exploration laws for shale gas in the country because current exploration licenses do not include unconventional sources and need to work out how companies that produce shale gas will share profit with the government, when India puts oil and gas block for auctions under NELP.

India, Asia's third-biggest energy consumer, faces an energy shortfall of 55 per cent by 2030 as demand more than doubles to the equivalent of 1.3 billion metric tons of oil, according to the Paris-based International Energy Agency.

Enterprise to Provide Midstream Services for EOG Resources in the Eagle Ford Shale

Enterprise Products Partners L.P. on September 1 announced that its operating subsidiaries have entered into long-term agreements with EOG Resources, Inc. to provide a comprehensive package of midstream energy services that will service EOG's growing crude oil and associated liquids-rich natural gas production in the prolific Eagle Ford Shale in South Texas. As part of the arrangements, Enterprise will utilize its existing assets and build additional infrastructure to provide EOG with a full range of value-added midstream services for its Eagle Ford production, including crude oil transportation, storage and exchange; natural gas transportation, treating and processing; and natural gas liquids (NGL) transportation and fractionation.

"We are very pleased to contract with EOG, a leader in the development of the Eagle Ford Shale in South Texas," said Michael A. Creel, President and Chief Executive Officer. "EOG's need for crude oil, natural gas and NGL midstream services clearly illustrates the advantage of an integrated midstream network with access to attractive markets to maximize the value of its Eagle Ford Shale production."

"The South Texas Eagle Ford has the potential to be one of the largest crude oil discoveries in the United States including the Deep Water Gulf of Mexico, in the last 40 years and we believe we have captured 900 million barrels of oil equivalent, net on our 505,000 net acreage position in the play. Contracting with Enterprise, which brings a comprehensive program of midstream services, is a strategic move for EOG in marketing our production," said Mark G. Papa, EOG's Chairman and Chief Executive Officer.

As part of its long-term agreements, Enterprise will construct a 140-mile pipeline originating in northwestern Karnes County to transport EOG's crude oil production from the Eagle Ford Shale. The pipeline will extend to its existing crude oil system in Austin County where it will connect to the partnership's Sealy Station. The pipeline, which is anchored by a 10-year, firm transportation agreement with EOG, offers the flexibility to access the Houston refinery market or the Enterprise-operated Seaway Pipeline system that provides a direct link to Cushing, Oklahoma, a major domestic crude oil storage and trading hub. With a capacity of approximately 350,000 barrels per day (BPD), the crude oil pipeline will be large enough not only to meet EOG's requirements, but to accommodate other Eagle Ford producers, many of which are currently in discussions with Enterprise.

Enterprise plans to build central delivery points for receiving crude oil from trucks and gathering pipelines at multiple locations along the crude oil pipeline route. Completion of the crude oil pipeline project is expected in the first quarter of 2012. In the interim, Enterprise is providing crude oil transportation services via trucks until the pipeline is in service.

Enterprise will also provide firm natural gas transportation and processing, as well as NGL transportation and fractionation services to EOG, anchored by seven-year contracts. In support of this initiative, Enterprise has committed to the construction of 52 miles of additional pipeline laterals to complement its previously announced Eagle Ford rich natural gas mainline project. In addition to rich and lean natural gas transportation capabilities, Enterprise will provide EOG with natural gas processing services at the partnership's planned cryogenic gas processing facility. With an initial capacity of 600 million cubic feet per day, the new processing plant is projected to be in service in mid 2012. The NGLs recovered from EOG's natural gas volumes at the new plant will be transported through Enterprise's recently announced 127-mile, 12-inch diameter NGL pipeline to its Mont Belvieu complex where Enterprise will construct a fifth NGL fractionator. Prior to the completion of these new gas processing and NGL facilities, Enterprise will utilize existing capacity in its integrated network of South Texas infrastructure to process EOG's natural gas and to transport and fractionate the NGLs recovered from EOG's natural gas production.

Activity in the Eagle Ford Shale continues to exceed industry expectations as more than 90 rigs working in the play have drilled more than 175 wells to date. Current production from the play is estimated at approximately 300 million cubic feet per day of natural gas and 40,000 BPD of crude oil and condensate.

"Our broad footprint of assets in the Eagle Ford Shale provides us with the foundation to develop infrastructure with the size and scope to meet the needs of producers, and gives Enterprise a competitive advantage in pursuing other opportunities in this growing area," Mr. Creel said.

CANADA

Imperial Oil’s Kearl Tailings Pond Receives Conditional Approval but will Fall Short of New Standards

Imperial Oil Ltd. August 11 received conditional approval to build an oil-sands tailings pond that will not immediately hit Alberta’s new environmental standards.

The Energy Resources Conservation board said Imperial, which is controlled by ExxonMobil Corp., can proceed with its tailings plan for its proposed Kearl oil sands mine.

However, it will fall short of the environmental standards outlined in Alberta’s Directive 74, which is designed to reduce the tailings produced by the mines.

“Over the life of the plan, the Kearl project will cumulatively equal or exceed Directive 74 total fines capture requirements,” the ERCB said.

Imperial said it would miss Directive 74’s targets for the first six years because its plans incorporate new technologies that require time to be implemented, the ERCB statement said. Therefore, the watchdog has “directed Imperial to submit an updated plan by January 2012 that evaluates alternatives and proposes measures to further accelerate fines tailings treatment.” Further, Imperial “is also being directed to exceed the Directive 74 annual fine tailings reduction requirements for the years following 2018 such that cumulative overall fine tailings reductions equal to Directive 74 requirements are achieved by 2023.”

The first phase of the Kearl mine is expected to cost about $8-billion and produce 110,000 barrels of oil per day. It is slated to begin operating in 2012, and come with one tailings pond, which will be decommissioned by 2038. When the project is at full tilt, it will put out 300,000 barrels of oil per day.

Aecon offers $180 Mln for Troubled Oilsands Builder Cow Harbour

Aecon Group has offered $180 million to buy the assets of Fort McMurray's insolvent Cow Harbour Construction as it pushes to expand its footprint in the oilsands. Aecon CEO John Beck says expansion in the oilsands is a "priority."

Cow Harbour, one of Fort McMurray's top three oilsands excavation, land-reclamation and contracting-services companies owed $254 million to its bank and other creditors when it was granted court protection in April.

"The expansion of our capabilities in the oilsands industry has been a strategic priority for us," John Beck, chairman and CEO of Aecon Group, said in a news release.

"This acquisition will solidify our competitive profile in a market we believe is poised for significant growth. The fact that we've been able to acquire a truly competitive fleet in this manner only adds to the attraction of this investment for us."

Toronto-based Aecon, with operations in Edmonton and around the world, was one of two bidders for Cow Harbour. The deal, which includes the company's 500 pieces of heavy equipment, is scheduled to close Aug. 31.

Cow Harbour was started in 1987 by current owner Alphonse Hutchings, who came from Newfoundland to Fort McMurray on vacation to see what the oilsands were all about and worked for Suncor before starting his own company.

Court documents show Cow Harbour's annual revenue grew from $24 million to $231 million from 2005 to 2009, and it made a $19-million profit last year.

But the growth was financed primarily by short-term, high-rate equipment loans it was eventually unable to service, according to an affidavit by chief financial officer Demetri Koumarelas.

It was also affected financially by a fire that shut down its main client, Suncor, for two months in 2008. It moved some equipment to Syncrude, where it was awarded a $437-million, five-year overburden and land-reclamation contract.

It currently owes Royal Bank $34 million in equipment loans, a fully drawn operating line of $30 million and an overdraft of about $10 million.

It owes $156 million to other equipment financiers, $9 million to potentially lienable creditors and $15 million to unsecured creditors.

"We believe this transaction provides important benefits to all parties," Aecon president Scott Balfour said. "It is a solution that keeps Cow Harbour intact as a going concern, allows creditors to achieve significant repayment of their loans, and provides Aecon with entry into a strategically important market segment at a discount to any other entry strategy."

Teri McKibbon, CEO of Aecon's infrastructure division, said a key strength of Cow Harbour is a "very strong and well-respected employee base."

Aecon said it "intends to offer employment to most of the employees of Cow Harbour at compensation levels reasonably consistent with those currently in place."

Last year Aecon paid $220 million for Edmonton's Lockerbie & Hole, one of Canada's largest mechanical contractors, to increase its potential to win work in the oilsands.

Aecon held its annual meeting in Edmonton in June to underline its increased focus on the oilsands and used the event to announce the purchase of a 15-per-cent stake in Churchill Corp. for $59 million to add to its presence in Fort McMurray.

"It is bit of a repeat of the same, but at even more of an attractive valuation," said NCP Northland Capital Partners analyst Maxim Sytchev.

Analysts said Aecon plans to finance about 75 per cent of the transaction with asset-backed loans from the likes of Caterpillar Inc. and heavy equipment dealer Finning International Inc. and the rest from cash on hand.

The deal requires a $10-million deposit, a further $50 million to be paid in cash upon closing and the balance to be paid within 90 days of closing.

Suncor Shifting Cash Flow for more Dependency on Oilsands

As Suncor Energy moves forward with post-merger growth plans, its upstream assets will soon be 90% oil.

That was a prediction offered by Suncor CEO Rick George during the company's second quarter teleconference.

During that financial report, George added that when the company, now Canada's largest energy company, finished its asset sales and near-term growth plans are implemented, Suncor will move from its current 50-50 cash flow on oilsands to 65/35 — heavy on the oilsands.

"And as we go forward with growth plans, it will be closer to 75-25," predicted George.

"There are a number of solid achievements during the second quarter," said Steve Williams, Suncor chief operating officer. One of those was the turnaround at the oilsands being completed on time and on budget. The estimated $295 million project at its peak employed 2,300 people.

"So the strategy to break the turnarounds into smaller segmented scopes of work ... certainly paid off," he said.

A smaller turnaround is planned to begin Sept. 6 for about six weeks and remaining work on Upgrader Two will carry on into 2011 with a full unit shutdown planned in the second quarter for about seven weeks.

"I still expect production at the oilsands plant will average 280,000 barrels a day for 2010 and given the six months to date, we're just under 250,000 barrels, you can see we plan to have a very strong second half to the year."

Another Q2 achievement was regulatory approval in the second quarter to move ahead with its tailings reduction process which he said will dramatically reduce the time it takes to settle the company's tailings ponds — from 40 years to less than 10 from initial disturbance to reclamation.

"A significant game-change in technology for Suncor and the industry," said Williams.

Bart Demosky, chief financial officer, characterized Suncor's operational earnings of $781 million and operating cash flow of 1.76 billion "as a suggestion of the financial capability of this organization."

Net earnings for the second quarter rang in at $480 million compared to a net loss of $51 million for the second quarter of 2009. Q2 operating earnings were $781 million up from $38 million reported for the same period last year. Cash flow was up 167% to $1.758 billion over last year's Q2 cash flow of $295 million.

Oilsands production, impacted by scheduled upgrader maintenance in May and June, averaged 295,500 barrels per day, compared to 301,000 barrels a day in Q2 2009.

Demosky said the second quarter production performance made for one of Suncor's best quarters on record despite the 85,000 a day impact during the 45-day scheduled turnaround.

"We also enjoyed relatively high oil prices so it was a very good time to have the production running very well." However, he noted that success was partially offset by the continued strong Canadian dollar.

"Operating costs were relatively in line across the business which is very good news," added Demosky.

Anticipating low operating costs, especially in the oilsands at around the low $30 a barrel range following the turnaround, he does expect the oilsands costs to average $38 to $42 a barrel during for the year given the impact of the higher costs experienced earlier in the year.

Meanwhile, earnings and cash flow performance for that part of the business continue to be robust, he added.

"While the Q3 financial results will be impacted by that planned maintenance, the magnitude will be much less than what we saw this quarter and I'm expecting Suncor's earnings capability will become much more apparent over the remainder of 2010."

Giving a report card synopsis of the company's progress since the merger with Petro-Canada last August, George said "I feel very proud about what we've done in that one year; feel very good about the path forward and feel very good being on the right track."

He also acknowledged that despite "significant turnaround work at our oilsands. I can say it was executed very well. Despite the turnaround work that we had ... we still had one of the best quarters on record.

Suncor's take-over of the one-time Crown Corporation created Canada's largest energy company valued at about $43.3 billion. It became final. August 1, 2009.

He added the company is "on track" in its move to sell off assets, mostly natural gas, that don't fit the new corporate portfolio with most of the divestitures to be completed by year's end.

To date, the divestitures amount to about $2.4 billion of which only just under half has been collected the cash from those sales is expected to start rolling in during the third and fourth quarters of this year, with some lagging into the first quarter of next year.

Given the delay in collecting the cash from the asset sales, Demosky pointed out it has impacted Suncor's progress on debt reduction. The company ended the quarter with a net debt of $13.2 billion.

"Although the debt has not come down as fast as probably you would expect and certainly I would hope for most of that can just be attributed to timing," said Demosky. "I would expect with the completion of our $3 to $3.5 billion of divestitures and collection of those proceeds, we should see our debt collection ending up within our targeted range."

Along with the asset sales and operational improvements, George said the company is working to reduce its overhead costs a reduction that saw Suncor — post-merger — reduce its head office size by about 1,000 people.

Other cost cutting measures include closing the London Ontario office and relocating the Calgary staff to one building over the next four months.

"I feel like the team is really coming together."

While work on operational excellence and improving existing assets continue to be the biggest focus area, George said the area he is concentrating on is the drive for efficiencies and cost management.

On the growth side, he added Suncor continues to make progress with Firebag Three which is coming in largely on time and on budget.

The expectation is to have steam in the second quarter of 2011 and full production to start about 24 months after that for production of 62,000 barrels a day. Engineering for Firebag Four is continuing and Suncor expects to start putting assets in the field later this year with production starting up in the fourth quarter of 2012.

Penn West Draws on Chinese Payoff in Oilsands

Penn West Energy Trust, drawing on its new Chinese partnership, will spend up to C$100 million over the next year stepping up development of its oil sands leases in the Peace River region of northwestern Alberta.

About 60 percent of the planned 50 stratigraphic test wells will target additional primary opportunities, while the trust advances horizontal appraisal wells (which have already yielded positive results) and gears up to embark on a thermal project later this year or early in 2011.

Penn West currently produces 2,500 barrels per day from about 50 cold-flow horizontal wells.

Trust Vice President Dave Middleton told a conference call that so far only about one in five sections have been evaluated for the oil sands in place.

He said a horizontal cyclic steam stimulation pilot well will be drilled this year to test a recovery method that injects steam and allow the bitumen to flow.

A thermal project to raise production to 10,000 bpd has regulatory approval and could come onstream by 2014, Middleton said.

Chief Executive Officer Bill Andrew told analysts Penn West will “lean harder on the drill bit” as it prepares to convert to a dividend-paying corporation by the end of 2010.

The big breakthrough for Penn West occurred earlier this year when an affiliate of China Investment Corp. paid C$817 million for a 45 percent stake in the Peace River operation and agreed to spend C$435 million to acquire a 5 percent equity stake in the trust.

A C$312 million cash payment in June helped Penn West cut its debt by C$327 million, allowing the trust to reduce its net debt by C$750 million in the first half of 2010, primarily using proceeds from asset dispositions.

Second-quarter production averaged 163,700 barrels of oil and natural gas liquids per day (down 8 percent from a year earlier) and 408 million cubic feet per day of gas (down 11 percent) weighted 59 percent to crude oil and natural gas liquids.

Imperial Petroleum Acquires Exclusive Oil Sand Process Rights to Canada

Imperial Petroleum, Inc. headquartered in Evansville, Indiana announced that it has purchased the exclusive rights to Canada for the development of a process designed to recover bitumen or heavy oil from tar and oil sands.

In connection with the purchase, Imperial issued 1.0 million shares of its restricted common stock to Proven Engineering & Technologies LLC, the developer of the process. Imperial had previously announced the formation of Arrakis Oil Recovery, LLC in which it owns a 33.3% interest in the same process technology for territories outside of Canada. The oil sands recovery process uses a non-thermal, mechanical and chemical closed-loop system to recover the bitumen.

"Canada is the single largest producer of oil from tar sands in the world and as a result of the high temperatures employed in the recovery process currently in use in Canada, significant environmental issues associated with oil sand production have been created. The purchase of the exclusive rights to what we believe is the most advanced, cost-effective and eco-friendly processing technology currently available will allow us to penetrate this market more quickly as an environmental remediation company and solve these environmental problems," Jeffrey T. Wilson, President of Imperial said. "Our technology provider has already been selected by BP to remediate oil-stained beaches along the Gulf coast using an off-shoot of our technology and we encourage you to visit their website at www.cleanbeachtech.com. We are constructing a 10 ton per hour demonstration facility in Houston, Texas to begin show-casing the oil sand process technology to potential partners in Canada. We have also begun negotiations with larger companies to construct and deploy the equipment in Canada and elsewhere under a sub-license arrangement."

Suncor Reports Hydrogen Unit Outage at Fort McMurray

Suncor Energy Inc. reported August 20 that one of its hydrogen reformer units at its oil sands base plant in Fort McMurray, Alberta, experienced an outage. An assessment was underway to determine the cause of the outage and a schedule to return the unit to operation.

Although the production mix of low- and high-sulfur products will be impacted while the unit is undergoing repairs, oil sands production continues to be more than 300,000 barrels per day.

SNC-Lavalin Wins Grizzly’s Algar Lake Oil Sands Contract

SNC-Lavalin announced August 19, that it has been awarded an engineering and procurement (EP) contract by Grizzly Oil Sands ULC for its new Algar Lake Steam Assisted Gravity Drainage (SAGD) facility located near Fort McMurray in northeastern Alberta.

The project consists of an initial 5,000 barrel per day SAGD central processing facility with associated well pads, flow lines, tank farm and 8 MW cogeneration facility. Work has begun out of SNC-Lavalin's Calgary office and the detailed design of the project is expected to be completed in April 2011.

This is a unique project in the fact that the execution plan is based on engineering and constructing a completely modularized processing facility capable of being trucked to site. Field construction requirements will be limited to placing and interconnecting the modules followed by commissioning of the facility.

"We are very pleased to be recognized for our SAGD experience as well as our modularization expertise, and we look forward to supporting Grizzly with their novel approach" said Jean Beaudoin, Executive Vice-President, SNC-Lavalin Group Inc. "We have been active in the oil sands market for many years, and this award highlights our ability to tailor our experience and delivery model for our clients."

Enbridge to Build Wood Buffalo Pipeline

Enbridge Inc. announced August 26 that it has entered into an agreement with Suncor Energy to construct a new, 95-kilometer (59-mile), 30-inch diameter crude oil pipeline (the "Wood Buffalo" Pipeline), connecting the Enbridge Athabasca Terminal, which is adjacent to Suncor's oil sands plant, to the Cheecham Terminal, which is the origin point of Enbridge's Waupisoo Pipeline. The Waupisoo Pipeline delivers crude oil from several oil sands projects to the Edmonton mainline hub.

The new pipeline will parallel Enbridge's existing Athabasca Pipeline between the Athabasca and Cheecham terminals. Suncor's existing commitments on the Athabasca Pipeline will remain in place. An application has been filed with the Alberta Energy Resources and Conservation Board (ERCB); pending regulatory approval, the new line is expected to be in service by mid 2013.

"Suncor was the anchor shipper that enabled our original entry into oil sands regional pipeline and terminaling infrastructure with the Athabasca Pipeline and terminal in 1999," said Stephen J. Wuori, Executive Vice-President, Liquids Pipelines, Enbridge Inc. "Today, our regional system includes both the Athabasca and Waupisoo pipelines providing dual hub capability to both Edmonton and Hardisty; lateral facilities connecting the Mackay River, Surmont, Long Lake and Christina Lake projects to the system; and over 4.4 million barrels of supporting operational tankage."

The August 26 announcement brings expansions and extensions of Enbridge's Regional Oil Sands System announced over the last year to a total of approximately $1.6 billion.

"We're building new facilities to meet the needs of the Imperial Oil/Exxon Mobil Kearl project, and we recently added Statoil's Leismer project as a shipper on the system. We are fortunate to have Suncor as a shipper, and to benefit from their continued oil sands growth and need for pipeline and terminaling services, including this latest opportunity," said Mr. Wuori. "As the largest operator of oil sands regional infrastructure, and with our corresponding ability to provide favorable and competitive transportation solutions to producers, we expect to see continued attractive investment opportunities of this sort for some time to come."

Enbridge's Regional Oil Sands System At-a-Glance

Enbridge is the leading pipeline operator in the Fort McMurray to Edmonton/Hardisty corridor and well positioned to tie-in new oil sands developments to mainline pipelines and increase capacity for current customers. Enbridge's Regional Oil Sands Infrastructure includes the Athabasca and Waupisoo pipeline systems, connecting six producing oil sands projects.

Athabasca Pipeline:

-- 540-kilometer (335-mile) pipeline in operation since March 1999

-- Annual capacity of up to 570,000 barrels per day of crude oil (depending

on crude viscosity) from the Athabasca and Cold Lake regions of Alberta,

south to Hardisty, Alberta

Waupisoo Pipeline:

-- 380-kilometer (mile) pipeline system in operation since June 2008

-- Annual capacity of up to 600,000 bpd of crude oil (depending on crude

viscosity) from Enbridge's Cheecham Terminal to Edmonton

Tankage:

-- Largest operator of contract storage facilities at the Hardisty hub with

the 3.1 million barrel Hardisty Caverns storage facility, plus the 7.5

million barrel Hardisty Contract Terminal surface storage facility

-- More than 4.4 million barrels of operational storage associated with the

Waupisoo and Athabasca pipelines and laterals

Enbridge Inc., a Canadian company, is a North American leader in delivering energy and one of the Global 100 Most Sustainable Corporations. As a transporter of energy, Enbridge operates, in Canada and the U.S., the world's longest crude oil and liquids transportation system. The Company also has a growing involvement in the natural gas transmission and midstream businesses, and is expanding its interests in renewable and green energy technologies including wind and solar energy, hybrid fuel cells and carbon dioxide sequestration. As a distributor of energy, Enbridge owns and operates Canada's largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State. Enbridge employs approximately 6,000 people.

ASIA

CHINA

New Study Says China's Demand for LNG and Shale Gas to Soar

Fueled by its soaring demand for energy, China's demand for liquefied natural gas will increase by 48 percent in 2020 and is driving Pacific LNG growth, says a new study.

"Race for Supply -- the Future of China's Gas Market," by Wood Mackenzie Consultants finds that China's reliance on unconventional gas -- particularly shale -- will increase significantly to meet its strong gas growth.

But domestic unconventional gas resources will take a "significant" time to develop, the study says, so in the meantime China will have to import large amounts of LNG and piped gas.

Gavin Thompson, Wood Mackenzie's China gas study director calls shale gas "the major growth story" in China. As the country's national oil companies boost their unconventional gas activity, he said in a news release, they would be seeking partnerships and technologies for the initial phase of development.

This represents "a near-term window of opportunity for International oil companies to gain access to China's onshore acreage and to leverage skills honed in North America," Thompson said.

Earlier this month China Petroleum & Chemical Corp. announced it had launched a new division for the exploration of shale gas in Southwest China.

China Business News projected that Sinopec's annual shale gas output could reach 2.5 billion cubic meters in five years.

The IEA estimates China's shale gas reserves are about 26 trillion cubic meters.

Before development of domestic unconventional gas is completed, however, Wood Mackenzie forecasts China's coal bed methane, coal-based synthetic gas and shale gas imports to reach more than 11 billion cubic feet per day by 2030.

The Wood Mackenzie report comes after new data from the International Energy Agency shows that China had surpassed the United States as the world's biggest energy user.

The IEA said China consumed the equivalent of 2.25 billion tons of oil last year from sources such as coal, oil, natural gas, nuclear power and hydropower.

Edinburgh, Scotland's Wood Mackenzie projects China's demand for LNG by 2020 to be 46 million tons annually, up from an earlier forecast of 31 million tons annually.

"This will expand the opportunity for LNG suppliers seeking to secure markets, particularly those in Australasia," said Thompson.

"However, China's LNG import growth will be mitigated by the emergence of indigenous unconventional gas," he said.

The study attributes China's demand for natural gas to a number of factors, including national policies that aim to reduce the country's growing reliance on oil imports.

EUROPE

POLAND

Halliburton Performs Shale Hydraulic Fracturing for Poland’s PGNiG

Halliburton has performed a shale hydraulic fracturing operation in Poland for PGNiG, the state-owned Polish oil and gas company.

PGNiG contracted Halliburton to fracture the Markowola-1 exploratory well near Kozienice, Lublin province, to determine if the site contained commercial gas deposits.

Brady Murphy, vice president of Halliburton's Europe and West Africa region, said: "To have been chosen to provide the first fracture stimulation project in Poland was very exciting for us. We can use the experience we have gained and the technology we have developed for use in the unconventional gas plays in the U.S. to support development of unconventional gas resources in this region."

UKRAINE

Shell Seeks to Invest in Ukrainian Shale Gas if Legislation is Loosened

Shell will ask the Ukrainian Fuel and Energy Ministry to change legislation regarding shale gas production, Kommersant Ukrayina reports. During a roundtable entitled "The Prospects for Shale Gas Development in Ukraine" held in Kiev on August 12, Aleksey Tatarenko, Shell's liaison with government officials in Ukraine, stated Shell intended to invest in the segment if bigger areas are offered for production and license periods are lengthened and tax breaks introduced.

Ukrainian government officials have said they are prepared to initiate these changes.

On July 2 this year, Ukrainian Deputy Prime Minister Andrey Klyuyev said the government felt the issue of alternative gas holds prospects, specifically, shale gas in Ukraine. He said that despite the fact production costs of shale were higher than for traditional gas it was still a very promising field.

Before that, on June 11, Klyuyev said the Ukrainian government planned to double domestic gas production over the next 10 years to 40 billion cubic meters of gas a year. Specifically, he said Ukraine hoped to attract large investors "like Shell and Chevron".

Klyuyev also said Ukraine has one of the biggest shale fields in the world and noted the government had already been negotiating with companies on the topic.

Meanwhile, the director of the Horeshenin Institute of Management, Vladimir Fesenko, said the issue of beginning to explore and develop shale gas in Ukraine would only be possible if reforms in the country were carried out, including in the state oil and gas company Naftohaz Ukrayiny.

Fesenko said, "The problem of shale gas is one with promise, but not one for today, that would solve all our gas problems today. It is an issue for the mid- and long-term".

He added, "In order to solve the problem, work must begin today and it must be a serious government program, in order to not repeat the sad story of the program on coal methane gas".

"The problem of shale gas can only be solved in the context of energy sector reforms and reforming Naftohaz", Fesenko said.

Moreover, he said, "We need to solve two problems in order to solve the problem of shale gas: serious investment, and for that we need stimuli. And in order for there to be tax breaks or investment, we need serious legislation and, importantly, there should be political will from the government".

"If we truly want to achieve energy independence, then we need to get involved in energy conservation and develop non-traditional gas and provide the legal political and administrative stimulus and economic stimulus. If that does not happen, the resource will not work", Fesenko said.

McIlvaine Company,

Northfield, IL 60093-2743

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

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