Talisman Energy Inc. plans to hike production and reserves in the Montney, Marcellus, and Eagle Ford shale plays in North America and will explore for shale gas in northern Poland in 2011.

Rob Broen, president of the US shale business unit based in Pittsburgh, said, “We have enough lands and resource to support production growth to 1 bcfd for the company in each one of these plays.”

At 760,000 net acres the company also has the largest contiguous land position in a shale play initially targeting Ordovician Utica shale in Quebec’s St. Lawrence Lowlands, where it is working with government and industry to establish a regulatory system, service sector, and infrastructure.

Talisman’s overall 2010 production of 415,000 b/d of oil equivalent is balanced in liquids and gas, and 50% of projected 2011 growth volumes are liquids, said Broen.

Of US$4 billion in 2011 worldwide capital spending, Talisman will invest $1.7 billion in North America, $1.3 billion of it on shale properties. In the three main plays Talisman’s portfolio allows it to control the development pace, so it is not chasing land and isn’t required to spend to hold land, Broen said.

In the Marcellus shale in Pennsylvania, Talisman has an $800 million in 2011 capital program. It will run as many as nine rigs, compared with 12 at present and six at the start of 2010.

Production is centered on 218,000 net acres in Tioga, Bradford, and Susquehanna counties in northeastern Pennsylvania, where Talisman has identified more than 2,000 drilling locations and a 6 tcf contingent resource. The company also cites a 5 tcf Marcellus resource on lands it holds in New York.

Talisman expects to average 350-400 MMcfd of production in 2011 compared with 181 MMcfd in 2010. It ended 2010 at 315 MMcfd.

It has secured up to 600 MMcfd of pipeline capacity for Marcellus gas. The company had no Marcellus activity in 2008, when it was a Trenton-Black River explorer in the Appalachian basin, Broen noted. Drilling and completion costs have fallen 70% to $3.5 million/well or a full-cycle breakeven cost of $3.50/Mcf.

Wells are generally on line within 3-4 days of completion. Talisman drills 5,700-ft laterals and applies 16-18 frac stages to generate 30-day average initial production of 4-5 MMcfd and estimated ultimate recovery of more than 5 bcf/well.

In the Montney shale in Northeast British Columbia, Talisman operates the Greater Cypress and Farrell Creek areas west of Fort St. John and participates in the Shell-operated Greater Groundbirch area south of the city.

The company has 44 tcf of contingent resource in 271,000 net acres in the Montney, which is as thick as 1,400 ft spread over three horizons. Talisman estimates full-cycle break-even cost below $4/Mcf.

Talisman is moving from four rigs to eight in 2011, when it expects to average 50-60 MMcfd net production. It is expanding the Farrell Creek processing plant to 180 MMcfd from 120 MMcfd and has secured 500 MMcfd of pipeline sales capacity. Well metrics are 5 MMcfd initial rates and 7 bcf EURs, Broen said.

Talisman sold 50% of 52,000 net acres at Farrell Creek to South Africa’s Sasol in late 2010 for $1 billion. The 50-50 properties have an estimated 9.6 tcf contingent resource. The companies will drill 35 wells net to Talisman in 2011, and Talisman is examining alternate marketing options including Sasol’s gas-to-liquids technology.

Talisman has a $300 million capital program in the Eagle Ford shale and will grow from four rigs to eight in 2011, spending a net $300 million, Broen said.

Talisman, operator in 50-50 partnership with Statoil, sees 1,500 locations on 135,000 net acres and a 1.1 billion boe contingent resource in the liquid-rich part of the play. Well results are 1,200 boe/d initial rates and 660,000 boe projected EURs.

The company will drill three vertical wells in Poland’s Baltic basin in 2011 seeking gas in shales with favorable estimated technical parameters: 220-1,550 bcf/sq mile gas in place, 600-2,300 ft thickness, 8,000-14,000 ft depth, and 0.9-9% total organic carbon. Talisman holds the Gdansk West, Braniewo, and Szczawno blocks.

AMERICAS

U.S.

Shale Oil Drillers Chesapeake, EOG Hit with Higher Costs of Shifting to more Oil Production from Gas

U.S. natural-gas companies are getting hit with the highest costs in four years as they shift more production to oil to escape low gas prices.

EOG Resources Inc., Chesapeake Energy Corp. and SandRidge Energy Inc. each have announced $1 billion transactions in the past year to ramp up onshore production of higher-profit oil and other petroleum liquids as booming gas production deflated prices.

The new oil rush is focused on dense rock formations that require the same mix of horizontal drilling and hydraulic fracturing as the fields that created today’s gas glut. Surging competition for these drilling-related services has pushed costs up 16 percent, and are expected to continue rising at least through the first half of 2011, analysts said.

Prices are “outrageous,” Gary Evans, chief executive officer of Magnum Hunter Resources Inc., told analysts December 27 after buying liquids-rich shale gas fields in West Virginia and Kentucky. “It’s the pumping services and completion costs that keep us all awake at night.”

Those include hydraulic fracturing that frees oil and gas from untapped reservoirs by pumping in millions of gallons of water, sand and chemicals at high pressure to crack the rock.

Gas producers opted for oil-soaked rock deposits as crude prices on the New York Mercantile Exchange rose 15 percent to $91.38 a barrel in 2010. Natural gas fell 21 percent to $4.41 a million British thermal units in 2010.

Investors in 2010 initially snapped up energy producers that increased their crude output and punished those who didn’t. They proved willing to shed stock of companies that missed budget or production targets.

EOG shares closed at a yearly high April 23 after the company predicted April 2 that about two-thirds of its 2011 revenue will come from oil and petroleum liquids, compared with a fourth in 2010. The stock fell 9 percent on November 3 after it forecast lower production and higher costs than expected. The shares ended the year down 6.7 percent.

“You’re dealing with a liquid that doesn’t flow as freely as gas,” Kurt Hallead, an Austin, Texas-based analyst for RBC Capital Markets, said in an interview. “Some investors view oil wells as less complex and that is not absolutely the case.”

Southwestern Energy Co. stuck to its focus on gas and trailed the 13 other companies in Standard & Poor’s 500 Oil & Gas Exploration & Production Index with a 22 percent drop in 2010. Pioneer Natural Resources Co., one of the first gas producers to focus on oil drilling, lead the index with an 80 percent gain.

Companies that got into oil early benefit as rising crude prices yield more cash to accelerate drilling, Michael Bodino, director of energy research at Global Hunter Securities, said in a January 4 interview.

Though oil remains more valuable than gas, the higher costs are cooling investor interest. Moody’s Investors Service said November 17 it may lower EOG’s debt rating of A3, the fourth-lowest, citing the cost of switching to oil.

Argus Research Corp. cut its rating on shares of Chesapeake, the largest U.S. gas producer after Exxon Mobil Corp., to “sell” from “hold” on November 30, citing “profligate spending.” Chesapeake said its cost for new wells may rise 11 percent to $5 billion next year as it accelerates shale-oil exploration.

SandRidge, based in Oklahoma City, fell by as much as half after announcing the $1.55 billion purchase of Arena Resources Inc., an owner of Texas oil fields. The shares rebounded after the company announced a $110 million asset sale to help fund 2011 drilling. SandRidge shares lost 22 percent last year.

Gas production from dense rock such as shale; helped drive down the price of natural gas to about $4.41 per million British thermal units at year end from a high of $13.58 in 2008.

At the same time, average prices for fracturing in the first half of 2010 rose 16 percent from a year earlier and will rise further in 2011 on shortages of equipment, Hallead, the RBC analyst, wrote in a December 1 note to clients.

Oil dominates production in three of the four most expensive rock deposits currently being fractured, the Eagle Ford, Permian and Bakken, RBC Capital said. The Haynesville Shale gas field in Louisiana is the other.

Average well cost in the Eagle Ford surged 49 percent in the past two years to $8.2 million, Halliburton Co., a drilling service provider, told investors in a November 10 presentation.

Rising demand led to a two-month wait on equipment and services, Hallead said. A record 762 rigs were drilling for oil on land in the U.S. as of December 24, a 90 percent increase in a year, with almost all the added rigs in basins that require horizontal drilling; service company Baker Hughes Inc. reported.

Baker Hughes shares rose 41 percent in 2010 while larger competitor Halliburton rose 36 percent. Carbo Ceramics Inc., a maker of beads used to prop open cracks in oil-bearing rock, rose 52 percent.

Costs may begin moderating in the second half of 2011 as more equipment becomes available, Scott Gruber, an analyst with Sanford C. Bernstein Limited, said in a Jan. 6 note to clients.

EOG signed long-term contracts for fracturing services to control costs. Pioneer formed two in-house fracturing crews, saving $300,000 a well, Chief Operating Officer Timothy Dove told investors December 7.

Chesapeake sold a third of its Eagle Ford holdings to Cnooc Ltd. for $1.08 billion. Southwestern is selling acreage in the Haynesville Shale. EOG planned to sell $1 billion of gas fields to raise cash for drilling, though its first announced sale, for $405 million, fell through December 22.

Many dense-rock oil deposits may prove to be too expensive to produce with current fracturing technology, said Bruce H. Vincent, President of Swift Energy Co., which has begun pumping oil from wells in the Eagle Ford.

“We’re all learning and anybody who says they know it all or has the magic bullet is deceiving themselves,” Vincent said.

Graham Corp Wins $4 Mln in Ejector System Orders

Graham Corp., a designer and manufacturer of critical equipment for the oil refining, petrochemical and power industries, on January 6 announced that it has received two orders for ejector systems that total approximately $4 million.

The first order is for an ejector system to be installed at a U.S. refinery that is being modified to process crude oil from the Alberta oil sands. The ejector system is scheduled for delivery in the third quarter of Graham's 2012 fiscal year, which begins on April 1, 2011. The second order is for an ejector system destined for a refinery expansion in China. Delivery for that system is planned for the second quarter of fiscal 2012. The ejector system for China is expected to have certain of its components built in China.

James R. Lines, Graham's President and Chief Executive Officer, commented, "It is encouraging to see a major U.S. refiner preparing its facility to process synthetic crude oil from the Alberta oil sands. Although measurable industry-wide investment had been made prior to the recession to prepare some existing facilities for the processing of Alberta synthetic crude, there has been minimal investment during the last few years. The Alberta oil sands represent the second largest proven concentration of oil in the world after Saudi Arabia. And, with 170 billion barrels of proven recoverable reserves, it is still at a very early stage of development with only about 7 billion barrels of oil recovered to date."

"Even though refinery-related activity has been slow in China for much of the past year, we believe that our strategy of early involvement in major projects led to our participation in the equipment selection process with this refinery. With this project award, we have won nine major refinery projects in China over the past four years. We are confident that we can build on this success as considerable distillation capacity is expected to be added in China over the next five years," Lines noted.

Graham also announced that it had received orders of $17.8 million in its fiscal 2011 third quarter, which ended December 31, 2010. Lines concluded, "Included in our orders for the third quarter were about $800,000 in new orders received by Energy Steel & Supply Co. since our acquisition of the Lapeer, Michigan-based company on December 14, 2010. We view this to be a positive reflection of Energy Steel's solid market penetration and believe that it supports our strategy of broadening our reach into the nuclear power market."

DCP Decides Against Appalachian NGL Joint Venture with EQT Corp

DCP Midstream Partners, LP (DPM) and its sponsor, DCP Midstream, LLC (together, DCP), announced January 4 that they are no longer pursuing a joint venture or alternative transaction structures with EQT Corp. related to EQT's processing needs in the Marcellus and Huron shale areas of the Appalachian basin.

"We will continue to actively pursue economically attractive business opportunities in the Marcellus," said Tom O'Connor, chairman of DCP Midstream Partners, LP and chairman, president and chief executive officer of DCP Midstream, LLC. "We are very pleased with DCP's portfolio of growth opportunities, including our Marysville NGL storage acquisition announced yesterday."

DCP Midstream Partners, LP is a midstream master limited partnership that gathers, treats, processes, transports and markets natural gas, transports and markets natural gas liquids, and is a leading wholesale distributor of propane. DCP Midstream Partners, LP is managed by its general partner, DCP Midstream GP, LLC, which is wholly owned by DCP Midstream, LLC, a joint venture between Spectra Energy and ConocoPhillips.

DCP Midstream, LLC, headquartered in Denver, Colorado, leads the midstream segment as one of the nation's top three largest natural gas gatherers and processors, and one of the largest natural gas liquids producer and marketers in the U.S. DCP Midstream operates in 17 states across producing regions. DCP Midstream is a 50/50 joint venture between Spectra Energy and ConocoPhillips. The Company owns the General Partner of DCP Midstream Partners, LP, a master limited partnership, and provides operational and administrative support to the partnership.

MarkWest Liberty and Energy & Minerals Group Plan West Virginia Processing Complex

MarkWest Liberty Midstream & Resources, L.L.C., a partnership between MarkWest Energy Partners, L.P. and The Energy & Minerals Group, on January 4 announced the development of a midstream natural gas processing complex in Logansport, West Virginia.

MarkWest Liberty will construct a 120 million cubic feet per day (MMcf/d) cryogenic gas processing facility and associated natural gas liquids (NGL) pipeline by mid 2012 to process liquids-rich gas transported in EQT Corporation's Equitrans gas pipeline, which recently announced a significant expansion to increase transmission capacity. EQT has substantial rich-gas Marcellus acreage in northern West Virginia and has contracted with MarkWest Liberty for the majority of the Logansport plant capacity. The NGLs recovered at Logansport will be transported via pipeline to MarkWest Liberty's fractionation, storage, and marketing complex in Houston, Pennsylvania.

The Logansport complex is MarkWest Liberty's third processing complex serving Marcellus production in southwestern Pennsylvania and northern West Virginia. The new processing facility and associated NGL pipeline significantly expands the integrated processing, fractionation, and NGL marketing services that MarkWest provides to producers in the Appalachian region.

"We continue to expand our midstream presence in the rich-gas area of the Marcellus and the Logansport complex will allow EQT and other producers to fully develop their Marcellus acreage in Wetzel and Doddridge counties," said Frank Semple, Chairman, President and Chief Executive Officer of MarkWest. "We are excited to access significant new Marcellus acreage and to take advantage of the tremendous downstream takeaway options for residue gas on the Equitrans system, including Equitrans' planned expansion to five interstate pipelines. MarkWest Liberty is the largest provider of midstream services in the rich-gas areas of the Marcellus and is committed to continue investing significant capital to develop the critical midstream infrastructure necessary to meet our producer customers' long-term needs."

"We are excited about the strategic value created from the combination of MarkWest's industry leading Appalachian processing and fractionation footprint with EQT's Equitrans pipeline header system expansion," said Randall Crawford, Senior Vice President of EQT. "The linking of NGL processing with downstream transportation will provide the critical infrastructure solution to facilitate the development of EQT's and other liquids-rich Marcellus acreage in northern West Virginia."

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, transportation, and processing of natural gas; the transportation, fractionation, marketing, and storage of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has extensive natural gas gathering, processing, and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor in the Appalachian region.

The Energy & Minerals Group is the management company for a series of private equity funds totaling in excess of $2.5 billion of commitments. EMG focuses exclusively on making direct investments across the natural resources industry in conjunction with experienced management teams focused on hard assets that are integral to existing and growing markets.

Canadian Natural Resources’ Horizon Plant Fire Temporarily Halts Backup at Cushing, OK

Canadian Natural Resources Ltd. has shut its Horizon oil-sands plant in northeastern Alberta after a fire injured four workers, halting work at a facility expected to produce up to 112,000 barrels a day this year. Canadian oil often ends up in Cushing, OK, the delivery point for the barrels traded in crude futures contract on the New York Mercantile Exchange. Inventories there have risen 18% since early November, and the relentless flow from Canada has revived fears that Cushing's tanks would fill up.

With inventories at its delivery point rising steadily, Nymex futures prices had dropped sharply since hitting a 27-month high. Oil not tied to Cushing has held its value. The fire has started to reverse that trend; early on January 7, Nymex crude futures were down 70 cents at $87.68 a barrel, while Brent, a U.K. contract unaffected by events at Cushing, was down twice as much to $93.03 a barrel. Early in January, the gap was over $1 wider at $6.54, the biggest difference since February 2009, when Cushing inventories hit a record.

But the relief at Cushing is likely to be short-lived. Canadian producers continue to send increasing volumes of oil sands crude to Cushing, aiming to supply Midwestern refiners. Since early 2009, storage tanks that can store around 10 million additional barrels have been built to handle the rising flow, relieving pressure on Nymex futures. But inventories are rising again, and the market is now bracing for TransCanada Corp.'s (TRP) Keystone pipeline to start bringing up to 591,000 barrel a day to Cushing by March.

"All disruptions like this (fire) are by their very nature temporary," said Lawrence Eagles, an oil analyst at J.P. Morgan. "It's a question of how much it comes back."

Improving economic conditions could boost oil prices even if Cushing tanks continue to fill. Prices have been steadily rising for months, as strong consumption in the developing world and the U.S. economic recovery boost the demand outlook. Nymex crude futures hit a two-year high of $91.55 January 3, and a growing consensus of analysts say that oil is headed for $100 a barrel this year.

Stockpiles at Cushing rose by 858,000 barrels to 37.5 million barrels last week, the eighth straight week of rising stockpiles, a period when inventories fell 22.3 million barrels nationwide, according to the U.S. Department of Energy. About 82% of available storage space at Cushing is full, according to government figures. Total storage capacity is higher, but some tank space must remain empty for safety and other reasons.

The periodic bottlenecks at Cushing have led some analysts to call for the Nymex futures contract to be phased out as a pricing benchmark. IntercontinentalExchange Inc. (ICE) offers a similar contract that is financially settled, meaning no actual barrels must be delivered to Cushing. Brent is also seeing growing use as a benchmark for the growing volumes headed to China.

"(The Nymex contract) has been the benchmark for global prices for so long. But with China becoming a bigger global consumer, the historical legacy of WTI is under question," said David Hart, an analyst at Westhouse Securities in London.

But Nymex's Cushing-based oil futures contract still has twice as many open positions as ICE's financial contract, and other attempts to introduce new U.S. benchmarks have failed to gain traction. Officials at CME Group Inc. (CME), which owns the New York Mercantile Exchange, said there's plenty of space still available at Cushing.

"We're talking about a gap of 9 million barrels," said Robert Levin, managing director for commodities research at CME. "There's a lot of spare capacity for storage, according to the government numbers, and I think that needs to be taken into account."

Kinder Morgan, Copano to Add $100 Mln Capacity for Eagle Ford Project

Kinder Morgan Energy Partners, L.P. (KMP) and Copano Energy, L.L.C. on January 6 announced plans to expand the scope of their Eagle Ford Gathering LLC joint venture. Eagle Ford Gathering will provide more than 200,000 MMBtu per day of incremental gathering and processing capacity to producers in the Eagle Ford Shale through construction of additional pipeline facilities and a long-term agreement with Formosa Hydrocarbons Company (Formosa) for additional processing and fractionation services.

In addition to 111 miles of pipeline currently under construction, Eagle Ford Gathering will build a 54-mile, 24-inch diameter crossover pipeline between existing Kinder Morgan pipelines, and an additional 20-mile, 20-inch diameter pipeline that will enable the joint venture to deliver gas to Formosa. Kinder Morgan will construct and operate the two additional pipelines. Eagle Ford Gathering recently executed an agreement with Formosa to support its gas processing and fractionation needs, and expand operational flexibility.

Duane Kokinda, president of Kinder Morgan's Texas Intrastate Pipelines Group, said, "We are pleased to enter into this significant new agreement with Formosa, which will provide them with long-term supplies of NGL feedstocks and also make additional processing and fractionation capacity available to the joint venture as early as the fourth quarter of 2011. The crossover pipeline will have capacity in excess of 400 million cubic feet per day, which will give the joint venture additional options to provide services to Eagle Ford Shale producers."

"This expansion of our joint venture with Kinder Morgan provides significant additional capacity for Eagle Ford Shale producers and will allow the joint venture to more fully utilize the 600 million cubic feet per day of capacity on its 30-inch pipeline," said R. Bruce Northcutt, Copano Energy's president and chief executive officer. "We expect this additional capacity to be substantially contracted for by early 2011. We are also pleased with the new long-term relationship with Formosa, which brings additional market diversity for the expected growing volume of natural gas liquids from this play."

Kinder Morgan and Copano will invest approximately $100 million to construct the crossover pipeline and related facilities and expect to complete the new facilities by year-end 2011. Eagle Ford Gathering's previously announced approximately $175 million, 30-inch pipeline in the western portion of the shale play is under construction and remains on schedule to be completed in the third quarter of 2011. Copano will serve as operator of the 30-inch pipeline and serves as managing member of Eagle Ford Gathering.

Bear Tracker Energy to Build Gathering System in Western ND

Bear Tracker Energy, LLC (BTE), a midstream energy company, announced January 4 the signing of definitive agreements with a large U.S. independent oil and natural gas exploration and production company.

BTE will construct, own, operate and expand a natural gas gathering system that includes compression and other related facilities in the Bakken area. The associated natural gas production from 18 townships in Burke and Mountrail Counties, North Dakota will be committed to BTE's gathering system during the term of the agreement. BTE will gather, compress and deliver the natural gas for further handling at a Stanley, North Dakota facility. Construction will commence in the first quarter of 2011 with operations estimated to start mid-year 2011.

Bear Tracker Energy, LLC, headquartered in Denver, CO, is a full service midstream energy company with a primary geographical focus in the Rocky Mountain region. The company's services include natural gas gathering, processing, compression, treating, fractionation, crude oil gathering and NGL & natural gas marketing services. Bear Tracker Energy is a private company backed by GSO Capital Partners.

UGI Plans Open Season for Marcellus Gas Storage

On October 21, 2010, The Federal Energy Regulatory Commission (FERC) issued UGI Storage Co. a certificate to acquire from UGI Central Penn Gas, Inc. (UGI CPG), own and operate 14.7 Bcf of underground natural gas storage. In addition, FERC granted UGI Storage Company the right to sell storage services at market-based rates. UGI Storage Company is owned by UGI Energy Services Inc. (UGIES), UGI Energy Services, Inc. is a wholly owned subsidiary of UGI Corporation (UGI).

The storage facilities currently are operational and service from UGI Storage Company will be available to the marketplace beginning with the upcoming gas injection season on April 1, 2011.

The storage service is provided from three underground storage fields located in Tioga, Potter and Cameron Counties in north-central Pennsylvania. "These fields are located in the heart of the Pennsylvania Marcellus Shale region," said Peter Terranova, Vice President, UGI Storage Company. "Storage customers will have access to Dominion Transmission, Transcontinental Gas Pipe Line, Tennessee Gas Pipeline and UGI CPG's gas utility distribution system. Customers of UGI Storage Company potentially will have access to Millennium Pipeline, Empire Pipeline, Columbia Gas Transmission, Spectra Energy and significant amounts of Marcellus Shale gas being produced in and around the storage fields through a planned interconnection with the PENNSTAR Pipeline, a proposed joint venture between UGIES and NiSource Gas Transmission and Storage (NGTS)."

An open season—beginning January 17, 2011, will be used to solicit market-based bids for storage service. Capacity will be allocated to the highest bidder(s), and all winning bidders in the upcoming open season will secure rights-of-first-refusal for service after March 31, 2012 under FERC regulations. Open season will close February 16, 2011.

More information on the service offerings and the nomination process is available at www.ugistorage.com.

TransCanada Faces Legal Challenge from OK Landowners

TransCanada Corp. faces a legal challenge from a group of Oklahoma landowners to its planned expansion of its oil sands pipeline to the U.S. Gulf Coast.

The owners of a family farm in Oklahoma have filed a legal challenge in an Oklahoma state district court to TransCanada's plans to build an extension of the Keystone pipeline system through their land.

In the legal filing, the family is asking the state to cancel condemnation of their property on the grounds that Calgary-based TransCanada is a foreign-owned, Canadian company and that the U.S. government has no right to transfer the power of "eminent domain"--or the right to appropriate private property for public projects--to a project that allegedly doesn't serve the interests of the American public.

A TransCanada spokesman didn't comment on the Oklahoma case, but said that TransCanada offers above market rates for easements on landowner properties that allow the inhabitants to keep using the land.

"With more than 99% of all easements successfully negotiated with hundreds of landowners in seven states so far, it's clear Keystone is responsive to landowner concerns and apparently is addressing them to their satisfaction," the spokesman said in an emailed statement.

The U.S. State Department is reviewing TransCanada's proposal to double the capacity of the Keystone pipeline system, which transports oil from Canada's oil sands region, and to extend it to refineries on the U.S. Gulf Coast that process heavy oil. If approved on schedule early this year, the pipeline could be completed by 2013.

Environmental groups oppose the expansion because they say oil sands crude is more environmentally harmful than conventional oil.

TransCanada and the Alberta government have argued that the expansion comes with significant economic benefits, including a more than $20 billion economic boost from its construction and more oil supply from Canada, a secure and friendly supplier to the U.S.

The expansion would roughly double the line's capacity to 1.1 million barrels a day. Canada is already the largest source of U.S. oil imports at about 1.9 million barrels a day, with roughly half of that amount coming from Canada's oil sands region in northeast Alberta.

TransCanada did not immediately issue a comment.

Dominion Reaches Agreement on PPG Site for Gas Processing and Fractionation Facility

Dominion on January 12 announced that it has reached an agreement with PPG Industries on an option for Dominion to purchase land at PPG's Natrium, WV, site for the construction of a natural gas processing and fractionation facility.

Dominion Transmission, Dominion's natural gas pipeline and storage subsidiary, plans to process natural gas and separate natural gas liquids at the 56-acre site as part of its previously announced Marcellus 404 Project. Engineering design and project planning for the plant are under way. Financial terms were not disclosed.

The facility is designed to phase in service for processing up to 300,000 Mcf/d (thousand cubic feet per day) of natural gas. Fractionation capacity for up to 38,000 barrels per day of natural gas liquids would be available.

The Natrium site, in Marshall County about 9 miles north of New Martinsville, WV, is close to Dominion's TL-404 pipeline, an existing transmission line in Ohio and West Virginia that Dominion plans to convert into a wet gas service line. The Natrium site also is close to railroad, pipeline and barging services for marketing natural gas liquids.

Both West Virginia Governor Earl Ray Tomblin and Congressman David B. McKinley, who represents the district where the new facility will be located, welcomed the project to West Virginia.

"I am pleased to see business expanding in West Virginia because of the Marcellus Shale," Tomblin said. "This resource holds great potential for our economy while meeting the growing energy needs of our state and our nation."

"I want to thank Dominion for making this investment in West Virginia," said McKinley. "It's a reflection of their confidence in our state's great potential. This project will create new jobs and opportunity for West Virginia. In addition, the new facility is an important piece of the puzzle in achieving energy independence for America. It's good for our state and good for our country."

"Further development of the Marcellus shale demands additional processing and fractionation capacity," said Paul Ruppert, senior vice president of Dominion Transmission. "PPG's Natrium site is strategically located close to our existing facilities, near high-BTU natural gas development, and it allows for transport of the fractionated liquids by numerous options. The project will help further develop West Virginia's north central region."

"We continue to support projects that will provide investment and jobs in Marshall County," said Michael H. McGarry, PPG senior vice president, commodity chemicals. "We are pleased to welcome Dominion to Natrium, and we look forward to a successful collaboration."

Located on the Ohio River near New Martinsville, W.Va., PPG's Natrium plant produces chlorine, calcium hypochlorite, muriatic acid and caustic soda, which are used in many applications that improve the quality of life, including purifying drinking water and in the production of most pharmaceuticals. The plant employs about 530 people and has been in continuous operation since 1943.

Copano, Energy Transfer to Build NGL Pipeline in Eagle Ford

Copano Energy, L.L.C. on January 18 announced execution of agreements increasing Copano's capability to handle natural gas liquids (NGLs) associated with growing natural gas volumes from the Eagle Ford Shale.

Copano has entered into a long-term fractionation and product sales agreement with Formosa Hydrocarbons Company, Inc. and, to facilitate deliveries of mixed NGLs to Formosa, Copano has formed a 50/50 joint venture with a subsidiary of Energy Transfer Partners to construct, own and operate a 12-inch NGL pipeline ("Liberty Pipeline"). The Liberty Pipeline will extend approximately 83 miles, from Copano's Houston Central Complex in Colorado County, Texas, first to Formosa's leased NGL product storage facility in Matagorda County, Texas and then to Formosa's petrochemical facility in Calhoun County, Texas.

The agreement provides Copano with up to 37,500 barrels per day of firm fractionation services beginning in the first quarter of 2013 for a term of 15 years. The agreement also provides that Formosa will purchase the resulting NGL products and make product storage available to Copano for operational reliability. Following the completion of Liberty Pipeline, which is expected by the summer of 2011, and until additional facility improvements at Formosa are complete, Copano will have access to a minimum of 5,000 barrels per day of existing Formosa fractionation capacity, as well as additional capacity on a "space available" basis.

Liberty Pipeline will have initial capacity of 75,000 barrels per day, which will be committed to Copano and Energy Transfer (50% each) under firm throughput agreements. Copano and Energy Transfer will together invest approximately $52 million for the pipeline and related facilities.

"We look forward to a long-term relationship with Formosa and to working with Energy Transfer on the Liberty Pipeline project," said R. Bruce Northcutt, President and Chief Executive Officer of Copano Energy. "The Formosa agreement and Liberty Pipeline, together with our other recently announced projects, are important steps in executing Copano's overall Eagle Ford Shale strategy and will increase our total NGL handling capability to over 80,000 barrels per day. These developments provide an additional market for NGLs extracted at our Houston Central Complex and help support Formosa's fractionation, storage, and olefins production operations."

Houston-based Copano Energy, L.L.C. has assets that include approximately 6,400 miles of active natural gas gathering and transmission pipelines, 250 miles of NGL pipelines and eight natural gas processing plants, with over one Bcf per day of combined processing capacity and 22,000 barrels per day of fractionation capacity.

Alaska Pipeline Restarts after Weekend Shutdown

The trans-Alaska oil pipeline was restarted January 17 after a roughly 58-hour shutdown to allow repair work to deal with a leak.

The Alyeska Pipeline Service Co. shut down the 800-mile pipeline early January 15 to install a bypass pipe around the leak at Pump Station 1, where the pipeline starts on the North Slope. The shutdown was expected to last 36 hours.

Michelle Egan, spokeswoman for the Alyeska, told the Associated Press the target goal was to bring the pipeline up to a 500,000 barrels a day during the next 24 hours.

Before the leak was discovered nine days previous at a pump-station booster pump, the pipeline was carrying about 630,000 barrels a day—or $55 million a day worth of oil.

Egan said crews completed work on a 157-foot bypass line to go around the leak, and began the process for restarting the pipeline shortly after 4 a.m.

After the leak was discovered on January 8, Alyeska shut down the pipe for about 84 hours, and production at the more than two dozen oil fields was reduced 5 percent of normal, or about 30,000 barrels a day.

For the second shutdown during the weekend, the oil fields were producing at a rate of 75,000 to 150,000 barrels a day, Alyeska said, with production flowing into storage tanks.

Alyeska said the original leak in the pump station basement stopped after Alyeska shut down the pipeline for the bypass.

As of January 17 Alyeska had recovered about 13,300 gallons of spilled oil from the building where the leak occurred. No oil has been discovered outside the building, the company said.

More than 600 people have been involved in responding to the leak, including 375 workers at Pump Station 1.

The North Slope oil fields account for about 11 percent of U.S. domestic production.

Oil companies BP, Conoco Phillips, Exxon Mobil, Koch Industries and Chevron own the pipeline, which runs from the oil fields to the tanker port at Valdez.

Enbridge Ups MI Pipeline Cleanup Estimate to $550 Mln

U.S. pipeline company Enbridge Energy Partners LP (EEP) on January 14 raised to $550 million the expected cost of cleaning up the July 2010 oil spill that stemmed from its Line 6B pipeline. The new projection is more than one-quarter higher than its previous estimate.

About 19,500 barrels of crude oil were spilled at a pump station near Marshall, MI, with some of the oil reaching the nearby Kalamazoo River. Enbridge's previous cleanup estimate was $430 million.

"We have revised the estimate based on a review of costs and commitments incurred to date as well as additional information concerning the requirements for environmental restoration and remediation," the company said in a filing with the U.S. Securities and Exchange Commission.

Enbridge said it still expects its insurance to reimburse the company for all costs derived from the cleanup.

Enbridge operates about 9,500 miles of pipelines that deliver more than 2 million barrels of crude oil and liquids a day, according to the company's website.

North Dakota may Surpass Alaska as Largest U.S. Oil Producer

By implementing horizontal drilling and multi-stage fracturing in the Bakken Shale, North Dakota may well surpass Alaska in crude oil production by 2017, Bloomberg has reported.

According to separate reports from both the North Dakota Pipeline Authority and the U.S. Department of Energy, if the current trends in production continue, North Dakota may overtake Alaska as the No. 1 producer in the U.S. by 2017.

Should the increase in drilling and production in North Dakota continue, the output in North Dakota may rise to between 450,000 and 700,000 barrels of oil a day within the next five to seven years, reported the North Dakota Pipeline Authority.

On the other hand, the production coming out of Alaska is slated to drop to 450,000 barrels a day by 2017, the DOE reported.

The Bakken Shale has sparked a drilling frenzy in North Dakota, with drilling rig counts at the highest they have ever reached. According to the Baker Hughes Inc. weekly rig report, there were 151 active drilling rigs in the state during January, despite the winter weather. All of the rigs are drilling for oil in the Williston Basin of North Dakota, and 93 percent of them are drilling horizontally.

Resources and infrastructure have threatened to slow the drilling and production in North Dakota, which boasts plenty of jobs but lacks housing for employees and their families. But the state in general supports the burgeoning economy.

According to the North Dakota Pipeline Authority, there are several large projects ongoing to connect North Dakota production to U.S. markets, including the Enbridge Bakken Expansion Program, Keystone XL Marketlink, True Co’s Baker 300, Plains Bakken North and Unit Train Development.

Williams Completes $925 Mln Bakken Purchase in North Dakota

Williams Partners announced that it has completed a major purchase in North Dakota's Bakken oil play from private owners for $925 million cash.

In the transaction, Williams purchased 100 percent of the interests in Dakota-3 E&P Company LLC. Dakota-3 has approximately 85,800 net acres on the Fort Berthold Indian Reservation in the Williston Basin and 3,300 barrels per day of net oil production from 24 existing wells.

Williams' purchase had an effective date of October 1, 2010 subject to standard closing adjustments. Williams is the new owner of Dakota-3, which will continue its existing contractual arrangement for services with the contract operator and field services provider after closing.

Currently, Dakota-3 has three rigs operating on its acreage. Williams expects to double the current level of drilling activity to six rigs by 2012, subject to permitting. Williams estimates that Dakota-3's holdings represent approximately 185 million barrels of oil equivalent in total net reserves potential in the Middle Bakken and the Upper Three Forks formations.

Williams' entry into the Bakken Shale play follows its entry into Pennsylvania's Marcellus Shale, where the company has accumulated approximately 100,000 net acres over the past year and a half.

Savage to Build North Dakota Bakken Rail Terminal

Savage Companies on January 25 announced its plans to construct, own and operate a large multi-user rail terminal in Trenton, North Dakota.

The terminal, to be known as Trenton Railport, will be served by the BNSF Railway, and will be designed to bring large-scale rail service to the Bakken Formation (the Bakken) with oil-field related materials such as tubular, frac sand and other strategic materials, including the capability to load and ship unit trains of crude oil. Savage believes that the Bakken's oil and gas resource potential is significant and strategic in strengthening America's energy independence.

The 270-acre site on which the Trenton Railport will be built was secured by Savage in cooperation with Yellowstone Ethanol, LLC (Yellowstone). Bob Gannaway, President of Yellowstone, stated: "We are excited to be working with Savage, and see where it will bring many new opportunities for our area." Savage has begun first-level engineering, design and permitting studies, and anticipates that construction will begin later this year, with completion expected by late 2011.

The facilities will include rail infrastructure, open space for oil field materials storage, and receiving capability for frac sand and other materials. In support of its Trenton Railport customers, Savage intends to provide a total service model featuring the providing of railcars, and a complete logistics package.

Local officials have expressed support for the project, which is expected to employ more than 150 people in various capacities during construction of the terminal, and anticipates using local contractors wherever possible. Once operational, Trenton Railport employment on a steady state basis is expected to be between 40 and 60 people. Recruiting and hiring activities are expected to commence in Trenton during the first quarter of 2011.

Inergy Launches Open Season for Tres Palacios Extension

Inergy, L.P. announced January 18 that its wholly owned subsidiary, Inergy Midstream, LLC, is conducting a non-binding open season for firm wheeling service on an extension of its Tres Palacios gas storage facility pipeline header system. The proposed pipeline extension will create a new point of interconnection at the tailgate of Copano Energy, LLC's Houston Central gas processing plant in Colorado County, Texas.

The Tres Palacios header extension project is expected to include approximately 20 miles of newly constructed lateral piping, additional compression, and interconnect facilities (the "Tres Header Project"). Once complete, the Tres Header Project will allow shippers to move gas along 60 miles of header pipe with access to a combination of 10 interstate and intrastate pipelines and the Tres Palacios storage facility. Additionally, shippers will have access to the Tres Palacios Hub point, which is listed on the Intercontinental Exchange ("ICE") for natural gas transactions.

Copano's Houston Central Plant currently provides 700MMcf/d of processing capacity and 22,000 barrels per day of fractionation capacity and is being modified and expanded to handle rich natural gas from the Eagle Ford Shale play. The Tres Palacios gas storage facility will give producers additional options for the sale of residue gas at the tailgate of the Houston Central Plant.

The Tres Palacios gas storage facility is located approximately 100 miles southwest of Houston in Matagorda County, Texas. The facility includes 38.4 BCF of FERC-certificated working gas capacity with planned expansion to 47.9 BCF. The storage facility is strategically situated near the Eagle Ford Shale and one of the largest gas-fired power generation markets in the United States. Inergy acquired the Tres Palacios storage facility in October 2010.

The Tres Header Project, together with the existing Tres Palacios header system, is expected to provide significant commercial opportunities to Eagle Ford Shale producers, marketers, and others to deliver their gas to multiple demand markets and or storage. The open season is targeting shippers seeking: (i) additional market flexibility and reliability; (ii) liquid points of sale for locally produced gas from the Eagle Ford Shale play; (iii) additional storage opportunities; and (iv) to capture pricing differentials between the various interconnected interstate and intrastate pipelines.

Rates, including fuel retention, will be determined after the conclusion of this non-binding open season and are dependent upon the final scope of facilities and firm service commitments. Indicative rates are provided in the non-binding open season package.

The non-binding open season will commence on January 18, 2011, and will close February 15, 2011. The anticipated in-service date for the pipeline extension project is the summer of 2012. For questions concerning this open season or for an open season package, contact Bruce Page at 281-453-5306 or Jeff Reavis at 281-453-5307. Open season packages may also be obtained by email to bpage@inergyservices.com and can be downloaded from the following websites: www.gasstorage.net/trespalacios, www.storageboard.com

Inergy Midstream, LLC, a wholly owned subsidiary of Inergy, L.P., owns and operates the Tres Palacios gas storage facility, the Stagecoach gas storage facility, the Thomas Corners gas storage facility, and the Steuben gas storage facility. These four natural gas storage facilities have a combined 78 Bcf of working gas capacity. Inergy Midstream also owns and operates a solution mining and salt production company, US Salt, LLC, and a liquefied petroleum gas ("LPG") storage facility, Finger Lakes LPG Storage, near Watkins Glen, NY.

Inergy, L.P., with headquarters in Kansas City, MO, is among the fastest growing master limited partnerships in the country. Inergy's operations include the retail marketing, sale, and distribution of propane to residential, commercial, industrial, and agricultural customers. Today, Inergy serves over 700,000 retail customers from over 350 customer service centers throughout the United States. Inergy also operates a 78 Bcf natural gas storage business; a natural gas liquids supply logistics, transportation, and wholesale marketing business serving independent dealers and multi-state marketers in the United States and Canada; and a solution-mining and salt production company.

Bakken $500 Mln Pipeline Project to Reach Northern Colorado

Construction on another natural gas pipeline in Colorado’s northern Weld County is expected to begin in 2012, and representatives from ONEOK Partners met with Weld commissioners January 24 to give them a heads-up on the project.

The Bakken Pipeline, a $500 million project, will transport natural gas liquids from Sidney, MT, and will be connected to the existing Overland Pass Pipeline about 10 miles into northern Weld, west of Hereford and Grover.

The new pipeline, said Steve Johnson, director of government relations for ONEOK Partners, is expected to come online in the first half of 2013. The natural gas liquids -- ethane, propane, butane and natural gasoline -- will come from natural gas processing plants in the Bakken Shale in Montana and North Dakota. Once the material reaches the Overland Pass Pipeline, it will be sent to processing plants in Kansas. There it will be sold on the wholesale market to the petrochemical and plastics industries, as well as for refining and home heating.

The 510-mile Bakken Pipeline, Johnson said, is part of $1.3 billion in capital projects ONEOK Partners, based in Tulsa, Okla., plans to invest in the Bakken Shale. That will include construction of two, 100 million cubic feet per day natural gas processing facilities that are expected to nearly triple the partnership's processing capacity in that region.

Johnson said about 14 private landowners will be contacted in northern Weld to establish easement agreements. The new pipeline will not cross any federal lands, he added. The 12-inch line will be buried 3 feet deep and the land will be "restored the way it was or the way the landowner requests," Johnson said.

Johnson also said the construction company will hire locally where possible, mostly services needed during construction. At any given time, he said, there could be 200 people working on the line, "with company officials coming into and out of Greeley pretty regularly."

Willbros Is Awarded Contract to Build Segment of Acadian Haynesville Extension

Willbros Group, Inc. announced January 24 that a unit of its Upstream Oil & Gas segment has been awarded the construction contract for a portion of the Acadian Haynesville Extension Project, a natural gas pipeline being developed by Acadian Gas LLC, a jointly owned subsidiary of Enterprise Products Partners L.P. and Duncan Energy Partners L.P. The 270-mile project, which expands the existing Acadian Gas Pipeline System, will originate in Red River Parish, LA, southeast of Shreveport, and will terminate near Donaldsonville, LA.

The Acadian Haynesville Extension Project has been divided into three major segments. Willbros has been awarded the construction of Segment 1 which includes approximately 106 miles of 42-inch pipeline, 2.5 miles of 36-inch pipeline and 2.5 miles of 20-inch pipeline. Segment 1 will originate in the northwest portion of Red River Parish, traverse through DeSoto and Natchitoches Parishes and terminate near Boyce, LA. Construction on Segment 1 is expected to begin in February 2011 with completion in August 2011.

Randy Harl, President and Chief Executive Officer, remarked, "We are very pleased to have the opportunity to work with Enterprise as they expand their midstream energy assets. This award is significant for Willbros as it not only improves visibility for our U.S. Construction business unit, but it also reinforces our strategy to leverage our core competencies to perform large capital projects while expanding our regional capabilities. We believe the improvements we have made to our systems and processes over the past few years enable us to deliver superior execution for our customers at competitive pricing."

When completed, the Acadian Haynesville Extension pipeline will be operated by Acadian Gas LLC, which is owned 66 percent by Duncan Energy Partners and 34 percent by Enterprise Products Partners.

TransCanada Reports Successful Open Season for Bakken Project

TransCanada Corp. on January 20 announced it has concluded a successful open season for the Bakken Marketlink Project which will deliver U.S. crude oil from Baker, Montana to Cushing, Oklahoma. Bakken Marketlink will transport U.S. crude oil production to market using pipeline facilities that form part of the Keystone XL system. The project has secured a total of 65,000 barrels per day (Bbl/d) of firm, term contracts. The Bakken formation is one of the fastest growing crude oil plays in the United States.

"These agreements are a clear indication of producer support for the first direct link between the prolific Bakken crude oil producing region in the Williston Basin and key U.S. markets near Cushing, Oklahoma and the U.S. Gulf Coast, the largest refining market in North America," said Russ Girling, TransCanada's president and chief executive officer. "This project will provide U.S. producers with an alternative and competitive way of bringing their crude oil to market and supports American workers who produce the oil and American companies who will refine it."

Keystone XL's proximity to the key Bakken crude oil producing regions within the Williston Basin uniquely positions TransCanada to provide an effective market access alternative for U.S. Bakken crude oil production to reach Cushing, Oklahoma and the U.S. Gulf Coast.

Crude oil forecasts for the U.S. Bakken region continue to grow with production expected to increase by approximately 200,000 - 300,000 bpd by 2015. The Bakken Marketlink Project will help to relieve pipeline capacity constraints in the Williston Basin and will support forecasted growth in U.S. domestic crude oil production.

Keystone XL has extensive support south of the border and will reduce America's dependence on crude oil from Venezuela and the Middle East by up to 40 per cent. The expansion will also create 20,000 jobs for American workers and inject $20 billion into the U.S. economy.

The project is expected to be in service in the first quarter of 2013, subject to the receipt of necessary regulatory approvals.

With more than 50 years' experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 60,000 kilometers (37,000 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 10,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems.

Pennsylvania Investigating January Marcellus Well Blowout

Pennsylvania environmental officials said January 25 that they were investigating a blowout at a Marcellus Shale natural gas well in Tioga State Forest the previous week.

The state Department of Environmental Protection said specialists regained control over the Talisman Energy Inc. well in Ward Township, Tioga County, after 31/2 hours on January 17. There were no injuries.

The DEP said the incident occurred during a hydraulic-fracturing operation. Talisman reported that 21,000 gallons of fracturing fluids and sand spewed onto the well site. The agency said the fluids appeared to have been contained on the plastic-lined well pad.

"It does not appear that any significant amount of natural gas was released, and there was no fire or explosion," the DEP said in a news release.

The department sent a notice of violation to Talisman January 17 requiring the Canadian company to submit an analysis of the incident's cause and proposed changes to its Marcellus drilling operations.

The department's public response eight days after the incident stands in stark contrast with the DEP's all-hands-on-deck reaction last June to a blowout at an EOG Resources Inc. well in Clearfield County, which unleashed wastewater and gas for 16 hours before it was capped.

The DEP hired an outside consultant to assist its investigation and assessed fines of about $400,000 against EOG and a drilling contractor.

CUDD Well Control Services, one of several well-emergency contractors that have located operations to Pennsylvania after last year's Clearfield County blowout, is based in Canton, Bradford County, just a few miles from the blowout site.

DEP said Talisman had been cooperating with the investigation. The agency on January 18 permitted Talisman to resume hydraulic-fracturing operations in Pennsylvania, which the company had voluntarily suspended after the incident.

The controversial practice of hydraulic fracturing which involves the high-pressure injection of water, chemicals, and sand into an underground well to stimulate production is being restudied by U.S. Environmental Protection Agency.

Caiman Brings Marcellus Gas Plant Online and Announces Chesapeake Agreement

Caiman Energy, LLC on January 26 announced completion of the Ft. Beeler Processing Plant I, a cryogenic processing facility located in the Marcellus Shale formation near Cameron, West Virginia.

In connection with bringing online the plant's 120 million cubic feet per day (mmcf/d) capacity, Caiman also announced execution of a definitive long-term agreement with Chesapeake Energy Corp. to process rich gas Chesapeake produces in Marshall and Wetzel counties, West Virginia. Chesapeake is the second-largest producer of natural gas in the U.S.

Recent midstream service agreements with long-term acreage dedications include contracts with Gastar Exploration Ltd.; Stone Energy; Grenadier Energy Partners, LLC; and Drilling Appalachian Corp. Caiman has agreements in place with AB Resources LLC and Chief Oil & Gas, LLC, Caiman's initial anchor tenants in the Marcellus. Existing customers also include Trans Energy, Inc., and Republic Energy, LLC. The new agreements bring Caiman's total dedicated acreage in the rich gas Marcellus processing area of West Virginia's Marshall and Wetzel counties to more than 160,000 acres. Including dedications in the lean gas areas of Pennsylvania and West Virginia, Caiman now has close to 500,000 acres of Marcellus acreage dedicated to its midstream operations.

Drilling projections from numerous existing and potential customers have prompted Caiman to launch construction of a second cryogenic processing facility. The 200 mmcf/d Ft. Beeler Processing Plant II is expected to be complete by the end of 2011 and will bring the company's natural gas processing capacity at Ft. Beeler to 320 mmcf/d. Caiman will also explore construction of a third cryogenic processing facility with a capacity of 200 mmcf/d as early as the second quarter of 2011. Caiman has more than 60 miles of high-pressure, large-diameter pipeline in service in the Marcellus Shale and an additional 60 miles of gas gathering lines under construction.

"We are very pleased with the significant scope and pace of our expansion in the Marcellus," said Caiman Energy President and CEO Jack Lafield. "We are committed to meeting the needs of our dedicated producer base. There are 10 rigs currently running on dedicated acreage in our rich gas areas. To meet our customers' expanding requirements for infrastructure, we expect to have total processing capacity of 520 mmcf/d online by the second half of 2012."

Lafield said that by the end of 2011, "we expect to have invested more than $400 million for new infrastructure in the Marcellus Shale. Marshall and Wetzel counties in West Virginia are home to some of the best rich gas resources in the entire play. We will continue to develop and grow our assets as drilling activity expands, driving increased requirements for gathering, processing, and access to high value markets."

Cnooc Buys Chesapeake U.S. Shale Oil, Gas Assets for $570 Mln

China's Cnooc Ltd. (CEO) is buying into several shale oil and gas leases in the U.S. owned by Chesapeake Energy Corp. for US$570 million in cash, in the latest move by a Chinese oil company to learn a technology that has transformed the U.S. gas industry.

Also, Cnooc will fund two-thirds of Chesapeake's share of drilling and other costs up to maximum of US$697 million, the two companies said in a statement January 31.

The deal follows a similar Cnooc-Chesapeake agreement in October 2010 under which the Chinese company bought one-third of Chesapeake's 600,000-acre Eagle Ford, Texas, shale oil and gas project for US$1.08 billion--a pact which was the first major investment by a China state-run company in onshore energy reserves in the U.S.

Chinese companies had until then been reluctant to invest in U.S. energy reserves, following Cnooc's 2005 bid to take over California-based Unocal Corp. being blocked by a nationalist political uproar.

However, these new Cnooc investments appear to have political cover, given global efforts to curb greenhouse gas emissions and joint China-U.S. efforts to promote cleaner energy.

The project will accelerate commercial opportunities for the development of shale gas resources in China, furthering the objectives of the U.S.-China Shale Gas Resource Initiative announced by the White House on November 17, 2009, the two said in a statement.

Chesapeake chief executive Aubrey McClendon said the agreement "will provide the capital necessary to accelerate drilling of this large domestic oil and natural gas resource, resulting in a reduction of our country's oil imports over time, (and) the creation of thousands of high-paying jobs in the U.S."

Cnooc chairman Fu Chengyu described it as being "mutually beneficial to both parties as well as for both Sino-US energy industries."

The deal involves Cnooc, China's third-largest oil and gas producer, taking a 33.3% stake in Chesapeake leases covering 800,000 acres in the Denver-Julesburg and Powder River Basins in northeast Colorado and southeast Wyoming states.

"We don't see any U.S. regulatory concerns judging by the prior approval of the Eagle Ford deal, as Cnooc is only acquiring minority stakes, and the oil/gas produced will remain in the U.S. supply system," said Mirae Asset Management analyst Gordon Kwan.

Rapid growth in shale gas output in the U.S. has displaced imported liquefied natural gas, making more LNG available for other countries and keeping a lid on U.S. domestic and international gas prices.

Attention is now also being turned to the billions of barrels of oil locked in similar geological structures.

Both China and neighbor India, which are heavily dependent on imported oil and gas, are hoping to replicate the success seen in the U.S. with their own shale reserves, but to do this need access to that technology.

The International Energy Agency estimates China has reserves of 26 trillion cubic meters of shale gas, which it hasn't been able to access due to its lack of technical know-how.

While investing in U.S. shale deposits, China has allowed U.S. and European companies into its tightly controlled onshore acreage.

Royal Dutch Shell PLC and PetroChina Co. have been jointly developing shale-gas resources in Sichuan province while China Petrochemical Corp. is cooperating with BP PLC and Chevron Corp. in shale gas projects.

Under another recent agreement, China Sinochem Group Corp. and the U.S.-based Hess Corp. (HES) will cooperate in onshore shale oil and gas exploration in China. Hess also agreed with China Petroleum & Chemical Corp. (SNP) earlier this month on a joint study on shale oil reserves at China's second-largest Shengli oil field.

Indian companies, often laggards behind China in foreign energy investments, got into the U.S. shale sector ahead of their Chinese peers.

Reliance Industries, India's biggest private oil refiner, took a 40% stake in U.S.-based Atlas Energy Inc.'s Marcellus Shale acreage in a deal valued at $1.7 billion in April 2010 and then in June purchased a 45% stake in Pioneer Natural Resources Co.'s Eagle Ford shale natural gas asset in Texas for $1.3 billion.

CANADA

Statoil Reports Oil Sands Progress at its Leismer Demonstration Project (LDP)

Statoil announced first oil production from its Leismer Demonstration Project (LDP) after initiating steam injection in September 2010, one month ahead of schedule.

"We are very pleased with the safe start up of this demonstration facility and first oil at Leismer," said Lars Christian Bacher, president of Canadian operations for Statoil Canada Ltd. "This is truly a milestone for our business in Canada."

LDP, approved to 10,000 barrels per day (bpd), is the first phase of the Leismer project, which is expected to ramp up to its rated capacity of 18,800 bpd within 24 months, pending final approval by Alberta Environment.

Future phases of the Kai Kos Dehseh steam assisted gravity drainage (SAGD) project are also under study. Statoil originally entered Kai Kos Dehseh through the acquisition of North American Oil Sands Corporation in 2007.

Statoil's oil sands leases are located approximately 120 kilometers south of Fort McMurray in the Athabasca region of north east Alberta. The company's next phase, Corner, is a proposed 40,000 bpd facility, which along with the eventual further expansion of Leismer to 40,000 bpd, recently received approval by the Alberta Energy Resources Conservation Board (ERCB).

"Over the last three years we have increased our understanding of the oil sands business and feel we are now in a good position to apply what we have learned," said Bacher.

"We will proceed with several research and technology innovations and tests at the LDP project and if successful will apply them to future phases of development to drive economic efficiency and reduce environmental impact, including CO2 reductions at our Alberta operations."

Statoil Canada Ltd. is the operator of Kai Kos Dehseh with a 60% ownership in the project, while PTT Exploration and Production of Thailand is a partner with a 40% ownership.

Aecon Grp Hit by Suncor Oil Sands Project Losses

Aecon Group Inc.'s stock took a hit February 4 after the big Canadian construction and infrastructure development company said it will record significant losses on its field-construction contract at Suncor Energy Inc.'s (SU) Firebag 3 oil-sands project in northern Alberta.

In Toronto, Aecon was recently down C$1.06 or 11% to C$8.80.

The company projects losses on the project will range from C$40-C$42 million after tax, which will result in a 2010 operating loss for its industrial segment.

Losses will be limited to 2010 since the project was completed and turned over to Suncor at year-end. Excluding items, Aecon said its results for the fourth quarter are still generally in line with management expectations.

The contract, awarded by Suncor in November 2009, was the largest in Aecon's industrial division's history, though specific terms weren't disclosed.

In a recent note, Raymond James said the Firebag 3 job was more difficult to execute than expected and projected it would cause a drag on Aecon's fourth-quarter results. Separately, Paradigm Capital said the project loss was a "one off" and not indicative of a problem with existing backlog.

Aecon said it still has a "solid working relationship" with Suncor and continues to work on a number of Suncor sites, including the Firebag 4 cogeneration project. Suncor is targeting production from Firebag in late 2012.

Brewing Battle over Canada $7 Bln Keystone XL Pipeline

The Obama administration is divided over a proposed pipeline that would ease U.S. reliance on oil from politically unstable regions but boost dependence on crude from Canada's environmentally unfriendly oil sands.

The State Department may begin deciding as early as next month whether the $7 billion Keystone XL pipeline would be necessary to bolster U.S. energy security. The oil would cut dependence on imports from Venezuela and Middle Eastern countries such as Saudi Arabia.

The Environmental Protection Agency, however, is worried about the greenhouse gas emissions from production of Alberta's tarry oil sands and that the oil bounty could undermine U.S. plans to make cars more efficient and to electrify more vehicles in coming decades.

Calgary-based TransCanada Corp hopes the 510,000 barrels per day pipeline, which would bring oil from Canada to refineries in Texas and Louisiana, will be built and start in early 2013. It wants to build a link from the proposed line so that oil drilled in the northern U.S. could also be shipped to the huge Cushing, Oklahoma oil storage hub.

Here are some possible paths the plan could take if it is approved.

In July, the EPA asked the State Department to revise its environmental impact statement on the pipeline to consider greenhouse gas emissions, other environmental concerns, and pipeline safety.

Secretary of State Hillary Clinton hinted in October her department was "inclined" to approve the line on energy security grounds. Since then a senior State Department official said approval is not a foregone conclusion.

State could finalize a new environmental review of the project without taking public comment, but that could push the EPA to ask that the final decision be made by the White House.

Or more likely, State could revise the environmental review and open it to public comment before finalizing it.

That move could open up the planned pipeline to compromises, such as diverting the pipeline route away from environmentally sensitive areas, increasing pipeline safety measures, or reducing the proposed flow on the line. That could make the project more palatable to the EPA and the project could move ahead.

If EPA is unhappy about revisions to the environmental review after public comment, or if State finalizes it without opening up to public discussion, the regulators could ask that the final decision be referred to the White House's Council on Environmental Quality.

The CEQ is headed by Nancy Sutley who has said that clean energy and emissions reductions could help break the country's dependence on foreign oil.

Presumably State and the EPA would want to work out their differences before it gets to this stage.

After a potential environmental impact review with public comment, the State Department will work on a "national interest determination."

In this process, Clinton's department will weigh the importance of the line for U.S. energy security. The process would be open to comment by agencies such as the EPA and the Department of Energy.

The EPA will likely question whether the line strengthens energy security as an expected decline in fuel demand could mean some of the Canadian oil would be refined for export.

In addition, the EPA may argue that the life cycle emissions from the oil sands -- which it says are as much as 82 percent greater than the average crude refined in the United States -- could hurt U.S. security. The damage could be from the effects of global warming in coming decades, including heat waves, droughts and rising seas. Others have argued that inaction by the United States on emissions could crystallize anti-American resentment in countries vulnerable to climate change.

If the EPA is not happy with the State Department's decision in the national interest determination, it could take the rare step of asking that the decision be sent to Obama. The president has pledged the United States would cut emissions and dependence on foreign oil, but an opportunity to link energy systems with close ally Canada could be hard to resist.

But the administration may be anxious to avoid this option which could leave Obama directly responsible for a project that environmentalists -- one of his important voter bases -- would oppose. The administration would likely push State and EPA to compromise instead.

Canadian Natural to Assess Upgrader Damage at Horizon Oil Sands Project

Provincial safety officials have lifted a stop-work order at Canadian Natural Resources Ltd's Alberta oil sands upgrader, allowing the company to begin assessing the damage from a fire last month.

However, it is still not known when production from the 110,000 barrel a day project will resume.

Thomas Lukaszuk, minister of employment and immigration for the Canadian province of Alberta, said the safety and health agency will continue investigating the Jan. 6 blaze at the Horizon oil sands project, which injured five people.

The agency will issue another order preventing the restart of the plant's main processing units, known as cokers, until the cause has been determined and measures have been put in place to prevent another incident, he said.

The fire and outage of the upgrader, which turns bitumen from the oil sands into refinery-ready crude, have pushed up prices in the cash market.

Canadian Natural has said it may be possible to restart two of the four coker drums in the plant that were not damaged in the fire, but that has not been confirmed.

Company officials declined to comment on plans for gauging the damage and making repairs.

"Now that the stop-work order has been lifted they can assess the damage not only to the coker where the explosion was but the other coker that was right beside it," Alberta Occupational Health and Safety spokesman Barrie Harrison said.

"They would determine if there are any repairs needed, and once they feel they are good to go and they have their start-up plans available to us, then we would review and approve them."

Canadian Natural said it expected no production from the project in February, extending a force majeure -- which frees it from supply obligations -- through the month.

Canadian Natural shares rose 30 Canadian cents to C$44.95 on the Toronto Stock Exchange. They are up 11 percent since the explosion and fire.

Total's Joslyn Oil Sands Mine Approved

A review panel has conditionally approved Alberta's ninth oil sands mine, giving its blessing to an application from French energy giant Total SA.

The federal-provincial panel ruled in favor of the company’s controversial bid to build the Joslyn North mine, about 70 kilometers north of Fort McMurray. Total expects to begin operating the $7-billion to $9-billion mine in 2017, and is planning to produce 100,000 barrels per day.

Oil outlook Joslyn will add to a fast-growing oil sands industry that already produces 1.9 million barrels per day. According to data gathered by Strategy West Inc., Fort McMurray-area mines produce 1.1 million barrels today; mines with another 940,000 have also been approved, not including Joslyn.

In total, Alberta has given the thumbs-up to 2.2 million barrels in projects that have yet to pump oil. Companies have proposed a total of 8.2 billion barrels.

Suncor Energy Inc. is a part-owner in the Joslyn project, which Total purchased in 2005 when it paid $1.7-billion to buy junior Deer Creek Energy.

The approval increases the area in Alberta that can be mined by 7 per cent, and places 20 conditions on the company, and 16 on the provincial government and its energy regulator, the Energy Resources Conservation Board.

Those conditions mirror standing laws that require speedier reclamation of toxic mine waste and protection of species at risk and valued wildlife.

Total spokeswoman Elizabeth Cordeau-Chatelain said the company needs “time to review the report and the various conditions. But overall, we’re pleased.”

The French firm has committed to spending $15-billion to $20-billion in the oil sands, which it sees as a critical resource in an age of dwindling oil supplies.

A coalition of environmental groups strongly opposed the Joslyn project, calling on well-known climate change voices like James Hansen to argue that the mine will hurt the ecosystems of northern Alberta and Canada’s ability to meet greenhouse gas reduction targets.

“There should be a moratorium on building anything new until we get a monitoring system in place, and we get some idea what the damage has been from the previous development,” said Sierra Club Canada executive director John Bennett.

He also criticized regulators’ records on approving virtually all oil sands development.

“Alberta and the federal government have not seen a tar sands project that they didn’t love,” he said. “We have no faith in this process whatsoever, because it’s a system geared to encouraging the creation of more and more of these things, rather than to monitoring and controlling their environmental impact.”

China’s Sinopec Invests in Canadian $5.51 Bln Northern Gateway Pipeline Project

China is helping to finance the development of a proposed $5.51 billion oil pipeline to Canada's West Coast that would open the Asian market to Canadian crude, which is now chiefly consumed by the U.S.

State-owned China Petroleum & Chemical Corp., or Sinopec, is among a consortium of Canadian oil producers and Asian refiners investing $100 million in Enbridge Inc.'s proposed Northern Gateway pipeline, Enbridge Chief Executive Pat Daniel said during a Web cast investor conference January 17.

The Northern Gateway pipeline would pipe an average of 525,000 barrels of crude oil a day from Canada's oil-sands region to a port in British Columbia, from which it would be shipped to Asian markets. Regulators aren't expected to rule on whether the project can go forward until next year. If approved, construction is scheduled to be completed in 2016.

Canada's oil sands hold an estimated 170 billion barrels of oil, making it the second-largest oil reserve in the world, after Saudi Arabia's. The U.S. is the only export market for Canadian crude oil, and Canada is the U.S.'s largest single supplier.

Sinopec and other investors have put up $100 million to help Northern Gateway get through the regulatory process, which includes producing environmental-impact studies and consulting with native and environmental groups—some of which oppose the project.

Mr. Daniel said Enbridge itself has already spent $100 million on the regulatory process. The Calgary-based pipeline company applied for approval to build Northern Gateway in May, and expects Canada's federal energy regulator to approve it by the middle of 2012.

Mr. Daniel said confidentiality agreements prohibited him from naming the other investors, but said he could name Sinopec because the news had been previously reported by Canadian newspaper the National Post.

The proposal has met fierce criticism from native groups and environmental nongovernmental organizations. Some warn of the risk of spills from the pipeline or from oil tankers, while others are chiefly opposed to further growth of the oil-sands industry, which has come under fire for its substantial greenhouse-gas emissions and fears of water contamination.

Mr. Daniel said he is confident Enbridge could win over opposition. The company in November proposed giving a 10% equity stake to native groups in an attempt to win them over, Daniel said.

"That's been very well received and we're hoping to bring more First Nations on side as a result of that," he said.

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