Oil sands producers are interested in exporting crude to Europe and the U.S. East Coast by pipeline and tanker, the chief executive of Enbridge Inc. (ENB) said December 4.

With its Trailbreaker system, Enbridge would send oil from Alberta to Portland, Maine, where tankers could carry oil to Europe and the rest of the East Coast, said Patrick Daniel, CEO of the Calgary-based pipeline company. Oil would travel along existing pipelines from the oil sands region to Sarnia, Ontario. Enbridge would reverse pipeline flows linking Portland, Montreal and Sarnia to complete the journey, with a goal of transporting 200,000 barrels a day starting in 2010.

Enbridge had earlier this year announced Trailbreaker as a means to bring oil to the U.S. Gulf Coast from tankers that loaded in Maine, but interest fell along with the cost of oil. European buyers, and increased interest from refiners along the eastern seaboard, may prove sufficient to justify moving forward, Daniel said.

The company will decide whether to proceed in the first quarter of 2009, Daniel said.

Regulatory fees on crude shipped between U.S. ports are significantly higher than routing oil overseas, Daniel said. Pipeline and tanker costs would add up to $11 a barrel for Gulf Coast refiners, compared with $2.15 a barrel to bring oil from Alberta to Chicago via pipeline, Daniel said. Companies were willing to pay the added cost when oil prices were higher, but interest has dried up as crude futures plunged by two-thirds since July.

"A $10 charge on $150 crude doesn't impact the economics as much as it does on $50 crude," Daniel said.

Enbridge is exploring bringing oil to the Gulf Coast by Mississippi River barge from a storage hub in Patoka, Ill., following a route where the company had originally hoped to build a pipeline with Exxon Mobil Corp. Enbridge is still assessing interest in a third pipeline, linking Cushing, Okla., and Houston-area refiners. That pipeline, to be built with BP PLC, could move forward by the middle of 2009.

Sunoco Seeks Oil Sands Partner to Retool 180,000 Bpd Toledo Refinery

Canada's oil sands producers have a potential new partner, as Sunoco Inc. has said it wants more Albertan supply for its U.S. refineries.

Sunoco chief executive Lynn Elsenhans told an analyst meeting December 15 that the Philadelphia-based company is seeking a partner to invest in retooling its 180,000 barrels a day Toledo, Ohio refinery to take more bitumen.

After the Toledo refinery work is complete, Sunoco would also like to find a partner to invest in improvements at its three refineries on the U.S. East Coast, Ms. Elsenhans added. She didn't give a timeline for the potential projects or name which companies Sunoco would be interested in partnering with.

A deal with Sunoco could be attractive for oil sands producers eager to find a refining home for their output. The market for Alberta's bitumen is limited not only by pipeline capacity, but also by the nature of bitumen itself; the heavy, sticky crude is difficult to transport and refine, and can only be processed by advanced refineries.

Producers can broaden their market by processing their bitumen in upgraders – vast facilities that remove the heavier crude components and create a lighter, synthetic product. But upgraders can cost up to $12-billion to build, and companies have cancelled or delayed over $40-billion of planned projects in Alberta in recent weeks because of the uncertain financial outlook for such major projects.

A cheaper alternative to building upgraders is to reach a partnership agreement with a U.S. refiner. In 2006, Calgary-based EnCana Corp. struck a deal with ConocoPhillips whereby the Canadian firm took a stake in Conoco's Illinois refinery, in exchange for a share in its oil sands projects. Husky Energy Inc. and BP PLC reached a similar agreement last year.

Companies that have delayed or cancelled upgraders in recent weeks, and so may potentially be interested in a deal with Sunoco, include Petro-Canada, privately-held Value Creation Inc. and Norway's Statoil ASA.

Any entry by Sunoco into the oil sands would be tinged with irony. Sunoco was the original owner of the company that eventually became Suncor Energy Inc., which is now one of Canada's largest oil and gas companies.

Sunoco divested its interest in Suncor in the mid-1990s. In Canada, the brand name Sunoco is still used by Suncor Energy at some of its service stations, which aren't now affiliated to the U.S. company of the same name.

Tri-Valley Drilling Ahead on 8th Horizontal California Vaca Tar Sands Well

Tri-Valley Corporation announced its Lenox Ranch Lease No. 109-H oil well has successfully set casing at its pre-determined vertical depth, in preparation to make the turn for a horizontal bore into the Upper Vaca Tar Sands formation of the Oxnard, California oilfield. The Company intends to develop the lease with at least 10 such wells for production and ultimately drill several injector wells for continuous steaming to heat up the tar oil sands for ease of production and high recovery.

During the past year, Tri-Valley has successfully drilled seven other such horizontal oil wells on the Hunsucker Lease, just north of the Lenox Ranch Lease and, while steadily recovering oil from that project, it has been expanding the facilities there to accommodate much larger production capacity than initially thought possible.

"With sufficient heating cycles, all these wells can flow at least 500 barrels of oil per day. Of course, this requires commensurate expansion of every aspect of the field infrastructure from natural gas supply to fuel the steam generators, to treatment and processing equipment and storage facilities. Ultimately we will drill companion injector wells that enable continuous steaming for continuous production. Once all the said infrastructure is in place, our production rates will achieve maximum capacity," said F. Lynn Blystone, president and chief executive officer.

Simultaneously, Tri-Valley is in the final stages of steaming the first grouping of 19 existing vertical wells drilled by a prior operator on the same Lenox Ranch Lease, with the aim of returning them to full production. The new horizontal wells, which contact six or seven times as much productive reservoir as do the vertical wells, are expected to produce several times the output of oil per day than do the vertical wells. Nevertheless, all the remaining vertical wells will be re-worked to enable them to be steamed as well in order to add to the productivity of the lease.

Utah Geological Survey Downgrades its Oil-shale Estimates

Geologists have determined Utah has far less oil shale than previously estimated, but extracting usable energy from those still-vast deposits remains more of a possibility than a probability.

For the first time, the Utah Geological Survey has investigated the Uinta Basin independently of oil-shale regions in Colorado and Wyoming and found that a 44-year-old federal estimate of more than 80 billion barrels of Utah shale oil potential is closer to 77 billion barrels of crude-oil equivalent, the agency announced December 17.

But that calculation doesn't take into account how much energy it would take to convert the shale -- a rock called organic marlstone -- into something useful, economical and environmentally acceptable.

Estimates that there could be 1.2 trillion barrels of recoverable shale oil are based on a 1964 U.S. Geological Survey of Utah, Colorado and Wyoming, said UGS investigator Michael Vanden Berg; about half the shale is in Colorado, with Utah and Wyoming splitting the rest.

The UGS analyzed data from 293 wells throughout eastern Utah's Uinta Basin; then mapped the thicknesses of the oil shale. The study found that the richest zones are in central Uintah County. The resulting estimate of how much crude-oil equivalent might be there took into account areas where shale development is prohibited, such as national parks and wilderness-study areas, and excluded zones where oil and gas production is active.

The geologists used the petroleum industry's estimate that a ton of shale would yield 25 gallons of shale oil to hone their conclusion, Vanden Berg said.

Even so, it's all theoretical. "It's an in-place resource," he said. "That's very different from a recoverable resource."

The U.S. Bureau of Land Management likewise acknowledges Western shale-resource estimates aren't based on reality. But the agency had to include some number in its recently completed environmental study, Washington, D.C.-based BLM spokeswoman Heather Feeney said in February.

"Right now, there is no technologically or economically viable way to recover oil shale," Feeney said. "In this particular geological formation, it's difficult to determine exactly what portion is recoverable."

To calculate the amount of Utah shale oil that could be recovered economically, there would have to be a technology that works here because every deposit is different, Vanden Berg said. "A technology that works in Brazil is not necessarily going to work here."

Only one company, Oil Shale Exploration Co., has a lease to research, develop and demonstrate the economic feasibility of shale oil on federal land in Utah. OSEC's federal lease so far has allowed it to export waste rock left over from the 1980s shale bust to Alberta, Canada, for testing a process developed in Australia for an oil-shale experiment that recently was shut down, costing Calgary-based Suncor its $100 million investment.

Amy Hansen, an OSEC spokeswoman, said the 300 tons of shale shipped to Canada yielded 9,000 gallons of kerogen, which could be further refined into kerosene or diesel fuel. But no North American refineries accept kerogen.

In June, OSEC announced a partnership with Petrobras of Brazil and Mitsui & Co. Ltd. of Japan to spend $12 million to study the feasibility of Petrobras' Petrosix technology on Utah oil shale on 40,000 acres of private land near Vernal.

Oil-shale critic Randy Udall, director of the nonprofit Community Office for Resource Efficiency in Aspen, Colo., says that per pound, oil shale contains one-tenth the energy of crude oil, one-sixth that of coal and a quarter the energy that comes from burning dung cakes.

When crushed and roasted in a kiln, oil shale -- whose real name is organic marlstone -- yields a waxy hydrocarbon called kerogen, a substance that hasn't undergone the geologic heat and pressure necessary to create petroleum. It can be refined into diesel, naphtha and sulfur, but no U.S. refineries accept kerogen.

New Interior Secretary Pick, Salazar Urges Slow Moves on West's Shale

Utahans laud Obama's 'moderate' Interior pick Sen. Ken Salazar isn't a fan of moving swiftly on oil shale production in the Intermountain West and likely will have a big impact on the controversial issue if confirmed as President-elect Barack Obama's pick for Interior secretary.

Salazar was the author of language inserted into a congressional spending bill that blocked the federal government from pursuing a leasing program to allow oil-shale exploration on federal lands. That ban ended Oct. 1, and the Bush administration is now formulating a way to dole out leases in Utah, Colorado and Wyoming.

Salazar says the production of synthetic fuel from oil shale -- a sedimentary rock -- isn't yet commercially viable and the government needs to ensure vast tracts of Western land aren't destroyed in the attempt to harvest the energy source.

"If we are to succeed in developing oil-shale responsibly, which I support, we need to establish an orderly process for development that protects Colorado's communities, protects our water, and helps us avoid the busts that have, in the past, set us back," Salazar said recently.

The news that Salazar, a Colorado Democrat, was Obama's designee for the job brought cautionary reaction from those who are trying to tap oil shale.

"If there's a positive in this election, it is that Sen. Salazar understands Western issues," says Jeff Hartley, a Utah Republican and an energy industry consultant. "If there's a downside, it's that he's been rather myopic with regard to emerging technologies."

Sen. Orrin Hatch, R-Utah, has said the oil-shale deposits in Utah, Colorado and Wyoming are the equivalent of Saudi Arabia's massive crude oil resources.

Marcellus Shale Committee Launches Website

The Marcellus Shale Committee (MSC) have announced the launch of its new Web site, www.PaMarcellus.com, which will serve as an information resource for people interested in learning about the development of natural gas from the Marcellus Shale formation in Pennsylvania.

"Our Web site provides an opportunity for Pennsylvanians to learn about all aspects of producing natural gas from the Marcellus Shale," said Ray Walker, MSC Co-Chair and Vice President of Appalachia Shale for Range Resources. "Whether you are interested in learning more about the property leasing process, drilling procedures or land restoration efforts, all of the details will be available on the site."

The site provides a full range of information on the Marcellus Shale formation, how natural gas is extracted from the shale while protecting the environment, why MSC values the communities where its members do business, and the opportunities that the Commonwealth and its residents can realize in the coming years and decades through natural gas exploration and production. The pages highlighting process, protection, community and opportunity can be printed to provide detailed fact sheets on important topics related to the Marcellus Shale development.

"We will continually update this resource as development of the Marcellus Shale increases in the state of Pennsylvania over the coming years," said Rich Weber, Co-Chair of the MSC and President of Atlas Energy Resources. "As more natural gas drilling activity occurs, we want www.PaMarcellus.com to serve as a fact-focused information source for individuals and communities across the Commonwealth."

Formed in 2008, the Marcellus Shale Committee represents the oil and gas industry in Pennsylvania on matters pertaining to the acquisition, exploration, drilling, and development of the Marcellus Shale natural gas resource and provides a unified voice before all state, county, and local government or regulatory bodies. The committee, sponsored jointly by the Pennsylvania Oil and Gas Association and the Independent Oil and Gas Association of Pennsylvania, includes small independent producers with historical expertise in the Pennsylvania oil and gas fields and larger national companies dedicated to bringing their industry experience and resources to achieve common goals.

Fayetteville Shale Provides Bright Economic Spot for Arkansas

Arkansas' natural gas reserves helped keep the state economy afloat in 2008 while huge job losses and budget deficits were recorded elsewhere in the country and the federal government shelled out billions of dollars to prop up banks and car manufacturers.

Houston-based Southwestern Energy Co. began exploration in the underground Fayetteville Shale in north-central Arkansas in 2002 and determined the company could retrieve the gas and make a go of it commercially. Since then, drilling companies, service businesses, state and local government officials, and landowners in the Fayetteville Shale have been seeing dollar signs.

The passage in April of an historic severance tax hike on natural gas fueled and furthered optimism that millions more dollars would roll into Arkansas from its newly developing resource.

The following month, Chesapeake Energy Corp., the largest leaseholder in the Fayetteville Shale play, announced it would more than double its number of rigs from 12 to 25 and would drill about 300 wells a year in the state. Chief Executive Aubrey McClendon predicted Chesapeake would spend more than $1 billion in the state each year over the coming years.

Despite a national financial crisis, Arkansas' economy remained relatively stable partly, because of the state's underground formation. Natural gas development became one of the top stories in Arkansas in 2008, as selected by Associated Press members.

In its beginning years, Fayetteville Shale activity bubbled over with property and mineral rights deals between gas companies and land owners. The activity then moved into the drilling phase and construction of infrastructure - work that gobbled up 2008, which also saw the beginning of a major distribution pipeline.

"The majority of infrastructure is now in place," Lawrence Bengal, director of the Arkansas Oil and Gas Commission, said at year's end. "And the drilling is continuing on and will continue, certainly as long as prices hold up."

In May, Boardwalk Pipeline Partners LP began work on a 167-mile Fayetteville Lateral to pass through eight counties and move gas to the country's Northeast, Southeast and Upper Midwest regions. Boardwalk's Arkansas pipeline is part of a $4.7 billion expansion project involving six states.

In October, Fayetteville Express Pipeline LLC - a joint venture between Kinder Morgan Energy Partners LP and Energy Transfer Partners LP - announced plans for another distribution line. The partners hope to have the $1.3 billion, 187-mile pipeline in service by late 2010.

All the activity meant more work for Oil and Gas Commission inspectors. And even with four employees added to the agency, the commission said it needed another seven staffers and would seek legislative approval in 2009 for the positions.

Likewise, inspectors at the Arkansas Department of Environmental Quality were stretched thin as drilling increased and complaints rose over the use and disposal of water needed to fracture the shale to release the gas. At least two "land farm" operations, permitted to use wastewater from the shale activity on farm land, were ordered shut down in December when inspections found water quality violations.

Eight of 17 ADEQ inspectors already work the Fayetteville Shale, but department Director Teresa Marks said the agency will increase inspections and will need more people to do the work.

On another front, environmental groups expressed concern when the Arkansas Game and Fish Commission announced an agreement last summer to lease wildlife management land to Chesapeake Energy for $30 million.

The agreement allows the Oklahoma City-based company to drill on more than 11,500 acres in the Petit Jean River WMA in Yell County and the Gulf Mountain WMA in Van Buren County. The commission also holds a 20-percent royalty on any natural gas pumped from the public lands.

But at least one endangered species lives in creeks on the leased property, and commission Chairman Freddie Black said the panel does not take its responsibility toward wildlife management lightly.

"Dealing with a company like Chesapeake, we feel the impact will be minimal, but there will be an impact," Black said.

In December, more than four years after it sank its first commercial well in the Fayetteville Shale, Southwestern Energy announced it would invest an additional $25 million for a regional office in Conway. The company said it would continue to run about 20 rigs, while increasing production by 48 percent in 2009.

Also, new discoveries in the Haynesville Shale in Louisiana suggested there may be more gas beneath the Ouachita Mountains in Arkansas, keeping the industry busy.

SEC Changes the Rules on Oil Reserves

The Securities and Exchange Commission on December 29 announced that it has approved new rules to "modernize its oil and gas company reporting requirements."

The SEC did not publish the new rules yet, but a 172-page draft was published in June that described the proposed changes. Here are some of the more general changes:

Allows using new technology (3-D/4-D seismic) to calculate proved reserves, if the new technologies "have been demonstrated empirically" to accurately estimate reserve volumes.
Allows companies to disclose probable and possible reserves to investors. Currently, only proved reserves are required to be disclosed.
Allows companies to include resources such as oil sands as oil and gas reserves. Previously, these were counted as mining reserves.
Requires valuation of the oil and gas reserves using an average price for the previous 12-months. Currently, reserves are valued at the market price on the last day of the reporting period.

The SEC indicated in its press release that the use of new technology to determine reserves has been adopted, as has the reporting of probable and possible reserves. Average pricing will replace end-of-year spot pricing to determine reserves valuation. The announcement does not indicate whether or not oil sands will be classified as oil and gas reserves, but it's hard to believe that the SEC didn't approve that change. The changes take effect on January 1, 2010.

Does any of this matter to investors? It should, and it does. The biggest impact will come from valuing reserves at an annual average rather than a spot price. Oil is likely to close 2008 at around $35/barrel. The 12-month average is certain to be much higher than that. This change alone could add billions to an oil company's balance sheet.

Allowing companies to use new technology to determine proved reserves also benefits producers. Proved reserves are those which have a 90% chance of being produced economically. The key word here is "economically." At a price of $35/b for crude, it becomes uneconomic to produce many proved reserves. New 3-D/4-D technology is far cheaper than drilling to determine the extent of new reserves.

Producers will be able to report probable (50% chance of economic recovery) and possible (10% chance of economic recovery) reserves. This could be a good thing or a bad thing. Investors will need to pay close attention to movement among the reserves classes.

The addition of non-traditional reserves, such as oil sands, also needs to be watched closely. If the reserves are reported by type, then the new rule will add substantially to transparency. If, however, oil sands and shales can be lumped together with more traditional reserves, the new information is much less useful because the recovery techniques can be so different in both kind and cost.

Through its new rules, the SEC is moving toward a "principles-based" approach to accounting for reserves rather than a "rules-based" approach. This move parallels the current plan for the U.S. to adopt the principles-based financial accounting practices currently followed in the European Union. Principles can be tricky though, and one man's principles could turn out to be another man's problem.

Superior MN at Center of Canada’s Oil Production Plans

Just south of Lake Superior are fields pocked with gymnasium-sized tanks of oil piped 1,000 miles from tar sands in Alberta — one of the largest proven “unconventional” oil reserves in the world. Very quietly, the little town of Superior, MN has emerged as a mainline for the nation’s energy infrastructure. About 9 percent of the country’s imported oil, roughly 1.2 million barrels a day, already flows into this city of 27,000 at the headwaters of the world’s largest freshwater system.

And that figure is about to balloon with the opening of a $3 billion “Alberta Clipper” pipeline that could ultimately deliver some 800,000 barrels a day of the tar sands oil, called bitumen, to an existing tank farm just outside downtown Superior, before it is shipped to refineries around the region.

The black stew won’t arrive from Canada refinery-ready. That means billions of dollars must be pumped into retrofitting the regional refineries so they are able to strip away impurities.

Oil prices have plummeted in recent months, and some refinery upgrade plans have been put on hold, but the pressure to add refining capacity in the region won’t disappear.

This year alone, the Canadian Association of Petroleum Producers predicts $20 billion will be spent in Alberta developing the tar sands, which cover an area the size of Florida. The industry group also projects the volume of Canadian oil processed in Wisconsin, Illinois, Indiana, Minnesota, Ohio and North Dakota will nearly double between 2007 and 2015.

It’s going to mean a lot more locally refined fuel in a region that must now import it from places such as the Gulf Coast.

It’s going to mean an alternative to American reliance on unfriendly parts of the world for its energy lifeblood. It’s going to mean an economic boost tied to refinery expansions. And it could mean more pollution for the Great Lakes, the source of water for 40 million people.

To gauge the potential of this budding relationship between the Great Lakes and Canada’s tar sands, look at what’s planned for the tiny Murphy Oil refinery in Superior, which hopes to turn its sip from the pipelines into a gulp.

Murphy, which has a checkered environmental record in Wisconsin, wants to boost its refining capacity in Superior nearly sevenfold — from 35,000 barrels daily to 235,000. That’s almost 10 million gallons a day.

Billed as a refinery expansion, it would essentially be a tear-down and rebuild of a nearly 60-year-old facility, and it is an economic undertaking the likes of which northern Wisconsin has never seen.

“Let me try to put it into some perspective,” said Jeff Vito, Superior’s economic development director. “They’re talking about a $6 to $7 billion investment. The total value of the city of Superior (today) is about $1.5 billion.”

The proposed Murphy expansion, will “likely be the largest project in the history of the state of Wisconsin,” according to the Department of Natural Resources.

“For the region, this would be the equivalent of getting the Olympics and having them five years in a row,” said state Sen. Bob Jauch, D-Poplar, an unabashed proponent of the expansion. “They’re talking about 5,000 jobs in the construction phase.”

Those construction jobs would eventually evaporate. But Murphy said a new refinery would create 300 to 400 permanent full-time positions in addition to the company’s 150 current employees.

“Our economy would be transformed and the future of the region, which has long been bleak, will be substantially enhanced,” Jauch said.

But the DNR reports the expansion could consume 300 to 400 acres of wetlands just south of the Lake Superior shore. Conservationists say that would make it the most destructive wetlands project in Wisconsin since the 1972 passage of the Clean Water Act.

Conservationists also worry about the effect a refinery that size could have on Lake Superior, the largest and most pristine of the five Great Lakes. They fret the expansion could harm the lake’s ecology and squelch the area’s recreation and tourism industry.

Refineries are reviled by many who depend on them; they are so controversial that a major one has not opened in the U.S. since the 1970s. They’re resented for the pollution their smokestacks spit into the sky and the thousand of pounds of gunk their discharge pipes dump daily into area waters. They’re resented for the sulfur smell they emit and the flames that leap from their stacks.

It’s a dirty — though necessary — business that many simply don’t want in their backyards.

“Once you become a refinery town on that scale, you’ll never be anything other than a refinery town,” said Douglas County Supervisor Bob Browne, a retired welder who has done contract work at both the Murphy refinery and the Alberta tar sands.

The Murphy expansion is just a plan at the moment. The company reports it has spent about $7.5 million gobbling up neighboring properties, and preliminary engineering studies have begun, but no earth will be turned until the company finds a financial partner. Given the turmoil in the financial markets, that isn’t likely to happen soon.

“Even though we’ve done a bunch of work, we’re still five years away — if we started today,” said Jim Kowitz, acting manager at the Superior refinery.

But the oil is coming to the Great Lakes one way or another, and so are other refinery expansions.

British fuel giant BP is in the midst of a $3.8 billion retrofit of its Indiana refinery on Lake Michigan just south of Chicago. Marathon Oil has a $1.9 billion project under construction in Detroit (though it announced in October that the drop in oil prices was forcing it to rethink its opening date, slated for 2010).

BP has another tar sands retrofit planned for its refinery in Toledo, Ohio. Shell Oil had designs for a tar sands upgrade at its refinery along the St. Clair River in Sarnia, Ontario — those ambitions also are now on hold.

There are refineries outside the region that will be processing tar sands oil, but the Great Lakes are the logical place for much of this fresh crude to pool.

Pipelines from Alberta are in place or under construction, and there is ample room to expand their capacity. The Superior-bound Alberta Clipper is already under construction by Enbridge in Canada and is going through the permitting process in the U.S. Its owners plan to have it online by 2010.

The region is also home to a fleet of existing refineries that can be expanded — a huge plus because building a new refinery from scratch is a dicey prospect because of all the pollution permits required.

It’s also a ready-made fuel market with 40 million residents. And there is, of course, more than enough water in the Great Lakes to supply the thirsty refineries.

Production of Canadian bitumen is expected to triple to 3.5 million barrels per day by 2020. Alberta doesn’t have the capacity to refine it all, so the plan now is to mix it with a more liquid petroleum product, called diluent, so it can be piped south for processing.

This has the Great Lakes poised to emerge as the Gulf Coast for the Canadian tar sands, which hold a reserve of 173 billion proven barrels of oil — more than any place outside Saudi Arabia, according to the Province of Alberta.

“This is going to be a giant (entry) point for bitumen, regardless of what we do,” Kowitz said of Murphy Oil’s expansion plans.

Oil industry experts say modern pollution controls can ensure refineries tap the lakes without harming them.

Not everyone is convinced the emerging nexus of Great Lakes water and Canadian tar oil will be benign.

“The ongoing, hasty growth in oil sands production has already created an urgent need to develop infrastructure downstream to handle the dirty bitumen ... pipelines stretching thousands of kilometers across North America and massive, multi-billion dollar expansion of refineries in the Great Lakes region,” states an October report released by the University of Toronto’s Munk Centre for International Studies.

“We are already well into the development of a continent-wide industrial supply chain — a pollution delivery system — that could cause irreversible damage to the Great Lakes.”

Oil-Shale Waste 'Non Hazardous,' EPA Says

The Environmental Protection Agency issued an 11th-hour clarification on spent oil shale, declaring the byproduct of the development process not to be a hazardous waste.

The ruling could limit production costs if U.S. developers move ahead with oil shale development, but the next administration under President-elect Barack Obama is expected to put the brakes on commercial development.

Specifically, the EPA published data showing the characteristics of spent shale from operations indicate the waste is unlikely to be a hazardous waste.

The 11th-hour notice is one of a multitude of "midnight" rules made in the waning days of President George W. Bush's tenure, as department chiefs implement controversial regulations designed to imprint the current White House's policy mark well into Mr. Obama's administration.

In November, the Department of the Interior opened the western U.S. to commercial oil shale development after the expiration of a congressional ban that had so far only allowed demonstration projects such as the one operated by Royal Dutch Shell.

But in December Mr. Obama named Colorado Democrat Sen. Ken Salazar, an opponent of commercial oil shale development, to Interior Secretary. Analysts say the appointment portends a halt in oil shale lease sales.

While environmental concerns mainly focus on the carbon-dioxide emissions created from burning oil shale fuel and the quantities of water necessary for commercial development, the primary obstacle to development has so far been cost. It's currently uneconomical to develop, especially as oil prices have fallen into the $40 a barrel range.

Unbridled Energy to Discontinue Pennsylvania Oil Sand and Oil Shale JVs

Unbridled Energy Corp said it will not proceed with two previously announced joint ventures in Pennsylvania as part of a revised strategic plan for 2009 amid "dramatic" changes in the oil and gas industry.

The joint ventures include the farm-in on a tight sand oil play in southern Pennsylvania and the 8,000 acre Marcellus shale joint venture, the company said in a statement.

The company said it had finished production testing in its three horizontal wells in Ohio, but due to low gas prices and well productivity results, it will not proceed with the development of this play.

The explorer of oil and gas properties said it intends to farm out or sell the acreage.

"Unbridled will now focus its capital expenditures in the first quarter and second quarter of 2009 on cash flow and reserve building operations within its New York and Alberta properties," the company said.

BLM Publishes Rules Regulations Set for Oil Shale

The Bureau of Land Management published final regulations in November that will allow establishment of a commercial oil shale program.

The program could result in 800 billion barrels of recoverable oil from lands in the Western U.S.

The new regulations provide rules on which private investors will rely in determining whether to make future financial commitments to prospective oil shale projects, in keeping with the Energy Policy Act of 2005 and the Mineral Leasing Act of 1920, agency officials said in a press release.

"The U.S. needs all types of energy resources, both conventional and renewable, to meet our future needs," said C. Stephen Allred, assistant secretary of land and minerals management for the U.S. Department of Interior.

"Production from domestic resources makes us more secure and less vulnerable to future energy crises and increases our economic well-being," Allred said. "The tremendous oil shale resources we have in the United States contain several times the oil reserves of Saudi Arabia and can be a vital component of that secure future."

The regulations provide for a phased approach to oil shale development on public lands in the West. Commercial development of oil shale will not begin until it is technologically viable, which is not expected for several years. The regulations will provide a basis for decisions, as "rules of the road" for the large investment that will be necessary for industry to develop technologies to extract the resource in an environmentally sound manner. Those investments could exceed $1 billion.

Before any oil shale leases are issued, additional site-specific National Environmental Policy Act (NEPA) analysis would be completed on the proposed development.

Once a lease is issued, the lessee will also have to obtain all required permits from state and local authorities, under their respective permitting processes, before any operations can begin. Another round of NEPA analysis would be conducted before any site-specific plans of development are approved.

Trans Energy Completes Marcellus Shale Gas Well

Oil and natural gas producer Trans Energy says it's completed its third Marcellus Shale well.

The St. Marys-based company said that the Wetzel County well was completed December 16 and connected to a pipeline four days later.

Chief Executive James Abcouwer says the well's performance indicates that positive results from two earlier wells can be replicated throughout the company's West Virginia holdings.

The 6,000-foot-thick Marcellus Shale is believed to hold 50 trillion cubic feet of recoverable natural gas from upstate New York, across Pennsylvania into eastern Ohio and most of West Virginia.

Trans Energy has 271 oil and gas wells and approximately 26,000 acres under lease in Wetzel, Marion, Marshall and Doddridge counties, and holds interests in oil and gas leases in Kansas.

CANADA

StatoilHydro Scraps Oil Sands Upgrader Project

Norwegian oil and gas group StatoilHydro said on December 4 it would withdraw its application for the construction of an "upgrader" for its Canadian oil sands project.

A full-scale refinery or upgrader has been planned in Alberta after StatoilHydro last year bought 257,000 acreas of oil sands leases for $2 billion in a bid to diversify away from ageing North Sea oilfields.

"Prohibitive construction costs, the state of the global economy, uncertain oil price outlook and lack of legislative clarity are the main reasons for this decision," StatoilHydro said in a statement.

But StatoilHydro said it would monitor the cost and price situation and "reassess downstream options going forward."

StatoilHydro said it did not impact the progress of its upstream oil sands activities and its long-term view of the Canadian oil sands development remained unchanged.

"This decision does not impact the upstream part of the company's oil sands venture," it said.

In May 2008, StatoilHydro decided to postpone the planned upgrader by two years to 2016. The upgrader was intended to process the bitumen from oil sands into a synthetic crude oil.

Connacher Cuts Oil Sands Output as Prices Decline

Connacher Oil and Gas Ltd said it will cut bitumen production at its Alberta oil sands project as prices sink below costs, the first Canadian producer to take such action in the wake of falling oil prices.

Connacher said it will restrict output from its Great Divide project to 5,000 barrels a day for an undetermined period, down from recent rates of about 9,000 barrels a day.

"It recently became evident we could not secure adequate pricing for our bitumen sufficient to cover operating costs and royalties," Richard Gusella, Connacher's chief executive, said on a conference call. "Frankly, it does not make sense for us to produce away our reserves ... at a loss."

The company is the first Canadian producer to announce it would slash output because of low oil prices but others may follow if the discount, or differential, to light crude for the tar-like bitumen produced in Alberta's oil sands region doesn't narrow, an analyst said.

"Should oil price continue to trade in the $40 to $50 range and differentials remain wide then we will start to see more companies make a hard decision," said Menno Hulshof, an analyst at Dundee Securities. "I think it's inevitable."

Bitumen's discount to lighter crudes typically gets deeper in the winter when the paving season ends, since much of the heavy oil is used to produce asphalt. But the seasonal drop has been exacerbated as demand for oil wanes because of the North American recession.

"The differential certainly has widened out with the pull back in crude," said Martin King, an analyst with FirstEnergy Capital. "Some of the bitumen prices are certainly under $20 a barrel right now ... They've been pulled into the downdraft in the broader market for crude."

Crude prices were rising on hopes that OPEC would make its biggest ever supply cuts when it was scheduled to meet on December 17.

Some of the cartel's members are calling for cuts of up to 2 million barrels a day to boost oil prices that have slumped by nearly $100 a barrel since July.

Indeed, Connacher said in a statement it was looking to supply cuts to restore prices.

"We anticipate (higher prices) will emerge from the probability of an excess of supply destruction, with production cutbacks arising from very low crude oil prices," the company said.

Great Divide is a steam-assisted gravity drainage project, in which the company pumps steam into the ground to loosen the bitumen, allowing it to be pumped to the surface in wells.

Connacher also said it will temporarily suspend construction at its C$345 million ($278 million) Algar project.

The company has already spent C$110 million on its second steam-driven project and said suspending construction for six-months would add C$18 million in costs. It said the halt would last "until there is more clarity and certainty to the economics of the project."

Connacher said it has about C$500 million in cash and available credit lines and continues to produce conventional oil and operate a Montana refinery.

Total Needs Crude at $85 to $90 a Barrel for Canadian Oilsands

Total SA, Europe’s third-largest oil company, said crude oil prices need to be about twice current levels for investment in Canadian oilsands projects to be profitable.

“We estimate a price of about $85 to $90 a barrel is necessary to launch the project,” Jean-Jacques Mosconi, head of strategy at Total, said at a Paris conference in December. “We aren’t there yet.”

Mosconi said Total won’t take a final decision on pushing ahead with its own project until 2010. “We will see between now and then whether prices go up,” he said.

Total plans to expand its heavy oil operations in the Athabasca oil sands in northeastern Alberta by spending $10 billion to $15 billion over 10 years to develop projects. The company operates the Joslyn project, which began production in 2006, and in December started commercial output from the Surmont venture with its partner ConocoPhillips.

EVTN Enters Canadian Oil Sands Market with Voraxial Separator Sale

Enviro Voraxial Technology, Inc. (EVTN ) announced in December that the Company received a purchase order for its Voraxial(R) 2000 Separator from a wastewater service company based in Alberta, Canada. The Voraxial will be integrated into the existing wastewater processing system to enhance the capability of treating various wastewater streams produced in Canada's booming oil sands industry. The ultra-efficient Voraxial 2000 Separator is capable of separating oil/water, sand/water and oil/water/solids mixture streams.

The potential economic impact of EVTN's advanced Voraxial technology in improving the efficiency of the many separation processes involved in the production and processing of oil sands is significant. The separation process is critical to the oil sand industry as their high cost of production is in the range of $25 per barrel. The Canadian Oil Sand reserves are estimated to be 174 to 315 billion barrels, earning Canada the title of the "Saudi Arabia of Oil Sands" with the potential of exceeding Saudi Arabia's recoverable reserves. Their current, fast rising production exceeds 1 million barrels per day. By 2006, over $27 billion had been invested in the development of the Canadian oil sands production. (US Congressional Study, June 2006).

Since the superior separation capabilities of EVTN's Voraxial technology can reduce processing cost for the oil companies, its market potential would be very significant. The Voraxial's ability to perform simultaneous bulk oil, water and sand separation increases the efficiency of secondary equipment which reduces the overall cost of separation for the customer. Recent design breakthroughs incorporated in the latest Voraxial systems have increased its original market leading performance by over 300%.

Oil sands production consumes large volumes of water making water supply and waste water disposal a serious concern for the industry. For oil sands mining operations, it is estimated that between 2-4 barrels of water are used for each barrel of bitumen produced, equating to about 100 million gallons of water use per day. "The primary challenge for process water is that no large-scale water treatment facilities exist near the oil sands." ("Canada's Oil Sands Resources," Author, Soderbergh) The benefit of the Voraxial Separator is in its ability to process a large volume of liquids with a small footprint and without any pressure loss allowing companies to treat their wastewater more efficiently and economically.

"This wastewater service company provides extraordinary benefits to the oil sands industry and is rated in the top 50 of Canada's 100 fastest growing companies. We are extremely excited about working with a customer of this caliber. We believe that we can potentially sell hundreds of units into this market," said Alberto DiBella, President of EVTN.

Project Woes Cut Canada Oil Sands Output Forecasts

The Canadian Association of Petroleum Producers has cut its forecast for the country's oil sands output for the second time this year after falling prices led to a spate of project deferrals and cancellations.

The association, which represents most of Canada's big oil producers, said it expects the oil sands to produce 2.4 million barrels per day in 2015, down from the 2.8 million bpd it had forecast in June -- a figure that was itself cut from a 2007 outlook calling for 3 million barrels of daily production.

Canada's oil sands contain the biggest crude reserves outside the Middle East but they are technically difficult and expensive to extract.

With oil prices down more than $100 a barrel since July, nearly every major project in the region has been delayed, deferred or canceled outright as potential returns no longer justify the multibillion-dollar investments needed to tap the resource.

CAPP has also lowered its forecast for 2008 production from the oil sands because of project delays. It expects output this year to be 1.22 million barrels a day, down from a June estimate of 1.31 million.

Its estimate of 2009 production from the region has been lowered to 1.44 million bpd from 1.53 million bpd.

CAPP said in June that oil sands output should top 3 million bpd by 2017. It now expects to reach that milestone in 2019.

Nexen Spends $612 Million for Majority Control at Long Lake Project

Nexen Inc agreed on December 17 to acquire a majority interest in its Long Lake oil sands project, buying an additional 15 percent stake from embattled joint-venture partner Opti Canada Inc for $612 million (C$735 million).

The agreement boosts Nexen's share of the C$6.1 billion project to 65 percent from 50 percent, gives it operating control of the 60,000 barrel per day upgrader run by Opti and will boost its 2009 oil production targets by 5,000 barrels per day (bpd) to a range of 225,000 to 240,000 bpd after royalties.

The Long Lake project officially opened this year but the upgrader that had been operated by Opti is still starting up and not yet fully operating.

Opti, whose major asset is its Long Lake stake, has seen its shares pummeled in a downturn for oil sands stocks that hit smallest companies the hardest. Its stock, which traded at C$25.40 in June, has fallen 93 percent since then as oil prices tumbled, making it vulnerable to a takeover.

Now Nexen no longer has to worry about having an unwanted partner in the project but the purchase may make Nexen more attractive to any potential buyer.

"Nexen is now in the driver's seat at Long Lake and no one else can muscle their way in," said Martin Molyneaux, an analyst at FirstEnergy Capital. "But it does make them a more attractive target for someone with a bigger balance sheet ... There's not a caveat on Long Lake any more."

Nexen shares jumped earlier this month on rumors it was about to be acquired. Talk that French oil major Total SA was interested in buying the company has since eased, however.

Nexen said it does not expect the hand-over of the upgrader, which converts the oil sands bitumen into refinery-ready crude, to be troublesome.

It also expects that having control of both the upgrader and thermal production, where steam is pumped into the ground to liquefy the bitumen so it can flow to the surface, to cut costs.

Nexen said it can easily afford to pay for the acquisition, since it has C$4 billion in cash on hand and undrawn credit lines, and expects to generate substantial free cash flow.

Opti said the cash from the sale will let it meet financial covenants on its debt it would otherwise violate.

It will use the cash to repay and cancel a C$150 million revolving credit facility and put C$150 million for a partial repayment of a C$500 million credit facility, with the remainder for capital spending and general corporate purpose.

Billions of Liters of Tainted Oilsands Water Leaking According to Report

Oilsands production is releasing four billion liters of contaminated water into Alberta's groundwater and natural ecosystems every year, according to a new national report that was immediately dismissed as "false" by the provincial government.

The annual volume of water pollution in 2007 would have been enough to fill Toronto's Rogers Centre, but could be stopped if the federal government started enforcing its Fisheries Act, the report says.

"Virtually everyone close to the tarsands industry knows that all tarsands tailings ponds leak - even the new ones - and that while steps are taken to recapture the leakage, a significant portion of contaminated water still escapes into the environment," said the study, 11 Million Litres a Day: the Tar Sands' Leaking Legacy, released by Environmental Defence.

The report is the first comprehensive examination of water pollution from the mines in the Alberta industry and was prepared using the figures from environmental assessment applications submitted by oilsands companies.

The oilsands production process consists of using hot water to separate the oil from sand, resulting in tailings ponds that would remain contaminated for decades. The report calculated that the total volume of water pollution could increase by five times over the next 10 years depending on when new oilsands projects start production.

"Tarsands tailings water is widely acknowledged to be harmful to human health and the environment," the report said. "Experiments with this water on fish have shown serious reproductive impacts. Studies on birds have found increased mortality rates, and experiments on plants have shown delayed germination and lower seedling weights."

Matt Price, who wrote the Environmental Defence report, said that the federal government should intervene since the contamination is crossing jurisdictional boundaries from Alberta into Saskatchewan and the Northwest Territories.

"We think they (federal regulators) are turning a blind eye to tailings ponds," said Price, the energy and climate project manager at the environmental research group. "We just think that ever since Ralph Klein (was premier), they've sort of been chased out of Alberta and fearful of enforcing the laws."

A spokesperson for Environment Minister Jim Prentice referred questions to Environment Canada, which said it needed more time to examine the report before commenting.

However, a scientist from Alberta's Environment Department said the report is misleading people by suggesting that the waste from tailings ponds are contaminating natural ecosystems. The provincial government says that most of the waste is going into deep aquifers that are already naturally contaminated by the geology of the oilsands.

"They make some statements that are patently false," said Preston McEachern, who is section head for science research and innovation in the oilsands environmental management division of Alberta Environment. "The problem with the report, at least the way I see it is structured, is it basically gives the impression that these seepages (from tailings ponds) are turning into surface run-off and going directly into the Athabasca River. That's just not the case."

McEachern, whose division was created less than two years ago, said the Alberta government is spending millions of dollars for research on the environmental impact of the tailings ponds, but he said it was confident that it can prevent any serious contamination of groundwater or ecosystems.

"We know enough in terms of dealing with mitigation for aquifers that would be at risk," said McEachern. "Occasionally problems do occur . . . but we're finding now that are systems are set up well enough that we detect them right away before they will ever become a risk to the environment."

He said another important aspect of research is looking into eliminating waste from tailings ponds altogether.

"That's the holy grail of all of this," said McEachern.

Study Says Canada’s Mining of Tar Sands Endangers Migratory Birds

About half of America's migratory birds fly from destinations as far away as Chile to nest in Canada's boreal forest. In Alberta, that forest lies above tar sands that contain oil reserves second only to Saudi Arabia's.

But tar sands yield vast oil reserves and give the region a big economic boost. The excavation of the tar sands — projected to pump $2.4 trillion into Canada's economy between 2010 and 2030 — could reduce the region's migratory-bird population by almost half, according to a peer-reviewed study released December 2 by U.S. and Canadian environmental groups.

The Connecticut warbler and the blackpoll warbler are among about 300 species affected by tar sands mining. The study estimates that over 30 to 50 years, tar sands excavation will reduce bird populations by anywhere from 6 million to 166 million, including several endangered and threatened species. The world's only natural breeding ground for endangered whooping cranes, for example, lies north of the Albertan tar sands, and the Athabasca River, which feeds the cranes' wetland habitat, flows north through the sands.

The report calls for a moratorium on new tar sands development pending further study of environmental impacts or, failing that, measures that include noise reduction and habitat restoration.

The mining of bitumen, a form of crude oil, from the gooey oil sands destroys habitat, drying up and contaminating wetlands where birds nest or rest during migration. Birds also land on tailing ponds, the large reservoirs where toxic runoff is stored, and often sink after becoming covered in oily residue.

"They see what looks like this great lake to spend the night on, and it turns out to be a death trap," said Doug Stotz, senior conservation ecologist at the Field Museum in Chicago, where the study was released.

David Collyer, president of the Canadian Association of Petroleum Producers, said tar sands projects already undergo an environmental assessment process that includes effects on birds.

"There clearly is some environmental impact with any oil sands activity," he said. "But that has to be balanced with the economic impact of these projects. The report is clearly an advocacy piece by the environmental groups. I think it misrepresents and exaggerates the environmental impacts."

Henry Henderson, Midwest director for the Natural Resources Defense Council, one of the environmental groups involved in the study, said U.S. and Canadian endangered species laws and a migratory-birds treaty should be given more consideration when Canadian government bodies evaluate tar sands development, and when U.S. state and federal agencies judge applications for refineries and pipelines to process and transport the oil.

Henderson said the laws and the treaty "aren't enforced at all," partly because quantifying the wide-ranging effects of tar sands development is difficult without more data on bird populations.

Five Midwestern refineries are seeking permission to modify their plants to process Albertan tar sands oil, and Hyperion, a Dallas-based company, is proposing a new tar sands oil refinery in South Dakota.

Shell May Revisit Oil-Sand Projects as Procurement Costs Drop

Royal Dutch Shell Plc said construction and engineering costs may fall in Canada, allowing Europe’s largest oil producer to revisit plans to expand oil-sand projects.

“We expect that procurement costs will come down quite a lot,” Chief Executive Officer Jeroen van der Veer said in an interview at an energy conference in London. “If the overheating goes out of the market, the break-even price that you can build an oil-sands project will come down again.”

Shell last month delayed seeking regulatory approval for its Carmon Creek oil-sands development in Canada. That followed October’s indefinite postponement of the second-phase expansion of The Hague-based company’s Athabasca project because of rising construction costs.

Shell will go ahead with projects that could be profitable under various scenarios for oil prices, van der Veer said. “More oil sands will come, but you don’t know exactly when.”

Shell planned to drill wells and inject steam into the tar- like sands at Carmon Creek to increase production from the deposit in northern Alberta.

Shell operates the 155,000 barrel-a-day Scotford upgrader in Alberta, which converts bitumen extracted from oil sands into refinery-ready crude. The upgrader forms part of the Athabasca project, together with the nearby Muskeg River Mine, which supplies the bitumen.

Emissions still an Overall Issue for Oil Sands

Canada's oil industry had a sharp reversal of fortunes in the second half of 2008. But even as oil sands producers struggle to cope with low crude prices, they will have to continue to plan how to adjust to a carbon-constrained world.

Conventional wisdom suggests that, as the economy tanks, corporations face less pressure to improve their environmental performance because governments are reluctant to impose additional costs on struggling employers. And certainly, Prime Minister Stephen Harper's government – never an enthusiastic warrior in the climate change battle – is concerned about proceeding with new emissions regulations in the midst of a deep recession.

Still, pressures are building that should ensure that a reprieve – if indeed there is one – will be temporary, and major emitters from oil companies to electricity producers will have to make significant investments on new technology to improve energy efficiency and reduce emissions.

U.S. President-elect Barack Obama has indicated that he will move aggressively to combat climate change, while the world is looking to fashion a new agreement on emissions-reduction targets at a meeting in Copenhagen next November. The Harper government has said it wants to develop a North American approach to climate change, including a cap-and-trade system that will place real limits on emissions.

Ottawa has already released the broad outline of its regulatory plan, which would reduce emissions by 20 per cent by 2020 from 2006 levels. The Conservative government will impose intensity-based limits, forcing companies to reduce their emissions for every barrel of oil produced. It has said oil sands producers will have to dramatically reduce their emissions-per-barrel, though environmentalists fear there are major loopholes that give credit for research into unproven technologies.

But the government is regulating a much different industry than the one that existed six months ago. After riding high for five years, Canada's oil sands producers saw their fortunes take a violent turn in the second half of 2008, as profit margins shrank dramatically, and expansion and upgrading plans were put on hold.

After posting profits through the first three quarters of the year, the companies' fourth quarter revenues will reflect slumping crude prices. Many analysts now forecast oil prices will bottom out around $25 (U.S.) a barrel early in 2009 before rebounding with a recovering economy.

Project delays would give the companies some breathing room to figure out their future carbon liability, and how they will manage it. Based on forecasts of a tripling of production by 2020, the booming oil sands sector was expected to be largest source of emissions growth in Canada for the next 15 years.

However, the oil sands projects are among the highest cost sources of crude in the world, and a prolonged slump in global oil markets would clearly reduce future oil sands production, at least in the medium term. With cutbacks to planned oil sands projects, the emissions profile could change dramatically.

Ottawa was supposed to release its new emissions regulations this year, that will take effect in 2010 and impose added costs on new energy projects, whether coal-fired power plants, oil sands upgraders or oil sands extraction projects. Those regulations were delayed by the fall election and cabinet shuffle, and now aren't expected to be released until the middle of next year at the earliest.

In an interview, Environment Minister Jim Prentice said that, prior to finalizing those rules, he wants to work with the provinces – notably Alberta – on harmonization, to consult further with affected industries, and to get a better sense of how Canada can co-operate with the incoming administration of Mr. Obama.

But with the oil industry slashing capital budgets and once-booming Alberta teetering towards recession, the fragile economy is top of mind.

“In the short term, we can't afford to produce an uncompetitive burden on Canadian jobs,” Mr. Prentice said in an interview.

That reticence does not mean the industry is off the hook, or that the climate change pressures will diminish, he added.

“The transition to a lower-carbon economy is one of the central imperatives of our time,” the minister said, adding that Canada should play a leadership role in the commercialization of the new technologies that will be required to confront the challenge.

Barack Obama’s election has added tremendous impetus to the environmental agenda, notably on global warming. In the last few weeks, the president-elect has stacked his cabinet – including the energy secretary post, and a newly created role of special assistant on energy and climate change – with global warming experts who have advocated aggressive caps on emissions and major investments in conservation and clean energy.

It remains to be seen, of course, how aggressively Mr. Obama and the Democratic Congress will regulate once they take power and confront the inevitable tradeoff between costly emissions regulations and concerns about competitiveness amid weakened industries.

A central plank in Mr. Obama's presidential campaign – and in his rhetoric since winning the election – has been the need for massive investment in clean technology and renewable fuels to reduce greenhouse gas emissions and cut the U.S. dependence on foreign oil.

At the same time, Obama and Democratic leaders in Congress have promised to establish a national cap-and-trade system that will put real limits on greenhouse gas emissions. It is that cap-and-trade system that Canada is eager to be part of, even as American environmental groups target the oil sands as climate-change enemy No. 1.

Urged on by U.S. environmental groups, the Democrats are considering “low carbon fuel standards” – highlighting fuels with a lower carbon footprint – that could disadvantage oil sands producers if they don't reduce emissions.

Canadian companies are looking to reduce their carbon footprint through carbon-capture-and-storage technology, which diverts emissions from smokestacks and buries it permanently underground. But it remains a hugely expensive and unproven undertaking. In its pre-budget submission, the Canadian Association of Petroleum Producers, the industry lobby group, urged Ottawa to provide tax breaks to encourage companies to invest in carbon capture and storage, while the Alberta government wants Ottawa to match its $2-billion (Canadian) spending on the technology.

Mr. Prentice acknowledged that Canada needs to deploy carbon-capture-and-storage technology to meet Ottawa's emission targets. While it will get plenty of help from provincial and federal governments, the oil industry will have to make future investment decisions in the knowledge that the climate-change pressures are unlikely to fade, even in hard times. And that any oil sands expansion will require credible carbon-management plans.

Canadian Oil Sands Plans $440 Million in Capital Spending for 2009

Canadian Oil Sands Trust said it plans $440 million in capital expenditures in 2009 and daily average production of 115,800 barrels of synthetic oil per day.

The trust said operating costs are expected to be $30.72 per barrel, while cash from operating activities are expected to be $1.70 per unit Canadian Oil Sands holds a 36.74 per cent working interest in the Syncrude joint venture.

The trust based its guidance on an oil price of US$50 a barrel, C$6 per gigajoule natural gas and a Canadian dollar worth 82.5 cents U.S.

The trust has about $500 million in debt maturities in 2009 that it said it plans to refinance through draws on its $840 million of available credit facilities, or by terming out in the debt capital markets.

"The trust is in a strong financial position with low debt, the potential for growing volumes by reaching the design capacity of existing infrastructure and low expansion capital commitments," Canadian Oil Sands president and chief executive Marcel Coutu said.

"Our strong balance sheet is an important asset as we manage our business through this low crude oil price cycle."

In addition to Canadian Oil Sands, the Syncrude joint venture includes Imperial Oil Ltd., Petro-Canada, Nexen Inc., ConcoPhillips, Mocal Energy Ltd. and Murphy Oil Company Ltd.

MIDDLE EAST

JORDAN

Jordan Oil Shale Deal with Shell Initialed

Jordan Times reported that the Natural Resources Authority will soon forward to the Cabinet the commercial deal it initially signed with the Royal Dutch Shell Oil Company to tap the Kingdom's vast amounts of oil shale.

Shell will use its patented In-situ Conversion Process, under which the ground is heated over several years, to extract oil shale in oil form. Mr Maher Hijazin director of Natural Resources Authority said that Petra, the deal would be later referred to the Lower House for endorsement. He said that Shell will survey and develop 22,000 square meters of land, nearly Q1 of the country, in the central and southern regions of the Kingdom.

As per report, the project, which is expected to be completed in 15 to 20 years will be transferred to the government after the end of the concession.

According to the company's website, if endorsed, the project will mark the first large scale application of the firm's In-situ Conversion Process.

According to official figures, some 40 billion tonne of oil shale exist in 21 locations near the Yarmouk River, Buweida, Beit Ras, Rweished, Karak, Madaba and Maan districts.

McIlvaine Company,

Northfield, IL 60093-2743

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

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