Willbros Group, Inc. announced November 4 that it has been awarded the construction contract for spreads three and four of the Fayetteville Express Pipeline (FEP).

The approximately 185-mile natural gas pipeline will originate in Conway County, Arkansas, continue eastward through White County, Arkansas, and terminate at an interconnect with Trunkline Gas Company in Panola County, Mississippi. FEP will parallel existing utility corridors where possible to minimize impact to the environment, communities and landowners. FEP is a joint venture between Energy Transfer Partners, L.P. and Kinder Morgan Energy Partners, L.P. The Willbros scope of work includes 120 miles of 42-inch pipeline, beginning near Bald Knob, Arkansas and ending at the Trunkline interconnection. The project is expected to begin construction in April 2010 and be completed in October 2010.

Randy Harl, President and Chief Executive Officer, remarked, "This is a significant project resulting from the continuing development of the Fayetteville region. The FEP award improves 2010 visibility for our U.S. pipeline construction business, and we remain convinced that current favorable economics, combined with the benefits natural gas provides to the environment, will drive build-out of take-away capacity in areas such as the Fayetteville, Haynesville and Marcellus shales. We anticipate additional U.S. pipeline construction opportunities for Willbros as new infrastructure will be required to transport hydrocarbons to regions with growing demand. We are pleased to have been selected and look forward to performing this project with FEP and its partners."

Willbros Group, Inc. is an independent contractor serving the oil, gas, power, refining and petrochemical industries, providing engineering, construction, turnaround, maintenance, life cycle extension services and facilities development and operations services to industry and government entities worldwide.

EPA Improving Access to Available Data by Posting CAA, RCRA Data on the Web

The U.S. Environmental Protection Agency (EPA) has released new information on EPA and state enforcement of hazardous waste and air regulations. In addition, the EPA posted data that allows the public, for the first time, to compare toxic releases with compliance data from facilities. This is part of EPA's ongoing commitment to increase transparency and promote the public's right to know by improving access to available data, the agency stated.

EPA made available new summary reports and data from 2004 through 2008 on EPA and state enforcement program performance with Clean Air Act (CAA) and the Resource Conservation and Recovery Act (RCRA) requirements. The reports include online graphs, trend information on enforcement and compliance in each state, and comparative reports. Data such as compliance monitoring activity, violations discovered, enforcement actions taken, and penalties assessed are available.

EPA also updated the agency's Enforcement and Compliance Online (ECHO) Website to allow users to view current information on facility compliance with water, air, and hazardous waste requirements in relation to pollutant release data from EPA's Toxics Release Inventory and National Emissions Inventory databases. This reportedly provides the public with more information on the overall environmental footprint of each facility.

In the agency's reviews of both EPA and state enforcement program performance, it identified several concerns with some programs, including uneven enforcement response, failure to identify high priority violators, and inadequate penalty assessment. The recommendations that EPA made on how to address these concerns are now available through the ECHO website.

ECHO allows users to find permit, compliance monitoring, violation, enforcement action, and penalty information over the past three years. ECHO provides communities with important enforcement and compliance information about regulated facilities. Included in the new information released today is a list of commonly asked questions about the CAA and RCRA programs, such as air quality, pollutant releases, state performance, and overall compliance rates.

The EPA stated the compliance data posted November 6 tells only one part of the story and does not relate directly to overall hazardous waste management or air quality, which have improved in the United States over the past 30 years as the result of local, state, and federal implementation of environmental programs.

More information on RCRA data: http://www.epa.gov/compliance/data/results/performance/rcra/index.html

More information on CAA data: http://www.epa.gov/compliance/data/results/performance/caa/index.html

More information on ECHO: http://www.epa-echo.gov/echo/

Senate Panel Okays Climate Change Bill in spite of Republican Boycott

The U.S. Senate Environment and Public Works Committee approved a climate bill November 5 even as Republican committee members boycotted the meeting.

Democrats voted 11-1 to pass the bill, with Sen. Max Baucus of Montana the lone "no" vote, The Hill reported.

Republicans had been boycotting the committee meetings to protest the measure's markup, saying they wanted the Environmental Protection Agency to perform a second cost analysis of the bill.

The Senate bill, co-sponsored by Sens. John Kerry, D-Mass., and Barbara Boxer, D-Calif, the environment committee chairwoman, would reduce greenhouse gas emissions by 20 percent from 2005 levels by 2020. Another provision would require companies to have permits to cover their emissions.

Boxer defended the decision to vote on the measure without Republican participation.

"The committee and Senate rules that have been in place during Republican and Democratic majorities are there to be used when the majority feels it is in the best interest of their states and of the nation to act," she said in a statement. "A majority of the committee believes that S. 1733, and the efforts that will be built upon it, will move us away from foreign oil imports that cost Americans one billion dollars a day, it will protect our children from pollution, create millions of clean-energy jobs, and stimulate billions of dollars of private investment."

David McIntosh, associate administrator for EPA's office of congressional and intergovernmental relations, told the panel a study such as the Republicans want would cost $135,000 and take 1,600 man-hours to finish, the Post reported. McIntosh said the analysis would not yield significantly different results from the one the agency already completed.

EPA Announces Final Amendments to SPCC Rule

The U.S. Environmental Protection Agency (EPA) on November 10 announced a final regulation that amends certain requirements for facilities subject to the Oil Spill Prevention, Control and Countermeasure (SPCC) rule.

The amendments clarify regulatory requirements, tailor requirements to particular industry sectors, and streamline certain requirements for a facility owner or operator subject to the rule. With these changes, the agency expects to encourage greater compliance with the SPCC regulations, thus resulting in increased protection of human health and the environment. This rulemaking marks the completion of the SPCC action, which was proposed on October 15, 2007, finalized on December 5, 2008, and for which the agency requested public comments again on February 3, 2009.

The amendments do not remove any regulatory requirement for owners or operators of facilities in operation before August 16, 2002, to develop, implement and maintain an SPCC plan in accordance with the SPCC regulations then in effect. Such facilities continue to be required to maintain their plans during the interim until the applicable date for revising and implementing their plans under the new amendments.

AB Resources and Caiman to Build Marcellus Pipelines, Gas Plants

AB Resources on November 19 announced an agreement with Caiman Eastern Midstream, LLC (Caiman) to build and operate midstream pipelines and facilities within AB Resources' prime acreage in the Marcellus Fairway.

The Marcellus Shale spread across Pennsylvania and West Virginia and has become the premier natural gas play in the entire Appalachian Basin. AB Resources holds a commanding acreage position in key areas of the Marcellus Shale play and other potentially productive horizons throughout the Appalachian Basin.

Under the terms of the agreement, Caiman will design, construct, and install the pipeline and processing facilities. AB Resources will have rights to up to 60,000 MMBTU per day of firm capacity with the capability to move significantly larger overall volumes on the 30+ mile gathering system. Caiman will be installing temporary processing facilities to be operational upon the initial flow from the gathering system by the end of this year. The permanent 120 MMcfd Cryogenic Processing plant is expected to be operational by the fourth quarter in 2010.

"We are delighted to announce the partnership we have formed with Caiman," said Gordon O. Yonel, CEO of AB Resources. "The agreement leverages the abilities of our in-house midstream engineering group led by David L. Ishmael, Director of Midstream Operations. David has done an outstanding job engineering our business relationship with Caiman. We look forward to expediting the delivery of natural gas from many of our most productive horizontal wells."

AB Resources’ prime Marcellus Shale and Upper Devonian acreage in Pennsylvania and West Virginia has the potential for over 3,000 well locations. AB Resources currently owns over 700 wells throughout Ohio, Pennsylvania and West Virginia, 550 of which are producing. The company's strategic direction is to aggressively exploit its Marcellus Shale acreage throughout the Appalachian Basin in the next several years.

Regency Announces $40 Mln Expansion of Haynesville Gas Gathering System

Regency Energy Partners LP on November 19 announced plans to construct Phase II of Regency's expansion of its Logansport Gathering system located in North Louisiana.

The $40-million expansion will transport gas gathered from a producer's dedicated acreage located within DeSoto Parish to Regency's Logansport Gathering system. The project also includes construction of an associated amine treating facility.

"Including this project, Regency and the Haynesville Joint Venture will have approximately $790 million invested in gathering and transportation projects in the Haynesville Shale to meet producers' demands in this prominent play," said Byron Kelley, chairman, president and chief executive officer of Regency. "This fee-based project further strengthens our position in the Haynesville Shale, which is a key component of our growth strategy."

Regency will install 4.5 miles of 10-inch gathering lines, route 7.5 miles of 12-inch pipe through more than 17 sections of dedicated acreage in DeSoto Parish, and will add approximately 3.2 miles of 24-inch pipe to connect into Regency's 24-inch Logansport Phase I Expansion. Regency will also install a gas treating facility with capacity of up to 300 MMcf/d. Construction is expected to begin in early December 2009 with completion targeted for second quarter 2010.

In addition to its Phase II Expansion, Regency is increasing the diameter of the previously announced 20-inch, 17-mile Logansport Expansion pipeline to 24 inches. The Logansport Expansion pipeline will interconnect with CenterPoint Energy Gas Transmission's Line CP. This will provide Regency's Logansport system with approximately 450 MMcf/d to 485 MMcf/d of capacity along the corridor that crosses the Gulf South East Texas Lateral, as well as the proposed Energy Transfer Tiger Pipeline. Regency also is in the process of increasing the Logansport System's incremental interconnect delivery capacities to Tennessee Gas Pipeline and to Louisiana Intrastate Gas by approximately 100 MMcf/d and 30 MMcf/d, respectively.

"We are pleased to implement a solution that provides both needed takeaway capacity and also the potential to further expand Regency's gathering capabilities for production within the surrounding areas of Logansport and DeSoto Parish," said Kelley.

Enterprise, Duncan Raise Haynesville Extension Capacity

Enterprise Products Partners L.P. (EPD) and Duncan Energy Partners L.P. on November 17 announced they have received additional firm transportation commitments from shippers sufficient to support an increase in the capacity of its recently announced Haynesville Extension project from 1.4 billion cubic feet per day (Bcf/d) to 2.1 Bcf/d. As a result, Enterprise and Duncan Energy have placed an order increasing the size of the 249-mile pipeline extension of their jointly-owned Acadian Gas LLC intrastate pipeline into Northwest Louisiana to 42 inches in diameter.

Following its completion, which is expected in September of 2011, the project will provide producers in the rapidly growing Haynesville Shale play with much needed takeaway capacity, including access to more than 150 end-use markets along the Mississippi River corridor between Baton Rouge and New Orleans. In addition, shippers will be able to access a rapid-cycle salt dome storage cavern and have the ability to make physical deliveries into the Henry Hub and benefit from more favorable pricing points. The Haynesville Extension will also allow shippers to reach nine interstate pipeline systems.

Acadian Gas, LLC is 66 percent owned by Duncan Energy Partners and 34 percent owned by Enterprise Products Partners. Enterprise Products Partners is the parent of Duncan Energy Partners and currently owns approximately 52 percent of the outstanding common units of DEP, in addition to significant direct equity interests in each of Duncan Energy's subsidiaries.

Spectra Launches Open Season for TEAM 2013 Expansion

Spectra Energy Corp's Texas Eastern Transmission, LP (Texas Eastern) on November 23 announced an open season for TEAM 2013, a proposed expansion of its existing Texas Eastern system to deliver additional, emerging Appalachian and Marcellus Shale natural gas supplies to premium markets in the U.S. Northeast. The TEAM 2013 open season is in addition to the previously announced TEAM 2012 expansion which will provide customers with up to 300 million cubic feet per day (Mmcf/d) of capacity by the fourth quarter 2012.

The TEAM 2013 Expansion Project, with an estimated late 2013 in service, will target a capacity expansion of 500 Mmcf/d. The expansion project is not restricted to this target capacity amount and will be scalable and sized to meet customer needs.

Interested shippers will have the opportunity to nominate transportation services from multiple existing and proposed receipt points on the Texas Eastern system within the Appalachian and Marcellus Shale production regions to delivery points across Texas Eastern's market area, offering substantial options and flexibility to customers.

"TEAM 2013 will contemplate new, firm incremental transportation capacity of the Texas Eastern facilities with a targeted 2013 in service to accommodate customers' timing and increased transportation capacity needs as their production ramps up," said Bob Riga, general manager, Spectra Energy Transmission.

1. "As development of the Appalachian and Marcellus production regions increases, Texas Eastern will continue to develop expansion projects, like TEAM 2012 and TEAM 2013, that are timed and sized to meet customer needs, enabling them to address their growth requirements and get their supplies to market," continued Riga.

The open season for the TEAM 2013 Expansion Project was to commence Monday, November 23, 2009, and end Friday, January 15, 2010. Additional information is available at www.spectraenergy.com.

Marcellus Shale Committee Affirms Creation of Independent Organization

The newly named Marcellus Shale Coalition (MSC) announced plans to establish itself as an independent non-profit organization to represent the Marcellus natural gas industry in Pennsylvania and elected new officers to the group's executive committee. During its annual meeting held Nov. 19, the MSC also discussed plans to hire a president and enhance its ongoing communication with regulators, government officials, news media and Pennsylvania residents. The MSC anticipates hiring a full-time president and support staff by the end of January 2010.

"Over the last year, this organization has made significant strides to provide people throughout the Commonwealth with the facts about developing clean-burning natural gas from the Marcellus Shale formation," said Ray Walker, chairman of the executive committee. "The MSC has added significantly to its membership and now represents over 90% of the companies that have applied for permits to drill Marcellus Shale wells. The MSC has established itself as the leading voice for the companies exploring the Marcellus Shale, and continues to improve our stakeholders' understanding of how we safely extract natural gas and provide a needed boost to the economy of the commonwealth. The coming year will present new challenges and opportunities to tell the story of Pennsylvania's most important energy and economic development initiative in the past several decades, and the MSC is positioned to tell that story.

"The Marcellus Shale Coalition will work cooperatively with the other organizations working to advance the development of oil and gas resources in the Commonwealth," added Walker. "The Independent Oil and Gas Association of Pennsylvania, the Pennsylvania Oil and Gas Association and the Associated Petroleum Industries of Pennsylvania will be members of the newly formed Coalition."

Walker noted that the Pennsylvania Oil and Gas Association and the Independent Oil and Gas Association of Pennsylvania played a critical role in launching the Marcellus Shale Coalition and establishing the organization's presence in the Commonwealth.

The annual meeting included a vote to change the organization's name to the Marcellus Shale Coalition to reflect the broad base of companies that have joined ranks to support the industry's efforts. The following MSC members were elected to serve on the executive committee:

Ray Walker, Jr, chairman (Range Resources)

David Spigelmyer, first vice chair (Chesapeake Energy Corporation)

Rich Weber, second vice chair (Atlas Energy, Inc.)

William Fustos, secretary (East Resources)

Kristi Gittins, treasurer (Chief Oil & Gas)

The Marcellus Shale Coalition is committed to the responsible development of natural gas from the Marcellus Shale geological formation in Pennsylvania and the enhancement of the Commonwealth's economy that can be realized by this clean-burning energy source. For more information about the Marcellus Shale Coalition or natural gas production in Pennsylvania, visit the MSC Web site at www.pamarcellus.com.

Pennsylvania Residents Sue Cabot Oil & Gas over Drilling

Residents of a small rural Pennsylvania town sued Cabot Oil & Gas Corp on November 18, claiming the company's natural-gas drilling has contaminated their water wells with toxic chemicals, caused sickness and reduced their property values.

The lawsuit accuses the company of violating state environmental laws by allowing drilling chemicals to escape from gas wells, where they are used in a technique called hydraulic fracturing.

A Cabot spokesman said the company had not had time to study the lawsuit in detail but said Cabot was in full compliance with Pennsylvania's environmental laws and "disappointed" by the lawsuit.

"We don't see merit in these claims," Cabot spokesman Ken Komoroski said.

The company, like others in the industry, has argued that its drilling processes are safe because chemicals are heavily diluted and are injected into the ground through layers of steel and concrete thousands of feet below the aquifers that are used for drinking water.

The industry says there has never been a documented case of ground water contamination because of hydraulic fracturing.

The case is one of the first to confront the industry over the technique, which critics claim pollutes aquifers with chemicals that can cause cancer and other serious illnesses.

Cabot's drilling allowed methane to escape into private water wells and in two cases caused wellhead explosions due to a gas build-up, the 15 families in the lawsuit claim.

The suit is the culmination of complaints by residents of the northeastern Pennsylvania community where Cabot has drilled dozens of gas wells in its efforts to develop the Marcellus Shale, a massive gas formation that underlies about two-thirds of Pennsylvania and parts of surrounding states.

"These releases, spills and discharges caused the plaintiffs and their property to be exposed to such hazardous gases, chemicals and industrial wastes," said the complaint.

The complaint says residents have suffered neurological, gastrointestinal and dermatological symptoms from exposure to tainted water. They also say they have had blood test results consistent with exposure to heavy metals.

The lawsuit accuses Cabot of negligence and says it has failed to restore residential water supplies disrupted by gas drilling. It seeks a permanent injunction to stop the drilling processes that are blamed for the contamination, as well as unspecified compensatory damages.

Residents of many gas-drilling areas in the United States say the chemicals used in hydraulic fracturing are contaminating ground water. However, they have been unable to prove that, in part because energy companies are not required to disclose the composition of their drilling fluids.

Gas deposits such as the Marcellus Shale offer the United States an opportunity to reduce dependence on overseas oil imports and reduce carbon emissions, advocates say. But development could slow if fracturing is shown to be environmentally damaging.

CANADA

Suncor to Shed Billions in Assets to Complete Takeover of Petro-Canada

Bitumen giant Suncor Energy is still digesting Petro-Canada, the company it took over this summer, and expects to shed up to $4 billion in assets next year.

CEO Rick George didn't divulge details but said he expects to reveal more in the near future, when Suncor plans to release its 2010 capital budget and business plan.

"We still have a lot to do," George said November 6 during the first earnings call since Suncor became Canada's largest oil company after merging with Petro-Canada.

Come next year, he said Suncor will sell the "weaker assets in the portfolio," including holdings in Western Canada, the U.S. Rocky Mountains and the North Sea, especially natural gas.

Production will decline by 10% as a result, but George said new projects will compensate for this loss in production.

Another question Suncor brass will answer is which projects will be started up first, and when.

"Unlike most companies around the world, we actually have more opportunities than we have capital to invest," George said.

With Alberta's economy slowly recovering, George said oilsands development will be dominated by a small number of companies, such as Imperial, Canadian Natural Resources and Suncor.

As activity in the oilsands picks up after a year of recessionary stagnation, George said he'd like to see a "much more disciplined approach" to development to prevent a "firestorm of inflation."

Frenzied development during the bitumen bonanza led to labor and material shortages, and consequently drove up prices and led to budget overruns on numerous projects.

George described the three months ending September 30, as "a pretty messy quarter" because it included two months from Petro-Canada and one month from the pre-merger Suncor.

Earnings over the summer totaled $929 million, compared to $815 million one year ago, while cash flow was $574 million, down from $1.15 billion one year ago.

"We feared worse results given the weakness in North American refining margins and results of (Suncor's) competitors to date," Bank of America-Merril Lynch analyst Andrew Fairbanks said in a note.

Economically, George said the summer was a "challenging quarter" because oil prices were, on average, about $50 a barrel lower than one year ago.

Exxon Mobil to Pay $231 Mln for UTS Oil-Sands Stakes

Exxon Mobil Corp., the world’s biggest oil company, agreed to pay $231 million (C$250 million) for UTS Energy Corp.’s stakes in three oil-sands prospects in western Canada.

UTS expects after-tax proceeds for its 50 percent stakes in the leases east of Alberta’s Firebag River to be about C$200 million, the Calgary-based company said in a statement. Vancouver-based Teck Resources Ltd. owns the other 50 percent of the Alberta leases, which cover a combined area equal to half the size of Sacramento, California.

UTS, which defeated a C$830 million hostile takeover attempt by France’s Total SA in April, said the money will help finance its share of development costs in Suncor Energy Inc.’s C$25.3 billion Fort Hills tar-sands project and other prospects.

The transaction with Exxon Mobil and the Irving, Texas- based company’s majority-owned Imperial Oil Ltd. ends UTS’s efforts to find alternative buyers for assets after Total made its initial bid in January, according to the statement.

UTS’s directors rejected Total’s offer despite a sweetened bid after Chief Executive Officer William Roach said the proposal undervalued the company.

UTS rose 6 cents, or 2.9 percent, to C$2.10 on the Toronto Stock Exchange. Exxon climbed 48 cents to $72.15 in composite trading on the New York Stock Exchange.

The transaction is expected to close in the next month, according to the statement.

Canada’s Oil Sands Make Case for Carbon-Capture Subsidies while Major Oil Companies Can’t Agree on how to Proceed

Canada's oil sands companies say they must adopt expensive carbon-capture-and-storage technology to meet environmental challenges, but will require major government subsidies to do so for at least the next decade.

While carbon-capture-and-storage (CCS) will be expensive, the industry defends it as being competitive with wind power and biofuels in terms of the cost per tonne for reducing greenhouse gas emissions.

"CCS is vital to the sustainability of Canada's oil sands development and the continued production and use of Canada's fossil fuel resources," says the report from the Integrated CO{-2} Network (ICO{-2}N), an industry group that represents Canada's major oil companies and coal-based utilities.

"It makes environmental and economic sense to develop initial CCS projects within a vision of a long-term, large-scale integrated system."

While the major oil companies all endorse the need for CCS, they do not agree on the best way to impose the price on carbon emissions that will be required to commercialize the technology.

Imperial Oil Ltd.'s parent company, Exxon Mobil Corp., argues in the United States for a direct tax on carbon emissions, while Royal Dutch Shell PLC and ConocoPhillips Co. support a cap-and-trade system. As a result, the industry's main lobby group, the Canadian Association of Petroleum Producers, has been unable to forge a consensus on how Ottawa should proceed.

Both the U.S. and Canadian governments are developing plans to impose cap-and-trade regimes under which companies would have to pay a price per tonne for permits to emit greenhouse gases, and a limited number of permits would be available.

The ICO{-2}N report suggests that, whatever the mechanism, the oil industry and coal-fired utilities inevitably face requirements to significantly reduce greenhouse gas emissions, and CCS needs to be a part of the response.

However, the cost of CO{-2} capture at oil sands extraction sites would be far higher - perhaps prohibitively so - than at power plants, chemical facilities and oil sands upgraders, which refine raw bitumen into synthetic crude oil.

Even for the less expensive options such as chemical and fertilizer plants, wide-scale deployment would require carbon emission prices considerably higher than the levels that industry and government have suggested as reasonable for meeting greenhouse gas emissions targets.

The adoption of CCS would cost $85 to $120 a tonne at existing chemical and fertilizer plants and some new coal-fired power plants, rising to $120 to $160 per tonne for refineries and upgraders. But capturing CO{-2} emissions from the natural gas-fired boilers that create steam for oil sands extraction would top $160 a tonne.

In a companion report released by ICO{-2}N, Ottawa-based consulting firm Delphi Group compared costs of competing emission-reduction technologies. Delphi calculated that, in terms of displacing carbon emission from fossil fuels, both wind power and ethanol cost well above $150 a tonne, and both receive generous government support.

The oil companies and utilities are awaiting federal government climate change regulations that will force them to reduce their emissions and essentially set a price on carbon.

In the initial years at least, the carbon price is expected to be far below what is needed to justify investments in CCS by oil sands producers and utilities. In a now-discarded regulatory plan released in 2007, the Harper government estimated that carbon prices would rise to $65 a tonne by 2020.

To close that cost gap, the industry is suggesting governments must directly support the early adoption of CCS beyond what has been committed. Ottawa and Alberta have already announced $1.4-billion in funding for CCS pilot projects involving a coal-fired power plant and an oil sands upgrader, which together would reduce emissions by one million tonnes. The federal share amounted to $463-million.

The industry group does not put a price tag on its call for subsidies, saying the cost will depend on what carbon price Ottawa imposes, and actual cost of capturing emissions, and number of projects supported.

Environment Minister Jim Prentice has repeatedly delayed the release of his plan, saying he wants to see what regulations are adopted in the United States to ensure Canada's approach is compatible with our major trading partner.

With an aggressive program, the report says the technology could reduce emissions by as much as 35 megatonnes per year by 2020, roughly a quarter of the reductions necessary to meet Ottawa's target of a 20-per-cent reduction from 2006 emission levels. By 2025 to 2030, CCS could reduce emissions by 50 megatonnes per year.

Suncor CEO Predicts Controlled Growth for Oilsands

As Suncor Energy gets set to start up some of its stalled oilsands projects, the firm's CEO warns no one should expect another boom.

Rick George told investors November 6 that Suncor, "unlike most companies around the world, actually has more opportunities than available capital to invest."

And after chopping $3 billion from its capital budget one year ago, putting its almost half-built Voyageur upgrader into "safe mode," the firm suggested it will be in a better position to get its projects back on track in 2010.

An announcement was expected to be made by November 13.

The task for Suncor now is "ranking the order, that's the luxury we have, but without creating the firestorm of inflation up north that we have experienced for five years, up until last September," said George.

Suncor reported net earnings November 6, of $929 million for the third quarter compared with $815 million for the same period last year, George said his company would focus mostly on its oilsands and other oil assets after its recent $19.2-billion all-stock funded merger with Petro-Canada.

Suncor says it plans to sell about one-third of its total natural gas operations in 2010, hoping to collect up to $4 billion from the sales.

"That includes some of the natural gas assets, some small North Sea assets, Trinidad and Tobago assets. We have a corporate plane up for sale ... in total the target we have is about $2 billion to$4 billion worth of asset sales. Most of that will take place in 2010."

The proceeds will be used to pay down its $3.1 billion in debt. The 2010 capital program will be financed from cash flow.

George says the next cycle of construction in the Fort McMurray area will be different for Suncor, along with the other big players in the oilsands-- Imperial, Syncrude, Shell and CNRL.

"You are going to see a more disciplined approach. Otherwise you'll create an inflationary spiral again, which is not a position I want to rush to."

George added that Suncor is not looking to sell its 12-per-cent share of the Syncrude partnership, which it acquired when it merged with Petro-Canada.

"This gives us a window into some of the technologies Syncrude is trying to make work, and we can use the synthetic crude production if we have our own production problems, so we are quite happy with our interest there."

George reported that there have been 1,000 layoffs so far in the wake of the merger with Petro-Canada, and that Suncor is confident it will exceed its estimate of $300 million in expense reductions and $1 billion in capital efficiency savings by combining the two operations.

When Suncor slashed its capital budget last October, it said the Voyageur upgrader project completion would be set back one year, to 2012.

Also delayed were the Firebag in situ stage 3 expansion, which was to open this year, followed by stage 4 next year. The third part of the $20.6-billion Voyageur strategy--with an output target of 200,000 barrels per day when complete--is the Voyageur south mine, located near the upgrader.

The Firebag sites, which use steam to extract the deeper bitumen deposits, deliver raw bitumen to the upgrader via a pipeline.

George has said in previous interviews that he is eager to restart Voyageur construction as soon as possible.

Suncor also holds a 60-per-cent stake in the proposed Fort Hills oilsands mine it acquired through its takeover of Petro-Canada.

After its August merger, Suncor became Canada's biggest energy company and the fifth-largest North American-based energy firm by market value. It has 26 billion barrels of oil and gas reserves.

Suncor to be a Buyer of Oilsands Properties

Suncor Energy Inc., with its massive slate of oilsands assets, will be a buyer, not a seller, of bitumen-laced properties as it reshapes itself following its merger with Petro-Canada, the company's chief executive said.

"Down the road, I'd be more of an acquirer, or maybe a better way to put that [is] a consolidator [of oilsands leases], than I would be a seller," Rick George said during the company's third-quarter conference call. "It is our heartland and the core of this company."

George also provided a further glimpse into which projects the energy giant plans to sell in the wake of the takeover. The assets, valued at between $2 billion and $4 billion, include 30 per cent of its natural gas production, small North Sea properties, operations in Trinidad and Tobago, and a corporate plane.

Most of the auctions will take place in 2010, George said.

Suncor and Petro-Canada merged August 1 in a stock deal worth $19.2 billion, and this was their first combined quarter. The enlarged company made $929 million, or 74 cents per share, in the third quarter, compared with $815 million, or 87 cents per share in the corresponding quarter in 2008.

Suncor Unveils New Patented Technology in Dealing with Tailings Ponds

In a move that sets a new standard for the oilsands industry, Suncor Energy in October unveiled a novel way to speed the reclamation of tailings ponds.

The technique suggests a future with fewer ponds, and reclamation beginning in as few as seven years compared with the 40 years it now takes.

"Suncor's proposal raises the bar for all companies operating in the oilsands," said Simon Dyer, oilsands program director with the Pembina Institute, an environmental group.

"No other company is planning this," he said, adding that other oilsands companies should now be expected to match Suncor's system, if it works as promised.

Suncor applied to the Energy Resources Conservation Board to be allowed to use the patented technology, which has been under study since 2003.

The process is part of the submission Suncor made this month to the ERCB.

The board is reviewing proposals from all six oilsands companies on how they will meet tougher new standards for tailings pond reclamations.

Suncor's new approach allows mature fine tailings, which take years to settle out, to be pumped from the ponds.

A polymer clumping agent is added, and the thick, soupy material-- which is about 40 per cent clay and 60 per cent water--is then deposited in thin layers over sand beaches with shallow slopes in a contained area, much like a landfill site.

Thanks to the polymer, the water quickly separates from the claylike tailings and flows to collection pipes, which return it to the bitumen processing plant.

In just a month, the tailings are dry enough to be walked on.

The site is then turned over and over with discing equipment, and when totally dry the material is removed and used for construction projects around the site.

Suncor expects to repeat the process-- called tailings reduction operations-- every year, and compares the operation to farming.

The result is fast water recycling, and a shrinking environmental footprint, with fewer and smaller tailings ponds in the future.

The surface area of all tailings ponds in the Fort McMurray area is estimated at about 60 square kilometers, with a volume of more than 700 million cubic meters.

By comparison, popular Sylvan Lake south of Edmonton holds just over 400 million cubic meters.

The new treatment is "a significant advance in tailings management and reclamation," said Kirk Bailey, a Suncor executive vice-president.

"We believe it will help us meet new provincial regulatory requirements and, just as importantly, the changing expectations of stakeholders."

If approved, Suncor plans to rapidly implement the process next year.

When tailings--a mixture of fine clay, sand, water and residual bitumen produced through oilsands extraction --enter the giant ponds, they are 94 per cent water.

Oilsands firms now use a variation of the "consolidated tailings" technology to speed the settling process.

The process adds coarse sand and gypsum to accelerate the release of water.

"Consolidated tailings have proven effective, but in this industry, the focus is always on developing new technology and better processes," said Bailey.

"In 2010, Suncor plans to officially complete the reclamation of our first tailings pond to a solid surface," he said in a statement.

"It's fitting that in the same year we reach an important reclamation milestone, we expect to implement improved technology to increase the pace of reclamation."

The conservation board's directive for all oilsands companies is that fine particles in liquid tailings must be reduced by 20 per cent by June 30, 2011, and by 50 per cent by 2013.

The board wants tailings ponds to be able to carry traffic within five years after they are no longer being used.

The ERCB is still evaluating the proposals submitted on Sept. 30, and it will be several more weeks before officials will say whether the plans have been approved.

Canada Steps up Oil Sands Push in U.S.

Canada has mounted its biggest campaign yet to sell the United States on the energy security benefits of the oil sands as Washington debates new environmental policy, the country's energy minister said November 7.

Canadian Natural Resources Minister Lisa Raitt said she and her staff are lobbying interests in the United States at all levels, trying to send the message that the huge heavy-oil resource in Alberta is being developed responsibly and that U.S. input on environmental fixes is welcome.

The push comes as environmental groups have intensified their own campaigns warning of the impact of oil sands development on climate, water, land and local communities on both sides of the border.

"There are certain groups that just want to completely shut down the oil sands. That is completely unacceptable. That will not happen," Raitt said in an interview.

"This is too strategic a resource for the country, and that's the other part of the message: we will develop it, we will use technology, we are going to work with the United States on it."

Canada is already the largest foreign supplier of oil to the United States, topping such OPEC suppliers as Saudi Arabia and Venezuela. Much of that crude is derived from oil sands developments in northern Alberta.

TransCanada Corp is preparing to start its 435,000-barrel-a-day Keystone Pipeline to the U.S. Midwest, pushing even more oil to the country's biggest trading partner.

Raitt travels to New York the second week of November as part of the effort to promote the oil sands. That trip follows a series of meetings with the new U.S. ambassador to Canada, David Jacobson, and Prime Minister Stephen Harper's new top diplomat in Washington, Gary Doer.

"We're deploying people on the ground in the United States as well. It has to happen at all levels, you have to engage at 'officials' levels, you have to engage at ministerial levels, you have to engage at business levels," she said.

U.S. Energy Secretary Steven Chu has said he is aware of the impact of oil sands development, but has expressed optimism over the industry's ability to develop technology to limit the ecological damage.

California, often seen as a bellwether of U.S. environmental policy, established its own low-carbon fuel regulations this year that the Canadian energy industry has warned could eventually hurt exports.

"I absolutely recognize the fact that in some cases, individual states are implementing energy policy that would seem to be detrimental to Canadian positions," Raitt said. "But as well, even with all that, we exported more oil this summer than we ever have."

Raitt was in Calgary to talk to industry R&D people about ways to cut emissions, such as carbon capture and storage, as well as how to make energy production more efficient to offset some of the costs of CCS.

Despite the short record carbon capture technology, Canada and the province of Alberta have pledged hundreds of millions of dollars to private-sector projects they hope will help the country meet emission-reduction targets.

Canada can cooperate with the United States on some aspects of energy and environmental policy, Raitt said. But she said a full-blown continental energy plan is not possible.

Nexen Says Long Lake Project to Take Longer than Expected

Nexen Inc.'s Long Lake oilsands project will take longer to ramp up than expected, possibly not reaching full production until late next year, company officials said at the end of October.

The disclosure came as the company reported 86 per cent lower third-quarter profits, which came in at $122 million or 23 cents a share compared to $886 million or $1.68 per share a year earlier.

Discussing the results, CEO Marvin Romanow admitted the Long Lake startup has "gone sideways" over the past year.

Production at the site southeast of Fort McMurray averaged 9,000 barrels per day (bpd) in the quarter due to an extended maintenance turnaround and is currently pumping 10,000 to 12,000 bpd--well below its nameplate capacity of about 70,000 bpd.

But Romanow urged patience as the company works to sort out water handling issues that could take almost all of next year.

"As we move forward at Long Lake, our expectation is to get back on that ramp-up curve that we saw when we first brought the project on stream," he told analysts. "I think it's extremely important to keep our eye on the long-term goal. . . . We have very significant value to create here over the next 40 years, as we look to develop and monetize the six billion barrels of oilsands inventory that we have in our portfolio."

Long Lake partner Opti Canada Inc. also confirmed the delay while releasing its own financial numbers that showed a third-quarter profit of $12 million, its first in two and a half years.

Positive earnings included a $162-million foreign exchange gain on its U.S. dollar-denominated debt. Opti lost$95 million in the third quarter of 2008.

Chris Slubicki, president and chief executive, said the company would consider selling its interest in other oilsands leases or in the unsanctioned Long Lake Phase 2, but insisted no such deals are pending.

"The answer is no, we have not started any (sales) process," he said. "I think we haven't been shy about stating that with our debt load we have to look at those things."

Opti, which sold a 15 per cent chunk of the Long Lake project to Nexen earlier this year to reduce debt, said it has $207 million in cash and $215 million in undrawn credit to continue to fund its 35 per cent stake in Long Lake.

Unlike Opti, whose main asset is its 35 per cent interest in Long Lake, Nexen has a suite of exploration and development assets spanning the globe, including West Africa, the North Sea, the Gulf of Mexico and Horn River in northeast B.C.

At Horn River, Romanow said he expects aggregate production to triple to 300 million cubic feet per day over the next 12 months. "That's the building out of an industry," he said.

Nonetheless, Barclays Capital analyst Harry Mateer said in a research report that Long Lake remains "a key driver" for Nexen. The company's production volumes fell 14 per cent in the quarter to 214,000 bpd largely as a result of maintenance in the North Sea, in addition to Long Lake.

"Given timing uncertainties with respect to turnaround activity during the quarter, it was difficult to accurately gauge production and operating costs," he noted.

UBS analyst Andrew Potter described Nexen's earnings as a "big miss," but maintained a "buy" rating on the shares and a $30 price target. In a separate note, he also maintained a $3 target for Opti.

Haywood Securities analyst Alan Knowles said Long Lake remains an "attractive" project despite the ongoing operational issues. He's lowered his production expectations for 2010 but remains bullish over the longer term.

"There were always challenges; we were always cautious in that regard," he said in an interview. "There will probably be more challenges going forward. It's eventually going to get there; it's just going to take longer than everyone thought."

Connacher Oil & Gas Provides Algar Project Update

Connacher Oil and Gas Limited announced in October that a major milestone was achieved at the Algar construction site with the engineered lift of the two evaporator towers ("towers"), which constitute part of Connacher's second 10,000 bbl/d steam-assisted gravity drainage ("SAGD") plant at its Great Divide oil sands development project in northeastern Alberta.

The first tower, which weighed over 476,000 pounds and stands approximately 150 feet tall, approximately 40 feet taller than the evaporator towers at Pod One, was installed initially, followed by the second, smaller tower. These lifts required a sound plan, excellent teamwork, communication and cooperation among a wide range of disciplines, as well as favorable weather conditions with limited wind. The towers were transported to the site by truck, including over Connacher's newly-constructed road from Highway 63 to the plant site. This road was carved out of muskeg in a remote area and the towers were installed on reinforced concrete bases, situated on piles driven into the muskeg. The towers were each stood up in approximately four hours and are expected to be in place for approximately 25 years.

Construction at the Algar project is proceeding on time and under budget at this time, with a target to complete the plant and tie in the associated seventeen SAGD horizontal well pairs in early April 2010. Thereafter, it will take approximately one month to commission the plant and steaming of the well pairs should start in May 2010 and last approximately three months before first production in approximately August 2010.

Thereafter, ramp-up towards full plant capacity is anticipated to occur between startup and year end 2010 or early 2011. Completion of Algar will double Connacher's capacity at Great Divide to 20,000 bbl/d of bitumen.

Connacher is very pleased with the progress at Algar, as highlighted by this installation of the evaporator towers in a most timely and efficient manner. Barring any unforeseen problems or unduly adverse weather conditions, the company remains optimistic about the timely, cost effective completion of the Algar project and then its eventual impact on the company's production levels from the region.

Separately, with the recent closing of the $30 million flow through equity financing, after freeze-up Connacher will immediately be embarking on a multi-well core hole drilling program, primarily on the northwest portion of its main lease block at Great Divide and to a lesser extent on its 50 percent-owned Halfway Creek acreage. Additionally, 3-D seismic will be shot on Connacher acreage in the region.

Suncor Awards Jacobs Oil Sands Sustainability Project

Jacobs Engineering Group Inc. announced November 10 that it has received a contract from Suncor Energy (Suncor) to provide project management, engineering and procurement services to complete the scoping study and Design Basis Memorandum (DBM) for tailings and water transfer projects. These projects are a portion of the Tailings Reduction Operations (TRO) implementation at Suncor's oil sands mining, extraction and upgrading facility located 30 kilometers north of Fort McMurray, Alberta, Canada.

Officials did not disclose the contract value.

TRO is Suncor's new initiative to implement a Mature Fine Tailings (MFT) drying process, which results in the dry material to be reclaimed in place or moved to another location for final reclamation. The process helps achieve a dryer landscape in a shorter period of time and allows for accelerated reclamation timelines, shrinking the environmental footprint of oil sands mining operations.

In making this announcement, Chip Mitchell, Jacobs Group Vice President, stated, "We are pleased to broaden our capability to support this critical sustaining project for Suncor and to be part of its industry-leading efforts on sustainability in the oil sands."

CANADA / U.S.

Oil Sands Firms Fight for Their Share of the Market on the Gulf Coast

The refineries dotting the Gulf Coast of the United States represent a major new market that could fuel the expansion of Canada's oil sands producers, as well as a major pipeline player. And indeed, on the surface, growth appears to be the order of the day. But after a brief golden age, there is a growing fear along this refiners' alley that the bubble has burst.

In the fields adjacent to Motiva Enterprises LLC's sprawling Port Arthur refinery, teams of contractors work on stainless steel vessels and refining modules, all waiting for assembly in a $7-billion (U.S.) expansion of the plant.

Motiva – a joint venture between Royal Dutch Shell PLC and state-owned Saudi Aramco – is doubling its refining capacity to 600,000 barrels a day. The site will also add a coker so it can process the heavy grades of crude, such as bitumen from Canada's oil sands that make up a growing share of the world's oil supply.

Because the U.S. is the only export market for Canadian crude, expanded U.S. refineries like Motiva's are key to Alberta's ambitions to double, or even triple, oil sands production over the next decade.

But, the Motiva refinery is proceeding only because the company, after weighing discouraging trends in the market, decided not to kill it.

“In general, the outlook for total refining capacity in the U.S. is downward pressure,” says Motiva's chief executive officer, Robert Pease.

“As new capacity like ours comes on stream, there will be even greater pressure on others to close down eventually.”

The U.S. petroleum market is facing what one analysis has called a “tsunami of change.” The industry faces a bad combination of depressed demand, growing competition from foreign refiners and a sector-wide rationalization that will force refinery closings.

Moreover, looming regulatory changes requiring reductions in greenhouse gas emissions will drive up refiners' costs, particularly for the energy-intensive, emissions-heavy processing of heavy crudes.

“We're facing a lot of challenges,” Tom Botts, a senior refining executive from Shell, told an industry conference in Houston during the first week of November. “And not all of us are going to survive the coming shakeout.”

From the Canadian perspective, all this adds up to a not so sunny forecast. The hopes of oil sands producers such as EnCana Corp. and Shell ride on getting a larger slice of a shrinking pie – and those hopes are hobbled by the high environmental cost of oil sands crude. The producers will face downward pressure on bitumen prices as refiners look to pass added regulatory costs to their suppliers.

And, Canadian producers also face an array of other countries, from Brazil to Saudi Arabia, that are eager to export to the Gulf Coast, joining traditional suppliers such as Mexico and Venezuela.

Taken together, the U.S. demand and supply challenges raise questions about whether investment in the oil sands will ever reach the peaks that enthusiasts in the sector have imagined.

The Port Arthur complex, located 140 kilometers east of Houston on the Intracoastal Waterway, is one of the oldest refineries in the United States, dating back to the founding of the Texas oil industry.

It was built to handle oil from the great 1901 Spindletop gusher in nearby Beaumont, and has long been one of the workhorses of the Gulf Coast region, which boasts the world's largest concentration of refineries, accounting for nearly half of U.S. production.

Over the years, its successive owners have invested heavily in new technology – investments to reduce operating costs, keep up with the expanding market, or to meet environmental requirements such as the elimination of sulfur from gasoline and diesel.

When Shell and Aramco approved the current expansion three years ago, North American refiners were earning fat profits and were looking to expand capacity to meet booming demand.

At the time, refining bottlenecks were a hallmark of the industry. Every time a plant went down or a hurricane threatened the Gulf Coast, gasoline prices and refining profits soared.

But record-high oil prices in 2008 and the ensuing recession bludgeoned demand for petroleum products. Profits evaporated, and many refiners responded this year by shelving expansion plans or even shutting down operating units.

Last March, Motiva management sat down with its Shell and Aramco shareholders to re-evaluate whether it made sense to plow $7-billion (U.S.) into a project that would refine an additional 320,000 barrels a day of crude oil.

The decision: Proceed, but at a slower pace, pushing back the startup date by two years in order to shave costs and give the market some time to recover.

The cancellation of the Motiva project would have dealt a major blow to Canadian plans.

Currently, virtually all Canadian exports go to refineries in the Midwest, whether as bitumen or upgraded synthetic crude. Some exports do make their way to the East Coast, but only small amounts are exported to the Texas-Louisiana refining hub and to the West Coast.

In order to expand production in Canada, oil companies need to either add domestic upgrading capacity – which is tremendously expensive and raises emissions concerns – or count on American refiners increasing their ability to process the raw bitumen.

As of two years ago, companies like Motiva, Valero Energy Corp., Marathon Oil Co. and ConocoPhillips Co. had all announced plans to add cokers both along the Gulf Coast and in the Midwest to process bitumen. Some have proceeded, but many projects have either been delayed or slowed down, like Motiva's, or shelved.

Currently, the southern refinery sector is being watched closely not only by oil sands producers but also by Canada's big pipeline companies, which are likewise banking on growth. TransCanada Corp. and Enbridge Inc. have announced a series of expansions of their network, both adding volumes into traditional Midwest markets and extending pipelines deeper into the U.S.

TransCanada is seeking approval from state regulators in the U.S. and Canada's National Energy Board to build a pipeline extension, dubbed Keystone XL, to deliver 500,000 barrels a day of bitumen to Gulf Coast refiners.

Backing TransCanada's plan are some of the biggest producers in the oil sands, including Shell, EnCana, ConocoPhillips and Canadian Natural Resources Ltd. TransCanada's competitor, Enbridge, has opposed Keystone XL, saying that, for at least several years, there won't be enough production from the oil sands to keep all the new pipeline capacity full.

In seeking to reassure the NEB and the industry that Keystone XL makes sense, TransCanada presents a glowing picture of the appetite among Gulf Coast refiners for oil sands product. The company also pointed to the prospect of Canada making up for lower imports from Mexico and Venezuela, two of the biggest suppliers of heavy oil to the Gulf Coast.

Area refiners now import about six million barrels a day of crude, including two million barrels of Mexican and Venezuelan heavy. With little pipeline access, Canada exports a mere 100,000 barrels to the region.

Production at Mexico's largest field, Canterell, is dropping rapidly, while Venezuela is not investing in expanding production and, as a result of the predilections of president Hugo Chavez, is looking to shift exports away from the U.S.

Meanwhile, TransCanada argues that oil sands producers could easily move an additional 500,000 barrels a day to the Gulf Coast once Keystone XL is in place.

“There are tremendous opportunities for Canadian crude to access a new market.” says Paul Miller, a vice-president at TransCanada. “You have significant reserves up in the Alberta oil sands, and to the extent you need crude oil for your refinery, you look to the closest, most available and less risky supply.”

Canadian producers have long pursued a “market share” strategy in the U.S. The idea is that driving deeper into the heart of the continent can reap new revenue even if the overall market is not growing.

EnCana is a joint venture partner with ConocoPhillips on two U.S. refineries, and is in the midst of $3.6-billion expansion of its coking capacity at Wood River, Ill.

EnCana spokesman Alan Boras says the Keystone project represents a continuation of the southern campaign.

“Canadians have been very successful at pushing their volumes south and competing on a cost basis,” Mr. Boras says. “And the challenge will be to continually have low-cost supplies – or costs competitive with those supplies that are coming in from offshore.”

But there are limits to a strategy predicated on taking a greater share of a stagnant market, says economist Peter Tertzakian of Calgary-based ARC Financial Corp.

“They can count on it to a point, but they need to be very cautious,” Mr. Tertzakian says. “The challenge is going to arise when the potential for displacement stops – in other words, when Venezuela's and Mexico's production levels out or even start to rise again.”

Motiva's Mr. Pease says the Gulf Coast is the “logical” market for Canadian crude. But he also acknowledges that, as a buyer of crude, he has a vested interested in seeing as much supply in the market as possible, to drive down prices.

And there will be plenty of competition from other producers as Canada looks to increase its share of the market. In fact, Motiva configured its Port Arthur expansion specifically to process growing volumes of heavy oil from Saudi Arabia and Brazil.

At the moment, the Saudis have shut down much of their heavy oil production as part of the effort by the Organization of Petroleum Exporting Countries to defend prices in a weakened global economy.

But as the recovery takes hold, the kingdom will ratchet up production of its heavy crude, with the Gulf Coast and growing Asian markets vying as key export destinations.

In keeping with Washington's rhetoric about America's unhealthy addiction to Middle East oil, Canadian suppliers like to tout the oil sands as a secure source for U.S. customers.

But Mr. Pease plays down those political considerations, saying commercial factors will determine where Motiva buys its crude. “We have no better supplier than Saudi Arabia,” he says regarding his shareholder. “Their ability to hit what they say they're going to hit, deliver when they say they're going to deliver, is unmatched.”

Meanwhile, Brazil's state-controlled Petrobras SA is planning to increase production by two million barrels a day by 2020 as it develops its offshore discoveries. While much of that production is targeted for domestic refineries, some will also be shipped to the U.S.

As well, analysts say it would be a mistake to count out Mexico and Venezuela. While both countries face supply challenges, the Gulf Coast market is simply too important for them to abandon without a fight.

Despite all the unfavorable possibilities, Canadian producers believe two trends favor their expansion plans in the U.S.: Rising demand in emerging markets will draw off imports from traditional American suppliers, and the global industry will find it difficult to increase the overall supply base.

In fact, those two factors help explain why crude prices rebounded smartly from their recessionary lows hit earlier this year.

But oil sands producers face risks as their U.S. refining customers cope with weak petroleum demand and the environmental costs that could drive down the value of the heavy crudes.

A recent report from Deloitte & Touche's energy practice warned of a “tsunami of change [that is] bearing down on the refining industry.”

“What had been a profitable industry running at respectable operating rates will see higher costs, steadily declining demand and excess capacity,” Deloitte partner Roger Ihne says.

U.S. demand for gasoline may well have peaked in 2005. While overall consumptions of products like gasoline, diesel and jet fuel should recover from recessionary lows, the U.S. Energy Information Administration (EIA) forecasts virtually no growth between now and 2020.

American motorists are expected to cut their gasoline consumption by 8 per cent between 2006 and 2018, and by 13 per cent by 2030, the agency forecasts.

Combine that lower demand with rising production from offshore drilling in the American area of the Gulf of Mexico, and the EIA foresees a sharp drop in U.S. crude imports. From the peak of imports in 2006, the agency says demand for foreign crude will fall by more than two million barrels a day by 2018, and by an additional one million barrels a day by 2030.

Even now, as a result of weak demand and facility expansions of the past few years, U.S. refiners are running at about 82 per cent of capacity. The number is projected to drop further in the next decade after being above 90 per cent for much of the previous one.

As a result, the industry expects a rationalization that could reduce its demand for crude by 1.5 million barrels a day from the current 17.5 million barrels. And the less-competitive, higher-cost refineries will close, Mr. Ihne predicts.

The profit squeeze has already bit refiners in Canada. Earlier this year, Irving Oil Ltd. cancelled its planned expansion in Saint John, N.B., while Shell announced it is considering the closing of its Montreal East refinery, which processes 130,000 barrels a day of imported crude.

The forecast decline in demand suggests the industry is on the wrong side of a number of demographic and public-policy trends.

Higher pump prices will likely encourage consumers to switch to smaller vehicles, according to the EIA. An aging population will also drive less.

Meanwhile, federal regulations in both the U.S. and Canada will force greater fuel efficiency and more use of biofuels.

And looming on the horizon is the refiners' greatest fear: cap-and-trade regulations that would increase the costs of refining by forcing companies to pay for every tonne of carbon dioxide they emit. The regulations would drive up fuel costs, further dampening demand.

The U.S. House of Representatives has passed cap-and-trade legislation and a similar bill is now being debated in the Senate. But even if the bill fails to pass, the Environmental Protection Agency has vowed to regulate emissions.

Mr. Ihne calculates that refiners could see $8 per barrel added to their costs, a burden that would virtually wipe out their current profit margins.

The Canadian industry is particularly vulnerable because the refining process for oil sands bitumen is so energy-intensive, producing more emissions per barrel than light or medium-grade crudes.

Motiva's Mr. Pease says his company has included as many energy-saving and emission-reducing technologies as possible in the Port Arthur expansion. He acknowledges, however, that refining heavier-grade crudes, like Canadian bitumen, would be more costly under the expected regulations.

“The emissions costs will go into what we are willing to pay,” he says. “You would expect emission limitations to put downward pressure on the value of heavy sours [like Canadian bitumen].”

U.S. refiners worry that the cap-and-trade legislation will lead to a greater reliance on imported gasoline and diesel from countries like Brazil, India and Saudi Arabia. Those emerging economies are refusing to impose emission caps on their industries, giving their expanding refinery sectors a cost advantage over American refiners.

India's Reliance Industries Ltd. has just completed a 600,000-barrel-a-day refinery that is aimed exclusively at export markets. The Indian company has purchased sizable storage terminals in the U.S. and is clearly focusing on the American market.

“We feel this is a game changer in the worldwide refining industry,” Reliance's president of corporate development, Mat Malladi told an industry audience in Houston.

Such moves could further reduce American refiners' demand for Canadian crude.

In recent years, Canadian producers have shown little interest in gaining access to fast-growing Asian markets through a pipeline to the West Coast, preferring to expand their presence in the U.S.

That appears to be changing. Enbridge is pursuing such an option with its $4.5-billion Northern Gateway project, a 1,170-kilometre pipeline that would deliver 525,000 barrels a day of oil sands crude to a terminal in Kitimat, B.C.

The industry failed to support Enbridge's first run at the Gateway project three years ago, but there is more support for the current bid. However, critics – including first nations on the coast – have raised objections over the potential environmental impact from oil spills and tanker traffic.

Without such access to overseas market, Canada's oil sands producers will face a future where their prosperity depends wholly on a risk-filled American market.

“There needs to be recognition of that, and a wake-up call,” Mr. Tertzakian says. “We need to diversify into growth markets if we've made the conscious decision to develop these resources and export them.”

EUROPE / AFRICA / MIDDLE EAST

SOUTH AFRICA

Statoil Looks to South African Shale Gas Prospects

Statoil ASA (STO) confirmed December 1 it is interested in a shale gas prospect in South Africa, which could see it pick up its first oil and gas asset in the country.

"We, together with Sasol [Ltd.] and Chesapeake [Energy Corp], signed a joint application for an onshore petroleum exploration right relating to the Karoo Basin in South Africa," Statoil spokeswoman Mari Dotterud said.

"The area has shale gas potential. The agreement is part of the international venture we have with Chesapeake," she added.

Statoil joined forces with Chesapeake a year ago at the Marcellus shale gas prospects in the U.S. but its new foray to South Africa indicates it has ambitions above and beyond the shale gas sector's current heartland.

"We are still in the learning phase. It's been a very interesting year. We're working closely and well with Chesapeake, increasing our knowledge and experience together when it comes to shale gas," Dotterud said.

She noted the South African government will need some time to look into the joint application. "We expect it to take up to a year before we get any response on that. The next step will be seismic surveys and the third step drilling, so this is for the long term. We'll take one step at a time," Dotterud added.

Some market watchers have suggested unconventional gases, including shale and oil sands, are an uneasy bedfellow with the rest of Statoil's portfolio, although they accept that they help to top up the company's ailing reserve replacement figure.

Statoil has faced criticism over the timing and price paid for its purchases. In a recent interview with Dow Jones Newswires, Chief Executive Helge Lund said: "We believe we can sustain [these projects] from a long-term perspective. Regardless of the cycles in the industry, unconventionals will be an important part of long-term supply."

McIlvaine Company,

Northfield, IL 60093-2743

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

E-mail: editor@mcilvainecompany.com