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Providing coverage of Alaska and northern Canada's oil and gas industry
November 2006

Vol. 11, No. 47 Week of November 19, 2006

Oil sands barrel overflows

Mined output soars, Devon and Total caught in price grip, natural gas consumption a worry, nuclear power gets a political lift

Gary Park

For Petroleum News

Sifting through the latest grains from the oil sands seldom fails to yield a mix of the good, the bad, the ugly and the fascinating.

The last couple of weeks have produced the following:

The good:

• Mined oil sands output soared 26 percent in the third quarter to 764,800 barrels per day of bitumen.

The Syncrude Canada consortium hit 334,000 bpd, a gain of 55,000 bpd from a year earlier; Suncor Energy was up 104,000 bpd to 266,300 bpd, reflecting its recovery last year from a major plant fire; and Athabasca dropped marginally to 164,500 bpd.

For the first nine months of 2006, industry-wide production was 697,300 bpd, up from 561,533 bpd in the same period of 2005.

Suncor’s average total for the January-September period was 289,300 bpd, Syncrude posted 284,000 bpd and Athabasca fell to 124,000 bpd.

Operating per barrel costs for the third quarter were: Syncrude C$19.68 (down C$3.93), Suncor C$23.70 (down C$3.95) and Athabasca C$18.93 (down C$5.32).

• UTS Energy, a 30 percent stakeholder in the Fort Hills project (with Petro-Canada as 55 percent operator and Teck Cominco a 15 percent partner) is extending its asset base as its major investment moves ahead.

Bidding jointly with Teck, UTS picked up new oil sands leases in the Athabasca region, with auction records showing it invested C$82 million in September.

Five of the leases are alongside a lease held jointly with Teck where preliminary drilling results encourage the follow-up bidding.

Of the six wells drilled so far, all encountered oil sands and four indicated mineable quality oil sands with an ore thickness of 80 to 115 feet.

UTS now plans to drill 90 infill wells this winter to delineate the extent of one lease, which it owns outright.

In addition to its successful accumulation of future prospects, UTS is pleased with progress at Fort Hills.

President Will Roach said an extensive review of the impact of higher oil prices on the economic bitumen resources has determined that the producible resource is 4 billion to 5 billion barrels, a “substantial increase” from the current best estimate of 3.5 billion barrels. That estimate does not include any of the new lands acquired recently by the consortium.

• Suncor Energy plans to pour C$4.4 billion into oil sands-related businesses next year, representing 80 percent of its capital spending plans.

The breakdown shows C$900 million is earmarked for sustaining existing operations, including the planned relocation of mining and extraction facilities to support extended mining areas.

About C$1 billion is allotted to Suncor’s goals of hiking production to 350,000 barrels per day in 2008, including debottlenecking and productivity improvements, and C$2.5 billion is targeted to support the company’s goal of exceeding 500,000 bpd in the 2010-2012 period.

Chief Executive Officer Rick George said the plans reflect his company’s “significant growth opportunities over the next several years.”

In a gesture to those who see the oil sands as Canada’s worst source of greenhouse gas emissions, Suncor is investing C$120 million on renewable energy development, including construction of its fourth wind power project in Ontario and investment in biofuels.

The bad:

• Devon Energy is the latest to bemoan the capital costs of building production from northern Alberta, estimating that doubling output to 70,000 bpd from its Jackfish project by 2011 could cost in the range of C$650 million-$700 million, compared with the first phase price tag of C$550 million, or within 5 percent of its original budget.

The Oklahoma City-based independent said it is feeling the pinch from inflationary pressures, as labor costs rise in response to plans for a possible C$225 billion of capital spending over the next 10 years.

The concerns come only three months after Devon President John Richels said his company was not experiencing the same costs pressures as its peers and was pressing ahead with expansion plans.

He said Devon had cushioned the impact by contractually fixing the cost of many surface facilities.

• What started out good, with the Joslyn project, operated by France’s Total, initiating commercial production, quickly turned sour.

The start-up phase is using steam assisted gravity drainage techniques and is expected to reach its plateau of 10,000 bpd in 2008.

But Total’s 16 percent partner, Enerplus Resources Fund, followed that announcement by warning that Joslyn’s major surface mining operation has been delayed to 2013 from 2010 because of the competition for construction labor and materials.

A decision on whether the mine will come on stream at 100,000 bpd or 50,000 bpd has also been postponed from this year to 2007, Enerplus said.

The ugly:

• Calgary-based consulting firm Ziff Energy Group is predicting one oil sands trend the sector would sooner not hear about.

Bill Gwozd, Ziff’s vice president of gas services, told a Canadian Heavy Oil Association conference that gas consumption to extract and process the oil sands could soar over the next eight years to 1.9 billion cubic feet per day from 600 million cubic feet per day at the same time Western Canadian production could shrink by 3 bcf from its current 16 bcf.

He said the numbers could cause alarm for users of Alberta gas — across Canada and the United States — that the “gas might not be there.”

Ziff estimates that based on the average consumption of 500 cubic feet per barrel for mining operations, the cost of gas could grow to C$3-$3.40 per barrel of production between 2006 and 2015, while the in-situ average need of 1 thousand cubic feet could translate into gas costs of C$6-$6.80 per barrel.

But Gwozd said that facing total consumption costs of C$5 billion a year will give added incentive to the oil sands sector to improve efficiency, lower gas consumption and develop alternative fuels.

In a new study the Canadian Energy Research Institute forecasts that by 2020 oil sands production will reach 2 million bpd from mines and 1.8 million bpd from in-situ projects.

The study assumes the capital costs for mining and extraction projects will reach C$20,000 per barrel, C$32,000 per barrel for upgraders and C$55,000 for mining and extraction and upgrading projects.

The fascinating:

• Jim Dinning, the hot favorite to replace Ralph Klein as Alberta premier in December, grasped one of the province’s most prickly nettles by insisting nuclear power remains an option to power the oil sands sector.

He said natural gas is being “wasted” to remove and upgrade bitumen, but apparently startled his audience in declaring that “nuclear power has got to go on the list of energy sources to be considered to support the development of the oil sands.”

Two of Dinning’s rivals, Ed Stelmach and Lyle Oberg, agreed nuclear power should not be ruled out, despite widespread concerns among Albertans about the security risks.

Meanwhile, Klein, a vocal opponent of nuclear power, seems to be having second thoughts.

He is weighing an offer to become a nuclear lobbyist once he is out of political office, while candidly admitting “I don’t know anything about it.”

Alberta ethics regulations require a six-month cooling off period before Klein or any of his cabinet ministers can accept a job with firms that do business with the government.

Klein said he intends to take some time deciding which positions to accept, certain the end result is that he will “make a fortune … a hell of a lot more than I’m earning right now.”

Whatever jobs he takes “will be the ones that require the least amount of work,” Klein declared.

• Marathon is pushing ahead with plans to reconfigure all or some of two U.S. refineries to handle as much as 280,000 bpd of Canadian oil sands crude.

It has awarded a front-end engineering and design contract to convert its 100,000 bpd Detroit refinery to run entirely on Canadian heavy crude and is advancing a feasibility study to install similar upgrading facilities at its Catlettsburg, Ky., refinery, converting heavy crude capacity to 180,000 bpd of a total 220,000 bpd at the plant.

Rather than following the example of EnCana and ConocoPhillips in establishing a joint production and upgrading venture, Marathon is inviting bids for partnership rights, apparently swayed by the number of proposals it attracted.

As well, Marathon has indicated it may retain the upgrading rights for its 192,000 bpd refinery at Robinson, Ill., although the company insists the facility is not “off the table” to proposals.






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