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Oil sands in full flight Suncor partnership, Shell launch 2 mines; Enbridge rolls out plans for 2 pipelines; Suncor boss has no worries about fate of lines Gary Park For Petroleum News
The wall holding back development of the Alberta oil sands collapsed in dramatic fashion Oct. 31, with corporate sanctioning of four projects carrying a combined price tag of at least C$23 billion.
The end result was an end, however short-lived, to those who believe that exploiting Alberta’s bitumen deposits is too costly and doomed to fail in the face of unrelenting criticism.
A partnership of Suncor Energy, Total and Teck Resources, a standalone venture by Royal Dutch Shell and two projects by Enbridge emerged from years of careful evaluation.
For more than a year, the sector has been almost silent, partly because of concerns over opposition to major pipeline projects out of Alberta and partly because of uncertainty over cost inflation.
The Suncor-led partnership put an end to five years of delays by giving the go-ahead to its Fort Hills mine, a C$13.5 billion venture to initially produce 200,000 barrels per day of bitumen, with the long-range prospect of adding at least another 180,000 bpd. It will be located in the core Athabasca oil sands region of northeastern Alberta.
Shell joined the rush by giving the green light to an 80,000 bpd thermal-recovery project which will be the largest oil sands operation in the Peace River area of northwestern Alberta, which will now join Athabasca and Cold Lake as the core regions. Although the company did not disclose a price tag, observers believe it will be at least C$7 billion.
Accompanying those announcements, Enbridge unveiled two pipeline projects to serve Fort Hills and other oil sands producers at a combined cost of C$3 billion.
Economics ‘positive’ Suncor Chief Executive Officer Steve Williams said a careful evaluation has convinced his company that the economics of proceeding with Fort Hills are “positive” and will yield a “significant source of long-term cash flow” over more than 50 years.
Suncor is 40.8 percent operator, after inheriting the Fort Hills asset when it bought Petro-Canada in 2009. France’s Total, which formed a partnership with Suncor three years ago, holds 39.2 percent and mining giant Teck Resources has 20 percent.
Williams said the partners hope to cushion any inflationary impact by spreading construction costs over four years and limiting the workforce to 5,000-5,500 workers.
The capital outlay is estimated to work out to C$84,000 per flowing barrel of bitumen. So far, Suncor has spent C$650 million.
Steve Reynish, executive vice president of oil sands, said planning for Fort Hills has been based on long-term Brent crude prices of US$100 per barrel and West Texas Intermediate prices of US$95 per barrel, with bitumen expected to average 60 percent of those targets.
He said operating costs are forecast to average C$20-C$24 per barrel, plus sustaining capital costs of C$3 per barrel and Alberta government royalties of C$11.50 per barrel, resulting in an internal rate of return of 13 percent — a number challenged by several analysts, with Samir Kayande of ITG Investment Research targeting 11.5 percent, and Phil Skolnick of Canaccord Genuity and Menno Hulshof of TD Securities each estimating about 10 percent.
However, the gap between Suncor and analysts is not that huge given the difficult economics of an oil sands megaproject compared with other energy plays such as the light, tight oil of the North Dakota Bakken.
Pipelines not an issue Williams said the three owners will make their own choices about where to refine their share of the bitumen, with Suncor expecting its volumes will be shipped as far as the U.S. Gulf Coast and “even farther afield,” without specifying whether that could include offshore exports.
He indicated that a shelved coker unit at Suncor’s Montreal refinery could be a “very attractive option” for processing the bitumen.
Williams made it clear that Fort Hills is not dependent on approvals for TransCanada’s Keystone XL and Energy East pipelines or Enbridge’s Northern Gateway system.
“We have no market access issues,” he said. “We have plans in place to take all of our base and growth barrels to market.”
Williams told analysts that Fort Hills is based on “one of the best undeveloped oil sands mining assets” in the core Athabasca oil sands region of northeastern Alberta, with best estimate contingent resources calculated at 3.3 billion barrels, enough to support an operating life of more than 50 years.
First oil is expected in the final quarter of 2017, ramping up within 12 months to 90 percent of nameplate capacity.
Shell plans on vertical wells Shell said its Carmon Creek project, which gained regulatory approval in April, represents a “significant development opportunity,” said Lorraine Mitchelmore, Shell’s executive vice president.
“Our decision to invest in Carmon Creek has been carefully studied with the goal of designing a project that is competitive from a commercial, technological and environmental perspective,” she said.
The company plans to use vertical rather than horizontal wells, believing that will achieve better oil recovery.
Enbridge to move on two lines In its support role, Enbridge said it will go ahead with two related pipelines in northern Alberta — a C$1.6 billion Wood Buffalo system in Alberta and C$1.4 billion to develop its Norlite diluents pipeline in the Athabasca region.
The 281-mile addition to Wood Buffalo will carry 490,000 bpd from Fort Hills and other oil sands production to Enbridge’s mainline hub at Hardisty, Alberta, and is scheduled for completion in the second quarter of 2017.
Norlite is planned to initially deliver 270,000 bpd of diluent to several producers in the Athabasca region for blending with raw bitumen to facilitate pipeline transportation. The project, which could be expanded to 400,000 bpd, is targeted to start service in the second quarter of 2017.
Steve Wuori, Enbridge’s president of liquids pipelines and major projects, said in a statement that Norlite is his company’s entry into the regional diluent pipeline business and extends the pathway created by the Southern Lights diluents pipeline from the United States to Edmonton.
He said the Wood Buffalo extension will build on an established relationship with Suncor and Total and starts one with Teck.
Other projects abandoned, on hold The sanctioning of Fort Hills is the only one of three major oil sands ventures to survive since Suncor and Total announced an alliance three years ago, which was almost immediately squeezed by the economic downturn and rising costs in the oil sands.
Earlier this year they abandoned their C$11.6 billion Voyageur upgrader to process 200,000 bpd of bitumen into synthetic crude, despite spending C$4 billion on the project, largely blaming the rapid rise of tight oil in the North America and increased competition for light, sweet oil refining.
Still in a holding pattern is the Suncor-Total 100,000 bpd Joslyn oil sands mine, whose economics continue to look shaky to Williams.
Suncor trims guidance Separately from the Fort Hills announcement, Suncor trimmed its 2013 guidance to 545,000-590,000 barrels of oil equivalent per day from its original 570,000-620,000 boe per day, blaming three factors: The shut-in of production in Libya, mechanical problems which have lowered production at the Syncrude Canada oil sands consortium and the sale in September of a large portion of its North American natural gas division.
Suncor said its 2013 capital budget has been reduced by C$300 million to C$6.7 billion because of a shift in priorities for some operations and lower cost estimates for some E&P programs.
The company reported record average production of 396,400 bpd from its oil sands operations in the third quarter, compared with 341,300 bpd a year earlier, while overall output was 595,000 boe per day, up 59,700 boe per day.
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