A flurry of announcements involving another C$12 billion in major oil sands ventures in Alberta has been accompanied by indications that the sector is working on solutions to keep costs in check and find new ways to get their production to markets in the United States.
In less than a week, Imperial Oil said it will seek regulatory approval next year for an C$8 billion project; Suncor Energy, shrugging off a 20 percent rise in cost estimates, gave the green light to a C$3.6 billion expansion; and Syncrude Canada got the go-ahead to spend C$400 million retooling an upgrader to slash sulfur dioxide emissions.
In total the three schemes are associated with another 410,000 barrels per day of synthetic crude output over the next decade.
Almost submerged in that wave were two developments that signal new trends in handling and processing the ballooning oil sands volumes.
EnCana is working on a venture to process oil sands production at Premcor’s Ohio refinery and by mid-December new Canadian heavy crude blend that could open up all of North America to oil sands output is expected to make its debut.
Meanwhile, Imperial issued its strongest hint yet that it may scrap plans for an upgrader on the site of its Kearl Lake project as it explores options including using the refineries of its U.S. parent ExxonMobil.
More than any single factor, the upgraders, which convert the sticky oil sands’ bitumen into refinery-ready crude, have saddled operators with punishing cost overruns that have amounted to billions of dollars.
Upgraders a costly issue
Few know better than Imperial, which has a 25 percent stake in Syncrude, and earlier this year lined up with other partners to swallow some tough medicine when the giant consortium approved an expansion costing C$7.8 billion, 90 percent above initial estimates.
“Building upgraders … has been less than fun,” Imperial Chief Executive Officer Tim Hearn told shareholders and analysts Nov. 30. “That’s about as polite as I can say it.”
Without ruling out an on-site upgrader, he made the challenge clear to Imperial staff.
“Somebody’s going to have to show me how we’re going to build an upgrader a heck of a lot better (that other alternatives) … it’s going to be a hard hurdle for my organization to convince me that that’s the right path,” he said.
The Kearl project involves two leases owned 100 percent by Imperial and two adjacent leases owned by sister company, ExxonMobil Canada.
A regulatory application should be filed in 2005 and initial production for 2009 or 2010 is pegged at 100,000 bpd, growing to 300,000 bpd. Imperial is already pumping 180,000 bpd from its wholly-owned Cole Lake operations and its Syncrude stake.
Hearn said that before embarking on Kearl, which could cost as much as C$8 billion, the company must “take a real hard look” at what it has learned over the last seven years.
In addition to finding an answer in ExxonMobil’s U.S. refineries that could include upgrading the bitumen at Imperial’s Strathcona refinery near Edmonton.
Imperial has also been involved in studying a reversal of a pipeline to ship production from Chicago to Gulf of Mexico refineries which are able to process heavy oil.
“We will look for a path forward that gives us a competitive advantage,” he said.
Syncrude will reduce sulfur dioxide emissions
Separately, Syncrude has approval from Alberta regulators to spend C$400 million reducing sulfur dioxide emissions at its northern Alberta upgrader.
The net effect of the project would be to hold emissions at their current level of 245 metric tons per day even after production has climbed to 350,000 bpd in 2006 from the current 250,000 bpd. Other emissions would also be reduced by about 50 percent.
But a Syncrude spokesman said the approval does not apply directly to the expansion.
Instead, the consortium will make improvements to its base plant to “significantly cut emissions starting in about mid-2009.”
Suncor’s board of directors has cleared the way for a C$3.6 billion addition to boost production to 350,000 bpd by 2008 from 260,000 bpd in late 2005, putting the company well along the path to its targeted 500,000-550,000 bpd by 2010-2012.
The budget includes C$2.1 billion to expand capacity at its Fort McMurray upgrader and C$1.5 billion enhancing mining and extraction.
The upgrader work is C$600 million above original estimates, but the new plans call for expanded volumes to 350,000 bpd rather than the 330,000 bpd proposal made last March.
Downstream players look for cost-cutting answers
While the upstream end of the oil sands is galloping ahead the pace is also quickening downstream as players look for cost-cutting answers and ways to open up more markets.
A breakthrough is expected by mid-December when Western Canadian Select hits the market before Christmas.
Four partners — Canadian Natural Resources, Petro-Canada, EnCana and Talisman Energy — will introduces 250,000 bpd of the blending of heavy oil from conventional wells, oil sands bitumen and premium light synthetic crude, along with condensate made from chilled natural gas that is added as a diluent to aid the flow of WCS in pipelines.
The hope is that other producers will add to the supply pool, including the Alberta government, with its royalty share of production.
If WCS gets a positive reception, sales are forecast to reach 450,000 bpd by 2007 and could peak at 1 million bpd.
It is not yet certain what pricing basis will be used, although talks are taking place with the New York Mercantile Exchange.
But EnCana Vice President Walt Madro told the Edmonton Journal WCS will cut by at least half the 19 heavy oil grades now marketed out of Western Canada and will offer a broader appeal to more U.S. refineries.
If the Nymex creates future contracts that could improve prices, he said.
Rapid change in North American oil markets
The rapid change in North American oil markets is reflected in the fact that West Texas Intermediate is down to 350,000 bpd and Brent has dropped to 360,000 bpd, while FirstEnergy Capital is forecasting heavy crudes will surpass 2 million bpd by 2015.
EnCana, which has converted more than 50 percent of its term supply contracts to WCS from January, is involved in a study that could result in a US$1 billion upgrade of Premcor’s Ohio refinery to handle 200,000 bpd of blended oil sands crude.
Within nine months the two companies could form a 50-50 joint venture to own and operate the reconfigured refinery, although Premcor Chief Executive Officer Thomas O’Malley told a Nov. 30 conference call that the onus is on EnCana to figure out ways to build or modify heavy crude pipelines from Chicago to Lima in west-central Ohio.
In a separate pipeline development, Devon Canada and MEG Energy have created Access Pipeline as a joint venture to study building a C$300 million blended bitumen and diluent pipeline from Christina Lake in northeastern Alberta to Edmonton.
Although Devon is not committed to owning or operating the pipeline, it views the project as one option for transporting 35,000 bpd from its C$550 million Jackfish project that is aiming for full production by 2008. MEG is working on a nearby pilot project to produce 5,000 bpd of bitumen.
The proposed Access system would offer capacity of up to 400,000 bpd. A regulatory application should be filed in the first quarter of 2005, with start-up occurring in late 2006.
