Is the U.S. a Friend or Foe?

Alberta Oil - - OBSERVER -

The United States is of­ten

por­trayed in Cana­dian me­dia as the bad boy on the block, Canada’s for­mer client turned cut­throat com­peti­tor, forc­ing us to sell our land­locked crude for far less than it’s worth. In re­al­ity, for those big oil sands pro­duc­ers that op­er­ate re­finer­ies south of the bor­der, the U.S. is the gift that keeps on giv­ing. The shale boom has pro­vided plenty of cheap pipe­line con­den­sate from the U.S., which is sold in Canada at far higher rates and re­cy­cled in dil­bit. Fur­ther­more, the de­cline in Alaskan and Cal­i­for­nian heavy crude out­put has cre­ated more ca­pac­ity for Cana­dian ex­ports at U.S. re­finer­ies. Still there are some who ar­gue for more oil re­fin­ing right here in Canada, es­pe­cially given the dif­fi­cul­ties that oil sands pipe­line com­pa­nies are hav­ing in win­ning pub­lic sup­port for their projects. Bruce Peachey is an in­struc­tor of petroleum engi­neer­ing at the Univer­sity of Al­berta, and he’s been think­ing a lot about those very things lately.

How many new up­graders have been planned and can­celled in Al­berta re­cently, and why?

At the peak there were around 13 planned ex­pan­sions and new up­graders. Only one, North West Red­wa­ter Part­ner­ship’s at Stur­geon, is go­ing ahead. The eco­nom­ics of up­grad­ing are driven by the high dif­fer­en­tial be­tween heavy crude and syn­thetic crude; peo­ple get ex­cited when the dif­fer­en­tial is $40 per bar­rel but cool off when it’s $5 per bar­rel. In the case of Husky and Syn­crude’s up­graders, the gov­ern­ment had to buy in to sup­port them. In the case of the North West up­grader, the gov­ern­ment guar­an­teed both a sup­ply of bi­tu­men and a price, so it couldn’t be taken else­where.

Com­pa­nies like Para­mount Re­sources that don’t have re­finer­ies in the U.S. are very in­ter­ested in up­graders so they don’t have to buy dilu­ent from their com­peti­tors. U.S. re­finer­ies that can han­dle Al­berta’s bi­tu­men re­cy­cle dilu­ent, buy­ing it at a dis­count when it ar­rives as di­luted bi­tu­men and send­ing it back to Canada at a pre­mium to the oil sands op­er­a­tors.

The Kearl project didn’t build an up­grader be­cause Exxon has its own sup­ply of dilu­ent and re­finer­ies in Illi­nois. Shell’s Car­mon Creek needed the North­ern Gate­way pipe­line to the B.C. coast to be vi­able. North­ern Gate­way would ship dil­bit to the coast for Shell’s Cal­i­for­nian re­finer­ies that can re­fine heavy crudes, and have a re­turn pipe­line bring­ing back dilu­ent to Al­berta. Right now, Shell’s Scot­ford up­grader in Al­berta’s In­dus­trial Heart­land is pro­cess­ing Shell’s own mined bi­tu­men from the Al­bian Sands project. It has a nice steady sup­ply, so it won’t likely ex­pand to take Car­mon Creek crude un­til the Al­bian min­ing pro­duc­tion winds down. The Trans Moun­tain ex­pan­sion is a one-way pipe­line, so there’s no re­cy­cling of dilu­ent.

Dilu­ent costs only $3 to $5 per bar­rel to re­cy­cle. Com­pa­nies with­out U.S. re­finer­ies might buy dilu­ent at 10 per­cent over WTI in the U.S. and sells it as part of the dil­bit vol­ume at 30 per­cent be­low WTI in Al­berta. That’s why com­pa­nies like Para­mount want to send it by rail where only seven per­cent is dilu­ent rather than 30 per­cent in a pipe­line. From a Cana­dian macroe­co­nomic per­spec­tive, as dilu­ent is worth more than the oil we’re sell­ing, the bal­ance of trade takes a hit. Partial up­grad­ing means the pro­ducer doesn’t have to buy dilu­ent. But this de­pends on up­grad­ing process. Im­pe­rial has looked at vis­break­ing. This up­grades bi­tu­men enough to go by pipe­line, but it still doesn`t look like nat­u­ral crude. Even Syn­crude is sold at a dis­count to WTI and the fur­ther you get away from nat­u­ral crude the heav­ier the penalty you pay.

Do you see any more car­bon-cap­ture up­graders pop­ping up in Al­berta, see­ing as the gov­ern­ment has been non-com­mit­tal about the tech­nol­ogy?

Ju­ris­dic­tions want the jobs from up­grad­ing but not the emis­sions. CNRL has con­ven­tional ma­tur­ing oil fields south of Ed­mon­ton along the Al­berta Car­bon Trunk Line, which have wells that were aban­doned af­ter pri­mary pro­duc­tion fin­ished. CNRL is prob­a­bly lob­by­ing the gov­ern­ment to sup­port car­bon cap­ture in fu­ture up­graders for CO2 in­jec­tion—if some­one buys an oil pool af­ter its aban­doned some­one knows some­thing. ACTL has to get its CO2 from some­where and Agrium’s fer­til­izer plant and North West Part­ner­ship’s re­fin­ery won’t pro­vide enough for many projects at a time.

If KXL goes ahead, how does the de­ci­sion im­pact the Trans Moun­tain ex­pan­sion and En­ergy East projects?

It could im­pact En­ergy East, as both can get crude to the same At­lantic markets— KXL will sup­ply the U.S. Gulf Coast, which can get it to other At­lantic markets by tanker. KXL doesn’t af­fect Cal­i­for­nia as much. It will get it closer to a rail line to get it to PADD 5 in Cal­i­for­nia, but it doesn`t go di­rectly. Mex­ico might in­crease out­put in five to 10 years, if they can bring in for­eign in­vest­ment, but mean­while it’s drop­ping like a rock. How­ever, Cal­i­for­nia is still the main mar­ket we’re try­ing to get to as there are up­graders there al­ready. Ten per­cent of U.S. oil pro­duc­tion used to come from heavy oil from Cal­i­for­nia but this feed­stock has de­clined by about 500,000 b/d since 1985—they’ve been in­ject­ing steam into those fields since 1940. Alaska pro­duc­tion, in­clud­ing some heavy oil, has also de­clined by about 1.3 mil­lion b/d so this loss of U.S. West Coast sup­plies has cre­ated sur­plus ca­pac­ity in Cal­i­for­nia that is now open to other heavy oil sup­plies. Venezuela is build­ing pipe­lines through Ecuador to get to the Pa­cific, even though their to­tal pro­duc­tion has de­clined, and Colom­bia has also built pipe­lines to get heavy oil to Pa­cific markets, with Cal­i­for­nia be­ing the clos­est. Trans Moun­tain would also likely be used to sup­ply any re­main­ing Cal­i­for­nia de­mand, in com­pe­ti­tion with Venezuela, Colom­bia, Mex­ico and Peru, be­fore it would sup­ply much to more dis­tant Asian markets.

Is the Cana­dian Oil Sands In­nvoa­t­ion Al­liance’s goal of tak­ing car­bon out of the bar­rel by 2040 re­al­is­tic?

CO2 is very sta­ble. It’s hard to turn it into some­thing use­ful with­out us­ing a lot of en­ergy and there’s a lim­ited mar­ket for graphite etc., which has to com­pete on cost against nat­u­ral sources. Tech­ni­cally pro­cesses can be de­vel­oped but they are ex­tremely un­likely to be eco­nom­i­cally vi­able by 2040.

Bruce Peachey, In­struc­tor of petroleum engi­neer­ing, Univer­sity of Al­berta

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