Explaining Canada's hurry to build pipelines in the U.S. - Macleans.ca

Explaining Canada’s hurry to build pipelines in the U.S.

Andrew Leach on why the status quo is hurting Canada


Washington’s decision to temporarily shelve the Keystone XL project has Canadian companies rushing to redraw the pipeline map. Enbridge announced plans to reverse the direction in which crude oil flows in the Seaway pipeline connecting Oklahoma to Texas in order to send more oil from Midwestern refineries to those on the U.S. Gulf Coast. Keystone godfather TransCanada, on the other hand, wants to start building the southern leg of the pipeline, also linking Oklahoma to Texas. Both projects aim to reduce the pressure on a bottleneck of crude in the U.S. Midwest that’s been building up for a year. Why are Canada’s majors so eager to build pipelines to the Gulf? Andrew Leach, a professor of natural resources, energy, and environment at the University of Alberta’s Alberta School of Business, explains.  

Why is there a buildup of crude oil, including Canadian crude, at refineries in the U.S. Midwest?

It’s a simple case of supply and demand in a local market. We’re often told the market for oil is global, but in truth it’s more of an integrated web of regional markets and the U.S. Midwest is one of those regions (in the graphs, you’ll see it referred to as PADD 2). This regional market has pipelines running both in and out of it, and oil is used by refineries within the region to produce gasoline, diesel fuel and other products. There are essentially two ways in which crude oil gets out of the Midwest–either it’s refined or it’s transported to another region by pipeline, rail, barge, or truck. On the demand side, use of crude oil by Midwest refineries has been decreasing since the year 2000, as shown in the figure below:

On the supply side, two sources of growing oil production feed largely into the Midwestern market: Canadian production, both conventional and oilsands, and U.S. Bakken production in North Dakota and Montana. Canadian production has been especially important in this trend, with imports into the Midwest increasing by about 50 per cent over that same 2000-2011 time period, as shown below:

Normally, it’s possible to take care of excess imports into one region by moving excess supply to another region, and that has been happening in this case too, but just not quickly enough. You can see in the graph below the jump up in movements of crude oil from the Midwest to the Gulf Coast, increasing over fourfold since 2005:

Even with the added shipments out of the Midwest, a glut of oil remains, and the excess supply has pushed down prices. In the last year, the spread between what a barrel of oil is worth in the Midwest (called WTI–which is usually the oil price you see on the nightly news) and what it’s worth either on the Gulf Coast (LLS) or when shipped to Europe (called Brent–which is generally used as a benchmark for world prices) has widened to historic levels.

How would unclogging the bottleneck affect prices and profits for Canadian oil producers?

This price spread has been hurting Canada in two ways. On the production side, since most of the export capacity leaving Alberta goes to the Midwest, our producers have been receiving significantly less value for their oil than they would if that oil were shipped to the Gulf Coast, or to any other port where it would sell at world prices. With Canadian oil exports to the Midwest at over 1.6 million barrels per day, a discount of $25 per barrel translates into about $15 billion per year of lost value to producers. And because these lower revenues mean lower royalty payments and income taxes, these costs are felt by all Canadians and in particular Albertans.

In addition, since Eastern Canada continues to import oil, and since they are importing oil principally from overseas and not from the Midwest, they are paying premium price for oil. In fact, at times during the summer and fall this year, when the price spread was at its widest, Canada was effectively facing a financial trade deficit for oil—the value of the oil we exported was lower than the value of oil we imported—even though we were a net exporter of oil in terms of barrels. So, Canadians are both paying higher gas prices as a result of higher world oil prices and getting less for their oil production as a result of the depressed regional oil prices in the Midwest.

Either increased shipping capacity out of the Midwest or alternative markets for Canadian production would increase oil production profits for producers and the royalty and tax inflow for federal and provincial governments. However, since Canada’s population is concentrated in markets that already fetch their oil at higher world prices, even if western Canadian producers were to access better prices for their products, that would be unlikely to have a meaningful effect on gasoline prices or other segments of our economy.


Are Enbridge and TransCanada really in a race to get the oil from the Midwest to the Gulf, or is there a need for both pipeline routes?

Pipeline companies are generally in the business of moving products from where there is an over-supply to where there is an under-supply. Right now, the price spread makes it clear there is a need for more capacity from the Midwest to the Gulf. If you look at production forecasts for oilseeds—where exports could exceed 3.5 million barrels per day by 2020—as well as U.S. production in the Bakken—watch this animation to get a feel for how fast that’s growing—then there’s definitely a market for significant new pipeline capacity.

Enbridge has two projects in play now. First, it announced last week the purchase, reversal and proposed expansion of the Seaway pipeline, which will eventually move 400,000 barrels per day of oil from the Midwest to the Gulf Coast. Second, it has proposed the Flannagan South pipeline project, which will take another 400,000-500,000 barrels per day from the Chicago area south to the Gulf, with part of this project likely to involve a twinned pipeline on the Seaway route. These two projects alone are unlikely to be sufficient to completely eliminate the glut of oil in the Midwest, so there is likely still room for TransCanada’s Keystone Phase 3 (the southern part of the XL pipeline) from Cushing, Oklahoma to Houston and Port Arthur, Texas.

Was the Keystone XL expected to eliminate this Midwestern buildup?

Yes, the commercial case for the Keystone XL project was entirely based on this Midwestern buildup and future production growth in the Bakken and Canadian oilsands. If you look at the Keystone project map, you will see that the pipeline will pick up production from those two regions, largely bypass the Midwestern region, and deliver oil to the Gulf Coast. Currently, the Gulf region imports over 5.5 million barrels per day of crude oil and related products at world prices. In other words, without the Keystone XL system, shippers are selling into depressed Midwestern markets or paying extra costs for transport by rail. Thus, the Keystone XL pipeline offered a win-win for producers and refiners, notwithstanding the environmental issues along its route.

As shown in the figure above, over three million barrels per day of imports to the Gulf Coast come from OPEC countries, many of which have frosty relations with the U.S. The commercial case for the Keystone XL project, which would allow Gulf Coast refiners to access oil from lower-priced, landlocked markets such as Alberta, therefore, would potentially allow the U.S. to reduce their dependence on foreign oil–albeit by a small amount.

Andrew Leach is an associate professor at the University of Alberta’s Alberta School of Business. He blogs regularly at: http://andrewleach.ca/. You can follow him on Twitter at: @andrew_leach


Explaining Canada’s hurry to build pipelines in the U.S.

  1. I can’t say as I have much sympathy for this situation.

    • you should you depend on it

      • No, ‘fraid not.

  2. So can someone tell me why, if we import it at high prices on the east, and export it at low prices on the west, isn’t there a rush to simply transport it from the west to the east? And if the answer is a lack of refineries, does building a new refinery somewhere in the middle not make economic sense, as this would not only ease the glut going to midwest refineries, it’d allow the rest of Canada to buy the refined products cheaper even as the price for midwest refined oil goes up in the US.

    • I believe the answer to that was “Let those eastern bastards freeze in the dark”.

      • Blah blah blah.. I’m not asking about what was. I’m asking what reason such a thing can not be. Unless you’re suggesting that the profit motive is over-ridden by hurt feelings.

        • It ‘cannot be’, because of ‘what was’…and still is.

          Alberta forgets it is land-locked….the only route left is east

          And yes, the profit motive can be overridden by a lot of things.

          • So you’re saying that every oil industry executive with enough clout/resources to build a refinery would rather eschew the profits for him and his shareholders because of hurt feelings over the NEP? Seriously?

          • Hey, don’t look at me. It was Albertans wot said it, not moi.

            Mind you, this is a province that figured it should have nuclear subs.  LOL

      • That really upsets the Maritimers!!

        • To Albertans…it’s all easterners.. from their border on

          • Hahaha….yes, I have heard people from Saskatchewan refered to as “easteners”….not.  
            Be honest, Emily….Ralph Klein, who was mayor of Calgary at the time made the comment about eastern bastards freezing after the National Energy Program crippled Alberta.  He was refering to Ottawa and specifically Pierre Elliott Trudeau and the Liberal Party.  If you lived in Alberta as you claim, you would know that Albertans have no issue with people from the maritimes and when we refer to the east, we mean Ontario.

          • a) the NEP didn’t cripple Alberta. The world price of oil collapsed.

            b) yes Albertans always confuse their geography

            c) Maritimers are the ones with the ‘culture of defeatism’ according to Albertans

          • Emily, look that quote “let those Eastern bastards freeze in the dark up” on google and Wikipedia will tell you all about what the NEP did to Alberta…and why those bumper stickers became so popular.
            If you had a clue, you would know half of the population of Fort McMurray is made of of Newfoundlanders so your theory about Albertans looking down on Maritimers is wrong.

        • Oh no, when Ralph Klein said “let those eastern bastards freeze in the dark”, he was the mayor of Calgary and he was talking about central Canada and specifically, Ottawa.  In Alberta, when we talk about ‘down east” we mis-speak because we ultimately mean Ontario.

    • People have talked about this, and it’s not an unreasonable suggestion.  There is not really any heavy-capable refinery capacity in the east, but there’s plenty of light/synthetic supply currently going south which could move east. 

    • Blame Diefenbaker! In the 1960s a decision was made to separate Canada along the Ottawa river, with folks west of the river forced to buy Albertan oil. To the east it was historically cheaper to import oil, and there was a powerful pro-import constituency among refineries in Montreal that didn’t want to pay for Albertan oil. 

      That decision had some path-dependent effects, in terms of where refineries clustered, and where pipelines were built. Because Albertan oil wasn’t sold east of the Ottawa river, you got an industry that was integrated in a north-south direction. 

      • And if I cared how it was as compared to how it is/can be, you’d have something worth talking about.

        • He’s talking about a confused version of the Borden Line.

          • No, I’m talking about the National Oil Policy. For somebody as old as time itself, your knowledge of history is wanting.

          • Yes, and the Borden Line.

            You’re just confused about it.

        • Yeah, because the politics of how this came to be have nothing to do with the feasibility of reforming energy policy. 

          • Wait.. so you’re saying there’s legislation against doing this now? Okay.. that’s an important reason then.

          • But nothing that couldn’t be changed, if so, should Harper want to.

    • Because it takes a minimum of 10 years to go through the regulatory hoops to build a refinery, which is why there have been so few built in the last 20-30 years in North America. There are refineries in Ontario processing Alberta crude but I believe (could be wrong) that they are at capacity.

      • Ah. Thank you, this does go some way to explaining it.  That’s a hell of a long-term plan, and when corporate success is measured in quarters while oil prices are changing by several percent a day.. I can see why companies would be reluctant.

  3. Maybe I missed it somewhere here, but what of the US State & Energy Departments’ report to President Obama stating that not building Keystone XL would result in more jobs and investment in Alberta instead of the US for upgrading? And I’ve also heard that upgrading more oil in Alberta would put off the need for a pipeline like this for decades. I appreciate your analysis of the problems facing industry, but with this being such a controversial project, I think it would be great for someone to clearly address the criticisms.

    • Joel,

      Not sure why more upgrading capacity would put a project like KXL off for decades.  More upgrading capacity would still mean you want to ship out upgraded product. Depending on the upgrading technology (carbon removal vs. hydrogen addition) you are likely +/- 15% on the volumes.  See my blog at andrewleach.ca for some numbers on current capacity vs. growth forecasts.  You’d perhaps change the timing of a crunch by 1-2 years, but you’d further exacerbate cost inflation in Alberta, so the net value effect would be negligible.


    • Well, refineries are very technologically sophisticated beasts, and they’re also massively expensive and have large workforce requirements. Although I would agree that having more refining capacity in Canada is a good idea, I think refining a large proportion of what we produce is just beyond what can be considered reasonable, when the shortage of tradesmen in Alberta is already huge, and when short-term considerations must also be observed. Keystone may be viable right now, and as oilsands production grows, there will still be opportunities for Canadian refineries to spring up.

      • Okay. This is a good reason finally, but that really only applies in Alberta. I haven’t really seen a reason we can’t have a refinery somewhere else. So far as I’m aware, there’s no shortage of tradesmen in SK or MB.

        • And I’m sure a refinery at the head of the Great Lakes, with the ability to ship to markets east, west and south, could quickly be profitable and provide work in an area that could use it.

  4. Excellent overview and explanation of the situation Andrew.  I just bookmarked your blog, Rescuing the frog – chock full of information.
    So sad this has become so emotional.  Robert Redford is at it again today – funny but I anticipate some witty journalists making future use of Redford vs Redford, lol

  5. Andrew,

    Nice piece. But, I would like to take issue with one thing we discussed previously on twitter. You state here:

    This price spread has been hurting Canada in two ways. On the production side, since most of the export capacity leaving Alberta goes to the Midwest, our producers have been receiving significantly less value for their oil than they would if that oil were shipped to the Gulf Coast, or to any other port where it would sell at world prices. With Canadian oil exports to the Midwest at over 1.6 million barrels per day, a discount of $25 per barrel translates into about $15 billion per year of lost value to producers. And because these lower revenues mean lower royalty payments and income taxes, these costs are felt by all Canadians and in particular Albertans.

    As I indicated earlier http://twitter.com/#!/JvfM1/status/137568098143318016 ” The obvious sol’n is vertical integration”  (wiki def’n here: http://en.wikipedia.org/wiki/Vertical_integration )

    In other words, the producer also owns the refinery, so that any excess profits (diff between crude price and sales of refined gasoline etc) are captured by the same company. The issue then becomes one of accounting (ie transfer pricing and where do you report profits – which province/state/country?)

    It seems to me a few years ago, some oil sands companies and O&G companies that owned refineries were entering into joint ventures on this basis (EnCana?)  And this recent G&M piece suggests the same situation exists for some Gulf Coast refineries:

     As Texas-bound crude shipments from Mexico and Venezuela shrink, these American refineries – some owned by the same companies with operations in the oil sands – are running under capacity.

    So, a couple of questions.

    Jim Prentice was reported as saying in Edmonton:  “He pointed to the planned C$15 billion North West Upgrader, which will process the royalty oil from the Alberta government, as an important step in that process.”

    What say you to this approach, and also, where do you get the 3.5 million barrel/d by 2020. Seems like one hell of a lot of “oilseeds”?


    • Good questions. 

      First, 3.5 million bpd by 2020 is the ERCB’s current forecast, consistent w CAPP’s. When he was energy minister, Ron Liepert was regularly quoting 3-4 mbpd by 2020, and occasionally higher.  Second, you are correct that JVs like those of Cenovus in WoodRiver insulate them from the effects of the depressed WTI as they earn higher refinery profits.  However, both the Albertan and Canadian governments do not share in that hedge as they collect royalties based on WTI, and taxes based on profits earned in Canada. Finally, vertical integration has a role to play, but the heavy-to-light differential is not markedly different in Edmonton vs. Chicago vs. Port Arthur.  At the end of the day, upgraders in Alberta will be competing with brownfield capacity in the US, and we’ll still be looking to ship most of the production into their markets. I can see some advantages of the BRIK program, but at the end of the day if you are subsidizing jobs with bitumen in a tight labour market, you’re costing yourself on royalties from other projects due to cost inflation.


      •  I can see some advantages of the BRIK program, but at the end of the day if you are subsidizing jobs with bitumen in a tight labour market, you’re costing yourself on royalties from other projects due to cost inflation.

        Interesting choice of word. But if the “tight labour market” is a result of capital projects out of control, that are relatively short term, arguably you’re subsidizing today’s capital jobs with tomorrow’s operating jobs.

        • Right, but remember that today’s capital costs are effectively deductible against tomorrow’s taxes and roylaties.

          • Here’s an analogy 

            Q: You win the lottery. $1.5 million.  Do you accept the lump sum of $1 million today, or $150k over the next 10 yrs (I’m assuming NPVs are same)?

            A: If you are prone to blow the money on fast cars, fast life, today’s pleasures I’d suggest a 10 yr annuity. Otherwise – boom/bust.

            Same with capital projects. Too many short term – boom. When completed, if nothing else to do, move on, or bust.

  6. Btw the title: Explaining Canada’s hurry to build pipelines in the U.S.

    Could be explained, more properly, as a result of Ralph Klein’s/Alberta’s out-of-control development of the primary extraction of oil sands bitumen. Properly control oil sands development, and the rush to build pipelines, with significant longterm implications, suddenly diminishes.

    • Agreed.  No question that the unconstrained development is leading to rent dissipation.  Question is how to fix it now that the horse has left the barn.

      • Realistic forecasts on jobs and production volumes. And looking beyond today. I still find it hard to believe the 3.5 mmBbl/d by 2020. That is more than doubling current production over the next 9 yrs. And it took us what 40 yrs to get to this point?

        It seems to me just a few yrs ago, 3 mmBbl/d by 2030 was optimistic – and we’ve since seen an economic recession and heightened opposition to this type of dev int’lly

        • If you attend one of my talks sometime, you’ll see me go through some archived forecasts to make this point.  Key is that rising oil prices have allowed us to continue at this pace, and for the effects of cost inflation to be muted. Impact is that we are much more exposed to world oil price risk than we need to be, among many of the other issues you highlighted.  No question that, in a more controlled growth strategy, you’d have more upgrading. My point, in all our discussions, has been that forcing more upgrading does not create that strategy – if anything it would exacerbate current problems with inflation.

          • My point, in all our discussions, has been that forcing more upgrading does not create that strategy – if anything it would exacerbate current problems with inflation.

            Not necessarily. Depends on how it is implemented. Could be just shifting capital from primary to secondary if you control primary dev’nt through regulation.

          • Right, and that’s two policies 1) Controlling primary development 2) Requiring that production be upgraded. Then I agree with you. 

            My point is that doing 1) does not imply that 2) will happen (although it will improve cost structures for it) and that doing 2) will lead to higher costs, so in-so-doing might lead to less primary extraction, but not in the way you envision.

          • You’d be surprised how O&G companies could actually figure this out for themselves. You are allowed to develop oil sands but must be upgraded in AB or wherever.
            Then they prepare cap budgets and plan – if I build primary where do I upgrade? And if it is unfettered dev as per now, except both primary and secondary projects, then if costs inflate too high (as they did in 2008) then they just postone dev. until the costs settle back down. The self regulation model. There would be no less cap investment/activity – just of a different nature.

          • No idea why you think anything in this reply would surprise me. Still have cost inflation issues though.

  7. Gee, “It’s a simple case of supply and demand in a local market.” lol.  Is a (predictable) $15 billion of lost revenue from Cdn producers and royalty revenue just a ‘Whoops”?  lol  Give me a break.  COP decided (publicly) not to reverse the Seaway last February.  Capline still running northward at ~15% capacity.  Who wudda thunk that flowing expensive crude from the GOM northward would be a good business decision?  Of course it was.  Now that the CORE project is done, jetison the ’empty’ pipe for $1.15 billion.  Who said “I love it when a plan comes together”? 

    Do your homework.  Go ahead, look at the Maya-WCS spread to see what it really costs Alberta.  Forget the Cdn 40 API-LLS spread.  As you noted, grade counts and the bulk of exports are heavy. Maybe use the NEB export data for PADD 2.  Dil-bit future production is known years in advance.  Just add up the projects & expansions.  They all have to be permitted years ahead of production.  This isn’t rocket science. 

    Hey Alberta!  When are you gonna figure out you’ve been punked to the tune of $10~$20 billion just in 2011?  Gee, isn’t that about the same size as the trade decitit for the entire country?  Gee, isn’t Ottawa running a deficit? 

    Are you going to get punked again on Gateway? And an Eastern line? 
    Help Wanted: Location: Alberta, Qualifications: Oil business savy, planning aptitude and cahones. 

    • By all means, let’s extend the discussion to Maya-lloyd or Maya-wcs spreads.  No question that’s a more indicative spread for the potential value of exporting heavy to the Gulf Coast rather than PADD II.  The heavy-light differentials have been higher in PADD II (average of just over $20/bbl over Q1-Q3 2011) than in PADD III (average of 15.95 over the same period). Both are high, but not unprecedented historically.  Long story short, whether we’re shipping heavy or light, shipping into PADD II vs PADD III has been costing Alberta a similar amount per barrel, but more in percentage terms on heavy. 

      If you think the numbers are off by more than that, how about providing some analysis to pass your wealth of knowledge on to readers?