Why falling global oil prices aren’t hurting Alberta

Crude prices may dropping, but diluted oil sands bitumen is actually worth more than it was four months ago



Since mid-June, global oil prices have been softening, dropping from a peak value of $115 per barrel the week of June 20th to last week’s average of $97 per barrel with further decreases recorded this week as well.  These decreases have been read by many as warning signs for the oil sands, and it’s likely that they should be taken as such overall, but they also provide an illustration of how many other factors affect the value of oil sands bitumen.  For, you see, bitumen has not followed the same trends. The value of bitumen, assuming that it were sold as diluted bitumen, was about the same last week as it had been in mid-June—about $83 per barrel, in Canadian dollar terms.  As of last week, heavy oil in Alberta was selling at its lowest discount to global commodities since early 2011.

There are three primary reasons for this movement—first, changes in the North American crude market have led to reduced discounts for Canadian crudes; second, changes in the Canadian dollar have lessened the shock due to global crude price decreases; third, a significant drop in the value of diluents has changed the value of bitumen sold as diluted bitumen.


Figure 1 Bitumen and Brent crude in $CAD. Source: Bloomberg and author’s calculations.

 Let’s start with the value of bitumen—it’s not a widely traded commodity in its pure form, since it can’t be shipped by pipeline without being diluted.  As a result, we often see diluted bitumen or Western Canada Select prices equated with bitumen prices.  It’s crucial to note, however, that while diluted oil sands bitumen may trade at a small discount or premium to Western Canada Select, a barrel of diluted bitumen is about 30% diluent.  The value of bitumen itself can be derived if you net out the value of the diluent–usually a natural gas liquid or condensate–which currently trades at a premium to light oil in Canada. If we look at the last week of September, 2014, condensate traded at around $100/barrel in Edmonton, while diluted bitumen traded at around $88 per barrel.  This would imply that the value of the bitumen in the barrel was approximately $82.85 per barrel.  It is this implied value of bitumen which you see graphed above.

So, what’s happened over the past few months to lead bitumen discounts to shrink? The first place to look is the Canadian dollar, which has dropped significantly in value against the US dollar.  While we hear a lot about how a lower Canadian dollar helps manufacturing exports, it also helps crude exporters. Since mid-June, the Canadian dollar has depreciated by almost 4% against the US dollar, and so while Brent crude has dropped by 15.5% in US dollar terms, it has dropped only 12.4% in Canadian dollar terms over that timeframe.

The second place to look is the value of heavy crude in central North America, benchmarked by the Western Canada Select price discussed above, versus the value of global heavy oil benchmarks.  Relative to Gulf Coast Maya crude, the value of Western Canada Select has declined, but not by as much as Maya. Relative to mid-June prices, in US dollar terms, Maya crude has dropped almost 13% in value, while Western Canada select has dropped a little less than 9%. Once you factor in the Canadian dollar buffer, the decrease in western Canadian heavy oil prices is only 5% since mid-June.

The last and often ignored piece of the puzzle is the value of diluent. In mid-June, condensate at Edmonton was trading at over $116 per barrel – prices which declined to just under $100 per barrel last week.  This decrease means that the value of diluent in a barrel of diluted bitumen has decreased by almost $5 per barrel – a decrease large enough to compensate for the decrease in the prices paid for diluted bitumen over that time frame.  For simplicity, if you assume a facility is able to get WCS prices for its diluted bitumen, the bitumen part of these diluted bitumen barrels (70% of the barrel) would have been worth $58.40 in mid-June and $58.57 last week.  If you scale these up to a per-barrel-bitumen basis, you find prices of $83.45 per barrel in mid-June and a slightly higher $83.68 last week.

What should you take away from all this?  Remember that an oil sands project is, fundamentally, still an oil price bet, but that the product is priced locally in ways which may differ significantly from global crude oil prices over long periods of time. Over the past 3 years, we’ve seen historic discounts between global crude prices and Alberta bitumen values but those discounts are lower today than they have been since early 2011.  While global oil price decreases are a warning sign for oil sands, in this case they aren’t associated with a whole lot of pain in Alberta.

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Why falling global oil prices aren’t hurting Alberta

  1. “second, changes in the Canadian dollar have lessened the shock due to global crude price decreases”

    In other words, an overvalued dollar does as much harm to bitumen exports as it does other exports.

    A dollar at 90 cents US is only 12% overvalued, compared to one at parity which is 25% overvalued — according to the OECD’s calculations based on PPP.

    Clearly an overvalued dollar is bad for the Canadian economy. The deluge of politics and bad economics being channeled into this issue is astounding when the facts are so obvious and irrefutable.

    • You’re right…as long as you don’t concern yourself with real wages, purchasing power, etc. Why is the reaction to assume that our real wages are too low, as opposed to concluding that our price levels are too high?

      • Increasing purchasing power through an overvalued dollar at the expense of exports is not good economic policy.

        Certainly wealthier Canadians would prefer an overvalued dollar, which increases their wealth. But this purchasing power doesn’t trickle down to the little people, who pay for it with job losses. This was shown by Mike Moffat who noted in a March 2013 G&M article:

        “A decade ago, a product that cost $1 (U.S.) in the United States cost, on average, $1.20 (Canadian) in Canada. A decade later, there has been little change.”

        From this period the dollar rose 60% in value. He concluded it was the Bank of Canada’s fault. But it took no measures to intervene (e.g. cutting interest rates to counter deflation.) Just like it took no measures to counter the falling dollar from 1996 to 2003 (raising interest rates to counter inflation; in fact inflation was lower in Canada than the US during this time and so were interest rates.)

        While BoC monetary policy caused the drop in the dollar from 1996 to 2003 (because its inflation fighting policies from 1989 to 1995 were harsher than the Fed’s and it had to counter low inflation) the rise of the dollar from 2003 to 2008 (where it remained around parity until 2013) was caused by external factors. Namely, the rising of the price of oil and other commodities.

        The values of the CAD and AUD followed the rising price of oil around this time. The graphs are very similar. It would seem the 10% drop in both currencies over the last year or so is also due to falling commodity prices.

        In short, a market distortion that causes the dollar to become overvalued is not good for the economy. Just because a currency is named “dollar” doesn’t mean it’s supposed to have the same value.

        An undervalued currency is good for countries facing a crisis like high debt. An overvalued currency counters a country running a massive trade surplus. Otherwise a properly value currency is ideal.

        BTW, those who accuse Poloz of devaluing the currency are wrong. Both the CAD and AUD have fallen. And both currencies are still 10% overvalued.

  2. A couple of points needing clarification while I give your post more thought.

    1) Diluent is basically just a transportation fluid for dilbit. A flow through so to speak. So, at a basic level, shouldn’t the implied price of bitumen be unaffected by the relative movement in diluent price, which is essentially what you have confirmed?

    2) Your post does, I would suggest, reinforce the view that the market for bitumen (supply/demand) is separate/different than WTI or Brent – both light crudes. Why I would continue to suggest that rules/historical trends for light crude don’t necessarily apply to un-upgraded bitumen.

    • It is a transport medium, but when the observed price is for bitumen + diluent, the value of diluent matters. You’d be correct if we were looking at bitumen prices, and then arguing that it’s value changes because of the value of the diluent.

      • Huh? You wrote:

        For simplicity, if you assume a facility is able to get WCS prices for its diluted bitumen, the bitumen part of these diluted bitumen barrels (70% of the barrel) would have been worth $58.40 in mid-June and $58.57 last week. If you scale these up to a per-barrel-bitumen basis, you find prices of $83.45 per barrel in mid-June and a slightly higher $83.68 last week.

        Bitumen prices remained relatively constant, despite diluent dropping in price.

        • Right, but WCS prices dropped over that period, although not by as much as Brent.

          • Ergo — there appears to be a much stronger correlation of condensate, SCO, light crude out of AB with Brent (both decline) – that portion of WCS that is not raw bitumen, than bitumen which appears to low correlation over the period studied.

          • Not so much with Brent per se – simply a fact that WCS, as well as Alberta condensates and SCO, are regional market prices. So long as the markets are somewhat isolated from global markets, they’ll move differently. over the period studied, Alberta condensate dropped more rapidly than anything else in $CAD terms – more than Brent, WTI, Mont Belvieu natural gasoline, or naptha. The basic point is that, if you’re producing something which is 30% X and 70% Y, you can’t just look at the price of the final product and determine what that means for the value of Y. You understand this, so the article is not really aimed at someone with your level of knowledge of these markets. If it were, it would be in Oil Sands Review.

          • OK, fair enough. Some final rhetorical questions/thoughts.

            I will concede that for the short to medium term, shipping diluted bitumen to the US for upgrading seems to make sense – whether due to excess capacity for processing heavy crude through declining Mex/Ven heavy, or overbuilding of upgrading facilities – and excess light narrowing the crack spread by it appears predominantly pushing light down.

            And up to 2006ish, due to that local market at that time, it made more sense to upgrade in Canada.

            However, I have yet to be convinced that the global market (that accessible by tidewater) for AB bitumen is more like 2014 (where it makes sense to ship bitumen) than 2006 (where it makes sense to ship SCO). Maybe one will never know until actual tidal access is gained to find out.

          • Not sure you can view diluent as a “flow through” because the regional market price it commands in Alberta is far greater than what it is worth landed at the Gulf Coast. Effectively diluent value is destroyed in moving it from Alberta to the US Refining complex and this is a real cost.

            I should have qualified it by saying: assuming during the period in question, arbitrage opportunities for diluent (change in relative prices of the two locations) don’t change.

            The relative shipping costs should remain the same in this example. If the market flips (say price in Edmonton was price in Gulf plus shipping, then reverses) – your point is valid – ie it is not just a flow through.

          • All of the dynamics you are talking about would be reflected in the value of WCS at Hardisty. My point is that, as condensate costs in Alberta change, the cost of supplying a barrel of dilbit to Hardisty change. That’s not saying that all the points you each bring up don’t matter – it’s just that they are reflected in the value of the dilbit here.

    • Not sure you can view diluent as a “flow through” because the regional market price it commands in Alberta is far greater than what it is worth landed at the Gulf Coast. Effectively diluent value is destroyed in moving it from Alberta to the US Refining complex and this is a real cost. Look at the tolls on the Southern Light diluent return line to get an impression of how significant this cost can be.

      A tighter differential for Western Canadian heavy oil has certainly cushioned producers from declining Brent prices recently, but I think much of the micro economic support for these tight differentials is disappearing quickly.

      The 6 million barrels of incremental demand for Canadian Heavy for line fill for Flanagan South is nice while it is in the market, but this demand is circumstantial and will disappear before year end. And seasonal demand associated with asphalt season is scheduled to come to an end soon as well.

      Incremental demand for heavy oil from the Whiting Project was also nice while it was ramping up, but it is now more or less at full rates. And US Refiners have stopped investing in new coking projects and are actually unwinding bets on heavy oil in favor of lighter varieties. Not sure that we can count on new demand from US refiners. As for excess US coking capacity, the EIA reported record coker throughput in July of this year for PADD 3, which includes the Gulf Coast (95.5% coker utilization).

      Since September global heavy oil prices have been supported by a decision by Venezuela to inventory substantial diluted crude instead of selling it to refiners. They are looking for an alternative to heavy naphtha for blending purposes. But there are limits to storage capacity and without a true cut to production Venezuela will soon need to increase volumes supplied to refiners. And when they do they will be competing with incremental Canadian supply from the continued ramp up of project like Kear Phase 1 and Jackfish Phase 3, and new projects set to come on line soon like Sunrise, Surmont, Nabiye, and Kearl Phase 2.

      I am wondering if a “Yet” should have been appended to the headline?

      • Oops, posted my reply above by mistake.

        • I have trouble seeing this as arbitrage. It is not a play where you are sourcing in a cheap market and selling into a premium market. This is a round trip. You are sourcing in a premium market, transporting it to a cheap market to fill a business need, and then incurring a cost to get it (the diluent) back to a premium market.

          • Oh, it’s a cost, for sure. But, as you point out, treat the diluent as a closed system. Say round trip costs $20/barrel. This should not change with market value of diluent.

            You buy for $100 in Edmonton, pay $10 to ship to Gulf, get $90 in return. Cost of $20.

            You but for $80 in Edmonton, pay $10 to ship to Gulf, get $70 in return. Cost of $20.

        • I think I get it. You didn’t mean to say that diluent was a flow through. There is a real cost associated with this diluent. It is the cost of moving it to a distant market and then back again. But in the absence of opportunities for arbitrage, changes in the price of diluent can be treated as a flow through because of the “closed loop”. I think this is right.

          As noted previously, given the market reports blend pricing rather than bitumen pricing, changes in diluent pricing will impact calculations of bitumen price which is why it was introduced into the conversation in the first place..

          • Yes, I probably should have used a different term for clarity

            “Flow through” is used in say the gas utility business where the utility makes no profit on the cost of gas – just cost recovery. It simply passes on the costs to the consumer – gas cost in this situation is referred to as a “flow through” from the utility’s perspective.

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