Rating: Advanced high school and post-secondary
Summary: Markham interviews Kevin Birn, an economist with IHS MarkIt, about how oil sands producers have driven down costs to around $30 WTI per barrel. Falling supply from Latin American countries like Venezuela and Mexico has tightened global markets and supported higher prices. Falling costs and higher prices combined to create a positive 2021 outlook for oil sands producers.
This interview has been lightly edited.
Markham Hislop: Bloomberg ran a story last week that got a few people talking, because it basically said that the Alberta oil sands is well positioned to be profitable and competitive in 2021, which these days is a pretty contentious comment. We’re going to talk to Kevin Birn, who’s the oil sands economist for IHS market and knows this sector inside and out. What’s your take on Bloomberg’s article?
Kevin Birn: It’s something we’ve been saying for a better part of half a decade. I think this goes to some of the misconceptions about the oilsands sector.
The challenge with the oilsands sector has always been the large upfront out of pocket expenditure required for multiple years to bring on incremental production. Once these facilities are in operation, however, the cost to maintain them is quite competitive. And that basically means you can maintain your production with little or no material decline from year to year or day to day. And that gives you a huge upside potential because you’re not doing what most oil and gas companies are doing or have to do eventually, which is to go hunt and find something new and bring it online.
Markham Hislop: Now you follow the operating costs for the various projects in the oil sands fairly closely. I try to as well. And I’m seeing, you know, for instance, Suncor, I think has one project that breaks even at $25 a barrel West Texas intermediate. Some of them are up in the thirties, maybe some in the low forties, but most seem to be under $50 a barrel, which is where OPEC seems to be positioning the oil prices these days – or will when things return to some semblance of normal. Have I got that right?
Kevin Birn: I think that’s fair. You know, when we talk about operating costs, we need to be very clear what we’re talking about. If we talk about pure operating costs, some of the oil sands facilities have ridiculously low numbers. You’ll see them report $7 or even $6 a barrel.
But that’s not the full cost to maintain that operation. They have things like transportation and marketing to cover. They have to buy diluent to blend with the bitumen and that takes up some transportation costs as well. There’s also the fact that there’s a quality differential as well to take into consideration.
When you add all those additional factors, what we call “cash cost breakeven” is higher than that $6 to $7, which is on the lower end of even oil sands projects. But you’re usually in and around the $30 a barrel on a WTI basis. That doesn’t include head office costs. but that would keep an oil sands facility running every day. And that’s competitive.
When you think about the environment we’ve been through this year , that gives you the ability to hold onto what you have now, while the cost to bring on new production is much higher.
Markham Hislop: What I do want to talk about is supply within the global heavy crude oil market. According to IHS market information that I’ve seen, the global market for heavy crudes is about 10 million barrels a day out of a hundred million barrel a day total market. And Canada is the big player in that market [about 4 million barrels per day]. But we’ve seen Venezuela’s production drop off since 2016, by about two and a half million barrels a day. Mexican Mayan, another competitor for Canada, is in long-term decline and is declining even faster now.
That tightening of supply has actually made Alberta bitumen quite competitive.
Kevin Birn: It’s benefited all heavy producers, to be honest. Even the producing regions that have seen the production fall off globally, what it does is it tightens the availability of heavy. The spread between light and heavy is influenced by the availability or the relative availability, both those crudes. They don’t really compete head to head (they can compete on the margin). And so we see a contraction and availability of heavy globally, this precedes the global pandemic this year, and we saw a surplus or run up and the availability of light.
That compresses the [“price differential“] difference between those crudes. We’ve seen that become more pronounced this year, in part because of the degree or the severity of the shut-ins we saw in Western Canada. Like you said, it is one of the largest producers of heavy sour, crude oil in the world. It had one of the largest shut-ins because it is to some extent landlocked, was more exposed to the demand contractions.
But the punchline is globally that spread between light to heavy crude oil. That value difference has collapsed in the last couple of years to the benefit of upstream producers, including in Western Canada and to some degree to the disadvantage of refineries that run that crude.
Markham Hislop: Fair to say that the producers have got their costs down to the point where they’re pretty competitive, the supply has bolstered the price and looks fairly good as we head into some kind of recovery? Which I guess is the rationale behind the Bloomberg article.
Kevin Birn: I think there’s one more aspect and I’ll come back to that differential in a minute. I think what we’ve seen over the last half-decade is we have seen cost reductions like operating costs. We saw fall on average, about 40% to 50%, depending on the operations.
We also saw, and this is just a matter of fact, a contraction in the expenditures of these companies. They finished the projects they were building. We haven’t seen a significant amount of new projects come forward. So their capital expenditures have tightened [fallen] over the years. That’s resulted in is a greater amount of free cash flow. And so we’ve seen a gradual recovery of free cash flow from about 2016. I’m going to say on average for the big four oil sands producers, and in 2019, before the, you know, the global pandemic, we saw an average free cash flow of around $3 billion USD each. Some of them were much higher and some of them were lower.
They demonstrated their ability to throw off free cash flow, which has always been the reason for the oil sands development and the reason you’d invest this capital, those large out of pocket upfront expenditures is to get to the other side where you’d see this free cash flow.
On the differential side, when we look forward, we do see the opportunity for a narrower light/heavy spread to the benefit of Western Canadian producers. One factor you already mentioned was the contraction of available heavy sour, crude oil globally. This is occurred principally from Latin America, but also the potential for greater pipeline egress capacity out of the base. And whether it goes West or South, the pipeline has the ability to provide greater price security.
We’ve seen periods where they’ve had system bottlenecks and the differential widens naturally. And so when we look forward, these two combined factors could result in a narrow spread for Western cane producers. Then we saw the last decade and we estimate this could add, you know, potentially or reduce that spread by $3, maybe $4 over the decade on average is we still expect variability from year to year.