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Journalist Markham Hislop interviews leading energy experts from around the world about the energy transition and climate change.
Welcome to episode 309 of the energy talks podcast. I'm energy and climate journalist, Markham Hisler. I've been interviewing energy economist, Kevin Byrne, about the Alberta oil sands for the better part of a decade. He patiently, patiently, sometimes over and over again, explained the nuances of bitumen extraction and North American heavy crude oil markets. Over the years, our conversations have increasingly focused on greenhouse gas emissions.
Markham:The oil sands represents 12% of Canada's entire emissions. At 68 kilograms of c 02e per barrel on average, it's some of the most emissions intense oil on the planet. Now Kevin is the vice president, Canadian oil markets chief analyst, and head of center for emissions excellence for S&P Global, and his team recently released its 10th annual 10 year production outlook for the Canadian oil sands. Thanks to higher prices, or output is forecast to grow faster than expected last year. Today, I'll be talking to Kevin about that new report.
Markham:So welcome to the interview, Kevin.
Kevin:Markham, it's a pleasure to be here.
Markham:Well, you I don't know how many times you said that over the better part of a decade, but it's a lot. We've had a lot of interviews, you and I.
Kevin:Yeah. Yeah. We've we've aged a little bit too. So
Markham:Okay. No hair jokes. I promise.
Kevin:That's only directed at me.
Markham:It is. But you know what? This is an audio only podcast. So you're saying
Kevin:Then then I have a lush just luscious long hawks.
Markham:Yes. Of course, you do.
Kevin:I I
Markham:I agree, and a 100%. That is true, listeners. As they chuckle, yes. Well, look. One of the things that's happened over those 10 years is that you have helped me to understand that crude oil heavy crude oil, but in particular, Alberta bitumen, crude is not the same as light crude.
Markham:It has different markets and different refineries, and the producers make different decisions than conventional oil producers. And we won't we don't necessarily have to get into that in detail today because we've covered that in many, many other, interviews. But where give us a state of the union overview of where the oil sands are these days.
Kevin:Sure. Yeah. If I go go back if you go back back in time, right, to when we were younger and you look at the periods of, the history of the development of this unique resource, you know, it was the early 2000 that led to the innovation technology, the horizontal steam injection technologies, the SAGD, that unlocked the majority of the oil sands deposits. And at that time, there was also a uptick in global prices, and there was also a shift in mentality that the world thought it was running out of oil. And that led to a tremendous amount of investment.
Kevin:And projects and production began to climb. And it was around 2,012 that there was a concern about the inflationary effects of the degree of the investment, the amount of development, and the cumulative environmental impacts. 2015 the oil price fell out. Driven principally by tremendous amount of supply coming from North America because tight oil had also been born from a tremendous amount of innovation late in the 2010 or late 2008, 9, 10 day period. It overwhelmed the market, and we went through a protracted period of lower prices.
Kevin:The oil sands had a number of long lead time projects in development. Those were largely seen through to completion. I'd say almost yeah. Most almost all of them. And that led to these things turning on and then ramping up.
Kevin:As we've moved into this decade, those projects have all been completed, Those ones that were sanctioned prior to the price collapse. And the operators have honed in on focusing on optimizing, improving the efficiency. So things like reducing downtime means you can produce more units over fixed period of time, and that's a good way to drive your cost down. But you could also amortize your emissions over a greater number of units as well. And that's what we've seen drive a tremendous amount of production growth.
Kevin:You're getting more from existing facilities, but also you see reductions in operating costs and reductions in carbon intensity as well.
Markham:What is the, daily output of the oil sands now? The last time I looked, it was about 3.3 1,000,000 barrels a day. Are we still right around that?
Kevin:I think that sounds about right. Like, you know, do you get a there's a seasonality in in Canadian production associated with turnaround seasons in the oil sands. That's usually in the spring. They take things down. They do maintenance sort of those sorts of things.
Kevin:So last year, we estimate the oil sands production. So production not including the diluents averaged about 3 point or just shy of 3,200,000 barrels per day. This year, we think they could do over 3,300,000 barrels per day, maybe maybe halfway to, you know, 3.35. I don't know. Splitting hairs here, depending on how the year, shakes up for them as a whole.
Markham:Right. Mhmm. And, what we're seeing, of course, is that the as you pointed out to me a number of times, the global market for, ultra heavy crude or heavy crude entire, even though Alberta's ultra heavy crude, is about 10, 10 and a half 1000000 barrels a day, and 5 and a half 1000000 barrels a day of that refining capacity is in the United States, and it's concentrated in the, American Midwest. I'm sorry. Well, in in the Midwest and in the US Gulf Coast and then on a little bit in California.
Markham:Alberta's heavy crude mostly goes to the Midwest, has been increasingly moving into the US Gulf Coast in the last, what, 5 years? 10 years? That's
Kevin:what I'm saying.
Markham:Yeah. Yeah. And then it takes a it then it it's some some shipments, find their way into California depending on what, California's requirements are. It of late, the comp the competition there is not shale oil. Light crude does not compete with heavy crude, but it heavy crude does compete with other with Latin American producers.
Markham:So we would have Mexico, and we have Venezuela, and Colombia. Those 3 come to mind. And there's been some question about their reliability. Venezuela, we've seen go from, I don't know, 2a half, almost 3,000,000 barrels a day down to next to nothing. And Mexico said that this year, it would take its 600,000 barrels of Mexicomaya, off the off the market because it was going to, process them, domestically for domestic market.
Markham:So is in fact the competitive situation for Alberta heavy crude in the US improving?
Kevin:Well, yeah. You, the history of North American slate, what refiners run is is interesting. You touched on it briefly. So if you go back in time, the the seventies, we had growing Latin American supply, heavy supply, and we had US Gulf Coast refiners looking for security of supply, and we had declining US supplier, or list the prospects of decline supply. And they entered into long term contracts with Latin America to process the heavy crude.
Kevin:So the US refiners got security of supply, and then they would make investments to be able to process that heavy crude because you have to have special kit to do it. And they'd lock in a demand center. And, certainly, you know, that led to a build out of US refining capacity in the Gulf Coast to process heavy crude. Canadian was growing, through this period too, much slower, but the heavy crude began to materially grow after 2000 into the mid 2000. And it flowed south into the US Midwest.
Kevin:Our pipelines had targeted there since the 19 fifties through through the Enbridge system. And the Midwest refiners started to take an interest in that growing Canadian heavy crude security supply. Some of the data reconfiguration, some of them had configurations capable of doing it. We saw expansion of heavy crude refining capacity in the Midwest. Canadian heavy continued to grow, overtook their refining capability in that region that flowed south.
Kevin:And that meant decline it met declining Latin American supply at that point. And so they took market share from Latin America and re displaced those crudes out there. So it was a to your point, Mark Mark, there was a symbiotic relationship of sorts between the 2. You know, the Canadian supply was there to meet and offset declining Latin American demand, supply and met those refiners. And then some Canadian heavy had begun to move off the Gulf Coast in recent years as well to further flung markets, including internal market in the United States that have less accessibility to pipelines.
Markham:Now there's a a a very controversial aspect to this, and that is the trans mountain expansion pipeline, which is boy, I was I was reporting on that way back in 2016, before construction began when when approval on on the West Coast of Canada was a big, big political issue. And it finally got built. It only cost 7 times what what the initial estimates were. I think the the the bill came in instead of $5,000,000,000 was, like, $35,000,000,000. But now it's operating.
Markham:It's got oil in it, and and oil is flowing out to the, the Trans Mountain, facilities, in Burnaby, for shipment. And you've always said, once it gets put on a ship, unless it's contracted for, you never know where it's gonna go, but it will get sold. That's an important point. But their opponents always argued that there was never gonna be a market in Asia, particularly, for this for, the oil sands heavy crude. At the best it would do is is, find markets in California.
Markham:What's your take on that now?
Kevin:I I don't think it's changed. I think, you know, this is a rather crude way to say this, but I think it's generally true. Your economics of moving oil around the world kinda go waterborne is the cheapest, then pipeline, then rail. So once you put it on a vessel, it is free free to flow to the highest price point globally for that. And so, yes, California has a potential to consume, some Canadian heavy sour, but there are refiners configured in Asia that can also consume it.
Kevin:I think another misconception is everybody expects it to go to one place and one facility. No facility is gonna run a 100% of this stuff. It's gonna be a blend of of crudes coming into that facility, meet the specification of, like, what I mean is the product demand in that region that that refinery thinks it can make the most out of given what's available in feedstock, its own unique configuration to produce what's yield of outcomes, so gasoline jet, geez diesel, and a bunch of other products as well. And so it will flow to the highest price point. We'll find out what that is.
Kevin:Anytime you enter a new market, you need to have people try your product. And that you know, so you have to enter the market. And generally, that comes at a little bit of an introductory discount. And so try it, see what it does, see what products you can make out of it. And as more facilities try and get accustomed to it, you get this secondary market.
Kevin:So a refiner will buy cargo. But if you can't resell it, if they have an upset or something, they can't resell it to someone else, they're obviously gonna price that into what they'll value it. And so and as a market crude oil gets adopted in the market, you increase the the familiarity with it, and you can trade it amongst the refineries or the demand centers as well. So there's there's that process that will that'll happen.
Markham:There are some changes, in the Chinese market that has, bolstered, oil demand, and that is the construction of these giant refineries, refinery slash petrochemical plants. The one that I I read about was Hengly, which is a 400,000 barrel a day complex. And it's it appears that as, oil demand has softened in China because of the electrification of transportation, Some of the refiners, have been shifting, shifting to petrochemicals and refined, petroleum products, and and that's maintained demand, at least for now. What are the chances do you think or do you have any insights into the likelihood that those kind of complexes will become a home for Alberta crude?
Kevin:You mean the crude to chemical configurations?
Markham:Yeah. In Asia generally and China specifically.
Kevin:I I don't know if I can tell you for sure. You know, the the best way to think about it is in the world today, they can you consume over 80,000,000 barrels per of a day of oil. Forget about the NGLs and everything else. I'm talking about oil. Canada now has a capability to ship a half a 1000000 barrels into the Pacific basin, which has been the one of the key growing markets.
Kevin:There's a multitude of markets that end up too. There's a lot of refiners that are gonna try it and see what it'll do in terms of product yield. One of those could be crude to chemicals depending on what chemicals they wanna make and what's the configuration of the facility that comes from it.
Markham:So what I hear is that the there's no certainty that the, or a heavy crew that gets shipped through the trans mountain expansion pipeline put on a on a on a ship will, it'll it'll certainly get tried out in Asia, but there's no guarantee that there will actually be a market there. It'll have to compete. And, hopefully, it, from the producer's point of view and the Alberta's point of view, it'll find a home and and it'll be it'll be profitable. But there's it sounds like there's going to be a period, could be a year or 2, 3, whatever it is, of uncertainty while it gets established in a market.
Kevin:Yeah. I think, 1, there is a market there. They've consumed similar types of crude from elsewhere in the world. Just whether it will be consumed there will become, you know, a factor of what it competes against in which markets, and what's the demand for it around the different markets for it. You know, the we also it's all about the price mark at the end of the day.
Kevin:And so for refiners, what is the value of the feedstock to produce product, and what's the price that's being competing against others to buy it from? So if you don't buy that, what else are you gonna buy? And what's the del delta between it? It's relatively new product in that basin. And so it's gonna take some time for people to run it and try it and to see what it, you know, what the what it meets means for their facility and the products that they wanna produce.
Markham:Okay. With with all of that as as, context, give us an overview of your of this year's, production forecast.
Kevin:Sure. So the this year, we this is the 2nd year in a row. We've revised up our expectation for oil sands production growth. We see it reaching, about are approaching about 3,800,000 barrels per day in 2030, which is about a 100,000 just less than a 100,000 barrels than we had last year. The reason for this upward revision is as we move through time, operators have continued to scour their facilities, and they've been scouring them for operational improvements.
Kevin:And so they're looking for ways to further, again, reduce those downtimes or make efficient investments in in ways to grow that output within their existing infrastructure. So they're trying to maximize the design of the footprint they have in place to increase and produce as many units as possible. The other thing that's happened is we've moved through time, and the producers have had a long enough runway in terms of prices that are just as high enough to be rebuild their balance sheets. We're seeing some of those optimizations that they're talking about growing a little bit in scale as well, becoming a little bit more ambitious, not anywhere near with anything we've seen in the past, but that's also adding to the expectations of what we see in terms of potential for growth.
Markham:When you say, optimization expectations are changing, what give us an example. Like, make that assume that your audience knows nothing and and probably knows slightly more than nothing. Give us you know, explain that.
Kevin:So it's it's like you and me. We look to prove the efficiency is something we do. Right? We reduce for them, reducing downtime, getting equipment last longer, those sorts of things. But they they discover these things through learning by doing.
Kevin:Hey. If we did this differently, maybe I'd be able to get a few more units out that way. Right? And as you do that, you discover new things. So you're continually finding little things you can tweak.
Kevin:I don't wanna give the people this as, in an infinite pool that can go on forever. But you will discover, you know, different ways of doing things that have improvements in terms of how you use fuel or how may how you keep the operation running at different temperatures, what have you. And so we move through time. They've continued to, discover additional things. And it and it so we've added growth from the prior year.
Kevin:We're and we move forward a year. They banked some of that stuff, and so we're putting another kind of wedge on top of it. And I think another reason why this is so different in the oil sands is because oil sands production declines don't materialize in the medium medium to even long term. And so, you know, a lot of other players, there's these very steep declines. This this sort of thing, the the amount of growth we're talking about, would would easily be eaten by the decline rate in most other plays, and it would not it would not probably show up.
Kevin:In this case, because the declines are so shallow, every one of these little investments do add up to growth in the immediate and short term. And if you look at the revision we posted, if you look online, most of it's in the very near term, so 2 to 3 years out. And so that's why we also talk about the potential that they could find more of these things. Now, again, I don't wanna say it's infinite, but they could find more and can you just squeeze that, resource base in the assets they have.
Markham:Right. And we should make a point for for folks who have have not listened to our interviews in the past that the oil sands production is very different than conventional oil production. You're not drilling wells, you know, getting very high production rates for 6 months, 12 months, 18 months, and then seeing a drop off in that in your production rate. You're you don't have a decline rate. These are basically more like and I don't I know if I remember correctly, you don't like this comparison, but I it has some application.
Markham:They're more like manufacturing plants where you have to spend money, the capital on the plant upfront, but the cost to operate them is relatively low compared to, you know, your, conventional oil where you have to replace supply all the time because of the
Kevin:I don't mind that analogy, Mark. I I I think it's a very good one. Right? Because it's it's not putting up a and they do drill, but they're not putting up a a rig or drilling down the ground and then having it produce and then decline off. That does happen more or less, but it's into a centralized processing facility that can separate the bitumen from the sand, clay, and the waters.
Kevin:And so they're limited by that separation capacity, whether it's in a mine or it's a thermal plant, and that's a key difference. You're funneling all that volume into a centralized facility. So you can see how, oh, if I find a different way to handle that volume or I can separate in different way, I can get more through it. You know? We did see number of facilities improve their steam to oil ratio on the thermal side, so the amount of steam per barrel of oil they produce.
Kevin:And that means if that steam to oil ratio falls, they potentially could use that steam, so how many barrels of steam to produce a barrel of oil to produce more oil. And so that's another thing you can see them do. So they're incented to improve the efficiency, but then they can recoup some of that benefit by producing more.
Markham:What let's what are the, the breakevens now? You and I have talked about this in the past, and I've been using numbers that I recall from an interview that we did couple years ago maybe. And at that time, we were talking on the low end, maybe West Texas Intermediate prices. They would be in the low thirties to maybe $45 a barrel, which is competitive. Have we seen production costs fall in the in the last little while or we and and I remember correct if I remember correctly, Kevin, you had said that some of the projects would see their costs fall into the twenties, maybe high twenties, something like that.
Markham:Is that kind of where we're still at?
Kevin:Yeah. I I think this is interest the cost is one of the things that's been hard to understand the oil sands. We taught you to use the language earlier when you describe the manufacturing. There's these long lead times to bring these projects on online. That's what we would consider the full cycle cost, You know?
Kevin:So the development time so the cash up front, the development time to bring it online, and then the amount of time it takes you to recoup that capital. Right? Say, generate a pay grade. Those are those are a lot higher. On the thermal side, we did see them come down.
Kevin:We would probably assess them probably in the mid 40 to 60, $65 WTI WTI range. And then on the mining side, they'd be a lot more. That's quite different than the cost to continue to operate something that's installed. And that's a lot lower, and we'd call that half cycle cost. So this is the cost to produce the barrel, maintain the operations, so sustaining capital to maintain it.
Kevin:They also have to buy diluent from the market if you're a heavy producer without an upgrader. So you have to pay for that. You have to buy the natural gas for fuel. So all these things. I think we generally say on a half cycle cost, at least for the thermal guys, they're probably sitting around well, mine's too.
Kevin:Mid twenties to 40, 45 depending on the individual operations. And so yeah. And the other thing to understand for that half cycle cost, because I talked about inputs, critical inputs or cost for them, is the diluent, is the natural gas. And so in a down cycle that we saw over the couple years, there's a natural, shock absorber in there to some degree because your input costs fall too. Right?
Kevin:So you the dollar value you're getting for your product is gonna fall, of course, because the oil price fell. But the diluent they buy is based on oil prices. And the natural gas, although it doesn't always trend 1 to 1, does does follow a similar trend when the the oil price does fall.
Markham:I wanna get you to react to an interview that I did with, the, chief economist at the Canadian Energy Regulator and in the last energy futures, report for Canada that these, Canadian CER did, they did a a net zero modeling, first time. And one of the things that surprised me was that, under particular conditions, the, output of the oil sands falls significantly in the in the 20 thirties. And I talked to the, to the economist about that, and his argument was that if the oil sands have to pay for their climate compliance So they have to bear the cost, and just, Alex Pourbaix of the of Synovus, the former CEO of Synovus, has pegged that, at $75,000,000,000 for the entire oil sands to decarbonize by 2050. If they have to pay those costs themselves and there isn't a significant offset from the government, they they become uneconomic. The cost the compliance costs were an an emissions intense barrel are so high that it makes them uncompetitive.
Markham:And we see reduction going down to, I think, by 2040, like, a1000000 and a half barrels, something like that, depending on which scenario you're talking about. Did any of that play into your, production forecast?
Kevin:In terms of the CCS costs? Is that what you're gonna get?
Markham:Like, who like, who bears that and and and how does that impact, how does that affect? I we should never use impact as a verb, my friend. Never do that. So I apologize to everyone. How does that
Kevin:It's also a product for us, by the way, just to totally confuse everybody.
Markham:Okay. Well, now I'm confused. Anyway, that's yeah. How does it affect that?
Kevin:So it is it it you know, it's not, like with any of these things, they're an art and a science to them. And we look at things like, the half cycle cost, our long run oil price forecasts, alternative and competitive source supply, those sorts of things. One of them is, of course, the implications of spending more on decarbonization in the oil sands. Right? So that is, if you look at the actual, publication, there is a plateauing in the production outlook that you can see there.
Kevin:And one of those is the need to allocate capital towards CCS. Right? And so whatever that cocktail is in terms of, these companies' dollars, but it isn't actually their dollars, it's their investors' dollars, and direct them to decarbonization. So there is a capital allocation question that we think weighs on the growth profile. There's also, the basically, a project execution side.
Kevin:These are not small scale projects they would have to invest in. They're large complex industrial construction projects. And there is a finite ability to organize around those as well in terms of how many of those can you execute at one given point. Those things weigh in that production, outlook that we have.
Markham:I don't think we've asked I've asked you the question yet, and that is, how much extra production, extra supply are you forecasting over the next 10 years?
Kevin:So in relations to release or supply globally? I
Markham:No. No. No. Sorry. Of the oil sands.
Kevin:Oh, over the next 10 years? So right. So we have our production outlook going to 3,800,000 barrels per day from, you know, 3.3 and change this year. We have it sliding down to about 3,600,000 barrels per day by 2,035. And that's because, you know, these operations many of these operations have been in around for a while, and we start to see some, evidence of production declines in around that period on the other side of 2030.
Kevin:Pinpointing that, Markham, is as much, I said this before, as much an art as a science. There's a physical limit to resources. In this case, the oil sense isn't necessarily physically limited by the resource. It is the resources under a specific lease and the ability to do an extension into new lease land. Those sorts of things start to complicate it.
Kevin:And so and then the the cocktail of what's produced also changes it. There's a potential for some of the larger mining facilities to start to absorb more of the thermal operations bitumen that changes the output, profile in a different way.
Markham:Yeah. I think we'll add voodoo priest to your now, that's quite a title you've got now. So, I mean, we've got room. Right? You probably have room on your business card, voodoo priest.
Markham:Right?
Kevin:To be to yeah. To be to be fair, there's a team here that does the oil sands outlook, and I I support them. That's that's their primary job. My primary job now is, focused on the expansion of carbon intensity assessments, within the business.
Markham:That is true, and I always enjoy it when we will have further conversations. But for now, we're gonna talk about supply. And and I have to ask you, because a lot a big focus of our work at Energy Media is the energy transition, and we acknowledge that there are various models or, various scenarios. OPEC, for an example, sees global oil supply growing out to 20 45, 116,000,000 barrels a day. The International Energy Agency is calling for peak oil demand by 2030.
Markham:Rocky Mountain Institute, for example, says that there will be peak oil demand this decade and or 2024, so not much tech not much runway left. And and, you know, there are all sorts of variables that will affect whether which scenario we actually see at the end of the day. To what extent have any of those scenarios played into your supply forecast?
Kevin:So we have our own, production forecast, Markham, and we do them based on bottoms up. So we do a global supply stack, and we match that against the global demand stack out to 2050. So we're doing this by region and a lot of granularity. I don't think our outlook is tremendously different from some of the ones you mentioned. We see peak oil in around the 2030 mark.
Kevin:But that doesn't mean that pretoil's demand falls off, the next year after. Everybody wants to, pick on the word peak. I think more accurate may be a plateau for quite a while. And that's the same with the oil sands with people like, when does it peak? If you go and download the imagery, it's more like a plateau for a while before it starts to slide off, you know, 6 or 7 years.
Kevin:So that that's the other way to think about it.
Markham:Yeah. And I should mention that. Of course, you know, I I don't wanna, you know, provide a 5 minute introduction to your to the question I'm gonna ask you. But, yes, I mean, everybody, OPEC, IEA, Rocky Mountain Institute, everybody, has a plateau built in their scenarios. And the the the the length of that plateau is up for debate.
Markham:And the That's fair. And and the side that the shape of the decline curve is also, applicable here.
Kevin:I think that's where you see a lot of difference of opinions, and that's, you know, there's a lot of different reasons for that. But we you know, in terms of our balance, our supply does do a global balance into the demand side.
Markham:And so here's where I'm going with this, because, your report talks about pipelines. It transport cape capacity within Western Canada. I think I have I still have the the graph on my computer someplace where a few years ago, 3 years ago, your team had forecast, you know, that probably, you know, Western Canada was good 2 20:30. Now you're talking maybe only until 2026, and I have taken the position editorially that we will never ever see another interprovincial pipeline. We will never see another pipeline built from Alberta to the West Coast.
Markham:We'll never see another pipeline built across the, international border south or across the border into Saskatchewan headed east to Ontario and Quebec. What we got is what we got, and you either make better you optimize the use of that, this or you figure out ways to ship by rail, or maybe you don't have the demand to begin with. So given that pipelines are 30 to 50 year infrastructure, Boy, that is a complicating factor if you're a company, if you're a policymaker, because you don't know if you build a pipeline by 2035, say, that it's gonna be around in 2065. There'll be enough demand for it. I don't know.
Markham:Your your thoughts?
Kevin:Sorry about the life cycle of pipelines or the
Markham:Well How our outlook has changed. Look. We're in we're in an energy transition. And so if you agree that that it's the likelihood you're calling for peak oil demand by 2030 and then maybe 6 years of plateau and then a decline curve. You know?
Markham:By the time you get a pipeline planned, approved, and built, you know, it's 10 year process, so now you're looking at, you know, mid 20 thirties. And just as your own forecast shows that demand will begin will begin to decline. It who's gonna build that pipeline? I wouldn't build that pipeline. Is this chances of it being a stranded asset are very high.
Markham:I just your opinion, your in any insights you can share with us on that conundrum.
Kevin:So there's a there's a lot in that. So oil demand, what the future of oil demand is, that's certainly a lot of difference of opinions. And I think that's why you see the words people people talk about the words, use words like transition risk. And that comes into whether you get the funding to sanction a new project or what's the cost of capital percent say fund sanction a new long lead time project globally. We have seen, a reduction in the interest in longer lead time projects globally because of that.
Kevin:I think the other one to think about is it's not just what happens to global demand. It's what happens to global supply that matters as well. And you know, what is, again, oil and gas is generally best perceived as a wasting asset. And what I mean is as soon as you drill a well, you're going to enter into production decline. So the next day you produce, you have less than the day before.
Kevin:So it isn't something that's static. And so the suppliers of the tomorrow may not be the supplier's day. It's gonna shift around to some degree, and it's gonna be dependent on how you get capital to develop what and then who declines steeper than others depending on when you get that capital. To your question about the pipelines, I don't know. I think we would opine very similar to you that that I think with Trans Mountain, what we saw was that private capital said they couldn't endure the uncertainty of the pipeline development process in Canada.
Kevin:And that's why we saw them, exit and the government of Canada having to step in to to to to foot the to cover the continuation of the project. Our balances show because we're seeing more growth, that there is more demand for pipelines in the forecast needed to ensure that the system continues to buy be priced on pipeline economics. So what does that mean? Western Canadian heavy sour tracks globally traded prices of similar quality or you adjust for quality in your pricing, subject to that transport to reach those competitive markets. And so for the longest time, that has been the Gulf Coast.
Kevin:So the Canadian crude would trade very similar to Mexican Maya in the Gulf Coast region, less the cost to get it there. The producer here effectively bears the cost to deliver it to where someone would pay and compete for it. And so without that pipeline, adequate pipeline, you would face a wider differential because a higher cost of transport by rail historically. The other thing, Markham, is when you talk about pipelines, there's ones you have today, but that doesn't mean, like, to to your point, like, they all become equally important through the transition. As demand falls off, different regions may be more competitive for refining than other regions.
Kevin:And so pipelines are hollow tubes or straws. Where they point matters through the transition. So our analysis was pointing out to the point that you made earlier. With our higher production outlook that we see, which is not just oil sands, I should say, we're seeing liquid growth too in the unconventional side. The demand for Canadian export pipelines or pipelines leaving the Western Canadian Central Basin is higher.
Kevin:We do see the potential for optimizations to meet that need, the utilization rate gets very, very high, which may leave the basin susceptible to price dislocation because of the seasonality. So in the winter, when we have peak production, you may see a weaker price in the differential.
Markham:Gotcha. So let's wrap up our our interview this way, Kevin. One of the thing I really appreciate the technical way you answer these questions. Not all listeners may be on the same page as me with that. I mean, I've I've had the benefit of of 10 years of in, learning to interpret Kevin E's.
Kevin:In enduring me?
Markham:I I wouldn't quite I wouldn't characterize it quite that way. I wouldn't say
Kevin:Not that painful.
Markham:But I've I've learned I've I've I've learned what you mean by things. I and, when you talk like an economist, which, of course, off camera, you don't. You're just regular Kevin. But when you're on when you're talking like an economist, there's a whole different language involved here, and it takes a little while to get used to, and I've had the benefit of getting used to it. But for the benefit of listeners who aren't used to it, give us a wrap up on where we see the next you know, where you see the oil sands going in the next 10 years, just in plain old language that anybody can understand.
Kevin:Well, I I think the the the the base outlook, you know, we published it. We see more growth coming from optimization, focusing on, like, things that prove their cost, and, ultimately, what can contribute to lower emission intensity, but will push volume higher. And that's gonna run into the pipeline egress issue. I think the other big challenge you see is the industry is under pressure to decarbonize from domestic policy, but there is also international interest in this as well, from the investment community who see the need to decarbonize generally. You know, there's a there's a gonna be different perspectives on the pace and when that needs to happen, and I think that's the challenge to the oil sands is how fast can this happen.
Kevin:Because these decarbonization projects that they are leaning towards, carbon capture and storage, are frankly are the best suited to decarbonize them. They use natural gas to produce heat, and natural gas is still one of the most efficient ways to do that. So they're looking at removing the emissions from that process. That requires time, and they're capital intensive. And so if you look at the pressures under them to get get those things online by 2030, we're sitting here in 2024, and those are, you know, over a half decade kind of build cycles.
Kevin:And so the time is incredibly tight, and it'll require significant capital investment to be able to do that. So there is tremendous potential there. They've been proven to be resilient through all the volatility we've seen, but there are certainly pressures coming around decarbonization. And then there's questions around the adequacy of pipeline capacity. And we can debate about that peak and, you know, what it looks like, Markham.
Kevin:But the for Canada, it has to get the product to market. And that's been its biggest challenge for over 10 years, and that includes the gas market too.
Markham:Yeah. Well, look. Thank you very much, my friend. We'll look forward to the your next, emissions report where we can talk about GHG intensity and where that's going. So thank you very much for this.
Kevin:Thank you, Mark. Hit connect.