Ladies and gentlemen, thank you for standing by, and welcome to the Suncor Energy Fourth Quarter 2019 Financial Results Call. At this time all participant lines are in a listen-only mode, after the speakers presentation there will be a question-and-answer session. [Operator Instructions] I would now like to hand the conference over to your speaker today, Trevor Bell, Vice President of Investor Relations. Please go ahead.

Thank you, operator, and good morning. Welcome to Suncor’s fourth quarter earnings call. With me this morning are Mark Little, President and Chief Executive Officer; and Alister Cowan, Chief Financial Officer. Please note that today’s comments contain forward-looking information. Actual results may differ materially from the expected results because of various risk factors and assumptions that are described in our fourth quarter earnings release as well as in our annual information return. And both of those are available on SEDAR, EDGAR and our website suncor.com. Certain financial measures referred to in these comments are not prescribed by Canadian GAAP. For a description of these financial measures, please see our fourth quarter’s earnings release. Following formal remarks, we’ll open the call up to questions. I’ll now hand it over to Mark Little for his comments.

Good morning everybody and thanks for joining us today. Even though the commodity market continued to be volatile in 2019, Suncor generated quarterly funds from operations of $2.6 billion and ended the year with $10.8 billion of funds from operations, a new annual record even with WTI down nearly 12% year-over-year. The last two years demonstrate the resilience of Suncor’s business. 2018 highlighted the strength of our integrated model through market volatility while 2019 built upon this foundation by focusing on value over volume as we operated in a production curtailed environment. And so for the second year in a row, we generated annual funds from operations in excess of $10 billion. We continue to deliver on our commitment to increase shareholder returns. Suncor returned $1.1 billion in the fourth quarter and $4.9 billion in 2019 in dividends and share repurchases to shareholders. This represents approximately 45% of our annual funds from operations. Our ongoing commitment to shareholder returns is demonstrated through the repurchase of over 9% of our outstanding common shares since May, 2017 and with our board approving an 11% increase in our dividend, 2020 will be the 18th consecutive year of dividend increases. The dividend increase is supported by our strategy to grow the structural cash flow of our business by $2 billion annually by 2023 and our board has also extended the share buyback program by up to $2 billion over the next 12 months. Now moving to operations, across our Oil Sands assets on a full year basis, we recorded the highest SCO volumes in the company’s history, which generated an additional $800 million of additional funds flow for Suncor relative to 2018. This is a result of our strategy to maximize value at Base Plant and at Syncrude as well as improved reliability at…

Thanks, Mark. As you previously highlighted Suncor was able to generate $2.6 billion of funds from operations in the quarter despite the impact of continued mandatory production curtailment and planned maintenance downtime. These results demonstrate the strength of our integration and flexibility within our business model. During the fourth quarter, price realizations in Oil Sands were lower than the third quarter as differentials widened. However, our integration mitigated the majority of such price volatility. Our production and cash costs per barrel across Oil Sands were impacted by mandatory production curtailments, our focus on high cost and higher value synthetic oil production and increasing natural gas prices in the quarter. With the expected removal of curtailment in 2020 and its impact in how we operate our assets you can expect us to remain focused on driving down costs throughout our business. Due to the decline in our forecasted heavy crude oil pricing and the increase in the capital cost estimate for the West White Rose project, we recorded non-cash asset impairments in the fourth quarter for Fort Hills and White Rose of $2.8 billion and $400 million after tax, respectively. These assets continue to perform operationally and deliver free cash flow. We continue to see significant upside value in our company’s shares. And we executed in our share buyback program during the quarter, spending approximately $450 million to repurchase 11.1 million shares. As Mark said, 2019 we returned $4.9 billion to shareholders, including $2.3 billion in share buybacks, repurchasing 3.5% of our outstanding share at an average price of $41 per share. For the full year, our dividend and buyback program equated to a total shareholder return of nearly 8% using an average share price for the year. With a strong balance sheet, which includes over $400 million of debt reduction in 2019, we continue to focus on increasing shareholder returns as evidenced by the 11% dividend increase and the extension of the buyback program as Mark mentioned earlier. It’s important to highlight the strength of our shareholder returns. Over the last three years, we have returned approximately $14 billion to our shareholders. This amounts to cumulative returns of $9 per share or approximately 20% of our common share price. These returns are reflective of our strong financial position. No near-term requirement to pay down debt and the resilience of our free funds flow. As we look forward, the combination of this foundation and the $2 billion increase in funds flow goal will set up the company to generate tremendous value and increase shareholder returns for years to come. So, Mark, I’m going to turn it back to you for some closing comments.

Perfect. Thanks, Alister. As you would expect in line with our capital discipline principles, we’re carefully evaluating future projects. We take into account the current environment of volatile commodity prices, market access challenges and government intervention into crude markets. While at the same time, we’re making progress on new technology development, which has the potential to significantly reduce capital and operating costs, greenhouse gas emissions and water use. With these factors in mind, we have decided and identified a number of opportunities to debottleneck Firebag, including the completion of our emulsions handling project this year, and integrated well pad development program and expanding our solvent SAGD program. Our near term expectation is to have actual Firebag annual production at nameplate capacity of 203,000 barrels a day in 2021, assuming no production curtailment. We have the potential to add another 20,000 to 30,000 barrels a day of lower capital intensity production by the time we get to 2024 and 2025. Some of this is in execution and some of it is still being scoped. As a result of this opportunity, we will defer Meadow Creek and in situ replication sanctioning until 2023 at the earliest. For downstream, given project economics and the deferral of significant bitumen production growth, we have decided to no longer progress the coker project at Montreal refinery. That said, we continue to look at alternative lower capital investments across our refineries to support our integration strategy. Lastly, we expect to file a regulatory application in Q1 for the base mine extension to potentially replace our Base Plant mines as they reach their end of life around 2035. I want to emphasize, this application is not a project sanction and understand that the base mine extension is only one of many options under consideration with a final sanctioning…

Great. Thank you, Mark and Alister. I’ll turn the call back to the operator to take questions, first from the analyst community and then if time permits from the media. Over to you, operator.

Thank you. [Operator Instructions] Our first question comes from the line of Neil Mehta with Goldman Sachs. Your line is now open.

Good morning, team, and thanks for taking the question. So the kickoff question I have for you is your CapEx range for 2020 is $5.4 billion to $6 billion. It’s a wide fairway. In light of the lower commodity price environment we find ourselves in today, do you think there is a scenario where you could be on the lower end of that range? And then as it relates to CapEx, you made some comments around West White Rose. Anything you can provide around that would be helpful as well.

Thanks, Neil. I appreciate the question. There’s no question that we’re going to be looking at all aspects of the business around cash generation, operating costs, capital and such. That said, a lot of these, like the cogen project and the wind project, and many of these projects were in the middle of execution, we’re committed. And one thing we do know is to drive shareholder value we need to stay in the course. And one of the choices we have is our strong balance sheet to be able to allow us to, when we initiate a project, follow it through; shutting these projects down to conserve cash, although, yet if you go back in our history, we did that a decade ago and suffered the consequences associated with it. So one of the things is we’ll be looking to manage any discretionary investments and such associated with it. We will be looking at our cost structure and looking at maximizing cash flow of course. But we don’t expect it to be fundamentally different. And I would expect you’re still going to see us in the declared range. The fairway that you described is consistent with how we’ve done our capital forecasting in the past. And last year, if you recall, we ended up lowering the upper end of our capital range from $5.6 billion to $5.4 billion in the second quarter and then came in at the higher end of the modified range. And so, we’ll look for opportunities to do the same thing as we go through 2020.

Perfect. And – sorry, go ahead.

Sorry. White Rose, I think as we’ve said before, one of the challenges we had is we were not happy with how this project was getting executed. I think in the last quarter I said that although this was overspending, this was not what we would consider normal overspending and so that this was – there was a substantial move outside of what we viewed was a reasonable range for project execution. That’s a key factor in driving the impairment on White Rose. That said, we believe the operator has intervened and been able to put together a project execution plan that we believe in, and this project is on track to get finished up based on the estimates and stuff that we’ve put in place. So, all of that was factored into how we positioned White Rose and the impairment that we took.

Perfect. And a follow-up is you’re talking about a path to higher production of Firebag and walking away from the Montreal coker. One of the things that’s made Suncor more defensive and differentiate over time is the degree of portfolio integration. So just talk about the importance of integration to Suncor and how you manage that on a go-forward basis.

Well, it’s interesting because we’ve talked about our range of integration and such, and we’re sitting within that range. We’re in the low 70s now around the amount of volume that we have integrated into the portfolio. One of the reasons that we were looking at some of the bigger integration steps like Montreal that would take 40,000 to 50,000 barrels a day of bitumen into Montreal was the fact that we had a substantial investment program coming around replication. With pushing that out, we think that, shutting down the coker project, we don’t see this as a temporary step, we see this as a permanent step in Montreal looking at all the various factors there. And we have other opportunities to integrate barrels, so we’ll continue to work it. But these are enhancements around the integration, the range we find ourselves. And where we are right now, we’re very happy with how that’s playing out and where we’re positioned in it.

All right, guys. Thanks so much.

Thank you. Our next question comes from the line of Greg Pardy with RBC Capital Markets. Your line is now open.

Yes. Thanks. Good morning. Mark, your base mining ROI has kind of come up as a question of late. So I’m glad you addressed that. It’s also been seen as kind of a motivating factor to potentially acquire and MEG has kind of come up in that mix. But could you maybe just elaborate a bit more on the game plan you’ve got in terms of resource runway and then just how acquisitions may or may not fit into that strategy?

Yes, it’s interesting. One thing I will tell you is if we’re going into acquisition, it won’t be for resource. We have an enormous amount of resource. And if you take all our contingent resource, we have about at current production rates, about 100 years of resource. So the reason that we would look at acquisitions is really for three key reasons, one is a top quality resource and cost structure that would be better than actually building something. Secondly, there would have to be synergies associated with it. And, thirdly, and I think we’ve proven this in the actions and investments that we’ve taken as we need to ensure and feel very comfortable we’re going to get a solid return for our shareholders. But resource, like when we look at the resource to put behind it, we have a lot of resource and the resource we have is rate within proximity to our upgrading complex, which is what’s fed by the mine today. So, we’re not – and so – and if you look at relative to the cost of the other options and stuff on the street, we view that buying resource through M&A right now is very expensive. And it’s one of the reasons that people have asked us for quite some time about whether in Fort Hills or Syncrude and such, and transactions literally have been rumored for years and nothing’s ever happened, and it’s just a difference between valuation and how we look at it. So our plan right now is we think, especially, with the technology advancements that we’re making both in the in situ side as well as in the mining side, we think that it’s far – it’s going to be far better for our shareholders to pursue the path that we’re on, at least at this stage.

Okay, great. And you talked about essentially debottlenecking Firebag. So I haven’t heard about Firebag 5 or 6 for some years now. Is that going to use solvent aided SAGD essentially? And would that be like just one incremental phase of 20,000 or 30,000? And how firm are you on doing that?

Well, it’s interesting, Greg. I’m glad you asked that question because I think maybe one of the things I didn’t describe well is both in the mine replacement as well as at Firebag, we’re leveraging a lot of the existing assets that are on the ground. So it’s not like what we did at Fort Hills, where you’re building a fully independent mine at grassroots costs. We can leverage a lot of the existing assets from energy utilities, infrastructure, tankage and even some of the extraction facilities associated with it. So it’s very different than what we did at Fort Hills in the mine. At Firebag, we’re not talking about Firebag 5 and 6. Those would be grassroots investment, where most of the infrastructure, yes, we’d get a little bit on utilities and tanks and infrastructure, but those were independent builds. What we’re really talking about is enhancing the performance of the first four phases of Firebag through debottlenecking the facilities and those sorts of things. So one of the things we’re doing right now is improving the water handling capacity at Firebag as an example. So this would be substantially lower cost than what we would do if we were building Firebag 5 or 6.

Okay. And it’s firm or it’s not firm that you’ll go ahead with that?

Well, we feel very optimistic that we’re going to make this work. Some of this activity is underway, so it’s one of the reasons in 2021 we’ll see our volumes creep up. And I think what we will see ultimately, and we need to get a firmer plan in place, but you’ll see our volumes start to drift up over time until we get into 2024, 2025, where you’ll see the final steps up, where we could – we think we can get up to 230,000, 240,000 barrels a day. So that’s actually the path that we’re on right now. And so some of it is firm, some of it is still being scoped and worked, but we’re optimistic enough that we pushed out the replication strategy because we think that we’ll be able to do it a lot more economically for the shareholder at a lot lower cost. And obviously, we would want to do that before we spend grassroots to grow volumes.

Okay. Last one for me, if you’ll accommodate. As you’ve got a lot of stuff going on, what’s the max CapEx we should be thinking about between kind of 2021 through 2024 just like an annual basis? Like, are you going to be through a $6 billion or $6.25 billion number or the number is going to be generally at or south of that?

We don’t give multi-year guidance, Greg. And so…

Yes, but that would be fun, Mark.

I know it would. I know and I’m sure I’ll get the question three more times to see if we mess it up. But I think if you look out though, the range that we’re in this year is kind of where we expect to be in the year ahead and I think it’s a good proxy for how we move forward. And obviously, I think that a lot of the concern comes out around, oh, you take what we’re doing and then you add on top of the replication, then you add on top of the coker, then all of this stuff and people go, wow, this isn’t affordable. It’s true. We have to make some decisions and some of which I communicated this morning.

Okay, terrific. Thanks all.

Thanks, Greg.

Thank you. Our next question comes from the line of Dennis Fong with Canaccord Genuity. Your line is now open.

Hi. Good morning and thanks for taking my questions. The first one just maybe falls along the lines of what Neil was kind of maybe hinting at there. You essentially moved away from the Montreal coker project. Is there still consideration around the Edmonton, potential debottlenecking and so forth around Strathcona? And how should I be thinking about that? Obviously, from a context of if there is some optionality around a mine life plan and the extension around Steepbank and potentially introducing, we’ll call it in situ volumes as a potential replacement for some of the component out of the mine, then obviously the level of integration isn’t as required as much on a go-forward basis. How should I be thinking about kind of Edmonton and how that plays into that construct? And I’ve got a follow-up. Thanks.

Thanks so much, Dennis, for your comments and questions. It’s interesting. I see where you’re going with this. Maybe the best way to characterize it and talk about is we’re always looking through our facilities to find debottlenecking opportunities because if we can figure out how to enhance the volume or performance of the assets by some amount of $0.25 on the dollar to Greenfield, for sure we’re going to do that. And I think that – and quite frankly, I’d say, some of the concern we see from the investors is, wow, you’re going to plow $2 billion into Montreal. Are you sure? We’ve spent a lot of time thinking about that and running all the analysis and concluded that actually wasn’t a prudent investment for the shareholder. But we have quite a significant complex in Edmonton. We are looking for continued opportunities to debottleneck and enhance it. As we have at Fort Hills, and I’ve talked about Fort Hills before, we can’t really get to it until we can run the facility full and we can’t run the facility full because of curtailment. So we’ve been delayed. I thought we would have a plan at this point in time to debottleneck Fort Hills. So now coming back to your other question about the mine, part of the issue with technology as we see it is we’ve always considered mining technology to be in a certain type of resource and in situ technology to be a very different type of resource. But now when we’re looking at things like radio wave technology and solvent with low pressure in situ recovery with, in some cases, some of the technologies we’re looking at have no steam at all associated with it. So greenhouse gas emissions are fundamentally different, 50% to 80% lower. But when you look at it that way, a lot of this resource, it’s just which technology should we apply to which resource. The integration strategy, yes, if you go back 50 years when we started up the operation, the upgrader was needed to be able to move the mine bitumen. But if you look at both the mining technology, I talked about the non-aqueous extraction, not only does it produce a barrel, but the way we envisioned the technology and the way we are testing it is it’s kind of like a Fort Hills, is that we literally extract carbon from the barrel, put it back in the ground. So the upgrader doesn’t have the same claiming requirement, but it has the same financial requirement. So really the integration strategy for us is maximizing the value of the barrel and being able to manage the commodity price risk of the light/heavy spread. So the upgrader and the refineries are still needed even if it’s an in situ barrel or if it’s using this new mining technology. Does that answer your question?

No, I think so. And I think the point is essentially utilizing existing assets to be able to, I guess, grind out the most value out of them.

For sure.

The second question is just around the buyback and kind of the timing around the Board renewal essentially on the $2 billion kind of from March forward, as well as kind of the discrepancy in timing as where you guys have TSX approval up until I think mid-May to complete the 5% there. And how we should be thinking about the, we’ll call it the cadence of share buybacks? I know in the past your program has never really been robotic and it has been definitely more opportunistic. How should we be thinking about this over the next couple of months? Thanks.

Yes. Thanks, Dennis. I’ll take that one. First thing I would say is, we’re in the normal timing when the Board looks at both the dividend and the buyback at the time period meeting, and we said those annual sort of guidance and targets going forward. So that’s really the Board has done for the next 12 months. We can see as parts of seeing up to $2 billion over stock buybacks. So I would say that the key number you guys need to look at. There’s an administrative piece that you’ve mentioned that goes around getting TSX approval to buy stock back, where it’s purely an administrative exercise. So don’t think that that is a different set of approvals and it sounded slightly differentiated as you noted, it’s a May timeline. The key thing for you guys to know and investors to know is what has the Board authorized us to buyback? It’s the $2 billion starting in March. And May, we’ll review the TSX stuff, but that’s just, as I said, administrative. On a cadence perspective, we are typically opportunistic as you said. We are now robotic. We have buying bonds at certain levels. At lower levels of our stock, we will buy more backs. So if the stock price is low as we saw in Q3 last year, we’ll buy more back. And if it’s at a slightly higher level, the pace slows down in a bit. But overall we’re targeting to buy up to $2 billion a year back.

Great. Thanks.

Thank you. Our next question comes from the line of Phil Gresh with JPMorgan. Your line is now open.

Yes. Hi. Good morning. First question, just to follow-up on the buyback question, just in a slightly different way; given the current oil prices are a bit lower than your framework of $55 WTI at the moment, how do you think about buybacks versus balance sheet if we are in a lower price environment? Is this something where on a short-term basis you’d like to stay committed to the $2 billion range and you just leverage the balance sheet if necessary? Or is it – yes, is it something you want to be rateable each year on understanding opportunistically quarter-to-quarter? Thanks.

Yes, thanks, Phil. I mean, if you look at our Investor Day, there’s sort of a capital allocation and metrics that we’ve laid out somewhere between $50 and $60 of WTI level, we say we will spend between $1 billion and $2 billion of buybacks. So it is rateable compared to where the oil price is going to be for the year. So there’s no doubt about that. We’ve always said that we would like to target $2 billion. Oil price is extremely volatile. Today we’re at $50, $51. Three weeks ago we were heading over $60. So I don’t think I’m prepared at this point in time to call off where we think it’s going to be and I still believe $2 billion is achievable.

Yes, sure. Understood. Okay. The second question is just on the CFO improvement opportunities. Mark, appreciate the additional color to the $1.05 billion number at this point. I think if we rewind back to when you initially laid out these targets, the idea was it’d be rateable at about $500 million per year from 2020 through 2023. And so as we look at the 2020, I think its Slide 6 where you have the FFO expectation for the year, that $55 WTI. Just trying to understand some of the moving pieces behind that. Is there some kind of embedded, $500 million – the first $500 million is embedded in that on the guidance or is it – or some of these things a little bit later because of the timing of the Syncrude pipeline or just any thoughts you have there on that guidance? Thanks.

Yes, thanks. It’s interesting because I would say it’s getting a little bit skewed. It’s a little bit later. I think the interconnecting pipeline is one that’s now towards the end of this year. Originally we thought it’d be at the start of this year, so we’ve got the full year benefit associated with it. We continue to push forward on the autonomous trucks, although we’re working to accelerate that and get it all the way on Fort Hills and such. So it’s skewed a little bit towards the back from the original rateable $500 million a year that we originally said, Phil. But the thing that I really like about it is we have real plans funded, they’re in execution and it’s moving forward. And the teams are really working it. And I think to some degree you see it in the fourth quarter in capital, once we approved the cogen and then the wind farm, the teams were all over it. And that’s a couple of hundred million dollars of what we’ve spent in Q4 were projects, that were approved in late Q3 and Q4. So, the teams are moving forward to get this stuff executed, but it’s a little later than anticipated.

Got it. So, if we look at that guidance for 2020 FFO, it’s basically, it looks to me like $2 lower on the price tag, but 5% higher in the production due to less curtailment. And those are the main moving pieces embedded in there, is that reasonable?

Yes, that’s – and so we haven’t modified our guidance. And so, yes, that’s how we put it out.

Yes. Okay. Thanks a lot.

Thanks.

Thank you. Our next question comes from the line of Benny Wong with Morgan Stanley. Your line is now open.

Hey, good morning, guys. Thanks for taking my question. My first one is on the results on the downstream. The other margins, which I think includes supply marketing lubricants, it’s a bit weaker than we anticipated. Just want to get a sense of how much you think this is kind of attributed to the seasonal weakness. We’ve been hearing that retail margins in Western Canada has been a bit under pressure from new entrance. So just wanted to get a sense of how persistent this could be, if at all.

Yes. We really see this as a seasonality issue associated with it. And so we think this is kind of normal course. The downstream really had a great job. They’re focused on driving market and really securing the market share and moving forward on some of that was really good. They’ve done an excellent job of running the refinery, second highest refinery utilization in the history of the company. So it’s – they’ve done a really good job, I’m proud of the team there, but this is just season – normal seasonality, Benny.

Understood. Appreciate those thoughts. My follow-up is, it looks like you guys are putting a little bit more money into ventures. They’re a little bit more sustainability focused, like the wind farm, that EV charging station and the equity interest in the biofuels. So just wanted to get your thoughts, Mark, on the long-term strategy here, is there a long-term mixer balance that makes sense to strive for? And as you look at these projects, how do you approach it and maybe a sense of what metrics you use when evaluating these projects against more conventional oil and gas opportunities or even shareholder returns?

Yes, it’s interesting because those I would put into some different categories associated with it because I think the one thing that’s abundantly clear is that the world needs more energy. 700 million people globally are still in extreme poverty and they need food and energy and medical support and such. So we need more energy, but we need a lot less emissions. And so some of these are technology plays when we look at it to try and understand is this a technology that could be part of the future. And so when you look at some of these little equity positions that we’ve taken as we explore some of these technology pieces, when you get into the electric highway, our view was, is that the world is changing. We can be a part of this. And so we put that in to see how the response would be because one of the biggest challenges with an electric vehicle is can you drive long distances? Clearly people can drive short distances and we felt the electric highway across Canada was a real positive complimentary to it. But then the third one you mentioned was the wind farm. And if you stand back and look at that, if you recall six years ago, we committed as a company to reduce our greenhouse gas intensity by 30% by the time we got to 2030. And I think everybody knows that yes, we might spend a bunch of time thinking about our goals, but when we set a goal and bring it forward, we are going to work on it. And so when you look at it in the last eight months, we’ve made two investment decisions that will essentially accomplish one third of that or 10%. So, so far we’ve achieved 10% of the 30%, the next 10% is related to the cogen investment and the wind farm that we’re in process of executing. And the remaining 10% is still getting worked and scoped out. And so I feel very comfortable that we’re executing the plans that we committed to six years ago. And the wind farm is part of that overall plan. And so this is just normal course. We’re fulfilling the commitments that we’ve made as we go on our journey. What we do know though is 2030 doesn’t solve everything and there’s more that needs to be done. So some of these technology pieces are really exploring some of the options for the future.

Great. Thank you.

Thanks, Benny.

Thank you. Our next question comes from the line of Asit Sen with Bank of America. Your line is now open.

Thanks a good morning everyone. I just wanted to follow up on the earlier question. Mark, you have given some specific numbers on these clean energy investments, 40-mile project $300 million, 25% spent in 2019, and also on Enerkem the $73 million. My question to you is – these investments have clearly been a strategy at Suncor, but could you frame for us how big in terms of CapEx these projects could be on a ratable basis and where do you see this going in a five year framework?

Yes, thanks Asit. It’s – the real focus around it is and the focus as I just mentioned on this is trying to figure out how are we going to hit our 2030 goal that we committed to six years ago. So, when you see it right now we have with the wind farm and the cogen, so we’re now two thirds of the way or we have an execution two thirds of what we had committed to. So there’s another third left. So if you look at – the cogen was $1.4 billion and the wind farm was $300 million and it is $1.7 billion to achieve 10%. But there’s obviously there’s a lot more to it because it wasn’t just greenhouse gases. Both of these we think are going to drive good returns for our shareholders and they were both done in unique ways to be able to maximize that value for the shareholders. So, in those cases, we’re spending money and finding economic ways to achieve the environmental goal that we set out. When you look at Enerkem as an example, $73 million, it’s a technology play. We thought it was prudent to explore the future as we start thinking about what is the world of energy. If you go and look at it, crude oil demand is growing about 1% a year this year. It’s – quite a few people with coronavirus believe that it will be negative this year. So this isn’t a market that’s growing. I think people are concerned about lots of companies talking about growing oil production forever. We know that can’t happen, so we’re trying to explore the future. Do we see massive money going into this? Certainly not into the future because these are technology plays. If something becomes commercial and we’re going to look at as an investment, then we would be able to lay out an investment path forward. But at this stage of the game, we don’t see that as a huge part of it. The wind farm is something that’s unique because our missions in Alberta, we can use the credits from a wind farm in Alberta, but we don’t see onshore wind at this stage being a significant part of our future.

Thanks for the details Mark. Appreciate it.

Thanks Asit.

Thank you. Our next question comes from the line of Manav Gupta with Credit Suisse. Your line is now open.

Hi guys. I have a little bit of a macro question. There were few developments in the last week, which were regulatory positive for two of the pipelines TMX expansion as well as Enbridge Line 3, I’m just trying to understand how do you view these developments? Do they make you more positive and what’s your outlook for any of these pipelines to start them in the next two to three years?

Yes, thanks Manav, I appreciate it. I think we’ve been consistent for as long as these conversations have gone on that we support these lines. Line 3, Trans Mountain as well as Keystone XL and so, so we have been supportive of these particular ones. We have always thought that they’ll move ahead and get executed. Timelines are what we’ve spent most of our time talking and debating. Generally, we’ve been later than what the operators have been saying on these lines because we know that in today’s world there isn’t a straight line between two points trying to do some of this big infrastructure. But now in saying that Line 3, they have the approvals. The Canadian portion is operating today. So we have about a 100,000 barrels a day of capacity on that line. So there’s an incremental 270,000 barrels a day to go with the latest hurdles getting cleared there’s a chance we could see it by the end of this year. But it may be, it’ll get delayed further – from our perspective, we’re not, we’re certainly not betting any of our shareholders money on any particular timelines. Trans Mountain, really encouraging to see it moving ahead, we’ve appreciated the support that the federal government has been putting behind it and it’s nice to see that project under construction and the courts continue to reinforce and support that. Will that decision get appealed? Maybe it will, it was a unanimous decision by the court. So, we’re encouraged by that and they’re on track to get this all executed. I think it’s going to take a little longer than what the operator says just for the challenges of execution and maybe there’ll be some further core challenges associated with it. But again, we stand by our position that it gets done and it just might be a little later than originally anticipated. Keystone XL, it’s another one that’s got some significant approvals recently and so we’re encouraged by that. It looks like Enbridge is getting ready to push ahead. So all of those projects, Keystone XL is probably the latest in that whole thing. Line 3 looks like it’ll be first and Trans Mountain in the middle.

Thanks guys. And a quick follow-up on the similar lines. We saw the year start with – looking at December the inventory in Alberta was building all the way to 38 million. We believe it’s come down about 5 million, 6 million, in the near term do you see rail ramp plus what you mentioned on Enbridge to put the inventory mode in control and trend down or do you see a scenario where it actually moves up and pressures the differentials?

No, I think you’re going to see inventory continue to decline. I saw another report last night that said it went down almost another million barrels week on week. So we’re making some progress there. We will get some advantage as well when the diluent lending changes here a little bit as we come into spring. But that said the arbs open rail is economic and so you’re seeing quite a bit of lifting. We’ve seen some record volumes now on the rail lines moving oil, which I think is encouraging. But, to the extent that the spread comes in, I would expect you’re going to see a whole bunch of rail get laid down too. So that’ll be interesting to see how that plays out. Productions come up as rail has gone up because of these special production allowances by the province and we’ve been very thankful for their support in putting that program in place. So I think we’re going to see inventories continue to decline slowly. But it wasn’t that long ago that we were sub-30 million barrels and one pipeline issue took us to tank tops. So, things can change quickly.

Thank you for taking my questions.

Thanks Manav.

Thank you. Our next question comes from the line of Mike Dunn with Stifel FirstEnergy. Your line is now open.

Thank you. Good morning everyone. Thanks for taking my questions. If I could, I’d like to just ask a bit of detail about the mine extension at the base mines Mark, is that, should we think about that as extensions of the North Steepbank side and, or the Millennium side of the mine? And is this on lands already held by Suncor, not considering any potential pushing onto the lease 29 boundaries? And I have a second question after that.

Yes. The resource that we’re talking about is on the West side of the river by where the upgrader is. So, that’s actually the resource that we’re talking about filing the application on. And I guess this just emphasizes the importance of what I said about, hey, we’re just filing an application to move this thing forward. We’re a long ways from a project sanction on this because we filed this application over a decade ago, as an expansion project, as a growth project like Fort Hills was. Now we’re treating this very much, as I mentioned before, this is just a sustaining project. So the amount of investment, the amount of assets that are required to be able to produce this resource is significantly lower. We see new technology that we’re working on that would collapse the cost structure further along with the greenhouse gas emissions and such, and also allow us to alter the carbon content of the crude, which would help with Scope 3 emissions. So, so there’s some really exciting technology plays associated with it. The resource we’ve had in our portfolio for a substantial period of time. And so this is something that we, the resource we control, obviously the regulatory process we don’t. But we’re allocating a substantial amount of time consistent with how we see applications being processed. We’re going to file conventional technology like we have at Fort Hills. The reason we’re doing that is because we have to provide the details. And it’s hard to do that on a new technology, but we’re outlining the new technology and the application to tell people what we’re trying to do.

Right. So this is the Voyageur South resource.

Yes, it is.

Mark. Okay. And second question. 18 years of straight dividends, dividend increases, I think in the past you folks may have talked to what you need for a WTI price to fund the dividend and sustaining capital. What do you guys have a target for? What you can, what you can fund and how does that, I guess if you do, what is it and what is it relative to the dividend and not just half cycle but full cycle sustaining capital.

Well, maybe I’ll come back and clarify on sustainable capital, but it’s $45 WTI. So what we look at is sustaining capital plus our dividend at $45 we should be able to fund it. And that’s actually how we model it. And so we look at the growth of the cash flow of the company and then test it against this benchmark to ensure that we feel that it would be affordable even at low prices. So that’s the methodology. It really hasn’t changed. This is what we’ve been doing for quite some period of time. It’s interesting when you say full cycle and sustaining capital in the same sentence because one of the joys of our asset is we have very long cycles. So, like Fort Hills, when we started up Fort Hills, we believed that it would produce and it has a resource to produce for 50 years, which is very different than if you look at the most short cycle capital in our business is shale and so essentially there to maintain your volumes and such, you’re playing a full cycle capital game a 100% of the time. So, one of the joys of it is we’ve – with this capital is on the ground, but that’s a very long cycle and we can sit, sustain the assets and continue to generate cash flow. When you say full cycle, I think about, okay, so when the resource runs out at Firebag, which honestly we don’t see happening for many, many decades is then you have to start thinking about, okay, the fundamental cost of replacing it. So even when you look at Voyageur South and the example we’ve talked about, it’s not even full cycle, although it’s much higher than what it would be in our normal sustaining where we’re not building assets to open up a whole new ore body. But we can do it at much lower cost. Why? Because we’re leveraging all the infrastructure that’s still on the ground. So, our costs right now, if you look at our sustaining capital, we would view that this is characteristic. It’ll be a little higher in the 20, 30 plus period as we decide how we’re going to put the resource in place to sustain the operation for the next several decades to come. But right now our sustaining capital really is sitting in this $3 billion to $4 billion range. I’d say $4 billion when we get into the big turnaround years, next year is a big turnaround year. This year isn’t, so the sustaining capital can move around when we look at our $45 we’re looking at kind of a normalization of that, so.

Okay. I guess Mark, what I meant probably on the full versus full cycle is historically you haven’t really included any capital for your E&P business in your sustaining capital definition.

Yes.

And then I think it was last year that you started to exclude the drilling of any sustaining well pads at SAGD from your definition. So combined, I mean there’s no perfect number for that, but combined I would peg those numbers at – closer to $1 billion a year likely like over the medium term needed.

Hey Mike, let me just clarify something, clearly is self understood out there. We do actually include, a while our definition externally for sustaining capital and it does include the well pads. We do include them when we calculate our breakeven at $45. So just to clarify that, the well pads are in there when we’re calculating the $45 breakeven in WTI. You’re absolutely correct we don’t include E&P, that’s a very lumpy business, so from that perspective that all economic in our view, we either decide to do them or not to do them, so we don’t really consider them to be sustaining capital projects.

Okay. Thanks for clearing that up. That’s all for me. Thank you for taking my questions.

Thank you. Our next question comes from the line of Jon Morrison with CIBC Capital Markets. Your line is now open.

Morning all. Can you just talk about the heavy CapEx spending Q4 and whether that was purely a function of kind of pulling things from 2020 into Q4 given some of the unexpected outages like Fort McKay where logistically it would make sense to do that maintenance work since there was downtime anyways or was there any other major factors at play there?

Jon, I think there’s really three factors that are driving that. And what you’re saying is, okay at McKay there is a very little bit, but I would say it doesn’t even show up in here. What – when is the fact that we approved some projects late in the year and started moving on them quickly, so you saw quite a bit of spend with the cogens and the wind turbines in the fourth quarter, which I don’t think people fully appreciate it. The other issue with it is there were some things that got delayed in the year, so unfortunately a lot more capital got spent in Q4 than what was originally planned. This is an area that we’re working with our organization because we need to, it’s much better for this to be rateable and that’s an area that we’ll be working with the organization going forward, but it’s really this – some of the capital getting delayed on some of the projects for various reasons and then bringing the cogen and the wind turbines and that’s why Q4 is so high. Obviously, if you look at our range for next year, what we did in Q4 isn’t characteristic of the quarters that we’ll have going forward.

Would it be fair to assume that Q4 reshapes 2020 at all or largely the guidance that you put out holds.

No, no. Our guidance holds for sure on capital for 2020.

Okay. Alister, any color on why you guys elected to take the Fort Hills right down in the quarter where we didn’t see that on a total. And is that just a difference in accounting standards, price deck assumptions or are you being a little bit more conservative than kind of your forecasting of CTUs?

Well, I’ll, maybe a comment on that Jon and then hand it over to Alister to provide a few of the details. But part of the issue with it is when the price went down in 2014, I don’t think people realized that we literally were going to go in year-over-year and years. So when you looked at the way that we did the tests for impairment previously, our costs or the price of crude that we assumed when we did those tests was much higher. So, and now you look at it and yes, the crude price is bouncing around and in some forecast it’s going up, and some forecast it’s going down. But when you look at it year-over-year, we’re literally bouncing around but trading sideways. And when we look at the markets, we think, hey, we’re sitting in this same range going forward for a foreseeable future. And our view was this let’s go test our bucks against that. And it’s really an adjusting the price forecast down, which is about a $10 adjustment in kind of the global crude price. When we look at it, that’s where this impairment took place. So, I don’t know, Alister, do you want to add to that?

Yes, the only thing I would say, it’s really a price driven view as we look forward. Just confirming what Mark said, I can’t make any comment to our partners on whether or why they’re taking any impairments. They have their own views from price. And remember everybody has a different starting point from a capital perspective, whether they bought in at a high price. So, it’s up to each individual partner as to what they take or not take.

Okay. Can appreciate that. Mark, in terms of the diversification efforts that obviously are new and they’re part of this historical DNA, but maybe are of growing importance, do you have a different return threshold for those projects? Maybe ex the Enerkem investment, which is a bit of a different animal?

Well, when you look at it, you have to factor in all the various views around carbon pricing and all that kind of stuff associated. So will we have different criteria on a risk basis, I would say no. Although the risks are often very, very different associated with it. But you have to keep in mind that a lot of these technologies, whether it’s Enerkem or LanzaTech – LanzaTech and such, you’ll find out that okay, but these, I wouldn’t consider them commercial technologies. We’re just trying to understand how can we move forward and find some of these solutions for the future. But when you look at commercial deployment of technology, our expectations are going to be very similar. It’s just that risks that we factor into it are very different on some of these investments.

Perfect. And maybe just a final one for me, just clarification on the dividend bump that was announced. Is it fair to assume that that would have been the increase that would have happened independent of whether WTI was oscillating at 50 or 60 as again, it’s really just being calibrated on a bottom-up cycle pricing and you might have taken greater comfort at a $60 level, the bump would have been the bump, independent of where the price is coming into the decision.

Yes. We view this as just this is what the expectation would be. And it didn’t really matter where we were in the price range associated but we view this as part of the fundamentals of where we think the price is going to be.

Okay. Appreciate the color. I’ll turn it back.

Thank you. This concludes today’s question-and-answer session. I would now like to turn the call back to Trevor Bell for closing remarks.

Great. Thank you, operator. Thanks everyone for joining us today. My team is around and IR are around all day, so please if there were questions that we didn’t get to, please reach out to the team and we’d be happy to do that. Otherwise, everyone have a great day and thank you.

Ladies and gentlemen, this concludes today’s conference call. Thank you for participating. You may now disconnect.