Suncor Energy Inc (SU) 2019 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Suncor Energy Fourth Quarter 2019 Financial Results Call.

(Operator Instructions)

I would now like to hand the conference over to your speaker today, Trevor Bell, Vice President, 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.

Now I'll 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 2 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 Syncrude.

2019 was the third best upgrading utilization at base plant in our history.

Year-over-year production volumes were relatively flat.

However, there was approximately a 12% increase in SCO production.

Although this has put pressure on our 2019 production volumes and costs per barrel metrics, the result of this strategy is higher margins and cash flow.

At Syncrude, we marked the second best annual production in the asset's history, which is quite something when you consider that there was -- it was in a year where mandatory production curtailments impacted the operations.

This performance supports our multiyear journey to 90% utilization and $30 per barrel costs at Syncrude.

While Syncrude has had its own challenges, we're encouraged by the progress that Syncrude team has made in 2019.

Fort Hills continued to be curtailed during the quarter, which restricted its performance and its potential to 88,000 barrels per day, thereby, increasing the cash cost per barrel metric.

Offshore assets had a solid quarter with 116,000 barrels per day of production.

Hibernia returned to normal operating levels, while Hebron and Oda both continued to ramp up, partially offset by natural declines in the U.K. North Sea.

2019 marks a new annual record for downstream funds from operations of $3.9 billion.

In fact, Q4 2019 marks the tenth consecutive quarter with funds in excess of $750 million.

Refinery operating expenditures continued to remain low at $5 per barrel, reflecting our focus on costs.

Despite all that, we had 2 issues in the quarter.

As most of you are aware, on December 19th, we were notified by the regulator in Newfoundland and Labrador to shut in Terra Nova.

This is a regulatory issue, and we are working diligently with the regulator to get the issues satisfactorily resolved, and only when that occurs, do we expect the asset to return to operations.

I'll remind everyone that our value of safety, above all else, is foundational to everything we do at Suncor, and at no time did we operate unsafely.

We did have an operational issue in the quarter related to MacKay River, which is disappointing.

The facility has been out of service most of December and is currently shut in for repairs.

In light of the continued mandatory production curtailments in Alberta, the downtime is anticipated to have no material impact on our 2020 guidance.

With that, I'll pass it along to Alister to provide some additional financial context, including an overview of the impairment that we took in the quarter.

Thanks, Mark.

As he 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 cost 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 on 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 noncash 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 on our share buyback program during the quarter, spending approximately $450 million to repurchase 11.1 million shares.

As Mark said, in 2019, we returned $4.9 billion to shareholders, including $2.3 billion in share buybacks, repurchasing 3.5% of our outstanding shares at an average price of $41 per share.

For the full year, our dividend 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 3 years, we have returned approximately $14 billion to our shareholders.

This amounts to cumulative returns of $9 per share or approximately 20% of our current 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, an 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 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 decision approximately 1 decade away.

We feel that filing in 2020 is prudent under the current regulatory process, including the effects of the new Impact Assessment Act to ensure adequate time is provided for the regulatory process.

Should we choose to extend the mine, the plan is expected to incorporate non-aqueous extraction technology, which significantly reduces the cost and environmental impacts of mining Oil Sands versus our current operations.

If sanctioned, the extension would significantly contribute to our commitment to reduce the emissions from our operations and it's in line with Canada's global commitments and takes advantage of Canada's important strategic resource.

These decisions continue to advance our strategic priorities while demonstrating capital discipline and a deliberate approach to maximize shareholder returns from each of our investments.

Looking at the year ahead, we will remain focused on safety and reliably operating our assets.

We will execute our plans to grow our free cash flow by $2 billion annually by 2023, while continuing to make progress on our ESG targets.

Our 2020 plans include completing deployment of autonomous haul trucks at Fort Hills, beginning construction of the cogeneration unit at base plant, continued deployment of our past tailings management technology, optimizing our supply and trading organization and completing the Suncor and Syncrude long-awaited interconnecting pipeline in the second half of 2020.

And as part of our digital strategy, we have completed the planning for a data-enabled enterprise-wide processes that will improve the effectiveness and efficiency of our business.

We expect this program to deliver approximately $250 million in annual benefits at a cost of approximately $450 million, which is included in our capital guidance.

Sanctioned projects, along with this initiative currently represent approximately $1.5 billion or 75% of the $2 billion 2023 funds flow goal.

We understand the need to provide more clarity on our commitment to achieve our $2 billion target.

To accomplish this, we will host an investor showcase in Toronto on May 20 to highlight the details and focus on our ESG targets and performance.

More information will follow-on this half day event.

And as we move into the new decade, I'm excited and optimistic about the future we're building at Suncor.

We are focused on what is necessary for us to be profitable, resilient and relevant over the long term.

We're making investments in high-return projects in the core of our business, which will increase our cash flow in a sustained way without being dependent on oil prices or egress.

Our history of countercyclical investments have funded large and increasing shareholders returns as demonstrated by our 11% dividend increase and our extension of the $2 billion buyback program this year.

While at the same time, we're continuing our multi-decade history of being a leader in ESG, and deepening our relationships with the indigenous and nonindigenous communities where we operate.

With that, I hope you can appreciate why I'm optimistic about entering this new decade.

With that, I'll turn it over to Trevor.

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.

Your first question comes from the line of Neil Mehta with Goldman Sachs.

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.

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 we're in the middle of execution, we're committed.

And one thing we do know is to drive shareholder value we need to stay the course.

And one of the joys we have is a 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, if you go back in our history, we did that a decade ago and suffered the consequence 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 that the fairway that we've -- that you described is consistent with how we've done our capital forecast 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 Q2 and then came in at the higher end of the modified range.

And so -- and we'll look for opportunities to do the same thing as we go through 2020.

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 that 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 differentiated 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 a 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 view 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 in.

And where we are right now, we're very happy with how that's playing out and where we're positioned in it.

Our next question comes from the line of Greg Pardy with RBC Capital Markets.

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 MAG 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'd take all our contingent resource, we have about a -- at current production rate's about 100 years of resource.

So the reason that we would look at acquisitions is really for 3 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 it 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 has 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 then essentially?

And would that be like just 1 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 cost.

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. We -- those would be grassroots investment, where most of the infrastructure -- yes, we've got 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 4 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 '24 and '25 where you'll see the final steps up where we can -- 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.

I feel accommodated.

As you got a lot of stuff going on.

What's the max CapEx we should be thinking about between kind of 21 through 24 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?

You know, we don't give multiyear guidance, Greg.

And so...

Yes, but that would be fun, Mark.

I know it would be.

I know, and I'm sure I'll get the question 3 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 it replication than you had on top of it 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.

Our next question comes from the line of Dennis Fong with Canaccord Genuity.

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, and the 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 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 components 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 contract?

And I've got a follow-up.

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 to 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, 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 in (inaudible), 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.

That -- 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 envision the technology and the way we're 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 cleaning 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 and 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 has been definitely more opportunistic?

How should we be thinking about this over the next couple of months?

Yes.

Thanks, Dennis.

I'll take that one.

First thing I would say is we're in the normal timing for when the Board looks at both the dividend and the buyback at the February meeting, and we set those annual sort of guidance and targets going forward.

So that's really what the Board has done and set for the next 12 months, we can see us purchasing up to $2 billion of our stock buyback.

So I would say that's the key number you guys need to look at.

There's an administrative piece that you mentioned that goes around getting TSX approval to buy stock back.

That is purely an administrative exercise.

So don't think that, that is a different set of approvals and it's done on a slightly different schedule, as you have noted, it's a May time line.

The key thing for you guys to know and investors to know is what does the Board authorized us to buyback?

It's the $2 billion starting in March.

In 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 not robotic.

We have buying bands at certain levels, at lower levels over stock.

We will buy more back.

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 a bit.

But overall, we're targeting to buy up to $2 billion a year back.

Our next question comes from the line of Phil Gresh with JPMorgan.

First question, just a follow-up on the buyback question, just 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 something you want to be ratable each year on understanding opportunistically quarter-to-quarter?

Yes.

Thanks, Phil.

I mean, if you look at our investor deck and the sort of capital allocation metrics that we've laid out somewhere between $50 and $60 of a WTI level, we say we will spend between $1 billion and $2 billion of buybacks.

So it is ratable 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.

3 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 is 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, I appreciate the additional color to the $1.5 billion number at this point.

I think if we rewind back to when you initially laid out these targets, the idea was it to be ratable at about $500 million per year from 2020 through 2023.

And so as we look at the 2020, I think it's Slide 6 where you have the FFO expectation for the year at 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 guidance?

Or is it -- are 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?

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 would be at the start of this year, so we'd get 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 in at Fort Hills and such.

So it's skewed a little bit towards the back from the original ratable $500 million a year that we originally said, Phil.

But the thing that I really like about it is where we have real plans, funded, they're in execution, and it's moving forward and the teams are really working at -- and I think, to some degree, you see it in the fourth quarter in capital once we approve the cogen and the wind farm, the teams were all over it.

And that's a couple of hundred million dollars of what we 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 looks to me like $2 lower on the price deck, but 5% higher in the production due to less curtailments.

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.

Our next question comes from the line of Benny Wong with Morgan Stanley.

My first one is on the results in the downstream.

The other margins, which I think includes supply, marketing, lubricants, was a -- 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 entrants.

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.

Their focus on guiding 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.

And -- but this is just 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 that are a little bit more sustainability focused, like the wind farm, the EV charging station and the equity interest in the biofuel.

So just wanted to get your thoughts, Mark, on the long-term strategy here.

Is there a long-term mix of 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 property 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 complementary 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 6 years ago, we committed as a company to reduce our greenhouse gas intensity by 30% by the time we get 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 8 months, we've made 2 investment decisions that will essentially accomplish 1/3 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 6 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.

Our next question comes from the line of Asit Sen with Bank of America.

I just wanted to follow-up on the earlier question.

Mark, you have given some specific numbers on these clean energy investments, 40-mile wind project, $300 million, 25% spent in '19 and also on Enerkem with $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 5-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 6 years ago?

So when you see it right now, we have -- with the wind farm and the cogen.

So we're now 2/3 of the way -- or we have in execution 2/3 of what we had committed to.

So there's another third lap.

So if you look at the cogen was $1.4 billion and the wind farm was $300 million, it's $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 it 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 emissions 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.

Our next question comes from the line of Manav Gupta with Crédit Suisse.

I have a little bit of a macro question.

There were a few developments in the last week, which were regulatory positive for 2 of the pipelines, TMX expansion as well as Enbridge line three?

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 up in the next 2 to 3 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 we have been supportive of these particular ones.

We have always thought that they'll move ahead and get executed.

Time lines 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 2 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 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 -- maybe it'll get delayed further.

From our perspective, we're not -- we're certainly not betting any of our shareholders' money on any particular time lines.

Trans Mountain, really encouraging to see it moving ahead.

We've appreciated the support that the federal government's 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 will be some further court 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.

And 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 will be first and Trans Mountain in the middle.

And a quick follow-up on 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 more 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 1 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 liftings.

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 it will be interesting to see how that plays out.

Production has come up as rail has gone up because of these special production allowances either 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 top.

So things can change quickly.

Our next question comes from the line of Mike Dunn with Stifel FirstEnergy.

If I could, I'd like to just ask a bit of detail about the mine extension at the baselines, Mark.

Is that -- should we think about that as extensions of the North Sea Bank side and/or the Millennium side of the mine?

And is this on lands already held by Suncor, not considering any potential pushing on to the at least 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.

It's -- 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 there is 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.

And -- 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 the new technology.

But we're outlining the new technology and the applications tell people what we're trying to do.

Right.

So this is the Voyager South resource?

Yes, it is.

Okay.

And second question 18 years of straight dividends -- dividend increases.

I think in the past you folks may have talked to you know what you need for a WTI price to fund the dividend and sustaining capital.

Do you guys have a target for 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 sustaining 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 view 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 -- 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 and our business is shale and so essentially there to maintain your volumes and such, you are playing a full cycle capital gain 100% of the time.

So one of the joys of it is we -- this capital is on the ground, it has 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 it 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 the 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 cost right now, if you look at our sustaining capital, we would view that this is characteristic.

It will 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 full versus full cycle is, historically, you haven't really included any capital for your E&P business in your sustaining capital definition.

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?

Mike, let me just clarify something that clearly isn't self-understood there.

We do actually include -- well, our definition externally for sustaining capital does include the well pads.

So we do include them when we calculate our breakeven at $45.

So just to clarify about the well pads are in there when we're calculating the $45 breakeven in WTI.

And you're absolutely correct.

We don't include E&P.

It's a very lumpy business.

So from that perspective, they're 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.

Our next question comes from the line of Jon Morrison with CIBC Capital Markets.

Can you just talk about the heavy CapEx spend in 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 3 factors that are driving it.

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.

One 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 fourth quarter, which I don't think people fully appreciated.

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 ratable, 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 in, that's why Q4 is so high.

Obviously, if you look at our range for next year, what we did in Q4 is uncharacteristic of the quarters that we'll having 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 write-down in the quarter where we didn't see that over at Total and is that just a difference in accounting standards, price deck assumptions or are you being a little bit more conservative in

kind of your forecasting of CGUs?

Well, I'll maybe 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 on year.

So when you look at the way that we did the test for impairment previously, our cost 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.

In some forecasts it's going up.

In 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 -- is let's go test our books against that.

And it's really in 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 is 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 on price.

And remember, everybody has a different starting point from a capital perspective, whether they bought in at a high price or -- so it's up to each individual partner as to what they take or not take.

Okay.

I appreciate that.

Mark, in terms of the diversification efforts that obviously aren't new, and they're part of the 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 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 and it's just that the risks that we factor into it are very different on some of these investments.

Perfect.

And maybe just a final one for me.

Just a clarification on the dividend bump that was announced, is it fair to assume that would have been the increase that would have happened independent of whether WTI was oscillating at $50 or $60?

And again, it's really just being calibrated on 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.

We view this as part of the fundamentals of where we think the price is going to be.

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 I are around all day.

So please -- if there were questions that we didn't get to, please reach out to the team and we'll 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.