Good day, and thank you for standing by. Welcome to the Suncor Energy Second Quarter Earnings Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. I would now like to hand the conference over to your speaker today, Mr. Trevor Bell, Vice President of Investor Relations. Please go ahead.

Thank you, operator, and good morning. Welcome to Suncor's second 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. The actual results may differ materially from the expected results due to various risk factors and assumptions that are described in our second quarter earnings release, as well as our current annual information form. Both of these 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 second quarter earnings release. Following formal remarks, we will open the call up to questions. Now I'll hand it over to Mark for his comments.

Great. Well, thanks, Trevor, and good morning, and thank you to everybody for joining us. In late May, we held our Investor Day. At that event, we detailed our five-year plan, which focuses on value capture of our integrated business model. Building on the growth phase from 2015 to 2018, this optimization phase is governed by extracting increasing value from our business through enhancing margins, lowering our cost structure, providing increased shareholder returns and fortifying the balance sheet with significant deleveraging. In comparison to the growth phase, we will lower our economic capital by 40% and add new revenue streams at mid-teens returns. The optimization phase is expected to deliver significantly higher shareholder returns, including a 25% dividend CAGR through 2025 and continued stock buybacks. At the same time, we'll maintain a $35 US WTI breakeven and retire debt, strengthening the long-term financial health of the company. Foundational to this performance is our steadfast focus on operational excellence. By increasing the productivity and efficiency of our operations, optimizing the value of each barrel and thereby increasing free funds flow, we will grow cash returns to shareholders and fortify our financial position. The second quarter results delivered on our focus objectives, mainly operational excellence, lower costs, and increased shareholder returns. I'm going to go into each area in a bit more detail. Our focus on operational excellence continues to result in strong operating performance. Our operating performance from November to June of 2021 marks the best months of production from our oil sands operations asset in our company's history. That’s the best eight months of production in over 15 years. Base Plant utilization was 98% over this period, and we had yet another quarterly record at in situ with 253,000 barrels per day. We also completed significant turnarounds at all of our refineries, as well as at Syncrude and Buzzard, and at the same time generated funds flow from operations of $2.4 billion. Approximately 40% or $1 billion of these funds was returned to shareholders in the forms of dividends and buybacks. Since we began the buyback program in early February through the end of July, we have bought back over 42 million shares for $1.2 billion, representing approximately 3% of the outstanding shares. Turning now to operating performance. Oil sands operations production of 460,000 barrels per day was approximately 10,000 barrels per day higher than the first quarter, reflecting strong and reliable operations. From a utilization perspective, Base Plant operated at an average utilization of 96% in Q2, continuing its strong trend. Meanwhile, the operating performance at in situ from November 2020 to June 2021 averaged 250,000 barrels per day, making it the highest daily production period in nearly 20 years for Firebag and MacKay. Executing the nameplate capacity increase at Firebag last October contributed to this record production. In terms of costs, second quarter cash operating costs at oil sands operations were $23.85 per barrel. Looking at the last eight months, oil sands operations averaged $23.50 in cash operating costs per barrel. We've achieved these types of unit costs before. But what makes our 2021 performance stand out is that we fully absorbed over a 100% increase in natural gas prices versus the previous periods with similar unit cost results. That’s approximately a $1 per barrel increase being absorbed by reducing costs elsewhere. Syncrude production of 110,000 barrels per day includes the impact of significant turnaround at their largest coker. All planned scope, including some of the plans for this fall, was completed within budget. All three cokers are online, and operations are fully lined up for a solid second half of the year. While we went through this in detail at Investor Day, it's important to recall that this asset's operating performance has steadily improved, and we have a clear line of sight into synergies and reliability to achieve a sustainable $30 per barrel cash operating cost. At Fort Hills, production of approximately 45,000 barrels per day reflects the updated mine plan that we discussed on the first quarter call, specifically building our inventory for ramp-up towards a two-train operation. By the end of the quarter, the ore inventory build was slightly behind schedule, with access to additional contractor equipment and labor taking more time to ramp up than expected. We now have most of the additional contract resources in the mine, and we expect that we will be fully ramped up by the end of August. Subsequent to the quarter, we realized that we would need to change the slope of the south mine phase to maintain slope integrity, as this part of the mine will form a critical permanent pillar between Fort Hills and the Syncrude over mines. This will delay our ramp-up at Fort Hills to two trains until the end of 2021, as the south mine phase contained approximately 60% of our ore inventory that we thought was available. So to access this ore, we'll need to mine more overburden, which is just going to take some additional time. Given the mine is very early in its life, our flexibility to ramp up earlier is limited. As a result, Fort Hills plans to continue on one train at the current production level for the remainder of the year, with the transition to both primary extraction trains beginning late 2021 to enable full production in early 2022. The 2021 annual guidance for Fort Hills production and operating costs has been updated to reflect these changes. There's no change to our long-term view on costs, as discussed at our May 26th Investor Day. We expect costs to continue to improve every year towards a cash cost target of $20 a barrel by 2024. In our EMP operations, generally volumes were consistent with the first quarter other than Buzzard, which fully executed its turnaround in the second quarter. With our downstream segment throughput of 325,000 barrels per day, including planned turnaround activities across all our refineries, this was an opportune time for this activity as stay-in-place orders continued in Canada throughout the quarter, and the broader North American refining complex faced continued macro environment challenges. As we discussed previously, we built refined product inventories to support the planned turnarounds. With turnarounds complete and demand increasing across Canada as COVID restrictions are lifted, we are confident about our downstream strength and positioning for the second half of the year. We expect the U2 turnaround at the Base Plant to begin in early August, having a production impact of approximately 125,000 barrels per day in the third quarter. We anticipate partially offsetting the impact of the turnarounds via increased bitumen sales to market. Our decision to swiftly respond and stagger maintenance activities when COVID cases surged in the region, specifically pushing the U2 turnaround from Q2 to Q3, enabled us to complete the planned scope at the Syncrude turnaround and ensure safe and reliable operations across the assets. This was the right approach considering the strong operational performance at Base Plant and no material change in the scope or cost of the planned turnaround. We have completed one of the most significant maintenance schedules in our history during this quarter. While this has had an impact on production and costs at Syncrude and refineries in the quarter, we're now running at full rates and sets the stage for strong results in the second half of '21 and into 2022. In closing, I wanted to emphasize that our business model and philosophy, regardless of short-term volatility, will remain laser-focused on operational excellence, capital discipline, long-term shareholder value creation, and returning that value to shareholders while fortifying our balance sheet by continuing debt reduction.

Thanks, Mark, and good morning, everyone. For the second quarter, we’ve returned approximately $1 billion to shareholders in the form of $350 million in dividends and $650 million in share repurchases. During the quarter, our buyback amounted to approximately 23 million shares at an average price of $28 per share. In addition, we’ve received approval from Toronto Stock Exchange to increase our share buyback program from 44 million shares, or approximately 3% of Suncor's issued and outstanding common shares, to 76 million shares, or approximately 5%. In the second quarter, as Mark highlighted, Suncor generated $2.4 billion of funds from operations. The business environment continues to strengthen in the quarter with WTI increasing $8 per barrel, or 14%. This was due to realization of an average price of Oil Sands crude basket increasing by $10 per barrel, or approximately 16% versus Q1 despite the strengthening Canadian dollar averaging $0.81 during the quarter. This translated into approximately $300 million of additional upstream oil sands funds flow when compared to the first quarter results, even though production was 75,000 barrels per day lower due to the planned maintenance. Our Q2 financial results reflect a solid cost and reliability performance and demonstrate our leverage to increasing oil prices. The E&P segment generated $410 million of funds from operations with price realizations of nearly CAD 82 per barrel, delivering approximately $350 million of free funds flow net of capital expenditures. Finally, downstream recorded approximately $600 million of funds from operations with 70% utilization, which reflected the significant turnaround activity across the refineries and the continued lower consumer demand. The cost of royalty in the second quarter reflects the lower demand due to COVID restrictions, which were maintained throughout the quarter in Canada, and also the reduced volumes due to the planned turnaround activities. However, as Mark noted, we were able to partially offset some of the maintenance impacts by executing on our inventory build strategy we outlined in our previous quarterly call. Gasoline demand has steadily been improving in Canada with Q1 at 20%, Q2 at 15%, and gasoline demand in July at 5% below 2019 levels. Diesel demand has recovered while jet demand still remains 50% below 2019 levels. However, it is important to remember that less than 5% of our refined product volume is jet fuel. This improving demand trend in the second half of the year gives us confidence in the operational and financial performance of our downstream business going forward. As we expected, our debt reduction in the quarter was greater than Q1. We are managing our debt reduction and share buyback strategy on an annual basis and remain on track for our two-thirds debt reduction and one-third buyback strategy that we outlined at Investor Day. At Fort Hills, as Mark discussed, the only guidance change is related to updating the business environment. Steel commodity prices have increased since Q1, resulting in higher forecast profitability and cash flow. As a result, we've updated the cash tax range for 2021. Lastly, I'd like to note a couple of items for the second half of the year. We expect to close the Golden Eagle sale in September. The production will continue to be reflected as part of Suncor’s volumes, which will obviously close at which point it will be price-adjusted. There's no change in our full year volume guidance either specifically for E&P or overall for Suncor. Secondly, we expect the tax refund for the 2020 tax year in the fourth quarter, which will reduce our working capital. Total cash proceeds of approximately $1 billion from these two items will be used for debt reduction in the second half of the year. Before I close, I’d like to note that we have updated disclosure related to our rack forward business and our operating summary supporting the financial statements and are also in our supplementary IR page. We hope you'll find this additional disclosure useful as it does add more transparency on the significant part of our integrated model. And with that, I'll pass it back to Trevor.

Thank you, Mark and Alister. I'll now turn the call back to our operators so we can take some questions. Operator?

Your first question comes from the line of Greg Pardy from RBC Capital Markets.

Mark, I was wondering if we could revisit Fort Hills. Does the timeline for ramping up in the first quarter pose any challenges? Additionally, could you elaborate on when the instability you mentioned earlier became apparent?

So let me just step back for a minute on this, because the focus is on getting Fort Hills fully ramped up to two trains. And yes, that's been delayed until the end of 2021. So we're not expecting any impact in 2022 production. We found out about this in July as we've got later in the month associated with it. This is really about focusing to ensure that the slope has stability. As I mentioned, this is a critical pillar between the south end of the Fort Hills lease and the north end of the Syncrude Aurora lease. Because that mine space has about 60% of what we thought was the available ore and it's not going to be available until we clear more of the overburden associated with it. So this is just a time issue. We don't think it has any fundamental impacts beyond just delaying the ramp up of Fort Hills to add that incremental production to what you're seeing in our results now. The south mine phase is critical; after we've mined it, it’s just so critical that we don't want it moving and becoming unstable. In many places, it's not nearly as relevant, but this is a very critical piece of infrastructure going forward.

And I'm going to switch gears entirely here just to come back, I mean, you're a part of the quintet on the oil sands pathways net zero back in early June. You guys announced that. What are the milestones we should be looking for in terms of progression and so forth?

Well, it's interesting, Greg, if you just step back. Essentially, this is about taking the whole oil sand industry to net zero by 2050. I view this as an unprecedented collaboration between the oil sands producers. It represents 90% of the operators today. I fully expect that we will have the remaining operators join this journey as we go forward. There's one very significant foundational set of infrastructure that we see is critical for this. It's about building the carbon capture and sequestration capability for the industry. We think this is about 50% of the industry’s solution going forward, and so it's really important. By working together, we realize we can significantly drop the cost of this because we can all use a lot of common infrastructure, and we can go faster and do it cheaper. I think this is super important in this journey going forward. So if you look on the website now, the oil sands pathways to net zero by 2050, you'll see the map of the carbon sequestration system. You will see that this will be a common piece associated with it. Other parts are independent. Some are around fuel switching like our co-gen up north and switching to things like clean hydrogen, like our announcement that we made in Edmonton. You'll see through the company window some of this, but the big foundational project is what's being worked on. We’ve just come out with some of the details around the carbon sequestration system. We’re in the 90-day consultation period with the feds, and we're working on the details around the investment tax credits associated with that. So we're making good progress and we've been very happy with the cooperation between the province and the federal government.

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

The first question is around how Fort Hills factors into the production guide. You did maintain the 740,000 to 780,000 consolidated upstream number. Is it fair to say that you guys are targeting based on what you know right now, the low end of the guidance range?

I think that's probably fair, Neil. The assets have performed very well as I went through in my prepared remarks. You're seeing the oil sands year-to-date, it's at high 90s utilization. Syncrude has a proven strong record post turnaround that we've just gone through that coming into their turnaround in the second quarter. So with the completion of that work, we're expecting that the assets will perform very well. We're maintaining the corporate guidance associated with it, but we're not at the top end of guidance; we’re comfortable with the total guidance range.

Can you discuss your buyback strategy given that the stock has underperformed for most of the last two years? The free cash flow yield is quite strong, and it appears that you will focus on the buyback, likely reaching the upper limit of 5%. How do you plan to take advantage of the current valuation?

I mean, if you look at where we're headed, we obviously got 3% and already executed. We’ve got approval to go to 5%. We will be executing on that provided commodity prices remain at current levels. You'd expect to see that at the top end of that range through to February of next year and the buyback period. The strategy is one of a ratable buyback through the period, which is why you saw around $600 million in the quarter. We continue to execute it that way, obviously, within the remainder of the buyback.

Your next question comes from the line of Phil Gresh from JPMorgan.

I want to follow-up on Fort Hills. One of your partners on the project was referencing some issues with groundwater. I just want to understand the technicals of this a little bit better. You're talking about slope stability. I just want to make sure I fully understand why this would be a onetime issue as opposed to a recurring issue?

It's interesting, Phil. On the south mine phase, this is just the south mine phase, right? This is the one that we're building the corridor between the two mines. The integrity of that mine phase is important. Anytime you're building a dam structure, it’s super important that it has integrity and can be managed accordingly. Water management in oil sands is a very common issue, whether it's from rain events. Anytime you have soft rock mining, we are experiencing some egress of water from ground sources and such into the mine. We have procedures to manage it. Some events are more challenging than others associated with it. This is common across, I would say, almost all of the mines, if not all the mines in oil sands. We're following protocol. We don't expect this to be a fundamental issue any more than what we've seen. We expect the vast majority of this to diminish as we head north into the central pit. It needs to be managed, and that's what we've done, and we have the procedures in place and we're executing according to those procedures.

My follow-up question is just on OpEx. Obviously, acknowledging the strong performance for oil sands overall. The total company OpEx run rate is tracking a little bit over 10.8 billion. You mentioned the natural gas headwinds, which I think everybody's dealing with. Are you still confident in the 10.6 billion guidance you laid out for the year that you gave at the Analyst Day, given where the run rate looks and seasonality and other considerations?

If you examine our year-to-date figures, they stand at about $250 million, along with one-time items related to restructuring. Recall the significant severance restructuring provision we implemented in the first quarter due to workforce reductions. We also incurred some additional costs in the first half of the year linked to COVID restrictions, which are clearly easing, and we expect these costs to decrease significantly in the second half of the year. We are optimistic about this trend continuing into the latter half of the year, allowing us to achieve the run rate we discussed during Investor Day. Looking ahead to 2022, 2023, and 2024, we foresee a continued downward trend as we carry out our $2 billion cash flow improvement plan. On the gas side, we benefit through our power revenue, which is connected to gas prices in Alberta. While this is not classified under revenue, it is now included in the other revenue line.

And just to confirm, the 10.6 billion guidance just out of the one-time factors that you're talking about?

Yes, Phil, we excluded those. We focus more on the run rate rather than including one-time restructuring items in there.

And your next question comes from the line of Manav Gupta from Credit Suisse.

My question is a little bit of a follow-up on Neil Mehta's question. Looking at the quarter, I think you guys have given guidance that 66% of the discretionary cash that’s post-dividend goes to debt reduction and 33% goes to buyback. When we look at this quarter, there's about $750 million of discretionary cash, and $640 million went to buybacks while $100 million went to debt reduction. I'm just wondering if there's a change a little bit in strategy there or you expect a billion in buybacks and the Golden Eagle sale to come next quarter, so this was just a one-off quarter and there is no change to strategy?

There's no change to that annual allocation; it's an annual allocation to those debt repayments and one-third buybacks. So quarter to quarter it will move around, and obviously Q2, we always knew we'd be impacted by the maintenance higher capital and lower cash flow increase. That’s why we're looking at the annual allocation. But you're absolutely right, we have $1 billion of cash proceeds coming in, in the second half of the year from tax refunds and the Golden Eagle sale, and we're going to use those for the debt reduction.

Well, I think it's really twofold. You've touched on it here; obviously, we had all of our refineries doing turnaround work during this period of time. At Investor Day, we talked about when you look at refinery utilization, we said that we were 2x as profitable as the next year when we benchmark that from a cash perspective. That didn't count our rack forward business associated with that. The environment has improved significantly. As Alister talked about in his comments, as we go into the third quarter. The turnarounds are complete, the cracking margins are robust, and demand has recovered significantly, even in July versus the second quarter. We think we're set up really well for the back half of the year. It's simply the fact that between COVID and the turnarounds, you've experienced a much weaker market in the second quarter. We think we're in very good shape to perform well in the back half of the year.

There are no further questions. At this time, I will turn the call back to Trevor Bell.

Great. Thank you, Operator. Thanks, everyone for attending today. I know it's a busy day for earnings, and I appreciate you listening in. We're around all day if you have any follow-up questions. Thank you.

And this concludes today's conference call. Thank you for participating. You may now disconnect.