Good morning. My name's Colin, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the MEG Energy 2021 Q1 results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there'll be a question and answer session. If you'd like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you'd like to withdraw your question, please press star followed by two. Thank you, Mr. Derek Evans, CEO, you may begin your conference. Thank you, Colin, and good morning, everyone, and thank you for joining us to review MEG Energy's Q1 operating and financial results. In the room with me this morning are Eric Toews, our Chief Financial Officer, Chi-Tak Yee, our Chief Operating Officer, and Lyle Yuzdepski, our General Counsel and Corporate Secretary. I'd like to remind our listeners that this call contains forward-looking information. Please refer to the advisory in our disclosure documents filed on SEDAR and on our website. I'll keep my remarks brief today and refer listeners to yesterday's press release for more detail. MEG continues to proactively respond to the safety challenges associated with COVID-19 and remains committed to ensuring the health and safety of all of our personnel and business partners, and the safe and reliable operation of the Christina Lake facility. The screening procedures and protocols implemented by the company's COVID-19 task force during Q1 of 2020 continue to be enhanced to ensure continued safe and reliable operations. Flexibility and adaptability continue to be integral to the company's response to the pandemic. We continue to monitor the developing COVID-19 situation to determine what, if any, additional measures might be needed to be taken to ensure that health and safety of our people remain a top priority. I want to commend our teams for their outstanding diligence and focus that they have exercised in helping to ensure the health and safety of all of our employees and contractors. MEG had a strong Q1 from both a financial and an operating perspective. On the financial side of the business, we benefited from both the strength in the global oil market dynamic, as well as the structural improvement in heavy oil differentials. We remain very constructive that these changes will persevere and the headwinds that we've battled over the last six years with respect to egress and weakness in oil prices will abate and become tailwinds that will continue to drive significant free cash flow from our low-decline and low-cost business. On the operational front, we've now had two solid quarters of strong production performance at full capacity post our extended 75-day turnaround in the summer of 2020. This has given us the confidence to increase our production guidance from a range of 86,000 to 90,000 barrels a day to 88,000 to 90,000 barrels a day. The 2020 turnaround was extended to bring forward 2021 turnaround activities and eliminate the need for a turnaround this year. The elimination of a 2021 turnaround has been extremely helpful in managing the number of people at site from a COVID-19 perspective and the health and safety of our employees and contractors. Our strategy remains unchanged. Remain focused on executing on our capital program as efficiently and as effectively as possible, continuing to work on all our cost structures and using free cash flow to reduce debt. First quarter financial and operating highlights include adjusted funds flow of CAD 127 million, impacted by a realized commodity risk price management risk loss of approximately CAD 69 million. Quarterly production volumes of 90,842 barrels per day at a steam oil ratio of 2.37. Net operating costs of CAD 5.25 per barrel, including non-energy operating costs of CAD 4.05 a barrel. In that quarter, power revenue offset energy operating costs by 72%, resulting in a net impact of CAD 1.21 per barrel. We successfully refinanced $600 million of existing indebtedness at a coupon of five and seven-eighths, due February 2029, which pushed out the earliest outstanding long-term debt maturity to 2025. Total capital investment of CAD 70 million in the quarter was directed to sustaining and maintenance capital, resulting in CAD 57 million of free cash flow in the quarter. We exited the quarter with CAD 54 million of cash on hand and our CAD 800 million modified covenant- revolver essentially undrawn. MEG's bitumen realization averaged CAD 52.34 per barrel in Q1 of 2021 compared to CAD 38.64 per barrel in Q4 of 2020. The increase in average bitumen realization was due to a higher WTI price quarter-over-quarter. Offsetting the increase in bitumen realization during Q1 of 2021 compared to Q4 of 2020 was a realized commodity risk management loss of CAD 8.80 per barrel in Q1 of 2021 compared to a realized commodity risk management gain of CAD 1.31 per barrel in Q4 of 2020. This reflects stronger WTI settlement prices compared to WTI fixed price contracts put in place in late 2020. Corporation's cash operating netback averaged CAD 26.03 per barrel in Q1 of 2021 compared to CAD 18.66 per barrel in Q4 of 2020. Increased cash operating netback drove the increase in the corporation's adjusted funds flow from CAD 84 million in Q4 of 2020 to CAD 127 million in Q1. For the last nine months of 2021, MEG has outstanding benchmark WTI fixed price hedges and enhanced WTI fixed price hedges with sold put options for approximately 37% of forecast bitumen production and an average price of $46.20 per barrel. No new WTI fixed price contracts have been entered into since mid-January 2021. As previously mentioned, based on better than expected production performance in Q1, MEG is revising its full year 2021 average production from 86,000-90,000 barrels a day to 88,000-90,000 barrels a day. Due to increased apportionment on the Enbridge mainline, we're revising downwards our expected sales into the U.S. Gulf Coast via the Flanagan South and Seaway pipeline systems from approximately two-thirds to a full year average, AWB blend sales volumes to approximately 50%. As a result, MEG is revising down its estimated full year 2021 transportation costs from $7.75 US per barrel-$8.25 US per barrel of Access Western Blend sales to a range of $6.75 US per barrel-$7.25 US per barrel of Access Western Blend sales. As I bring my remarks to a close, I again want to thank our team at MEG for their commitment and perseverance through these exceptionally challenging times. MEG's performance continues to demonstrate our resilience, and I'm proud of our performance and confidence in our ability to continue this momentum throughout 2021. Looking ahead, we're confident in our ability to execute on our business plan and remain committed to sustainable, innovative and responsible energy development. We look forward to updating you on our progress in the coming quarters. With that, we'll now open the line for questions. Thank you. Ladies and gentlemen, we'll now begin the question- and- answer session. To ask a question, please press star followed by one on your telephone keypad. If you'd like to withdraw your question, please press star followed by two. Okay. All right. If you're using a speakerphone, please lift the handset before pressing any keys. Your first question comes from Phil Gresh from JP Morgan. Phil, please go ahead. Yes. Hi, good morning. Derek, first question for you would just be on the takeaway situation and your revision to the percentage you're planning to send down to the Gulf Coast this year due to apportionment. Just wanted to get your broader thoughts, just how you think apportionment and takeaway will play out as we exit the year and into next year. Great question, Phil. I'm going to ask Eric Toews to take that one. Phil, the reason we took down the amount of barrels we think we're going to move to Gulf Coast is simply mathematics. When we put our budget in early December, we expected apportionment to be around 35% for average for 2021. What we've seen through this first part of 2021 is about a 10%-15% higher level than that, and so simply, mathematically with higher apportionment, less barrels get taken down the Flanagan Seaway pipeline. We sell less down there. Now, as it relates to what we see going forward, we expect that apportionment level to go down to that sort of 10% level, ±, once Line 3 comes on, and I think the general view is that comes on in late Q3 or early Q4. We are aware of the ongoing legal challenges to that. I think Enbridge has tried that ground pretty well over the past. We expect that pipeline comes on in that timeframe. We'd see that level mitigate. Obviously the amount of barrels we move to the Gulf Coast in the back end of the year, if Line 3 proves to be true when it comes on, you should expect to see our barrels ramp back up when we get down that pipeline. Phil, I could just add two quick reminders. I know people, or I hope people remember that even though we do not move those barrels or cannot move those barrels, that there is no take or pay on those barrels. The cost of moving those barrels is not incurred. Those barrels just get moved to the end of our contract. I guess the other thing I'd just point out that there has historically been a negative price associated with high apportionment levels. That is not the case with the apportionment levels that we're seeing today. In fact, we can show you that in months such as February of this year, when the post-apportionment barrels, i.e., the barrels that had to be turned back from the line actually sold at a premium to the pre-apportionment barrels. I guess the long and short here is that, although apportionment levels are high, we're not seeing what we would've seen previously in terms of higher differentials. Sure. I guess just to follow up, as you look at, say, 2022, and assuming Line 3 is on relative to your 100,000 barrels a day of potential takeaway, do you think that the production environment would be such that you'd be able to fully utilize that in 2022 in a full Line 3 case? Yeah. It's Eric. We think that that apportionment level that we talked about for the back end of the year sort of carries through 2022, when you factor in what production may come on in 2022. Right. Okay. Just one other quick one from me. Your non-energy OpEx costs were quite solid in the quarter, fulfill your guidance. Maybe you could just share your thinking there on how that would progress. Is there something specific that would make the non-energy OpEx per barrel be going higher the rest of the year? Is it just some conservatism since it's still early? Thanks. Our non-energy operating costs tend to typically be. If we look across the year, they tend to be the lowest. Then they grow as we bring in more maintenance-type activities through Q2 and Q3, through the summer months. We try and minimize the amount of work that we do outside in the cold, in the winter. As a result, the operating costs in Q1 tend to be a little bit lower than on average. We do not see any reason to change our operating cost guidance at this juncture. Great. Thank you. Your next question comes from Greg Pardy from RBC Capital Markets. Greg, please go ahead. Yeah, thanks. Good morning. Derek, you comment on your production rates being in great shape here for a couple of quarters, which has caused you to change your guidance. What are the main drivers, then, of keeping those rates higher than what you might have expected? I'm going to ask Chi-Tak Yee, our Chief Operating Officer, to take that question. Good morning, Greg. One of the main things for Q1 is we have a very high reliability performance at the plant. We typically had about 97% type of reliability, but Q1 is around 98%, 99%. That really helped. Also, as Derek talked about earlier, the 75-day turnaround we did last year, really put everything in good shape. We've been able to get that type of reliability. Also, we've been doing a fair bit of optimization on the existing production as well, and that was translating into a better-than-expected performance in Q1. Then, we're able to expect that momentum will carry through Q2 and the rest of the year. Okay. Terrific. Just related to everything you said around pricing and diffs and production rates, this is kind of a question for Eric, I guess is, cash obviously sitting at CAD 54 million, but what's the path of that that you would see through the next three quarters? I mean, we've modeled it, but I'm curious as to what you see coming. I guess the only way to answer that is when you look at Derek talked about the hedging loss we had in the quarter. That dissipates as we move through the year, as you can see from our table on the hedging barrels we have hedged. I think when you model WTI, and if you keep the diffs. We think diffs for the rest of the year are in that sort of CAD 11-CAD 12 range, WCS diffs. Gulf Coast has obviously been very tight. We don't see that changing for the rest of the year. As the back end of the curve has moved up here, I think you should expect to see higher cash flow in each quarter as we move through the year at the current strip pricing. Okay. Terrific. Thanks very much. Your next question comes from. Thanks, Greg. Your next question comes from Neil Mehta from Goldman Sachs. Neil, please go ahead. Hi, good morning. This is Carly on for Neil. Thanks for taking the questions today. The first one was just kind of around the balance sheet, which has been a big focus for you guys. Can you just talk a little bit about how you're thinking about the path of debt reduction and kind of what you view as the optimal leverage level on a sort of normalized basis going forward? Yeah, sure. The first part, I guess, I think as Derek said outside of the call, all the free cash flow right now is going to go towards debt repayment. That's basically what we've been doing for the last number of quarters or number of years. The second question is, we've talked about sort of a $1.75 billion-$1.85 billion level of debt on a sort of first stopping off base. That's about a 2.25x-2.5x debt to EBITDA multiple. Based on the quality of the asset and the sort of low decline rate, we think that's an acceptable first stopping off level. That's about another $500 million of debt reduction that we have targeted. Our intention wouldn't be to stop there, but that's our first stopping off point from a leverage reduction perspective. Great. Super helpful. The follow-up is just around hedging. Commodity prices have recovered quite nicely here. Can you just talk about how you're thinking about the hedge book, moving to the end of the year into 2022? Yeah. We haven't put on any new WTI hedges since very early in 2021. We haven't looked to 2022 yet. We obviously need to work through our capital budget. We've seen the strip like everyone else has. As of right now, we haven't put any 2022 hedges on, but we'll consider that as we move through the back end of this year and whether or not we do that from a sustained capital preservation perspective. Did you have a follow-up? Nope. Good on my side. Thank you. Okay, your next question comes from William Lacey from ATB Capital Markets. William, please go ahead. Derek, you've been pretty acutely focused on the whole issue of carbon, and the Government of Canada with their announcement in the budget, it was notably vague and obviously it's evolving. Just wondering what you would be looking to see from, I guess, both the federal and provincial governments in terms of policies, incentives in order to encourage investment in CCUS and other sort of related technology. Good morning, Will. Thanks for the question. MEG's been a leader in reducing the intensity of carbon, on a per barrel basis, utilizing eMVAPEX, our SAGD and the cogen facilities that we've put in the field. I think a number of years ago, we realized that there was still some work to do there, but that ultimately that carbon capture and storage was going to be the way that we decarbonized our barrels. We have been looking to both the federal and the provincial government to support that idea, not only in terms of coming to the table with some level of fiscal support to help put in place the facilities to enable that, but also from a regulatory and a pricing perspective. We can't put capital to work on carbon capture and storage until you know that every time the provincial government changes, that your carbon regulations are going to change or that federal provincial jurisdiction is still under sort of question. That of course, as you know, has been sorted out by the Supreme Court here recently. I think what we were looking for in the budget was a much stronger sign of support from the federal government. We saw it in two fronts, in terms of an incentive that is currently going to be worked on, income tax incentive, that could be transferable. We think that held some promise that's very similar to what the 45Q program is in the United States, which is up to about $80 a barrel of carbon now. We'd be looking for some sort of certainty, obviously that the carbon regulations aren't going to change. We haven't seen that. We saw sort of CAD 319 million, I think, of R&D type expenditure. We'll continue to work with both levels of government. We believe both levels of government are interested in trying to find a path to get carbon capture and storage going. Obviously we're not spending any money on this. We're spending a lot of time trying to figure out how and what is the best way to navigate this carbon capture and storage on a go forward basis. It is the single biggest lever that we have as an industry to pull to put carbon away, and it's absolutely critical to find a way to make that happen. It's not something that MEG can do on its own. It's something that our industry, the oil sands industry needs to find a way to collaborate on and, with the assistance of both the provincial and the federal government. Thanks, Derek. I knew you had an opinion on this, so thanks for sharing it. You're welcome. Ladies and gentlemen, as a reminder, should you have a question, please press star followed by one. Okay, we've got a question from Menno Hulshof from TD Securities. Please go ahead. Good morning everyone, and thanks for taking my question. Derek, on the last call, you talked about potentially taking capacity to 100,000 barrels per day at a capital efficiency of, I believe it was around CAD 15,000 per daily flowing if you believe that oil prices were supportive. Have your thoughts evolved at all on that front since the last call? Yes. Our thoughts continue to evolve on that. Obviously we've seen some good, strong performance in the first quarter. I think a large part of whether we would put any capital back to work is really predicated on the strength and lack of volatility that we would want to see in terms of the WTI oil price and obviously, the differential. I think we're very encouraged by what we've seen, but obviously we're not ready at this point in time to put additional capital to work, but we're reevaluating that on a quarter by quarter basis. Thanks, Derek. That's all I had. Thanks, Menno. There are no further questions at this time. Please proceed. Well, thank you very much everyone for joining our call today. Appreciate it. It's going to be a busy day. Hope everyone has a good one, and we look forward to updating you on our continued progress at our next quarterly conference call. Take care. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.