Good morning. My name is Ludy, and I'll be your conference operator today. At this time, I would like to welcome everyone to the MEG Energy's 2023 Q3 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number 1 on your telephone keypad. If you would like to withdraw your question, please press the star followed by the number 2. Thank you. I would now like to turn the conference over to your speaker today, Mr. Derek Evans, President and CEO of MEG Energy. You may begin your conference. Thank you, Ludy. Good morning, everyone, and thank you for joining us to review MEG Energy's 2023 Q3 operating and financial results. With me on the call this morning are Ryan Kubik, our Chief Financial Officer, Darlene Gates, 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 advisories 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. Our top priority at MEG is our focus on health, safety, and the environment that ensures nobody gets hurt, eliminates serious incidents, and delivers operational excellence. I'm extremely proud of the safety, operating, and financial performance delivered by our team. Their focus on plant reliability, steam utilization, project execution, and ongoing well optimization have all contributed to a strong operational quarter. Before I turn the call all over to Darlene and Ryan to share details of our results, I would like to briefly touch on the business highlights. MEG's financial performance continues to benefit from strong oil prices, which reflect favorable supply and demand fundamentals for both WTI and WCS heavy oil differentials. WTI prices averaged $82 a barrel in the third quarter, supported by increasing global oil demand and coordinated OPEC+ production cuts and supply management. The WCS discount to WTI in Edmonton averaged $13 per barrel during the quarter, driven by effectively zero apportionment on the Enbridge system, strong U.S. Gulf Coast exports as a result of rising heavy crude capacity in Asia, and tight global heavy crude markets as a result of OPEC+ reducing supply. That WCS differential is a key indicator of pricing for our product in Edmonton, but it's important to remember that we sold 73% of our blend volumes in the third quarter into the U.S. Gulf Coast. Heavy oil in that market has been even stronger, allowing us to receive a premium over what is achievable in Edmonton. Our market access and market optimization activities in the third quarter generated a weighted average premium of $0.69 per barrel on our realized AWB price over the Edmonton AWB benchmark. After deducting diluent and transportation costs to get our product to market, our bitumen realization was $84.75 per barrel at our plant gate in Q3. WCS prices have more recently widened, reflecting refinery turnarounds, higher Western Canadian Sedimentary Basin production, seasonal heavy oil blending requirements, as well as perceived concerns about Alberta storage capacity and TMX timing. TMX pipeline to Canada's West Coast is on track for startup late in the first quarter. Line fill of 4.5 million barrels should positively impact the WCS differentials in Q1 2024. With 20,000 barrels per day of committed capacity on TMX, MEG will have over 80% of its production with access to tidewater. Near-term fundamentals remain strong as we head into 2024. The industry will also be positioned with excess takeaway capacity for the first time in many years, and that should narrow and reduce the volatility of WCS heavy oil differentials. We anticipate the current wide WCS differentials will narrow slightly as we head into the end of the year and will remain elevated until TMX moves into operation at the end of Q1. Q2 and Q3, or Q2 and Q3 2024 differentials should look similar to 2023, with Q4 2024 only marginally higher than Q2 and Q3. Our financial results reflect strong operating performance and enable our commitment to debt reduction and share buybacks. Since April 2022, we've repurchased $853 million of senior notes and CAD 668 million, or about 33 million shares, at a weighted average price of CAD 20.16 per share. Those share buybacks represent approximately 10% of our 2021 outstanding share count. Free cash flow remains allocated at 50% to debt reduction and 50% to share buybacks, but that will ramp up to 100% shareholder returns next year when we reach our $600 million U.S. net debt target. Corporation published its first, or excuse me, its third ESG report in September 2023, which discusses its foundational commitments of business model, resilience, and governance, and the corporation's priorities, ESG topics, health and safety, climate change and greenhouse gas emissions, water management, energy security, energy affordability, and indigenous relations. I will now ask Darlene Gates, our COO, to speak to our operating results, and ask Ryan Kubik, our CFO, to talk to our financial results. Before I open the call to questions, I'll provide an update on the Pathways Alliance efforts this quarter. Darlene, over to you. Thank you, Derek, and good morning, everyone. In the third quarter, as Derek mentioned, we delivered strong safety, health, and environmental performance, with no lost time injuries and no recordable spills. Production of about 104,000 barrels per day in the third quarter was delivered at a top-tier steam-to-oil ratio of 2.28, reflecting the successful completion of our short-cycle infill and redevelopment programs and a continued emphasis on steam allocation to the highest quality resource. When compared to the same quarter last year, this represents a 2% production increase and a 5% reduction in steam-to-oil ratio. These results were achieved while successfully completing our planned facility and field infrastructure projects, which will enable us to distribute a high-pressure steam to future well pads. Operating expenses, net of power revenue, averaged $5.11 per barrel in the third quarter, primarily reflecting higher production rates, planned maintenance activities, and inflationary pressures on services, chemicals, and staff costs. Power revenue exceeded energy operating costs in the quarter, generating a $0.04 per barrel net recovery, which continues to demonstrate the value of our cogeneration facilities. As we head into the fourth quarter, lower facility and maintenance activity levels and increased production rates are projected to drive our non-energy operating expenses back within our full-year guidance. Our outlook for second-half production continues to be approximately 105,000 barrels per day, and have us exiting the year near our 110,000 barrel per day facility capacity. In October, we also achieved first production from our newest well pad, which we'll continue to ramp up throughout the fourth quarter. I'd like to take this opportunity to thank our teams for this quarter's operational performance, and confident they have positioned MEG for a strong finish to the year. With that, I'll turn it over to Ryan to provide the Q3 financial update. Ryan? Thanks, Darlene. MEG generated adjusted funds flow of CAD 492 million in the third quarter of 2023, bringing our year-to-date total to just over CAD 1 billion. Q3 cash operating netback was CAD 58.64 per barrel, reflecting strong oil prices, lower diluent costs, and the first full quarter of higher post-payout Crown royalties. After funding CAD 83 million of capital expenditures, we generated CAD 409 million of free cash flow in the quarter, which was used for $68 million of debt reduction and to repurchase CAD 58 million, or 2.3 million shares at an average price of CAD 25.40 per share. In the first nine months of the year, MEG generated CAD 699 million of free cash flow. That free cash flow allowed us to purchase $227 million, or 10.3 million MEG shares, at an average price of $22.07 per share. In addition, we reduced debt by a further $194 million. At September 30, our net debt declined to $885 million, and at current oil prices, we forecast reaching our $600 million net debt target around mid-next year. As we head into the last quarter of the year, we expect to achieve the low end of our 100-105 thousand barrels per day production guidance. Under that production forecast, non-energy operating costs are trending to the top end of our CAD 475-CAD 505 per barrel guidance range, and G&A will also trend to the top end of our CAD 170-CAD 190 per barrel range. With continuing strong production in oil prices, MEG is well positioned to execute its strategy as we head into 2024. Guidance for 2024 is scheduled for release on November 27th. Thanks, and with that, I'll hand it back to Derek. Thanks, Ryan. I'd now like to share a brief update on Pathways Alliance. MEG, along with its Pathways Alliance peers, continue progressing pre-work on the proposed foundational carbon capture and storage project, which will transport CO2 via pipeline from multiple oil sands facilities to be stored safely and permanently in the Cold Lake region of Alberta. Significant engineering, front-end evaluation, and environmental field work is enabling more detailed discussions with indigenous groups, landowners, and local communities about the proposed project. Following early engagement over the last two years, formal consultation with 25 indigenous groups along the proposed CO2 transportation and storage network corridor is underway. We remain encouraged by the work and collaboration with both the federal and Alberta governments to get the necessary agreements in place to advance this ambitious and important project. I'd be remiss if I did not remember and acknowledge with great sadness, Ian Bruce, MEG's Chair, who passed away tragically at his cottage in Ontario in October. Ian was passionate about our industry and brought a wealth of experience and wisdom to MEG. He was a tremendous supporter of MEG and our management team and will be greatly missed by all of us at MEG and all who knew him. On behalf of our Board of Directors, management team, and employees, I extend our deepest sympathies to Ian's wife, Darlene, his family, and many friends. As I bring my remarks to a close, I once again want to extend my thanks to our team for their commitment and perseverance. Proud what we, of what we have been able to accomplish and confident in our future and our commitment to sustainable, innovative, and responsible energy development. On behalf of MEG's board of directors and our management teams, I want to thank you for your continued support. With that, I'll turn the call back over to Ludy to begin the Q&A. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the number 1 on your telephone keypad. You will hear a 3-tone prompt acknowledging your request, and your questions will be pulled in the order they are received. Should you wish to decline from the polling process, you may press the star followed by the number 2. And if you're using a speakerphone, please keep the handset before pressing any keys. One moment please, for your first question. Your first question comes from the line of Dennis Fong from CIBC World Markets. Your line is open. Hi, good morning, and, thanks for taking my questions. The first one, just around, capital structure. You've obviously been very focused around repurchasing the 2027 notes. Just wondering, and, especially focusing also on the $600 million net debt floor here. How are you thinking about your exposure to, term notes and, and kind of longer-term debt? I know the next kind of tranche after the 2027s is quite far out. Yeah, Dennis, thanks. I'm gonna ask Ryan to talk to that. Hey, Dennis. You know, you should think that we're just gonna continue buying back those 2027 notes, take that to zero. At that point in time, we do have the 2029s outstanding $600 million. That's our debt target. Those are at an attractive rate relative to where we could finance today, so we're gonna keep those outstanding, and, you know, that'll provide us significant liquidity, obviously, going forward without any near-term maturities. Great. Thanks. And then my follow-up here is just around, I guess, inventory and sales levels. You guys built up inventory through the quarter. I surmise it's to some degree around what was potentially an anticipation around line fill for TMX. Can you speak to that a little bit and just kind of some of your plans with the relatively elevated inventory levels that you currently have, that may or may not be in place at Hardisty and maybe in other locations like most of the coast? Yeah, I mean, we did. Inventory will move around, Dennis, and we did have a couple hundred million build in working capital at the end of September, I guess, versus the end of June. That was due to a couple of things. We did see oil prices rally, so receivables rallied into the end of the quarter. On the inventory side, you can see movements around various factors, whether we're building a cargo, for example, that might ship off the coast, which was the case at the end of September. Whether we're buying non-proprietary volumes to manage our pipeline space and you know add some optimization activities through our marketing activities, et cetera. So you will see movements up and down in that inventory level. With respect to TMX, we're expecting we'll be holding about 160,000 barrels a day, or 160,000 barrels of line fill. That will be long term. It'll be classified as long-term assets, I guess, in our financial statements, and won't won't be classified as inventory for working capital. Great. Thanks. And then if you may permit me one last question here. I understand that you obviously have a lot of experience with respect to marketing some of your production, not just within North America, but even potentially globally. How do you view that as being a potential advantage when TMX eventually comes online, in terms of finding buyers for your crude in obviously a, I guess, a different means of accessing that market? Thanks. Yeah, Dennis, it's Derek. I'll take that one. You know, a big part of our marketing strategy is to ensure that we don't move all of our crude into the US Gulf Coast and overwhelm that market and create a bigger differential. Just instead of moving the Instead of having a differential, egress-related differential in Edmonton, we've now got an oversupply in the US Gulf Coast. So we've spent a fair amount of time working to develop Asian markets, both in India and in China. I think we have a very good idea of people that like the quality of crude that we have. And this was a big driver behind our tankage and dock space in the US Gulf Coast. You know, as we move to Burnaby, you know, at this juncture, we think Burnaby's got basically two markets, the West Coast of the United States, that California market, and fundamentally China. We don't think transportation rates are going to, or netbacks are going to be sufficient to access India. But our understanding of those markets, our understanding of buyers in those markets are, you know, our historic ability to have shipped them samples of our product so that they can determine whether they would want to get in a queue to buy some of that is all, you know, very, very important. Not only to finding a market, but. Helping us be less reliant on US Gulf Coast operators, refinery operators to give us a fair price for our product. Great. Appreciate that, that color and context. I'll turn it back. Thanks. Thanks, Dennis. Your next question comes from the line of Greg Pardy from RBC Capital Markets. Greg, please proceed with your question. Yeah, hey, thanks. Good morning. Thanks for the rundown, guys. Derek, I wanted to come back to Pathways. So let's just say, in a hypothetical world, that the incentives are, you know, inclusive of operating costs, like you've got Pathways, it's got adequate incentives in place, let's just say, by the end of this year, and the trunk line's in place for 2029. What's the plan then for MEG? I'm just trying to think in broad strokes, what are the series of steps that you're going to take in terms of decarbonization? Great question, Greg. And a little more forward-looking, I guess I appreciate this because we're not gonna talk about when the pipeline's gonna be in. Let's just assume that all of that has taken place. What that means for MEG is in 2026, 2027, 2028 and 2029, in those four years, we would probably spend somewhere in the neighborhood of a net CAD 50-75 million of capital, building our first carbon capture facility at site. So that would be a facility that would capture a net capture of somewhere between 0.63 and 0.73 megatons a year of carbon. Once we've got a sort of fiscal certainty and the regulatory certainty, which would be associated with having the pipe in place and up and running by 2029, we will then start to push forward past our FEED type of work to an FID decision, which have capital being spent in that timeframe of 2026-2029. Okay, thanks, cause I was gonna ask you about the capital. So that's super helpful. And then maybe kind of related, 'cause it sounds like you'll be doing, probably going with post-combustion capture. Where does eMVAPEX fit into everything? Or is that something that might be, you know, several years away? I think eMVAPEX... So just for other people on the call, eMVAPEX is a solvent process that was developed at MEG and helps us reduce our steam oil ratio significantly. It, it replaces steam with solvent effectively. So, very important if you're trying to reduce not only your steam oil ratio, but also to keep down the amount of carbon that you have to capture. We have spent an extensive amount of time working with eMVAPEX. We think it's a technology that in a new greenfield development is something that we would look at very seriously. Or if we decided to move a significant ways away from our central processing facility, and we were gonna create a brownfield facility that was connected back to our central processing facility, we would look at it there. But at this point in time, you know, there's a number of commercial aspects that we don't have in place to contemplate that. The biggest one, which would be really the solvent that we would need, and a long-term agreement and pipeline transportation agreement, both for the supply and the transportation of that product. And, you know, just to be very clear, we've thought about those. We've costed those out. At this point in time, the brownfield work that we continue to do inside of the facility is much more economic, and significantly lower cost on a dollar per flow BOE than eMVAPEX would be at this point in time. Okay, terrific. Thanks very much. Thanks, Greg. Your next question comes from the line of Menno Hulshof from TD Securities. Your line is open. Thanks, and good morning, everyone. I'll start with a question on Surmont. Given Conoco's relatively recent decision to exercise its ROFR on Total's working interest on its Surmont project right next door, can you just give us a refresh on the status of your Surmont asset and the various options or scenarios longer term? Good morning, Menno, and thanks for the question. You know, Surmont is a fabulous asset. I would say it's as good, if not better, than what we are currently developing at Christina Lake. The reason it hasn't been developed is because it's substantially further away. At one point in time, a number of years ago, we had worked a license for the facility through the Alberta Energy Regulator. We no longer. We let that license go, because as we thought about it, it's going to be at least 10 years before we get there with the low-hanging fruit that we have at Christina Lake. And really, I think the challenge for us is not to go out there and build another once-through steam generator type of facility. The challenge will be, is this an opportunity for us to put solvents to work, warm solvents to work, and to bring a different exploitation strategy, to this reservoir? So, nothing in the medium term is going to be developed, and that's primarily because, you know, we still have a massive amount of running room going from, you know, say, 110,000 all the way up to 210,000. There's 100,000 barrels of incremental capacity that we can develop at Christina Lake, which has got our full and undivided attention at the current time. Thanks for that, Derek. And then moving on to buybacks, it looks like activity in the quarter was a bit light at CAD 58 million, roughly 14% of the Q3 free cash flow. Why was that? And does it imply an uptick in buyback activity in Q4 to get you closer to your 50% annual target? Hey, Menno. The main, I guess a couple of reasons for that. We already talked about working capital. We did see a build in working capital requirements in the quarter. And so that meant we didn't have the cash available to actually buy back the stock. When we look at stock versus the debt buybacks, the stock market is actually more liquid, I guess, than the debt buyback market. So we're a little bit more opportunistic on the debt side. If we see opportunities to buy different pieces, those may be chunkier, so we may buy back a little bit more debt than we actually buy back stock in the period. But, you know, over time, we do expect that we're gonna do exactly what we said we would do, 50/50 debt, shares, as we kind of move toward our Net Debt target. And you can... You know, depending on where oil prices go, et cetera, you'll see those working capital, requirements potentially reduce and, and, the cash available for both share and debt buybacks in the fourth quarter. Perfect. Thanks, Ryan. I'll turn it back. Thanks, Menno. Your next question comes from the line of John Royall from J.P. Morgan. Your line is open. Hi, good morning. Thanks for taking my question. So you, you mentioned energy OpEx net of power revenue was actually negative this quarter, and, I've noticed that net number has, has trended down a bit this year from an average of maybe $2-$3 per barrel over the, the few years before that. Is there anything structural there with the relationship between, energy OpEx and, and power revenue? Or is it maybe just kind of a Goldilocks scenario of, of the relationship between gas price and power price? Do you expect it to normalize? John, it's Derek. I'm not sure which one of the Goldilocks scenarios we should be going as too hot, just right, or too cold. But, we do have a unique situation on the go. I think we've got very high power prices in the province and very low gas prices, which has driven that. You know, as we look forward into next year, we see those power prices, or we're forecasting that they're gonna normalize down into that CAD 90 megawatt. So I think you shouldn't believe that this is a trend that is going to continue. We're very pleased with what we've been able to achieve or receive, I guess, in terms of that combination over the last couple of quarters. But, you know, it will revert to historic norms as we drive forward here. Got it. Makes sense. And then, I know you'll come out with a formal budget later this month, but, just thinking about next year's CapEx, and, am I thinking about it correctly, at least directionally, if I think about, higher than 2023 levels with a ramp in the second half, after you achieve your Net Debt floor and start to invest in the next phase of growth? Is that kind of directionally the right way to be thinking about it? I think directionally, I would tweak it a little bit and say, you know, you should be thinking about it as this year was sustaining capital. And, you know, as we've talked to you and others about what our sort of our growth project would be, taking it from 110,000 to 125,000, we think that's somewhere in the neighborhood of CAD 300 million, and you should expect that, you know, a third of that notionally would get allocated in the first year. Got it. And just to be clear, that would be after you achieve the Net Debt floor, so probably more second half loaded? No, I think, and, you know, this is all dependent upon where our board lands on this, but so it's subject to their approval. We haven't gotten this across the line with them yet. But I think we are comfortable enough that we are going to achieve that CAD 600 million debt target, so we would be planning on, you know, this would be a full year capital budget, which would basically be starting the growth plans or making allowances for and doing the long lead time work on the growth program, starting as soon as the budget's approved. Understood. Thank you. Thank you. And once again, if you would like to ask a question, simply press star, followed by the number 1 on your telephone keypad. Your next question comes from the line of Neil Mehta from Goldman Sachs. Your line is open. Hi, good morning. Thanks so much for taking the time. This is Nicolette Slusser on for Neil Mehta. So just the first question here would be on pricing dynamics. Curious, any thoughts in terms of what you're seeing in the Gulf Coast? And then also, more broadly, as we think into 2024, any outlook that you can comment on for the WCS differential would be helpful. Yes, good morning. You know, I think that one thing that we would say about the WCS differential is, for some reason, people aren't factoring in the 4.5 million barrels a day of line fill that TMX is going to need. So if you think, if you go and you look at the differential today, and you see a part of the reason that the differential has expanded or blown out is because of increased production or increased diluent, and you think that that's somewhere in the neighborhood of 100,000 barrels a day of incremental capacity. What we're talking about in terms of line fill is taking half of that away. 4.5 million barrels over the first quarter is about 50,000 barrels a day. I think my own personal opinion is the Q1 2024 differential is too high. It's not factoring in that TMX, the line fill. And I think there's also some concerns about storage, which I don't understand either. I mean, last week's storage in the Western Canadian Sedimentary Basin was about 26 million barrels or somewhere in the, you know, sort of the low to medium 30%. So we've got lots of room for storage. So I don't think we're going to see a tight storage situation. I think there's going to be effectively less transport, or less product moving down the line. I said in my previous remarks I provided my predictions as to where I think you're gonna see Q2 and Q3 land. You know, and Q3 was under $13 this year, and Q2 was in that $15 range. I think that those are quite achievable, again, next year. I think they'll actually be a little bit high, but if I were modeling, I'd be using those. Where I think it's gonna get very interesting is as you model Q4 of next year, because obviously with, you know, an incremental TMX volumes, I don't think you're going to see that historic run-up as you've moved into the fourth quarter of the differentials. I think it'll stay quite flat through that period. Maybe $1 or $2 more, but I think we're finally out of a period of lack of egress-driven WCS differentials, and I think we'll have a lot less volatility on that front going forward. That context is incredibly helpful. Thank you so much. And then not to come back to this question again, I know some other analysts have asked, but just on Pathways, any, you know, key updates we should be looking out for towards the end of the year, or anything maybe early next year, we should all be keeping an eye out for? You know, where to start on Pathways? I think, fundamentally, as we drive forward, you're going to hopefully hear something at some point over the next couple of months about how the federal and the provincial government, or Pathways, are continuing to work forward. I think we owe the market an update in that regard. And I think you'll, something will be coming in that regard. I hope over the next month or two. I can tell you that, we've got a few hundred people working on this project at the moment inside of the companies, continuing to work on the pore space, continue to work on the FEED engineering, continuing to try and get the pore space approval through. So I worry sometimes that, because, you know, we haven't hit milestones or we're not moving as fast as people think we should be or moving, that they think there's nothing going on on this project. I can assure you there is a massive amount of work that is going on in terms of indigenous consultation, pipeline sizing, looking for appropriate mills that could roll this pipe. So, lots and lots of work going on, as well as, the important work with both the federal and the provincial government, trying to arrive at, you know, the appropriate fiscal terms that will make this project economic. That's great. We'll, we'll definitely be on the lookout. Thank you so much for taking the time. Thank you. There are no further questions at this time. I would like to turn it back to Mr. Derek Evans for closing remarks. Thank you, Ludy, and thank you to everybody that joined us this morning for our Q3 results conference call. We're excited about what we have been able to achieve and look forward to updating you on our 2024 outlook when we release our budget at the end of November. Have a great day, and thank you. Thank you, presenters, and ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect. Have a good day.