Good morning, everyone, and welcome to our third quarter conference call. For Baytex, this represents the first full quarter of combined operations following the Ranger acquisition and demonstrates the strength of our diversified North American oil-weighted portfolio. The integration has progressed extremely well, and we have delivered strong results from Western Canada and the Eagle Ford in Texas. During the third quarter, we delivered top quartile results from our operated Eagle Ford assets, continued exceptional Clearwater results at Peavine, where we now hold the top 30 wells drilled across the entire Clearwater fairway, and significantly progressed our Pembina Duvernay play, with six wells drilled and completed trouble-free earlier this year, which are all tracking to our type curve performance expectations. I'll elaborate on this well performance in a few minutes. I'm also excited to announce two new land extensions at Peavine and Cold Lake as we continue to leverage our heavy oil expertise and recent exploration successes. We continue to execute on our 2023 plan and now anticipate fourth quarter production of 158,000-160,000 BOE /D, 84% weighted to oil and NGLs. We are forecasting full year 2023 exploration and production expenditures of just over CAD 1 billion, which is consistent with our previous guidance. Based on the forward strip for the balance of 2023, we expect to generate free cash flow of approximately CAD 400 million during the fourth quarter and CAD 650 million for full year 2023. As a reminder, we increased our direct shareholder return to 50% of free cash flow on closing the Ranger acquisition, which has allowed us to increase the value of our share buyback program and introduce a dividend. The remainder of our free cash flow continues to be allocated to the balance sheet. Our normal course issuer bid allows us for the purchase of up to 68.4 million common shares during the 12-month period ending June 28, 2024. And as a result of our free cash flow profile, we have increased the pace of our share buyback program during the fourth quarter. Through October 31st, 2023, we repurchased 28.1 million shares for CAD 155 million, representing 3.3% of our shares outstanding at an average price of CAD 5.51 per share. In addition, we paid an initial quarterly cash dividend of CAD 0.0225 per share on October 2nd, 2023, and our board has declared our Q4 cash dividend of CAD 0.0225 per share to be paid on January 2nd, 2024. I'll now shift to our Q3 results. Production during the quarter was 150,600 BOE/D, and we delivered adjusted funds flow of CAD 582 million, CAD 0.68 per basic share. We generated free cash flow of CAD 158 million, CAD 0.19 per basic share. Exploration and development expenditures totaled CAD 409 million during the quarter, consistent with our full-year plan, and we brought 87.8 net wells on stream. As of September 30th, 2023, our total debt was CAD 2.7 billion, representing a total debt-to-EBITDA ratio, Q3 2023 annualized, of 1.1x. During the third quarter, we repaid our $150 million U.S. currency term loan. Our total debt at quarter end increased relative to Q2 2023 due to the impact of the strengthening U.S. dollar relative to the Canadian dollar and our U.S. dollar-denominated debt, along with working capital adjustments. Based on current commodity prices and forecast free cash flow for the fourth quarter, we expect to exit 2023 with total debt of approximately CAD 2.5 billion. I'm going to shift now and talk more about our recent activity. In the Eagle Ford, our Q3 program reflects strong results across the black oil and condensate thermal maturity windows of the lower Eagle Ford. In our operated assets, the 13 wells generated an average 30-day initial production rate of 1,500 BOEs/D, 78% oil and NGLs per well, ranging from 769 BOEs /D to 2,355 BOEs/D. 7 wells from three pads, these pads are the Bloodstone, the Bubinga, and the Hickory, generated an average 30-day initial production rate of 2,000 BOE /D, 65% oil and NGLs per well. When we compare these results to a data set of 784 wells sourced from public data, our Q3 performance ranks in the top quartile of all wells drilled in 2023 in the Eagle Ford, and on a production per lateral foot basis, we are solidly in the second quartile. So I'm very pleased with this performance. In addition to delivering strong results, we remain focused on basin optimization and continued drilling and completion performance. Our Pembina Duvernay light oil assets are in the demonstration stage of commerciality and offer high operating net backs with strong economics and the potential for significant organic growth. We brought six wells on stream this summer. The six wells generated average production rates of approximately 950 BOE /D, 89% oil and NGLs. In September, ranging from 790 BOE /D to 1,080 BOE /D, and continue to track to type curve performance expectations. Production from the Pembina Duvernay increased to over 7,500 BOE /D in September, up from 2,000 BOE /D in H1, 2023, and the 2023 program has significantly advanced our understanding of the reservoir as we continue to progress this light oil resource play. On the heavy oil side, following a relatively quiet second quarter due to spring breakup, our program ramped up during the third quarter with 28 net heavy oil wells on stream, 14 at Peavine, eight at Lloydminster, and three at Peace River. At Peavine, the 14 wells generated an average 30-day initial production rate of 725 barrels per day per well, ranging from 330 barrels per day to 1,073 barrels per day. Production at Peavine averaged almost 14,000 barrels per day in Q3 2023, up 69% from Q3 2022, and increased to 16,400 barrels per day during the month of September. We are also following up our recent heavy oil exploration success at Morinville, Alberta, and Cold Lake, Alberta, during the fourth quarter. Building on our heavy oil expertise, we have expanded our heavy oil development fairway through two land extensions, including a 10-section extension at the Peavine Métis Settlement, adjacent to our existing 80-section land position at Peavine, and a farm in on 17.75 sections of land prospective for Mannville development near Cold Lake in Northeast Alberta. We've included a map of these incremental land positions in our updated investor relations presentation. Shifting to risk management, we employ a disciplined hedging program to help mitigate the volatility in revenue due to changes in commodity prices. For the first half of 2024, we have entered into hedges on approximately 40% of our net crude oil exposure, utilizing two-way collars with a floor price of $60 per barrel, and a ceiling price of $100 per barrel. For the second half of 2024, we have entered into hedges on approximately 25% of our net crude oil exposure, utilizing two-way collars with a floor price of $60 per barrel, and a ceiling price of $98 per barrel. As I wrap up my prepared remarks, I would like to reiterate our commitment to operational excellence and delivering long-term value and enhanced shareholder returns. I'm very pleased with the operating results across our portfolio, which has set the stage for a strong finish to 2023. We do see our shares as undervalued, and we have stepped up our share buyback program during the fourth quarter. We are a strong North American energy company with a high-quality, diversified, oil-weighted portfolio across Western Canada and the Texas Gulf Coast. Now, operator, we are ready to open the call for questions. Thank you. We will now begin the question-and-answer session. To join the question queue, you may press star, then one on your telephone keypad. You will hear a tone acknowledging your request. To submit a question in writing, please use the form in the lower right section of the webcast frame. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star, then two. We will pause for a moment as callers join the queue. Our first question comes from Greg Pardy of RBC Capital Markets. Please go ahead. Yeah, thanks. Thanks for the rundown, Eric. I know it's still early, but what are your broad strokes to think in terms of spending, you know, any guidance maybe around production and so forth for 2024? Yeah, it's a good question, Greg. Thank you, and good morning. You know, we like to think about 2024 as an extension of the second half of 2023. So if you were to take H2 capital, you know, on a half-year basis and extend that out into 2024, and the range of 155,000-160,000 BOE a day, and extend that across 2024, there'll be a little bit of lumpiness seasonally. But I think that would be a really good way to think about 2024. Thanks for that. And then, I'm gonna shift gears on you. Production rates, like, you've done the land extension now, in the Clearwater, so, so good on with getting that done. Does any of this really change that 12,000-15,000 bbl /d range that you've been kinda guiding us towards, in terms of where you think you could stabilize production in the Clearwater, or, or does that. Yeah, it's a great question, 'cause we are pushing kind of the top of that range here in Q3 and continue to see encouraging results as we develop across the body of what now looks like a green-headed prairie chicken on our map. And so I do expect, Greg, that you know, the 12,000-15,000 is probably something we'll continue to say, but I would expect to live near the high end of that more often than I might have expected even six months ago. So, it is a good, strong development plan over time. We continue to want to be very disciplined and really thoughtful about how we march forward. Social license to operate is very important to us in maintaining a strong and transparent relationship with the communities in which we operate, including here, the Peavine Métis Settlement. It's very important to us. So, I'll reiterate the 12,000-15,000, and I'll probably follow that up by saying we, we could live at the high end of that consistently, but you'll probably hear us keep saying that. Okay, got it. Thanks very much. Thank you, Greg. Our next question comes from Menno Hulshof of TD Securities. Please go ahead. Thanks, and good morning, everyone. I'll start with a question on Lloydminster Mannville, since you farmed in on another, rough number, 17 sections, you have a lot of running room in the play. And then I'm just looking at the slide deck, just at the relative returns. It looks like the Mannville is a, is a, I'm gonna say, a distant second to the Peavine, but comparable to your Eagle Ford Karnes asset. So what does all of this mean for Mannville activity levels in 2024 and beyond? Thanks, Menno. I think it means we're gonna continue to employ our geoscience exploration program. You know what? You and I have talked about the success that our two geoscience teams have had across the Heavy Oil Fairway. We're gonna continue to fund that exploration program with, you know, what we believe to be a unique petrophysical understanding of the rock, and this has led to the success at Peavine. It has led to the Waseca at Cold Lake, and it has led to additional extensions. And so, it competes very well in our portfolio, as you suggest, and it's a good problem to have. WCS basis diffs have widened a little bit here in Q4, but we fully anticipate those will narrow back up in 2024, and you know, as TMX starts line fill and comes on delivery. So we're very confident that the Heavy Oil Fairway will continue delivering new discoveries, new accumulations, as well as you know, continued extensions around the places where we've had good success already. So very fond of the Heavy Oil Fairway, very fond of the place that it lives in our portfolio and fully expect to continue funding. The good news is, you know, with the very significant cash flows coming out of our Gulf Coast asset, you know, that's 60% of our production priced at a premium to WTI. Those significant cash flows not only carry the development freight in the U.S. along the Gulf Coast and the Eagle Ford, but also provide very substantial cash flows back into the business, so we can continue leaning into all the rest of the strength of the portfolio, continue exploring and developing places like the Pembina Duvernay, and the exploration success in Peavine, the Waseca at Cold Lake, in and around the Rex at Morinville, and all the other places where we are currently excited to explore. Terrific. Thanks for that, Eric. My follow-up is on share buybacks, a big step up in October. Can you remind us of your overall strategy? Is it programmatic or more opportunistic? How does your measure of intrinsic value factor into how aggressive you are day to day? And is it possible that we see Baytex participate in the next Juniper secondary, which is coming up pretty quickly, potentially? Yeah. Yeah, so to sort of put a timeframe on that last part, Menno, you recall that it was three escrow periods, 90 days, 90 days and 90 days, each representing 1/3 of the total block. And so the first 90 days executed an overnight bought deal, not us, but Juniper executed an overnight bought deal, and that was September 18th, I believe. The next 90-day escrow period will expire on December 17th, I believe. And the question around us participating is really a legal and regulatory one. As long as Juniper holds more than 10% of our total outstanding shares, we are prohibited from participating as a buyer in that block, and Juniper currently holds, I think, right at or just under 12%. So I don't think, as much as we would love to, I don't think we will be able to participate in the book, and it's the same reason we couldn't participate when they were at a little over $18 and took it down to $12. The good news is, there was a lot of demand for the shares. It traded, it traded well, and we certainly do expect the next book to do just as well. So what I would say around the NCIB is, we expect to be programmatic and opportunistic, because right now we're undervalued, so it's a great opportunity to be buying back shares at a pretty good pace. And to do so on a kind of a cost averaging basis, which is the programmatic element of the NCIB. We really like the NCIB because it has this cost averaging, you know, functionality. But also because, you know, as a company, we go in and out of blackouts, and so we can set up instructions and let it run through the blackouts. Whereas if we were being opportunistic, that would have to line up with an open window, and that doesn't always happen. So right now we're doing both, programmatic and opportunistic, but it's because we're undervalued and both present themselves. But it's all taking place via NCIB, just to be clear. And then I would say, relative to intrinsic value, you know, I mentioned a couple of times already, we're not currently close to our fair value as we see it. So, you know, with the discount, we're buying back as much as we can and intend to continue at a pretty aggressive pace through Q4 of 2023. There will be a time, I suppose, if we're really fortunate, that you know, the share price begins to approach fair value. I hope that's the case. That'll be a good problem to have. And one of the linkages we really like here is as we buy up and take out shares, you know, outstanding shares, and let's just say, for the sake of argument, at an NCIB limit of 10% per year, then every year, we could rebase the fixed base dividend, you know, by that same amount, because you've taken out those shares, the total quantum of fixed base dividend would decline over time, on an absolute value basis. And so that would give us the opportunity to rebase it periodically. And that's a linkage we really like. To be clear, we haven't announced that plan, but it is a linkage we like because it creates a systematic approach to share repurchases and your fixed base dividend. So, that's something we like, and it, and it also helps answer, you know, the relationship between, current share price, intrinsic value, and other ways to, return capital to shareholders. So let me just pause there, Menno, and see if you want to follow up. No, that was really thorough, Eric. That's it for me. I'll pass it back. Thank you, Menno. Our next question comes from Amir Arif of ATB Capital. Please go ahead. Thanks. Good morning, Eric. Just a couple of questions on the Eagle Ford. Just, can you give us a sense of the cadence of drilling plans in the Eagle Ford? I think you brought on between 22 net wells, roughly this quarter, and let's drop into 11 next quarter. Is this, is it more of a level-loaded program when you operated asset and you just sprinkle in the non-op wells when they come in? Just trying to get a sense of how 2024 drilling activity will look in the Eagle Ford on a quarterly basis. Yeah, Q4, you know, on a quarter-over-quarter basis, Amir, there's gonna be some lumpiness. It has seasonality, you know, impacts to it, broadly speaking, you know, quarter-over-quarter. But then specifically in Q4, and specifically because we have a substantial non-op asset, the capital that gets allocated to the non-op assets in Q4 is, of course, beyond our control. And if the operator, you know, pulls back on capital in Q4 because that's, you know, they've essentially spent the capital and developed the program that they wanted to develop, then that sort of kind of is what it is. On the operated side of the business, we try to run the businesses as operationally efficient as we can. And for our operated Eagle Ford position, this means, two rigs, level loaded, running basically full time. And, those will feed, one frac crew at the tailgate of the rigs, clearing the DUC inventory that comes off the drilling program. And, you know, that'll be a little bit lumpy based on pad size and, and some, seasonality effects, but generally speaking, our operated program will be more level loaded, I think. But, Q4 is definitely seasonality related toward the end of the year and related more toward the non-op assets. Okay. Appreciate that color. And then just on the operating cost side, the third quarter results were $12.57/BOE. I know you mentioned there was some additional workovers going on in that quarter. Can you give us a sense of your comfort level in bringing that number down below $12 into Q4, just to make the updated guidance? Yeah, I think you're talking about OpEx? OpEx, yeah. Yeah. Yeah, yeah, yeah. Okay. So, it's come down, you know, by a couple of bucks on a unit basis, since closing of the deal, and that's certainly related to, you know, the, the blending effects of the, lower cash cost structure along the U.S. Gulf Coast, and just the dilution and blending effects of, of that lower cash cost structure. We've always, you know, continued to work on, you know, both sourcing, labor costs and, just operational efficiency to maintain, you know, as best we can, you know, flat to declining OpEx. I think over time, we're gonna see probably consistent, but light downward pressure on those, on those costs. That is to say, I think if there's a bias, it's biased downward, but it's not going to be, I think, earth shattering in terms of just how much it moves the needle. So from $12.75/ BOE, you know, is it gonna dramatically drop under $10 for 2024? I don't think so. What I would say is we'll probably see consistent, steady downward pressure on that number as we continue to, you know, make improvements operationally, we tend to, you know, continue to do the things that work and not repeat the things that don't work, and squeeze out waste and excess out of that system. I would target $11-$12 if I were, you know, pushing out into 2024 as a range. And I think that would be pretty responsible in terms of a 2024 cost range. Got it. Appreciate that. And then just final question, shifting gears over to the Duvernay. You, you have six wells there now that you bought on. You've got some good production results behind it. Can you give us a sense of what your next steps are on the Duvernay? Yeah. Yeah, so we're very excited about the Duvernay. I couldn't be more proud of the team. We have built really powerful models, statistical models, mathematical models, and continue to populate those models, build those out, history match those models, and converge on results that we think will continue to push higher going forward. But as you know, we're also rigorous in terms of our, you know, commercial expectations, and we wanna do this on a basis that is systematic. And so I would expect, even though we don't have the budget built for 2024 yet, I would expect more than 6 wells, and I would expect probably less than nine wells. So somewhere between six and nine is a reasonable step up as we approach kind of the second year of demonstration, probably the last year of demonstration, if I were to lean in a bit. And then, you know, we'll step up the pace of development after 2024. So there's still more science to do. We wanna better understand all the nature of variability, but we've got a lot of data, both delineation and all the various, you know, independent variables that drive variation in the output. We've got a strong understanding of those, and so I think next year will be another really good year of development progress in terms of performance and cost, and another year of a really strong demonstration toward full commerciality and, you know, development, full development pace. So let me, let me pause there, Amir, and see if you've got a follow-up on, on the Duvernay. No, that was great color. Thank you. Thank you. Our next question comes from Jasper Wijk of Valpal. Please go ahead. Thank you for taking my question. Most of my questions have already been answered, but I have one about the blending expenses, which have been trending down for the entire year. Could you add some color to this and what we could expect blending expenses per barrel of heavy oil to average for next year? Yeah, I'm sorry, Jasper. I'm not quite sure I'm picking up which category of expense you're asking about. Just try me one more time. Sorry, blending expenses. Blending. Oh, blending. Blending expenses? Yeah, diluent. Okay. Yeah, yeah, yeah. Okay. You know, I, I would expect that blending expenses are gonna be related to the value of condensate relative to the value of our heavy oil crude stream. So I think the value of our heavy oil crude stream that needs to be blended with the diluent is gonna trend up over time. I think that's gonna be on a benchmark at a benchmark level, and also at a higher kind of, you know, asset level, net back level. And so, you know, and I think condensate or all the diluents are probably also gonna be linked to that. So maybe the blending expenses, you know, are, are gonna be flat to potentially declining a little bit, but I would expect in the same way that I mentioned on OpEx, on unit OpEx, probably slight downward pressure, but I wouldn't expect it to be a real needle mover. I just think it's gonna feel like and look like operational efficiency improvements. Thank you. That was it for me. Thanks, Jasper. This concludes the question and answer session from the phone lines. I'd like to turn the conference back over to Brian Ector for questions received online. Okay, great. Thanks, Ariel. And we do have a few questions that have been submitted from the webcast, and so I'll moderate these now for you, Eric. And there are a number of investors that have reached out this morning looking for a little bit more color or clarity around our sort of free cash flow allocation policy. So how do we decide, Eric, between share buybacks, growing the dividend, and debt repayment? And what are the decisions that go into that type of criteria? And then, as a follow-up, an investor asking, "Should we be paying debt down first prior to share buybacks and dividends?" So I think they're all kind of interrelated. You bet. Those are, those are great questions, and, and I wish there was just a mathematical calculation one could do to arrive at, at the precise allocation. But it, in the end, it boils down to a couple of things. It boils down to, you know, subjective judgment on the part of the management team and the board, as well as listening carefully to our investors, right? The shareholder base, taking in that feedback and having these conversations. So as I introduce this idea of the linkage between our buyback program and the idea of potentially rebasing the dividend over time on a proportional kind of basis, then we will listen to the feedback on that conversation, and, and we will, you know, try to figure out, is, is the balance of the feedback leaning toward that being a good idea or that not being a good idea? Because, you know, as, as everyone knows, there is a fixed base dividend, which is the way we have it structured, which is a function of the, you know, CAD 1 per share, or in our case, cents per share per quarter, paid out, obviously, quarterly. So that's a function of the share count. And then there are variable dividends that can, you know, expand and contract on a quarterly basis according to some mathematical model. Then there are special dividends. Generally speaking, you get less credit in your share price for special dividends than you do for variables, and you get less credit in your share price for variables than you do fixed. Because the investment community can largely, you know, really begin to build in the return of a fixed base dividend predictably, whereas variables are a little harder, and specials are very hard to predict. So you don't tend to get a lot of, a lot of value back in your share price for those on a go-forward basis. So when it comes to what kind of dividend, we tend to lean toward fixed base dividends as a function of shares out, and we like this linkage to our, to our, share repurchase plan as a, as a functional linkage between the two. When it comes to the allocation between share repurchases and a dividend, you know, it, it really is about, you know, our view of our cost of equity relative to our view of the cost of debt on a risk-adjusted basis. And then, you know, how, how much you return between the dividend and the repurchase plan as a function of the linkage I talked about. But when you go away from dividends versus share repurchases, and you ask yourself, share repurchases versus paying down debt, if you think about our cost of debt as, let's just call it 8% for the sake of illustration, and then you compare that to, our cost of equity, which, let's say, for the sake of argument, is, you know, in the high teens, you know, potentially 20%, based on our free cash flow yield. And then you risk adjust, you know, between the riskiness or uncertainty around a share repurchase versus a debt reduction, you would make a little bit of an adjustment to that. But still, you know, 16%-18% is far higher return than, say, 8% on reduction of debt. And so on that basis, we would say, when you have such a high free cash flow yield, your cost of, that reflects your cost of equity, and you should pay down the highest source of capital, which is your most expensive source, which in this case is equity. And so we would say, bias toward, toward paying down your equity or buying back your shares. But as soon as that free cash flow yield comes down, because our share price is appreciating into it, that yield will come down, and it will make that balance harder, which is the natural conversion of, you know, share repurchases toward, debt repayment. And that's why we've been kind of 50/50 in this allocation. I know it's messy, and I know I said a lot of words, but in the end, these are the considerations we have to roll around with. You know, in the end, that's the decision we have to make. Now, I also think it's really important to make progress on paying down debt, even though you're comparing an 8% cost of debt capital to a 16% cost of equity capital on a risk-adjusted basis. That's still important to pay down the debt. And the reason I think it's important is because for every dollar of debt you pay down within your EV construct, if EV stays the same, your enterprise value stays the same, then a dollar of debt reduction moves over to a dollar of market capitalization accretion. So there's that linkage as well. In the end, it's subjective, and for that reason, we're gonna have to keep having this conversation, I think. We have to continue listening to our shareholder base and implementing what feels like scratches the itch of the broadest cross-section of shareholders. Let me just stop there, Brian. Do you think that gets it? I think you captured it well. Okay. All right. Keeping along the same theme, if we were to fully execute our NCIB program, so purchasing 10% of our public float during the year, would Baytex consider a substantial issuer bid if the free cash flow supported it? Yes. I think, put very plainly, we would consider it, and have thought about it and talked about it, just like the individual who's asking the question has thought about it. Right now, it's pretty early. I think the NCIB, you know, has given us plenty of room. And I would anticipate that our NCIB for, you know, for the July 1st of 2024 into June 30th of 2025, is also going to be substantial in terms of its total number of shares, based on the float we project. So, we may not have to have that conversation or make that decision soon, but we do consider it for sure. And then the last question, I think, on along this theme of capital allocation and share repurchases. We talked a little bit today about our view that our shares are undervalued, and a couple of investors are asking, like, what do you consider to be the sort of current fair value of our shares, Eric? I know it's a tough question to answer, but I wanted to put that out for you. Yeah, it is a tough one because it depends on your view of pricing. You know, I think if you take some fusion of a consensus estimate, you know, consensus bank forecasts over time, combined with the forwards, which I think underrepresent the future price environment. But if you take some fusion of a consensus estimate and a forward strip, maybe that's close. And if you assume that, I think you probably could take some average of the analyst estimates. You know, they're all very good models. Brian and the analysts work carefully together to ensure the models are well informed. You know, there's not a stale forecast out there. I would say taking some average, median, or central tendency to the analyst target prices might be the best place to look. Okay. Thanks, Eric. I'm going to pass this question over to Chad Kalmakoff, our Chief Financial Officer. We talked a little bit about the debt repayment. The question relates more to our debt structure. Chad, can you comment on the components of our debt? Is it floating rate, the interest rates we pay, any interest rate swaps associated with our debt structure? Sure. Thanks, Brian. Yeah. So Q3, like we mentioned earlier, we have CAD 2.7 billion outstanding in debt. In that, we'd have CAD 1.7 billion of that being our long-term notes. Those are all U.S. dollar-denominated notes, so $1.2 billion U.S. dollar-denominated notes. Those have interest rates of 8.5% and 8.75%. So $1.2 billion or $800 million at 8.5%, $400 million at 8.75%. So obviously, those are fixed, due 2027 and 2030. The The remainder of our debt is on our credit facility. That's so-called CAD 1 billion on the credit facility. That's a floating debt structure. Generally speaking, you know, it's kind of based on a margin, but think of that as kind of SOFR plus CAD 0.0225. We will keep that floating, so we have not,we do not have any interest rate swaps against that debt. Thanks, Chad. Then a couple of questions related to free cash flow. Most of the free cash flow over the last four months has been directed towards the share repurchases. If you looked at our Q3 free cash flow of CAD 158 million, maybe lower than some might have expected. I think there's some seasonality around capital. Eric, can you just elaborate on the free cash flow profile as it relates to our business and capital spending on a quarterly basis, and how it averages out over the course of the year? Yeah, there's definite seasonality. So, you know, folks, remember back to Q1. Q1's always a strong start to the year and, a lot of because it's, you know, frozen ground, really good operating conditions in terms of the ability to, to execute a program reliably. Although it's cold, you can, you can execute well. And so drilling capital, you know, you really get after your program in Q1, and that was a, a significant capital program. And remember, that was Baytex standalone. Then in Q2, you've got a lot of, you know, production with a lower, you know, capital program. So we generated almost CAD 100 million of free cash flow in Q2 as a Baytex standalone unit. In Q3, as the listener and writer rightly points out, CAD 158 million free cash flow. But we spent CAD 409 million in CapEx, and that CAD 409 million, as Brian pointed out, is a function really of seasonality. Q3 is a really good quarter for getting after it. Lots of drilling and completions activity in all of our active areas, so across the entire portfolio. In Q4, you know, we're getting the benefit of a rising production into Q4. So as everyone noticed in our release, you know, we're forecasting 158,000-160,000 BOE a day for Q4. And in that strength against a lower capital spend means there's a great deal of free cash flow left over. So free cash flow kind of is, is what comes out the bottom, and it's very dependent on, not only operating cash flow or AFF, but also the lumpiness of your capital program, and the capital program is lumpy because of seasonal effects. At one point in the year also, you know, these sort of base effects around, budget season that comes at the end of the year, which I talked about earlier. So let me stop there, Brian, and see if that. And then a couple, one more sort of financial related question, and I think we'll shift into a couple of more operational conversations. But maybe, Chad, over to you again on our current WCS hedging program on the heavy oil side. So, so we do have some heavy oil hedges in here. Q4, I think, oil hedging, maybe 8,000 barrels a day of the diff hedge that's around, around $14 here for Q4. Into 2024, we have pretty minimal hedging on WCS basis. We have a bit of transportation hedging for the first half of the year, and then, the rest of the year, we're unhedged. Eric, did you want to add some color around our expectations on WCS as we move through 2024? Yes. Thanks, Brian. I think at least from what we've read, and the intelligence we can gather, it sounds like TMX will be sort of mechanically complete in Q1 of 2024. This is what we read, this is what we're told, and there's a dispersion in data, but the central tendency of the various pieces of intelligence we get seems to point at Q1 mechanically complete. That same dispersed bit of intelligence also tends to point toward line fill, which is kind of already. You know, some of it is already taking place, because this is a big project, and it's been built in segments. I think some of the line fill is already complete, and this is what we've been able to ascertain. Q1 mechanically complete, Q1 continuing line fill, and really line fill progressing. And then we're certainly expecting, you know, Q2 deliveries through TMX. This is the best information we can gather. I think everyone has access to disparate intelligence on this, so we might all have, you know, slightly different collection of data. But that's what we think, and that's what we expect. And we think once TMX comes on, you know, in early 2024, we expect the WCS-WTI basis differential to narrow into the kind of $10-$12 per barrel range, and we think that becomes effectively described by the pipe economics to the U.S. Gulf Coast on the Enbridge mainline. Okay, thanks, Eric. We're gonna shift now to talk a little bit more. We've had some questions come in on the assets themselves and the performance during the third quarter. First question relates to the Eagle Ford operated acreage. Eric, the results that we're seeing, are they in line with our expectations? And any refracs planned on the assets? So, so the answer to the first question is, yes, in line. You know, we've, we've been modeling expectations like this. We've been, you know, working through the designs and the well performance expectations. So yes, Q3 meets our expectations, and we feel good about the way it represents the assets on a go-forward basis. We do have refracs planned, and we continue to think about the refrac program as kind of a parallel, if you like, a sidecar to the primary channel of drilling and completions development, primary capital development in the, in the play, along our operated portion of the play. As I described earlier, two rigs, level loaded, running full time through the program. That's a very efficient operation, 'cause these two H&P rigs are some of the best rigs in H&P's fleet, certainly some of the top-performing rigs in the Eagle Ford. And they've been with Ranger, now Baytex, for years, so they're very efficient. And then the Liberty frac crew, also been with the team on an extended basis, runs very, very well. So that's clear in DUC inventory. That's a nice, level-loaded, highly operationally efficient channel of progress on development capital. And then a sidecar to that is refracs. And the refrac program, you know, there's a lot to think about. There's you know, there's the candidate selection, which is, can you get in and get out with your workover operations and prep the line? Or do you have good zonal isolation? And is it a well that you think you can contain the fracture stimulation energy in the fairway or the stimulated reservoir volume that you're trying to refrac? And so there's a lot to think about in refracs, but we're quite encouraged and continue to progress, you know, that sidecar channel of capital development in our Eagle Ford. And we're gonna learn a lot there from our peers in the area who have more experience doing it. We sit on task groups and technical groups, and so there's a lot to learn, but we're very excited about it. Eric, can you comment on the range, sort of, of expectations for the current exploratory wells in our two new areas here in Western Canada? Just range of expectations on the program. Yeah. So the Rex at Morinville, you know, we've described these in our prior conversations, you know, as 30-100 locations each. So, you know, the Rex at Morinville, you know, somewhere in that range. I'm confident in the higher end of that range because the lower end, lower end has a pretty tight risking on it. That is to say, it's heavily risked, and I feel good about the fact that we'll probably get higher on the range there in terms of the locations in the Rex at Morinville. And similar, kind of, 30-100 locations at the Waseca at Cold Lake. We're continuing to develop those in Q3. And even today. And so we've got additional multi-lats that we have underway, and that we will continue to drill and bring online in Q4. And so there'll be more to talk about in Q4. Even though those are not needle-moving assets in terms of the number of locations and the production, they do continue to really demonstrate that, you know, this is a substantial footprint across a highly prospective fairway. And we feel really good about the steady diet of both discoveries and the geoscience team leading to new accumulation discovery and extensions. And so that just. It feels like a steady diet that will continue on. Eric, I think we're approaching almost an hour, so there are more questions. If we don't get to your questions here, we will certainly try and follow up with you, individually. So maybe two more, Eric. An investor here asking about the expected cost savings from the merger. Have we achieved what we expected from a synergy standpoint? We certainly have made a lot of progress. You know, the basis of the merger between Baytex and Ranger was not ultimately predicated on synergy savings. The synergies values were pretty modest in the outset, and we have accomplished all of those that we set out to accomplish. Again, they were pretty modest. It was, you know, eliminating duplication in things like back office, you know, financial audit, IQRE, or independent reserves audit, the redundant boards, the redundant leadership at the top part of the organization. So all of those, including a whole bunch of kind of redundant IT and software subscriptions, all of that has been extracted. And so, yes, given the fact that they were pretty modest to start with, we have achieved them. There's still a lot of additional meat on the bone, and we will continue to drive additional savings forward. And that'll appear like operational efficiency over time, the way we describe, say, the OpEx, the unit OpEx, and the blending expenses over time. Just consistently getting a little bit better over time. So that's the way I'd think about synergy progress. Another question, a little bit different, more of an ESG focus, and it might relate a bit to our Duvernay completions. But a shareholder is asking if Baytex has any interest in low energy or chemical or filter wastewater treatment technologies? So it's a bit of a different question that I thought I would ask. Yeah. So one of the ways to think about this is, you know, in both the Viking and the Duvernay, we are working very hard to lower our freshwater intensity. And in particular, in the Duvernay, for example, we use municipal wastewater effluent as makeup fluid for fracture stimulation. And, you know, that's particularly helpful because it helps, you know, lower the freshwater intensity of the operations. And in the Viking, of course, we use effluent from our Kerrobert thermal operation, and we use that as makeup fluid for our fracture stimulation in the Viking. So these are really helpful kind of intensity measures on an ESG perspective, from an ESG perspective in our fracture stimulation work in Canada. We're always looking to apply new technologies to creating, you know, better freshwater streams, less expensive freshwater streams, and in particular, the ability to use wastewater sources as freshwater for makeup. Okay, two, two last quick questions, Eric, I, I promise. Breakeven on oil pricing. Breakeven on oil pricing, down into the, I'd say, low-to-mid $40s across the entire portfolio. Okay. Getting better as we squeeze, you know, more efficiencies out of both the capital program and the operating expense program. And we're gonna wrap up with this one question, because I know it's something that Eric, you're clearly passionate about. And this comment comes from a shareholder who says that there are others out there, shareholders that are frustrated with our share price, unable to gain traction. Besides the buybacks, how do you plan to work to get that Baytex share price reflective of the fair value that you see in it? Yeah, it's a great question. I, too, you know, feel like it's been a long time. I, I'm reminded by the fact that, you know, we started this conversation about the merger between Ranger and Baytex on February 28. And, you know, it was a several months to close, and we released just a partial Q2. So Q3 is really the first full quarter. And, you know, when you find yourself in a show-me status or show-me mode, basically, all you can do is deliver results. And I think because Q3 is the first full quarter of delivering results, it really is, it really is the first opportunity for us to have showcased the full strength of the portfolio, the full strength of the assets, the skills and talents and experience of our team. And, you know, I think Q3 will go a long way to, you know, firming up the confidence that others have in the asset base and the team that I've had all along. Q4 will also reinforce that, and then full year, and then reserves, but it is a process. But it takes time to show the world, because, you know, these have to come out on quarterly cycles. And so here we are in November, releasing our first full quarter of results, and I'm quite pleased, and expect the good performance to continue through the year and well into the future. That's terrific, Eric. Thanks, everyone, for spending the last hour with us today. This is gonna conclude the Q3 conference call and webcast. Thanks, everyone, for participating. Have a great day. Thanks, everyone. This concludes today's conference call. You may disconnect your lines.