Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp Second Quarter 2023 Financial and Operating Results Conference Call. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. To join the question queue, you may press star, then one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star and zero. I would now like to turn the conference over to Brian Ector, Senior Vice President, Capital Markets and Investor Relations. Please go ahead. Thank you, Ishia. Good morning, ladies and gentlemen, and thank you for joining us to discuss our second quarter 2023 financial and operating results. Today, I'm joined by Eric Greager, our President and Chief Executive Officer, Chad Kalmakoff, our Chief Financial Officer, and Chad Lundberg, our Chief Operating Officer. While listening, please keep in mind that some of our remarks will contain forward-looking statements within the meaning of applicable securities laws. I refer you to the advisories regarding forward-looking statements, oil and gas information, and non-GAAP financial and capital management measures in yesterday's press release. All dollar amounts referenced in our remarks are in Canadian dollars, unless otherwise specified. Following our prepared remarks, we will be taking questions from analysts. In addition, if you are listening in today via the webcast, you will have the opportunity to submit an online question, and we will do our best to answer all questions submitted. With that, I would now like to turn the call over to Eric. Thanks, Brian. Good morning, everyone, and welcome to our second quarter conference call. We reached an important milestone this quarter with the closing of the Ranger acquisition on June twentieth. This transaction has added quality operating scale in the Eagle Ford and has reinforced what was already a resilient and sustainable business. We have emerged as a well-capitalized and diversified North American E&P company, and we're poised to deliver a powerful combination of increased Free Cash Flow and increased shareholder returns on a per-share basis. Before discussing our Q2 results, I'd like to take a minute and highlight the three key pillars to our business as we move forward. Number one is disciplined capital allocation. We are committed to a disciplined, returns-based capital allocation strategy, targeting modest single-digit organic production growth. Each of our core assets has 10 or more years of quality development inventory at our current pace of development, and this provides us the ability to efficiently allocate capital in response to changes in regional commodity prices and other economic, cultural, or regulatory circumstances. Number 2 is our focus on Free Cash Flow generation. Our commitment to efficient capital allocation across our portfolio is expected to generate meaningful Free Cash Flow. We intend to allocate 50% of this Free Cash Flow to debt repayment and 50% of Free Cash Flow to shareholder returns. Number 3 is maintaining financial strength. We have a strong balance sheet today with significant financial liquidity. This commitment to a strong balance sheet is unwavering. We've established a total debt target of CAD 1.5 billion, which represents 1.0x total debt to EBITDA at $50 per barrel WTI. This debt level will provide us with full flexibility to run our business through commodity price cycles and generate meaningful returns. For 2023, we continue to forecast exploration and development expenditures of approximately CAD 1 billion, which are expected to generate an average production rate of 120,500-122,500 BOE per day. For the second half of 2023, we expect production to average 153,000-157,000 BOE per day. Based on the forward strip, we expect to generate over CAD 400 million of Free Cash Flow in the second half of 2023 and approximately CAD 500 million of Free Cash Flow for the full year 2023. With the closing behind us, we have moved quickly to enhance shareholder returns. To date in July, we have repurchased 4.9 million shares. I'm very pleased to announce that our board of directors declared a quarterly dividend of CAD 0.0225 per share or CAD 0.09 per share on an annual basis. I'll now shift to our Q2 results, which include 11 days of operations from Ranger. Production during the quarter was 89,800 BOE per day, 86% oil and NGLs, which exceeded the high end of our Q2 guidance range due to the timing of operated Eagle Ford wells brought on stream late in the second quarter. It's important to note that our Q2 production was reduced by approximately 4,500 BOE per day due to the curtailment of production caused by wildfires in Alberta. Wildfires continue to burn in Northwest Alberta, and we could see further interruptions through the summer and into the fall. For the month of July, we expect production to be curtailed by approximately 2,000 BOE per day. We are incredibly proud of how our personnel have responded to these challenging conditions with sound, safety-focused decision-making and genuine concern for our communities. I would also like to thank the emergency responders and firefighters who courageously continued to protect our communities. We delivered Adjusted Funds Flow of CAD 274 million, CAD 0.47 per basic share in Q2, and generated Free Cash Flow of CAD 96 million, or CAD 0.17 per basic share. Exploration and development expenditures totaled CAD 171 million during the quarter, consistent with our full-year plan, and we brought 34.9 net wells on stream. Operationally, the highlight was the completion of our six-well Duvernay program, and new heavy oil exploration success in the Waseca, near Cold Lake, Alberta. As a reminder, our Pembina Duvernay light oil assets are in the demonstration stage of commerciality and offer high operating netbacks with the potential for strong economics and organic growth. Our completions and facility execution tracked ahead of plan, which allowed for an acceleration of the on-streaming of wells. 4 of the 6 wells are in the early stages of flowback and are tracking the type curve initial rate expectations. The remaining 2 wells are expected to be on stream by mid-August. In the Waseca, we drilled a 6-leg exploration well that was brought on stream in April. The Waseca formation is analogous to the Clearwater across the fairway and is highly amenable to open hole development, which drives strong returns and capital efficiencies. We're planning 3 follow-up wells in the second half of 2023. We have an active second half of 2023 development program ahead of us. In the Eagle Ford, we expect to bring approximately 24 net operated and 8 net non-operated wells to sales. In the Viking, we expect to bring 46 net wells on stream, and our heavy oil development program has ramped up, with 4 rigs running, 2 at Peavine, 1 at Peace River, and 1 at Lloydminster. We expect to bring 40 net heavy oil wells on stream, 19 at Peavine, 18 at Lloydminster, and 3 at Peace River. We also have 3 SAGD well pairs in Kerrobert that are expected to be on stream during the fourth quarter. With respect to risk management, we employ a hedge program to help mitigate the volatility in revenue due to changes in commodity prices. For Q3 2023 and Q4 2023, we have entered into hedges on approximately 40% and 35% of our net crude oil exposure. Utilizing a combination of two-way collars with a floor price of $60 per barrel and a ceiling price of $100 per barrel, and a 5,000-barrel purchased put at $60. For the first half of 2024, we have entered into hedges on approximately 22% of our net crude oil exposure, utilizing two-way collars with a floor price of $60 per barrel and a ceiling price of $99 per barrel. I also want to highlight our 2022 ESG and TCFD reports. Both were published yesterday and are available on our website. We've built into our culture a strong connection and sense of responsibility to our communities and stakeholders. We remain focused on key ESG initiatives, including GHG emissions, abandonment and reclamation, strong and mutually beneficial indigenous relations, safety, and climate risk management. These ESG initiatives are essentially driving our long-term sustainability alongside shareholder returns. I would encourage everyone to read through the reports, as they contain a tremendous amount of information and give great insights into the Baytex team and our culture, something I am immensely proud of. 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. With the Ranger acquisition behind us, we are building an even stronger North American energy company with a high-quality, diversified, oil-weighted portfolio across the Western Canadian Sedimentary Basin and the Texas Gulf Coast Eagle Ford. 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. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. The first question comes from Greg Pardy with RBC Capital Markets. Please go ahead. Morning, this is Justin Ho on for Greg Pardy, and thank you very much for taking my question. Just for my first question, we were wondering, now that the Ranger deal has been closed for about a month now, if you could provide us with an update on how the integration process is going so far, and if there's any low-hanging fruit or synergies that you see with respect to the integration with Ranger? Thanks, Justin. Good morning. Thanks for the question. Yeah, so, so it is, it is 1 month past close, and that's important, but we were well ahead of closing with the integration work. People integration, you know, technical and operational workflow integration, and business process integration was all well underway. We feel really good about all of the integration steps. And it feels, it feels to me like as we proceed through... you know, the Q3 and the second half of the year planning, like we've been a combined business longer than it might look on paper. Update-wise, we have taken, you know, a number of substantial steps, I think, to begin to unlock additional value through efforts around managing and optimizing the surface gathering system. g to add compression horsepower, which should reduce the gathering system pressure expressed at the wellhead. We've been working very diligently with the team on the ground in Houston and in the field on nodal analysis and optimizing artificial lift. And have actually liberated quite a lot of horsepower from gas lift into compression, back into sort of compression and move to sales horsepower by optimizing gas lift and optimizing other artificial lift approaches. And this is just the kind of blocking and tackling you'd expect these integrated teams to be doing." Um, and We will continue to focus on continued, you know, technical work around improving and extending stimulated reservoir volumes, improving economic returns around drilling and completions, but also the artificial lift and the gathering and processing analysis at the surface. These, these take a comprehensive kind of systems-wide engineering approach. You, you tinker with one piece, and it has knock-on, it has knock-on impacts. We're working on a handful of integrated optimization steps. I think the biggest steps right now that we've, we've focused on through the summer and since close, has been around gathering and processing optimization and artificial lift. That's great. That's great. Many thanks. Maybe just shifting gears, we were also hoping to get a bit more color on the exploration well that you drilled out in Cold Lake and the expectations for IP30s on the remaining three wells. Do you view this as another big potential play, and how does it stack up versus the Clearwater, which I heard you mention it was analogous to? Yeah. Yeah. You know, I-- we're, we're very excited about this. I think it's, it's, it's really important to point out that both the Waseca at Cold Lake as well as the Rex, the Clearwater equivalent at Morinville, that we actually disclosed in Q1, both of these are very exciting plays. They're small, cold flow, heavy, conventional discoveries. What's really important to point out, while neither one of them are going to be sort of needle movers in a larger business, each one is-- each one represents, you know, somewhere between 30 and 100 locations, depending on how you risk adjust probability of outcomes. You know, given the fact that each one of those locations is, you know, CAD 4 million-CAD 5 million PV, and all of that value accretion and value creation essentially came out of thin air. It materialized out of the efforts and the intellectual property of our geoscience teams and the operational and technical prowess of, of the organization when it comes to, you know, cold flow heavy development. I'm immensely proud of the making something meaningful. Again, CAD hundreds of millions of value accretion effectively materializing out of the, the, you know, just the intellectual property and time it takes to run an exploration program. I would point out that this is the 3rd discovery in 3 years. You know, 2 years ago, it was the Peavine, and then 2 more this year. Three discoveries in 3 years in cold flow heavy. We sit on a very large acreage position, 1.7 million net acres. Because oil is where oil was, we're gonna continue to create a steady diet of these, you know, meaningful, value accretive opportunities. I just couldn't be more proud of the, of the technical and operating capability of the team. In, in terms of expressing, you know, the next wells IPs, you know, I can be bold, but I'm not going to be that bold because I just... It's, it's 1 exploration well. The team is pretty confident in understanding the trapping structure of this, of these plays. I think we can continue to put up good numbers as we continue to release, the results of the second half, exploration and development program, both in and around Cold Lake and in and around Morinville. That's great. I'll turn it back now. Thanks again. Thank you, Justin. The next question comes from Amir Arif with ATB Capital. Please go ahead. Thanks. Good morning. Just one quick question for you, Eric. Just on the pace of buybacks, could you just give us a sense of how you plan to do those relative to your free cash generation? Is it gonna be essentially lined up quarter to quarter, so third quarter cash flow would line up with the expected buybacks in the third quarter, or is there a lag expected? Good morning, Amir. Thanks for the question. July was a little bit interesting because we had to catch up, and also because for the first half of the year, we wanted to honor, you know, the 25% framework, which was in place technically right up to close. You know, we hadn't been in the market because we were essentially blacked out for the entire first half of the year. We generated Free Cash Flow in Q2, essentially, we had to catch up in July that allowed us to take advantage of that accumulated Free Cash Flow, but at a 25% level. When you try to reconcile against, you know, why the 4.9 million shares in July, those are like kind of the mechanics of the arithmetic that go into that consideration. Going forward, you know, with the CAD 400 million of expected Free Cash Flow generation through the balance of the year, you know, if you just do the simple arithmetic, given the amount of months outstanding and the CAD 400 million of Free Cash Flow generation expected, you could see us ramp that up. It would also be logical that we would ramp that up, given the fact that where we sit today is likely to be a better opportunity to buy at a lower price than, than it, it's likely to be in the future, just given, you know, some reasonable expectations. If you, if you expected, you know, that CAD 400 million, you know, to carry, you know, kind of proportionally through the year, that would make sense. We do, however, we do want to be diligent about not getting too far ahead. For example, if we're generating substantial Free Cash Flow, and it's forecasted in December, we're not going to spend all of that, you know, on the come in, say, August. We're threading the needle between trying to be really diligent about buying as much back as we can today, while still recognizing that this is a commodities business, and things can change dramatically fairly quickly. We're threading the needle. I think I've given you maybe enough bits and pieces to the mechanics of the math. You'd be right to expect us to spend, you know, half of that CAD 400 million, and to do so as quickly as we can get comfortable doing so, based on based on the way things are looking. I appreciate that color. Just as a second question, just going back to the Eagle Ford acquired assets. I know it's only been a month, but as you develop it at a slower pace than what Ranger Oil was developing it, could you give me a sense of what the low costs are, and do you see any synergies on the capital side? I know you talked about the operational side a bit. Yeah, yeah. So, on the capital side, we're, you know, a substantially larger business, and that, and that larger business will allow us to negotiate better terms with suppliers: steel suppliers, proppant suppliers, hydraulic horsepower suppliers, and drilling contractors. All of these things, you know, we, we've got an opportunity to utilize that, that new scale to leverage agreeable terms or more agreeable terms. We're also planning to run all of our business as, as close to level loaded as we can, finding the optimal points of efficiency within each asset. That will also give us opportunities. As you level load, you know, the drilling and completions business and your steel supplies, that level loaded nature allows your suppliers, your vendors, to also find opportunities to lower costs, and that flows through. So what I would say is, you know, we continue to see opportunities to, to make commercial gains in terms of better terms. Also, you know, the two technical teams coming together and working together, within the Eagle Ford, you know, we've had, our team that was running, you know, our investment side of our Eagle Ford Karnes interest, the Marathon operated, Baytex non-operated, together with our operating and technical teams in Houston on the Ranger-operated assets, together with our Duvernay team, because those are very analogous assets. You know, combining, their ideas and their tools and optimizing, capital efficiencies. So we continue to see opportunities to both create higher performing wells, while holding the line on capital, and that should flow through over time into better and better capital efficiencies, together with better commercial terms. Thanks for the color. The next question comes from Jeremy McCrea with Raymond James. Please go ahead. Yeah. Hi, guys. just a couple of questions here. Your exploration success, just with Waseca and, and in Mannville and even Peavine. Can you give me some more sense of how aggressive and your geoscience team is in terms of finding potentially more of these prospects? How, you know, big and commercial and relevant could this be in the overall portfolio here now still? Well, you know, I, I, I think in terms of how aggressive they are, we will continue to fund for the foreseeable future, you know, an exploration, an organic exploration program in Western in the WCSB. It's, you know, let's, let's say notionally, it's going to be somewhere in the CAD 10 million range, and that should, you know, fund 10-15 strat wells and pilot wells, deepenings and additional, you know, kind of petrophysical reservoir characterization, as we expand our interpretation of, you know, core to logs and, and, and tighten these things up. We'll continue that investment. I would, I would fully expect that the team is continuing to build out prospect locations and continuing to move around our land position and, and, develop opportunities. I can't give you any specifics, because I, you know, I think that would be wrong in an exploration environment to do so. We've got a lot of land and a lot to discover, and, and I, I just, you know, again, it's very exciting to see, two discoveries in a single year, and every expectation that that, steady diet should continue. Because in most of these cases, in fact, in every case so far, at least in these two this year, we have, already ownership of the, you know, the rights to the land. We have teams in place, we have locations and infrastructure, and, and so, the ability for this to be material depends on the size of the discovery, but each one of these is, you know, highly accretive, based on the very, very low, you know, cost of entry. It's the exploration and any intellectual property which already exists in the organization. I know that's a, a lot of words. I don't-- I, you know, I can't really speak to the scale going forward. I would just say, you know, two discoveries in one year and a pretty steady diet, it feels like to me, as we move throughout, you know, our lands and continue to apply these new interpretations of the stratigraphic sequences that we've learned over the last couple of years. Does this, as a follow-up there, does this change your, the way you look at M&A up in Canada here, once again, in terms of, you know, the potential for these type of exploration wells or, or other guys where you're thinking it's being missed by different operators? Like,[Crosstalk]? Yeah. Yeah, it's, it's possible. I, I think, you know, M&A is always about creating value. You'd, you'd have to look at, you know, the, the opportunity set, and how the competitive environment has either bidded up or failed to recognize. In, in the case of Peavine, a couple of years ago, the Clearwater at Peavine, you know, I think the team did an exceptional job of, of finding it, ring fencing it early, and had that first mover advantage. As you well know, you know, the Clearwater, you know, kind of caught fire and was priced to the point where it, it couldn't really create any value. This is obviously one of the reasons why you wanna have opportunities in various places, because these factors will come and go. They will ebb and flow as you have opportunities to, you know, buy EBITDA. In, in terms of, you know, real M&A in the near term, I'd say we are absolutely laser focused on execution today. We are gonna deliver Q3, Q4, full year 2023, and a budget and a reserves book, that we are going to be very, very proud of. That is our singular focus. What happens in 2024, 2025, and beyond will depend on factors that, that present themselves in the future. We're always looking for, you know, opportunities to create value over time. I would say in the, in the next short while, we are absolutely laser focused on demonstrating this business is as good, to everyone else as we know it is, given, given what we understand about it. That's probably the best I can do, Jeremy. Thank you. Thanks. The next question comes from Jasper Wijk with Valpal. Please go ahead. Hi, hi, Eric. Thanks for taking my, for taking my call. You have with the Eagle acquisition, you have become or with the Ranger acquisition, you have become a significant operator in the Eagle Ford information, and you still have ample liquidity. My question would be: What potential do you see for sort of smaller tuck-in acquisitions in your core areas, both in the Eagle Ford but also in Canada? Hi, Jasper, thanks for the question. Yeah, it, you know, I think in the Eagle Ford, in the short term, we're, we're going to be focused on execution. We're gonna be focused on integration. We're gonna be focused on delivering, you know, on, on the second half of the year and also on a 2024 budget. That, again, demonstrates the strength of this company, to the outside world as, as, as much as we believe, from, from the inside. You know, I, I think specifically around the, the kinds of activity, you know, it's, it's going to be swaps and trades that create value, building, perhaps a larger, you know, operated working interest, and, and continuing to create opportunities for longer laterals, for higher working interest on the lands in which we already operate. Small tuck-ins, you know, you, you really shouldn't expect anything substantial to be taking place, you know, in the Eagle Ford or the WCSB in the near term. In the longer term, you know, we, we, we are very, very, you know, strong believers in the economies of scale. We believe that the Mannville is a very high-quality resource, and we've got an expansive position and understand it as well as anyone. We want to continue both exploring and developing on the lands that we already own. Mannville is really good. That includes the Clearwater. We're very, very excited about our continued organic growth opportunities in the Duvernay, and what that, you know, that growth, like, represents, organically, and then, continued development in and around our Eagle Ford position. We're, you know, as I, as I said earlier, we're laser focused over the next couple of quarters and into 2024 of, of delivering on, on this new Baytex and demonstrating the strength and resiliency of this business. Thank you. My second question would be if you would like to add some color on what your internal estimate is for the IP365 on the upper Waseca well? Boy, that's, that's gonna be a, that's gonna be a really tough one for me. You know, as, as we sit here today with one exploration well, you know, these are always designed to be proof of concept, Jasper, so I can't really forecast an IP365. What I can tell you is it's high-quality reservoir. We understand the structure of the reservoir, and we understand what drives its performance. We're one well in. You know, I think there'll be a lot more to share toward the end of the year when we get when we get our reserves work done, because, you know, these wells, you really don't even have enough production data yet to hang a reasonable decline curve off of. It would be just rank, rank speculation for me. We're pretty excited about, both the Waseca at Cold Lake as well as, the Rex or Clearwater at, Morinville. I look, I look forward to seeing the results of the, of the, of the upcoming drilling campaign and the, and the decline curve for, for the Waseca well. Thank you. With that, I would like to turn my call over. Thank you, Eric. Thank you, Jasper. This concludes the question and answer session from the phone lines. I would like to turn the conference back over to Brian Ector for any questions received online. Okay, thank you, Ishia. I do have a few questions that have been submitted from the webcast, so I'm gonna moderate these now for you, Eric. The first question relates to sort of capital allocation. Can you please discuss the allocation of E&D spending between Canada and the US? Your thoughts on how we allocate capital. Yeah. What we've been saying, you know, up, up to this point really isn't changed. We were saying essentially half of our capital would be allocated to our-- what would have been, and in all, all our prior language, standalone Ranger assets, and the other half of the capital allocated to what would have been standalone Baytex, including the non-op Eagle Ford. That, that's a way to tie what I'm, what I'm saying today to the past. That hasn't changed, that, that half and half. And, you know, over time, I think it's going to depend on economic conditions, things like how the WCS basis diff widens or narrows and what, what other kind of circumstances express themselves in these various parts of our business. We will be allocating capital to the highest returns first. We're also keenly aware that, you know, each one of our assets has points of, points of development efficiency where you really wanna run. For example, in our Peavine, we've been pretty clear that 12,000-15,000 BO a day, you know, although this is a, an absolutely spectacular asset, just anywhere in the world, it's a spectacular asset, you know, it runs most efficiently in this 12,000-15,000 BO a day band. We've been asked: Why don't you put all your capital into Peavine? It's just... I realize that that's sort of a philosophical question, but none of these assets can handle that much. Peavine will run at a, at a point of where it's, where it is maximum operational efficiency for lots of reasons. We have also talked about Eagle Ford, our Ranger assets, in the same way. You know, we like two level-loaded rigs running on the Ranger lands because that level loads a single frac crew. It allows us to build a responsible refrac program into the system, this is a way that we liberate intellectual horsepower out of the organization to work on all the other demands and dimensions of the business to continue to unlock value. It's why we've actually been able to, you know, focus on things like artificial lift optimization and gathering and processing optimization and other things. When we talk about capital allocation, we always start with, show me where these assets, each one of these assets, runs most efficiently, operationally, and from a capital efficiency perspective. Then we will, we will select capital allocation according to the returns, where each of the assets are running most, most efficiently. Okay, thanks, Eric, for that. A question regarding the balance sheet. You highlighted in your prepared remarks, a CAD 1.5 billion total debt target, and the question really is around the timeline to achieve that target. Eric, if you wanna comment, or maybe even Chad Kalmakoff. Sure, yeah. Let me, let me pitch it over to Chad K. Sure. I think, you know, I think we've, we've generally been saying we, we do see that being around 2 years' time. I think, we think that still, that still holds. Obviously, if you just take the back half of the year, the CAD 400 million, using that as a proxy, that would be closer to 2.5, maybe just a touch over 2.5 years. Obviously, we're pretty exposed to oil and, and foreign exchange price, you know, foreign exchange rates, that could change that materially. Obviously, a CAD 5 change in oil price up would be also a CAD 220 million increase in our, in our AFF. We still think we're marching towards around that 2, 2-year mark, approximately. You know, that hasn't changed. Okay, thanks, Chad. Maybe almost along the similar lines related to capital allocation, balance sheets. We've introduced a dividend now. Eric, can you just discuss the potential or the outlook, maybe towards future dividends, and could we see dividend increases? Yeah, we certainly could, Brian, and I, I appreciate the question. There's always a tension between, you know, using your Free Cash Flow allocated to shareholder returns. The tension between those who prefer larger dividends and those who prefer share repurchases. You know, as it stands today, our plans are to continue with the CAD 0.09 per share, per year dividend as a fixed base dividend, with no plans, you know, to, as we sit here today, raise that dividend. What I will say is one of the, one of the nice and, and elegant mechanisms, as you as you buy back and cancel shares, that reduces the number of shares outstanding against which you end up paying your fixed base dividend, and it lowers the absolute value of the, you know, the, the total value of the dividend that, that is paid out out of the company. Which allows you to then take that additional cash flow, and if the board so chooses, and if our feedback from our investment community is such that it supports, then we could decide to take that additional cash and then grow the fixed base dividend over time. It was a very thoughtful, you know, this was a, this was a very kind of thoughtful dimension of our discussion during our, our standup of the fixed base dividend. Where do we start in order to give us some room so that we can grow? This was one of the reasons why we started at this kind of notionally 2% fixed base dividend yield, to give us some room, to, to raise it over time, should the board decide they'd like to do so, and should the investment community support that. Okay, thanks, Eric. I think we have time for just maybe two more questions. One question relates to the Juniper position that they now hold in Baytex, Eric. With the merger now behind us, can you just characterize, you know, our long-term relationship with Juniper? Yeah. Juniper is our largest shareholder at, I, I would say right now, probably, as I sit here, I'm gonna guess, at about 19.5%. The relationship is very strong. We, we've been, you know, in, in communication with them like we are with all of our shareholders, in terms of gaining feedback from the investment community. You know, I, I think. These guys are, are long energy investors. They, they believe in the business, they believe in this business, they believe in the business overall of oil and gas worldwide, and the role it plays in fueling economic society over time. They're in, they're in no particular rush, as they tell me, you know, to, you know, to, to get out. That feels really good to me. Although we do recognize that, you know, at 19.5%, that's a large position, and I think, you know, over time, they'll, they'll probably want to get that position down just a little bit. It creates opportunities for us. One, it's a very strong relationship, and we understand where they are and how they feel about the business, both Baytex specifically, pro forma Ranger, but also more broadly, oil and gas in North America, but, but very specifically, you know, around, the steps we need to take. I get great feedback from them, as a, as a, you know, common shareholder. They, they tell me what they think, and, we season that in with thoughts from, all the rest of the investment, community along the way. All right, thanks for that question. The last one, it's a bit of a technical question, Eric, related to the drilling of wells on the Ranger lands. Just maybe to summarize, you know, the wells being drilled today versus perhaps the older vintage wells, are we seeing increased performance? Are there opportunities to drive better performance? On the-- maybe I'll add to the question: On the vintage wells, do you see opportunities for potentially reentries or refrac opportunities? Just a question on spacing and the technical side of the Eagle Ford. Yeah. it's, so it's a yes to, basically, Brian, all three of those questions, the answer would be, in short, yes. Yes, we're seeing better performance in the more recent wells. A lot of this has been driven by, you know, just industrial progress and the progress of our space in general and the unconventional fracture stimulation, in, in the art and science of fracture stimulation and unconventionals. You know, higher fracture intensity, you know, tighter stage spacing, tighter perf cluster spacing, higher total, you know, higher pressure differentials between the inside surface of the pipe and the end of the perf tunnel drives. more and more kinetic energy into the reservoir, and that breaks more rock, it shatters more rock, it creates more fracture surface area in the reservoir, from which to, to liberate or deliver oil and natural gas off the surface of the fractures. All of that has been progressive over time. In any unconventional, if you look at the vintaging of the wells, you see well performance on a per 1,000-foot basis go up. BOE per 1,000, if you look at, you know, 2015, 2016, and so on. This is in our deck, you can see the progression over time. The wells get better over time, and they get better on a unit basis as well as overall. There is still room to continue driving that performance higher. One of the ways in which you've, you've seen the industry do this, we're doing it in spades across our unconventionals, is, you know, larger bore tubulars delivering more horsepower to the reservoir to be converted into kinetic energy to fracture the rock. That is a continued evolution. You also see things like in the industry, you'll read about it as a term called simul-frac, whereby you're able to drive more kinetic energy or deliver more kinetic energy to the rock, given the units of horsepower you've got at the surface. It's a way of managing the parasitic losses through the pipe due to friction. All of these are very technical, but yes, they've gotten better. Yes, we see opportunities to continue to get better. You know, despite the fact that we've got development on the land, we see lots and lots of opportunities to continue to get better. Sharing those opportunities across our non-op technical team with experience in the Karnes Trough, our new operated technical team in the Ranger lands, and our existing technical team in the Duvernay, to, you know, to share those learnings, in and around unconventional performance and geomechanics. I, I would say, you know, the last question around refrac, it takes advantage of many of the same, you know, technical progression. These older wells, many of them were, were completed, with, you know, with substantially, [muscular fluids], zirconate cross-link, stimulation fluids, hybrid fluids. and those fluids had a tendency to create very, very dilated fractures, but limited the fracture surface area because it tended to over dilate fractures. Today, we use what we call slickwater fluids, and we deliver larger jobs, but also driving more fracture surface area, you know, per unit of kinetic energy delivered to the reservoir. So the fact that, again, let me repeat this, kind of, in-- it's true in unconventionals as well as conventionals. Oil is where oil was, and it's in the SRVs, inside these existing fracture-stimulated wells from a decade ago. We can go back into these wells, and we can clean them out, set new liners, recement those new liners, and restimulate those well bores and unlock existing resource. Because, you know, something like 90% of the resource remains in those existing old well bores that have an opportunity to be re-stimulated. All right. Thanks, Eric. It's a great answer to a, to a really good question. We've got 1 last question that just came in, so I think we will try to, to get to this one as well before we wrap up. This relates to the, the sort of the legacy Eagle Ford position with Baytex. Can you just comment on the relationship that we have with the operator? Yeah. So, we have a great relationship with the operator, have, have for a long time. You know, these assets came into the Baytex business in 2014, and the team has worked long and hard over, you know, almost a decade to build a good, high-quality technical and management relationship with the operator, and continue to do so. They're, they're a great operator. They do an excellent job, and their performance speaks for themselves, speaks for itself. We benefit from that expertise and from the scale, but we also recognize that, you know, you know, having such a large non-op position within Baytex, as a standalone organization prior to our Ranger merger, you know, presented certain risks to the business, because it was our largest asset and because it was entirely non-op. The risks weren't because we had a bad relationship or weren't because they aren't a good operator. It was because the capital allocations were entirely. The decisions for capital allocation into and out of those assets were entirely beyond our control, and that was, at its root, the risk. We couldn't be happier with the relationship, and we couldn't be happier with the performance of the operator, and want to continue leaning in on both of those. All right. Thanks, Eric. That does conclude the questions coming in from the webcast today. Again, I think it's, it's been a great success providing this opportunity to, to facilitate some additional questions from, from our shareholders. Everyone, thank you. Thank you, Operator. Thanks, everyone, for participating in our second quarter conference call. Have a great day. This concludes today's conference call. You may disconnect your lines. Thank you for participating, have a pleasant day.