Thank you for standing by. This is the conference operator. Welcome to the Baytex Energy Corp Second Quarter 2024 Financial and Operations 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 for analysts to ask questions. To join the question queue, you may press star then one on your telephone keypad. You may also submit questions in writing at any time using the form in the lower section of the webcast screen. Should you need assistance during the conference call, you may signal an operator by pressing star then 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, Brenda. Good morning, ladies and gentlemen, and thank you for joining us to discuss our Second Quarter 2024 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're listening in today via the webcast, you will have the opportunity to submit an online question, and time permitting, we will strive to answer your question. With that, I would now like to turn the call over to Eric. Thanks, Brian. Good morning, everyone, and welcome to our Second Quarter 2024 Conference Call. In the second quarter, we delivered strong results with higher production, disciplined capital spending, and meaningful free cash flow. Importantly, and consistent with our full-year plan, we returned $97 million to shareholders through our share buyback program and quarterly dividend. As we continue to execute our plans for 2024, our free cash flow is expected to strengthen in the second half of the year, allowing for increased shareholder returns and debt reduction. We increased production per share by 23% in Q2 2024 compared to Q2 2023, with production averaging more than 154,000 BOE per day, 85% oil and NGLs. Our crude oil production, comprised of light oil, condensate, and heavy oil, increased 4% from Q1 2024 to average over 110,000 barrels per day. We are executing our 2024 development plan with a tightened production guidance range of 152,000-154,000 BOE per day. At the midpoint, we continue to target 153,000 BOE per day for the year. Our 2024 exploration and development expenditures guidance is unchanged at $1.2-$1.3 billion, and we expect to generate approximately $700 million of free cash flow in 2024, 75% weighted to the second half of the year. We intend to allocate 50% of free cash flow to the balance sheet and 50% to shareholder returns, which includes a combination of share buybacks and a quarterly dividend. Now, I'll turn the call over to Chad Kalmakoff to discuss our financial results. Thanks, Eric. We remain committed to a disciplined returns-based capital allocation philosophy to drive increased per-share returns. In Q2, adjusted funds flow was $533 million, or $0.65 per share, 38% higher than $0.47 per share in Q2 2023, and we generated net income of $104 million, or $0.13 per share. During the second quarter, we generated $181 million of free cash flow, and as Eric mentioned, we returned $97 million to shareholders. We repurchased 16.4 million common shares for $79 million and paid a quarterly cash dividend of $18 million, or $2.25 per share. During the last 12 months, we have returned $378 million to shareholders, repurchasing 57.5 million common shares for $304 million, representing 6.7% of our shares outstanding, and paying total dividends of $74 million, or $0.09 per share. On June 26, 2024, we renewed our normal course issuer bid with the Toronto Stock Exchange, which allows us to purchase up to 70 million common shares during the 12-month period ending July 1, 2025. As of yesterday, we are proud to say we have repurchased 7.2% of our shares outstanding dating back to June 30 of last year. We touched on this last quarter, so I won't get into the details today, but I do think it's important to note that we have extended our debt maturities. The term structure of our long-term notes and the liquidity on our credit facilities has been greatly improved and positions us well to run our business through the commodity price cycles. Our total debt at June 30 was $2.5 billion, which represents a total debt-to-EBITDA ratio of 1.1 times. Our total debt is largely unchanged from year-end, as in addition to the free cash flow generated year-to-date, our total debt also reflects the strengthening U.S. dollar relative to the Canadian dollar, which increases the balance on our U.S. denominated notes, the call premium and issuance costs on our notes offering, and the credit facility extension and strategic land acquisitions we did in the first half of 2024. Continuing to strengthen our balance sheet remains a priority, and based on our forecast free cash flow and shareholder return profile, we expect a reduction in total debt in the second half of 2024. Now, I'll turn the call over to Chad Lundberg to discuss our operating results. Thanks, Chad. The strong free cash flow that our business generates is a testament to the efficiency of our exploration and development program and our stable production profile. I'm now pleased to speak to our Q2 operations and highlight the significant efforts of our team. During the second quarter, exploration and development expenditures totaled $340 million, and we brought 40 net wells on stream. In the Eagle Ford, we continue to deliver strong results across our acreage. We generated production of over 90,000 BOE per day, 82% oil and NGL, and brought 11 operated lower Eagle Ford wells on stream that were largely focused on the black oil window. Some of you will recall that during the second quarter, we hosted analysts and investors for a tour of our Eagle Ford operations. One of the site visits was our Pluto Pad that was in the midst of completion operations. This pad was brought on stream during the quarter and is now one of our strongest performing oil-weighted pads to date, with three wells generating an average 30-day peak initial production rate of over 1,150 barrels per day of crude oil. Due to the efficient drilling and completion activities, in the first half of 2024, we realized an 8% improvement in operated drilling and completion costs for completed lateral foot over 2023. In our Canadian light oil business unit, the first three-well pad from our 2024 Duvernay program was brought on stream in May and generated an average 30-day peak initial production rate of 890 barrels of crude oil and 1,350 BOE per day per well. These initial results are consistent with our expectations. The second four-well pad is expected to be on stream in August. In our Viking light oil and across all our heavy oil operations, second quarter activity is typically lower due to spring breakup. Following spring breakup, our heavy oil development program has ramped up, with four rigs running across our Peavine, Peace River, and Lloydminster regions, and two rigs running in the Viking. Peavine continued to outperform expectations, with production averaging almost 20,000 barrels per day, up 13% from Q1 2024. We brought four wells on stream at Peavine that generated an average 30-day peak initial production rate of 760 barrels per day per well. With that, I will turn the call back to Eric for his closing remarks. Thanks, Chad. I want to take a moment and circle back to our shareholder return framework. As many of you have noticed, we have gradually stepped up our buyback program and have now reached a consistent buyback level currently set at $1.4 million per trading day. We believe this is a prudent approach that allows us to meet our commitment to return 50% of free cash flow to shareholders in the form of share buybacks, quarterly dividends, and improving per-share metrics. I am pleased with the strength of our Q2 operating and financial results. As we execute our plans for the second half of 2024, our free cash flow is expected to strengthen, allowing for increased shareholder returns and debt reduction. And now, operator, we are ready to open the call for questions. Thank you. We'll now begin the question and answer session. To join the question queue, you may press star then one on your telephone keypad. You'll hear a tone acknowledging your request. To submit your question in writing, please use the form in the lower right section of the webcast screen. If you're using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star then two. We'll pause for a moment as callers join the queue. The first question comes from Greg Pardy from RBC Capital Markets. Please go ahead. Yeah, thanks. Thanks. Good morning, and thanks for the rundown. So I've got a couple of questions, but maybe just on the financial side. Could you give us a sense as to what the trajectory looks like in terms of CapEx and production in the second half, and then just the potential, particularly, I think, for debt reduction and buybacks? Please. Yeah. Hey, Greg. Yeah, yeah. I'll take those two first because I don't think I'll remember more than two questions. On CapEx and production trajectory, I'll answer that. On CapEx, we're still pointing to the midpoint of CapEx, and that's implied by the $1.2-$1.3 billion CapEx guidance range. It should be weighted more toward Q3 than to Q4, just in terms of that weighting and trajectory. And in terms of production performance, we're still pointing to the midpoint of full-year annualized, so that's 153,000 BOE per day, which would imply a pretty level second half of the year, kind of at the production level we're at right now. And that, of course, backing into levelized operations across our footprint allows us to really generate more efficient levelized operations. As far as the debt paydown trajectory, I'm going to pitch it over to Chad Kalmakoff and have him give a quick answer on that. And then please jump back in with if you've got another question. Sure. Yeah. Thanks. Sure. Thanks, Greg. Yeah. So we had free cash flow of CAD 200 million here in the first half of the year. We're looking at another CAD 500 million in the back half of the year. And of that, we should have CAD 200 million hitting the balance sheet or paying down debt. So look to see debt paydown obviously accelerate here in the back half of the year compared to the first half. Obviously, we had the bond refinancing done here in Q2 and some fees and the discounts associated with that, which would have impacted our ability to pay down debt this quarter. But at the same time, extending those debt maturities is pretty important to us and getting that lower coupon that'll be impactful in the years to come. Okay. No, thanks for that. Maybe just completely shifting gears, maybe into the Duvernay, could you frame maybe your learnings and results thus far as you work through your 7-well program? And then is there anything to say maybe about efficiencies or where costs are kind of coming out on that? Because it's a pretty important program, I guess, going forward. You bet, Greg. Again, it's Eric Greager here. So I'm going to give it kind of one minute at a high level, and then I'm going to pitch it to Lundberg for the details on efficiency gains. It's a seven-well program, a three-well pad, and a four-well pad. The three-well pad came on in May. The results have been in line with our expectations and our model and strong. And so 90% liquid, 65% oil, 1,350 BOE a day on average. We also pushed length on one of the laterals out to 4,000 meters, which feels pretty good. So lots of good, I think, operational learnings along the way, strong well performance. We should be bringing the four-well pad on in August, and we'll have more to talk about there. Yeah. I think, Greg, to really answer the question, you need to really look broad in terms of efficiencies and what you need to basics now as we have the Eagle Ford and the Duvernay. And I think it's a continuous evolution and learning process where the teams are swapping back and forth between each other. They're calibrating large machine learning model data sets to better inform what we do on quarterly basis. If I think about the Duvernay itself, just talk results. We've got drill results in now, a 20% reduction in overall drill days. That's translated into a 10% reduction in cost. Completion results are still being tabulated. I think if you look at that would be the order of same thing. We've seen a reduction in overall drill days and increase in effective pumping hours per well. If I take it just one to finish answering the question one layer deeper, the model would inform us year-over-year that the changes we've been making are on the water side in the Duvernay, so increasing water intensities. And then, like I said, you have to have a balanced conversation across the border. If you think about across the border, it's more on cluster spacing or stage spacing. So continuous evolution. We're playing the two plays off each other. We're seeing positive results in both. And I do believe that there's more to come. Okay. Terrific. Thanks very much. The next question comes from Jeremy McCrea from BMO Capital Markets. Please go ahead. Hi, guys. Thanks. Just I got a couple of questions here too. So first one, did you guys do anything different with those Eagle Ford wells that came on at some of the best rates you've done? I'm just curious if that's some of the rates that we could expect going forward. And then the second part here is some of the efficiencies you noted in your press release. Is any of that built into your guidance and capital costs? And then with some of the results today, particularly in the Duvernay, does it make you look to shift capital around come 2025? Yeah. Hi, Jeremy. It's Eric here. Again, I'm going to maybe take one minute off the top and then pitch it to Lundberg for a little bit more around efficiency changes, particularly in the Eagle Ford. So if we look back, I just want to put some kind of historical context on this. H2 2023, the well performance on the crude oil side was about 700 barrels per day. Now, those tended to be gassier, so the BOEs were way up. But let me just focus on oil for the moment. H2 2023, 700 barrels a day average across 22 wells. Then we advance to the first half of 2024. And in 23 wells, that same crude oil average daily on the IP 30 went up from 700 to 835 barrels per day on average. And then if you compress that to the second half of the first half of the year, that is Q2, the 8 wells we turned in had an average IP 30 crude oil only of 871. So to your point, that just reinforces the on the oil side of this mix, which is where all the value comes from, we've gone consistently higher. And in Q2, 8 wells averaging 88%. And so that all feels pretty strong, continuing to be either in the top quartile or the very top of the second quartile in terms of crude oil performance among a strong cohort of performers in the Eagle Ford. In terms of strength and efficiencies around the Eagle Ford specifically, Chad, why don't you take that, and then I'll come back to the allocation question. Yeah. Well, thanks, Jeremy. I would answer it this way. Similar to Greg's, we're continually trying to inform through our machine learning, through our models, through our results, what we're going to do next. Specifically, when we think about efficiency, I think it's a capital efficiency discussion, not just production, not just capital, but combining the two together. On the capital side, we've seen an 8% reduction in the Eagle Ford. This is from little things throughout the program. And again, we translate the learnings across from the Duvernay. Geosteering, so drilling in a tighter target, stage spacing that I alluded to, and specific to the Pluto Pad, we did improve the stage spacing that we think is helping the overall result, all the way down to how we handle frac valves, how we handle hookups from the frac to the wellhead itself. All that to say is there's a bunch of little things that are really driving up the cost. On the production side, again, I would point to intensity. It all comes back to the overall square or the area that we can effectively stimulate in the rock. And to do that, we know in these unconventionals, it comes back to intensity in the fracture stimulation itself. So that's what we're really keying in on, specific to the Pluto Pad. That's where we were going with it. In terms of efficiencies baked in forward, we try to do our best to think about that in a budget cycle. I think that the only thing I would end with is continuous improvement, and I think there's more to come. We always seem to prove that year-over-year. Okay, Jeremy. I'm going to come back to the allocation question. Here we are in kind of late July. It's a little bit early in the planning cycle for me to even have a really strong, crystal-clear view on allocation. But what we would say is we're always focused on allocating our capital toward the highest returning opportunities. And so we remain encouraged by the quality of our Duvernay asset, and the rate at which our machine learning models are advancing gives us a lot of confidence and encouragement around continued development in our Duvernay play. And of course, that includes the extension, the land extension that we executed on in Q1. You should expect us to continue to grow that both in terms of its total production mix in the total portfolio, along with increasing the rate at which we allocate capital to it, given the advancement in our models. It's too early to kind of guide more specifically than that. Okay. Thanks, Eric. Thanks, Jeremy. The next question comes from Amir Arif from ATB Capital. Please go ahead. Thanks. Good morning, guys. Just had a few quick operational questions for you. Just first, on the Duvernay, are you doing anything different on the second four-well pad, or is this more just to de-risk and delineate the size of what you're sitting on? Yeah. So the second 4-well pad is going to have many of the same features in terms of cluster and stage architecture and length and how we land in terms of the stack, where we land in terms of the lithology and resistivity marks along the way, and how we steer to stay in the highest quality reservoir, and all the same kind of operational tips and tricks of the trade in terms of cementing and casing and drilling. So all of that's done. But because these models are learning constantly and the 4-well pad is a little bit behind in time of the 3-well pad, it will have a few nuanced hydraulics, chemistry, fluid, and architecture changes in it that the model is suggesting. And so again, you don't waste an opportunity, not a moment, not a day, to test new applications and techniques. And so it'll have all the same advances that were built into our drilling, casing, and cementing program because it came at the same time. But in terms of stimulation, it's a little further on, and so the model is a little bit more informed. The model's advanced literally every well that's drilled in the whole play, but very specifically relevancy weighted to our own data. So they advance fast on our own data. Is there anything, Chad, you'd like to add to that in terms of advancements in the four-well pad versus the three-well pad? Just looking at bound versus unbound well spacing. That's another opportunity for us. That's it. Okay. And I appreciate the color. And then just onto the Peavine, the field-level production continues to get better, better than 15,000 that we were thinking about a while ago. Is 20,000 a number to think about as a sustainable rate, or is there potential to even get that a little higher than those levels on a field-level production? Yeah. No, it's a great question, Amir. And I was always trying to be, I think, prudent in my guidance given what you know and don't know about conventional reservoirs over time. As I think I've said before to you and publicly to others, the wells just continued to surprise to the upside as we moved our pads to the south. In late 2023 and into 2024, the pads came on stronger. They stayed stronger for longer. The pads and the team continues to surprise to the upside. And we're facing today a 20,000 barrel a day play here in Q2. I think that it can probably hold this for a little while, but I'm not going to suggest a new normal that's meaningfully above 15. But what I would say is maybe Peavine could exit the year around 17. And that probably means that it heads toward 15 over the longer arc of time. But again, if wells stay in stronger for longer and continue to surprise to the upside, that could be a while out. So I feel bad for having said 12-15 for so long, but I am going to say over the long arc of time, we should continue to be in these kind of mid-teens, and I'll continue to say 15 until we know a whole lot more about the aerial extent. But it feels really, really good, and just the whole thing is performing very well. Yeah. No, that helps. And just on the aerial extent part of it there, Eric, I know you've moved to the south from the core. Any plans to move to the northeast area, or is that more of a 2025, 2026 event? Yeah. Over time, we will, Amir. We will continue to move eastward and to the north and east. But it'll take some time. One of the things we've mentioned is that we remain very conscious of our social license to operate with the Peavine Métis. And it's not unique to sort of legal obligations as much as it is. We like to do what we say we're going to do. But also around capital, it's a very efficient use of capital to keep these developments nice and tight. And so over time, we're going to move eastward and then northeastward. But the tighter we keep it geographically, the more we're able to maintain high capital efficiency on the sort of pipelines and driving rights of way we've built and locations we've built. And that will just increase the efficiency of the investment over time. But we will, over time, move eastward and northeastward. Okay. Makes sense. And then just finally, shifting to the Eagle Ford there, Eric, I know as you move to the Black Oil, it's got lower overall weights with better oil cuts. So the total oil weights aren't significantly different. But I believe it's also shallower. Can you just give us a sense of what the well cost differences are from the volatile oil window as you stepped into the Black Oil window? And then also just second-half plans. Do you plan to stay in the Black Oil window, or will you be moving around as you make which position? Yeah. So one of the reasons we move around is partly to take advantage of gathering system room. So that is to say you build a CDP at some point in time, and then you fill it. But as the wells that justify that central production facility decline off, they leave available capacity. And that available capacity through the CDP and through the gas gathering and oil gathering system is effectively free. And so one way to manage capital efficiency on the facilities part of the business is to move around and what I call knife into that available capacity. And so one of the reasons we move around is, A, to continue to inform our models and keep them very current in terms of stimulation designs and optimizing that. But B, to also ensure that we are making maximum use of the available system space. In terms of capital, it's all very much in line with our expectations. Our AFEs have come in to expectation. Our capital budget is coming into expectation, and everything's running in line. As I mentioned earlier, in terms of our current budget reiteration, it all feels quite good. We're going to continue to move around a bit to ensure that we take maximum advantage of available space. The wells are going to continue to perform well according to the stimulation designs. I would say with confidence, almost no matter where we go, we'll be able to get the best out of the rock using the machine learning models. Okay. Can you just quantify the well cost difference? I think it's 10.5 on average across Eagle Ford. Is it different in the Black Oil window? Is it? Yeah. Yeah. Sorry, Amir. I didn't come back around to that. It tends to get a little bit less in the black oil window because you're dealing with a little bit lower pressure. So one of the reasons why it's less gassy is because it's less thermally mature. And thermal maturation, time and temperature and burial depth and all of those things drive gas production. And so because it's not as deep and it's not as highly pressured or thermally mature, you tend to get a little bit of a break on things like kick tolerance and the depth of casing shoes and those sorts of things. Having said that, you tend to have to drive a more intense stimulation into lower thermal maturation rock. And so the model compensates for all of these things. I'd say generally in line, but maybe a little bit lighter on a kind of a cost per foot basis. Chad, you want to just reinforce that or just? Well, yeah. So the only other significant difference is they are generally cooler reservoir temperatures. So to get deeper in the play and in this gassier portion of it or gas condensate area, we run hotter temperatures. But in some cases, it pushes us to different bottom hole assemblies. Just in terms of quantifying, we're in the $500,000 range to drill these Black Oil wells versus in the south where we're drilling more of the gas. That's the difference between the two. That's right. That's right. Okay. Appreciate the insights. Thanks. Stage concludes the question and answer session from the phone line. I'd like to turn the conference back over to Brian Ector for any questions received online. All right. Thanks, operator. And we have had a number of questions come in. I feel like we've addressed the majority of the operational questions that have come in from the webcast today as we've discussed the efficiencies across the portfolio and our guidance being unchanged. The one common question coming in, Eric, does relate to the share price performance and the reaction to the results today. What is your takeaway or thoughts on the market reaction today? Yeah. Thanks, Brian. Well, look, I'm disappointed anytime the share price trades down. But this is a beat quarter. We came in above consensus estimates on production, above consensus estimates on AFF per share. We continue to take out more shares every day. We've levelized our share repurchase plan so that it now accomplishes dollar cost averaging, which should over time drive the lowest possible volume weighted average price for that use of free cash flow. And what I would say is we can't control the share price. What we control is the business allocation of capital, capital efficiency, cost of capital to a lesser degree, not directly. And the free cash flow that we generate, if the share price goes down, will simply buy back more shares. So eventually, the shares we take out of the system and we cancel, that math will continue to drive better and better intrinsic per share metrics. As I mentioned earlier in my prepared remarks, over the past four quarters, we've increased our production per share by 23% in one year, 23% increase in production per share. That's both higher production on a flash share number of shares, but also we're taking out shares. That will continue. So I like a bargain as much as the next guy. We're going to keep buying back our shares at a discount. Eventually, that's going to be irresistible. But that math really works when you're generating strong and resilient cash flows and free cash flow, Brian. That math works to our advantage. Okay. Thanks, Eric. And this is a question that came in from an investor. It's a statement as much as it is a question. I think it relates to the performance today. And the statement is that the market is inaccurately focused on lower sequential BOE per day rate in the Eagle Ford. Almost lost on the market was the higher oil cuts and lower costs in the Eagle Ford, producing more oil for well in Eagle Ford during the second quarter. Getting oilier sequentially is a positive trend that drives higher cash flow generation. Eric, I know we've talked about the Eagle Ford a lot, but any final comments on getting oilier or the oil rates and the performance in Eagle Ford? No, I think that statement is spot on, Brian. What I would do is I would simply reiterate 8 wells, 88%. And in the Duvernay, the 3 well pad is 90% liquids. And so we're an oil company. Our Q2 results were 85% weighted to liquids, high value liquids. And we will continue to focus on that. And in terms of our free cash flow yield, when the share price goes lower relative to our free cash flow generation, that just means it punches at an ever stronger level in terms of these impacts to per share metrics. So I like the mechanism. I don't like the share price, but we can take advantage of it. And we will continue to buy back shares according to our NCIB and keep that VWAP as low as possible. The other comment coming in on the financial side does relate to the debt repayment and the timing. We addressed it in our prepared remarks. Chad addressed it. Any comments on the importance of continuing to deliver across the board? Well, yeah. No, it's extremely important. And I know folks are frustrated and have pointed to that. Our total debt to EBITDA is 1.1x. And that is a strong position to be in today in terms of the total debt to the cash generative capacity of the business. And that will get better over time. But we thought it was more important within the first half of the year to take advantage of these record-type spreads to prepare a more defensive posture with regard to our long-term debt structure. And so both reducing the coupon and extending the term of our long-term debt made a lot of sense to us. And then that allowed us to push our credit facility out another two years. And so the term debt structure within our business is very strong and very defensive. And you have to do that when you can because you can't control the timing. But these are record-type spreads for high yield energy. And we took advantage of it. And we think it's the right thing to do. And we think when our debt paydown does begin to happen in Q3 and Q4 and continue from there, folks will begin to take advantage of and realize the benefit of all of this. Okay. Thanks, Eric. At a higher level, portfolio-wise, any thoughts on asset sales, dispositions, the overall portfolio, and where you see the business going over the next 2-3 years? Yeah. I can't really comment specifically on asset sales or dispositions. What I would say is every asset in our portfolio is investable. Every asset is being invested in. And that all feels pretty good. But we're always looking at this through each planning cycle and making sure that if there are assets that we're allocating our capital to the highest returning assets possible, running all of our assets within the bands of maximum operational efficiency. And if there are assets we cannot invest in, then those are the assets that move to sale against a retention value expectation. Okay, Eric. And I know we're coming up on our time limits here, but just one last question because it's in the news a fair bit of late. Lots of wildfires again across Alberta and BC. Any impact to our operations so far this year with respect to the wildfires? Yeah. It's absolutely heartbreaking to read about Jasper and anyone who's lost their homes or their businesses. It's absolutely heartbreaking to see and to witness. We've had no impacts and have no wildfires within close proximity to our operation. So we're sort of better off this year than we were last year in terms of proximity of fires. We remain on high alert. We're always looking and watching and reading and lending a hand to our peers and our friends any place that we can. So that's about all I would say, Brian, on that. Terrific. Thanks, Eric. Thanks, everyone. As we reach the end of today's call, I would just like to thank everyone for participating. For those who submitted questions via the webcast, if your question was not addressed, please reach out to our investor inbox and we will be sure to respond. With that, thank you, operator. Thanks to everyone for participating in our second quarter conference call. Have a great day. This brings to a close today's conference call. You may disconnect your line. Thank you for participating and have a pleasant.