Good morning. We would like to welcome everyone to the Canadian Natural Resources 2025 Second Quarter Earnings Conference Call and Webcast. After the presentation, we will conduct a question and answer session. Instructions will be given at that time. Please note this call is being recorded today, August 7, 2025, at 9:00 A.M. Mountain Time. I would now like to turn the meeting over to your host for today's call, Lance Casson, Manager of Investor Relations. Good morning, everyone, and thank you for joining Canadian Natural Resources' 2025 Second Quarter Earnings Conference Call. As always, I'd like to remind you of our forward-looking statements, and it should be noted that in our reporting disclosures, everything is in Canadian dollars unless otherwise stated, and we report our reserves and production before royalties. I would suggest you review our advisory section in our financial statements that includes comments on non-GAAP disclosures. Speaking on today's call will be Scott Stauth, our President, and Victor Darel, our Chief Financial Officer. Additionally, in the room with us this morning is Lance Casson, Manager of Investor Relations at Canadian Natural Resources. Scott will start off by providing details on how strong operational performance, the completion of turnarounds, and our recent accretive acquisition set Canadian Natural Resources up for a strong second half of the year. Victor will then summarize our financial results, liquidity, and our significant return to shareholders year to date. To close, Scott will summarize prior to opening up the line for questions. With that, over to you, Scott. Thank you, Lance, and good morning, everyone. Our relentless focus on continuous improvement, combined with effective and efficient operations, drove strong performance year to date in 2025. Our ability to effectively allocate capital across our strong asset base provides us with a competitive advantage. This ability, combined with accretive acquisitions, creates significant long-term value for our shareholders. Our culture of accountability and the strength of our assets is a unique advantage that results in both capital and operating cost savings and maximizes value for our shareholders. We successfully completed a planned turnaround at AOSP in the second quarter of 2025, five days ahead of schedule and on budget. Production and operator utilization at Horizon and AOSP before and after the turnaround was high, driven by strong performance from our reliability enhancement and debottlenecking projects. In July 2025, oil sands mining and upgrading production averaged approximately 602,000 bbl per day, with upgrader utilization of 106%, and we expect the second half of 2025 to continue to deliver strong operating results. In the second quarter of 2025, despite the planned turnaround at AOSP, which reduced production levels in the quarter by approximately 120,000 bbl per day, we achieved quarterly production volumes totaling approximately 1.420 million BOEs per day, including liquids production of 1.019 million bbl per day and natural gas production of 2.4 Bcf per day. Total corporate production on a BOE basis in the second quarter of 2025 was up approximately 135,000 BOEs per day from the second quarter of 2024, reflecting opportunistic acquisitions and organic growth across our asset base achieved in the last 12 months. On the acquisition front, we closed the Palliser block on June 26. Originally, we budgeted to close this acquisition on March 1, 2025, which would have added production of approximately 50,000 BOEs per day, including 20,000 bbl per day of Mannville light crude oil and NGLs in the second quarter of 2025. This acquisition and production were included in our original 2025 capital budget and production guidance, but due to the delayed closing in late June, it added only 2,000 bbl per day to our production levels for the second quarter. This acquisition also included approximately 1.1 million net acres of high-quality land, with currently identified significant light crude oil inventory of approximately 850 locations. Subsequent quarter end on July 2, we closed an acquisition of liquid-rich Montney assets located in the Grande Prairie area for approximately $750 million, with production from the acquisition of approximately 32,000 BOEs per day, including 12,500 bbl per day of NGLs. Our original 2025 capital budget and production guidance did not include this acquisition. These assets are directly adjacent to our existing Montney assets, providing opportunities for synergies while adding approximately 120,000 net acres of high-quality land, with currently identified significant liquid-rich inventory of approximately 150 locations. To summarize, our combined recently closed accretive acquisitions have added approximately 82,000 BOEs per day of production, which includes approximately 32,500 bbl per day of liquids and a total inventory of roughly 1,000 light oil and liquid-rich drilling locations. Further related to these acquisitions, our full-year capital budget will essentially remain unchanged from guidance provided in the first quarter, excluding the purchase price of the Grande Prairie acquisition, which closed on July 2. All maintenance capital related to the Grande Prairie asset and other acquisitions we've noted will be covered by our 2025 budget. In Q1, Canadian Natural was one of the first in the industry to reduce 2025 capital spending due to efficiencies, and we are now executing development on the Grande Prairie asset while maintaining our capital guidance we provided in the first quarter for the year. We are also targeting to close the AOSP swap in the third quarter, and we plan to update our annual 2025 corporate production guidance after that swap closes. I will now run through the second quarter operational results. On the conventional side of the business, primary heavy oil production averaged approximately 87,300 bbl per day in the second quarter, an increase of 10% over the second quarter of 2024, reflecting strong drilling results from our multilateral well program. We continue to achieve strong results from our drilling programs across our conventional E&P assets as we are realizing capital efficiencies resulting in high levels of activity without increasing capital. This includes our multilateral heavy oil program where we are targeting to drill 26 more wells in 2025 than originally budgeted. Importantly, the low operating costs on these multilateral wells drive strong results on capital, adding significant value. Heavy oil operating costs averaged $17.44 per barrel in the second quarter of 2025, comparable with the second quarter of 2024. Pelican Lake production averaged approximately 43,100 bbl per day in the second quarter, a decrease of 4% from the second quarter of 2024, reflecting low natural field declines from this long-life, low-decline asset. Operating costs at Pelican Lake averaged $9.01 per barrel in the quarter, comparable to the second quarter of last year. North American light crude oil and NGL production averaged approximately 140,700 bbl per day in the second quarter, which is up 31% from the second quarter of 2024, primarily driven by production from our Duvernay assets in addition to strong drilling results in our liquid-rich natural gas assets. Operating costs on our light oil and NGL operations averaged $10.94 per barrel, a decrease of 24% compared to the second quarter of 2024 level of $13.75 per barrel, reflecting higher production volumes. On our Duvernay assets, we are continuing to achieve strong production results and further cost reductions on these assets in the short time that we've owned them. Through our culture of continuous improvement, we remain confident we will continue to realize more value for shareholders than what was originally planned for at the time of the acquisition. Our team's efforts have resulted in strong operating costs during the first six months of operating these assets, averaging $8.43 per barrel in the second quarter of 2025, a decrease of more than 11% compared to the first quarter of 2025 when operating costs were $9.52 per BOE. This results in annual operating cost savings of approximately $60 million as compared to our original target of $40 million. Our extended well lengths in the Duvernay, which are on average 20% longer than our 2024 well lengths, and optimized completion designs combined with strong execution continue to lower development costs. On a length-normalized basis, combined drilling and completion costs for 2025 are now targeting an improvement of approximately 16% or $2 million per well lower than compared to 2024 costs. That's a further improvement of $200,000 per well compared to the first quarter of 2025. We remain on track to achieve 2025 budget production of approximately 60,000 bbl per day in the Duvernay, BOEs per day in the Duvernay. North American natural gas production for the second quarter averaged approximately 2.4 BCF per day, an increase of 14% over the second quarter of 2024. Operating costs on our North American natural gas averaged $1.07 per MCF, which is 10% lower compared to the second quarter of 2024, of $1.19 per MCF, primarily the result of higher production volumes. In our thermal in-situ operations, we achieved strong thermal production in the second quarter, averaging approximately 274,800 bbl per day. This is up 3% from the second quarter of 2024, resulting from our capital-efficient thermal pad development program. Second quarter thermal in-situ operating costs averaged $11.05 per barrel, which is comparable to the second quarter of 2024. At Primrose, we target to drill a CSS pad in the third quarter of this year, with production targeted to come on in 2026. At Jackfish, during the month of July, we brought on production of recently drilled SAGD pad. At Kirby, we are targeting to bring the recently drilled five well pair SAGD pad on production in the fourth quarter of 2025. At Pike, we completed drilling two SAGD pads, which will be tied into the existing Jackfish facilities and targets to keep the Jackfish plants at full capacity. The first of these two pads is targeted to come on in production in the first quarter of 2026, and the second pad will be on production in the second quarter. At our commercial scale solvent SAGD pad in Kirby North, we began solvent injection in June of 2024. In the second quarter of 2025, we executed workovers on two well pairs to enhance SORs. Solvent recovery and production trends will continue to be monitored over the coming months. In our oil sands mining and upgrading, during the second quarter of 2025, our world-class oil sands mining and upgrading production averaged approximately 463,800 bbl per day of SCO, an increase of 13% from the second quarter of 2024. The increase is a result of the reliability enhancement project, eliminating the need for a turnaround at Horizon in 2025, and the Scotford upgrader debottleneck, which were both completed in 2024, combined with the additional 20% working interest in AOSP acquired in December of 2024. Oil sands mining and upgrading costs averaged $26.53 per barrel of SCO in the second quarter of 2025, an increase of 2% from the second quarter of 2024, reflecting the AOSP turnaround in the second quarter of 2025. Our growing world-class asset base is strategically balanced across commodity types so that we can be flexible and capture opportunities throughout the commodity price cycle, maximizing value for our shareholders. A substantial portion of our unique and diverse asset base consists of long-life low-decline assets, which have significant low-risk, high-value reserves that require lower maintenance capital than most other reserves, making Canadian Natural a truly robust and resilient energy company. I will now turn it over to Victor for our second quarter financial review. Thanks, Scott, and good morning, everyone. In the second quarter of 2025, we delivered excellent financial results on the strong operational performance that Scott just discussed, and this is highlighted by adjusted funds flow in the quarter of approximately $3.3 billion and adjusted net earnings of $1.5 billion. These results also reflect the turnaround activities at AOSP that were completed in the quarter. Results in Q2 clearly reflect our disciplined approach to capital allocation and where Canadian Natural focused and executed on our four pillars, where balance sheet strength and returns to shareholders went hand in hand with resource value growth and opportunistic acquisitions. Returns to shareholders in the quarter were $1.6 billion, including $1.2 billion of dividends and an additional $400 million of share repurchases. These returns, including dividend payments and buybacks, up to and including August 6th, bring shareholder returns for the year to date to $4.6 billion. Additionally, subsequent to quarter end, the Board has approved a quarterly dividend of $0.5875 per common share, payable on October 3rd, 2025, to shareholders of record at the close of business on September 19th, 2025. Net debt levels were below $17 billion at quarter end, while having completed the acquisitions that were included in our 2025 budget. Our balance sheet remains strong, where debt to EBITDA was at 0.9 x and debt to book capital came in at 29.1%. Liquidity of over $4.8 billion was also strong and reflects undrawn revolving bank facilities and cash on hand. The accretive acquisitions that were completed in late 2024 and year to date in 2025 immediately contribute to incremental production and additional free cash flow generation. Taken together with the strong operational results in 2025, Canadian Natural targets to provide similar shareholder returns in 2025 as compared to 2024. This is targeted to be achieved despite only allocating 60% of free cash flow in 2025 to shareholder returns as compared to allocating 100% in 2024. Our industry-leading cost structure, predictable long-life low-decline assets and reserve base, combined with a consistent commitment to continuous improvement and ability to execute on opportunistic acquisitions in our core areas, continues to drive significant value at Canadian Natural. We maintain our disciplined approach that contributes to our top-tier U.S. dollar WTI breakeven that remains in the low to mid-$40 WTI per barrel range, which we define as the WTI price required to generate the adjusted funds flow to cover both maintenance capital and dividends. Returns to shareholders remain a top priority for our focused and dedicated teams, where our culture and drive to do things right every day continue to enable material free cash flow generation and returns on capital. Those are my comments, and I'll turn it back to you, Scott. Thanks, Mark. In summary, our relentless focus on continuous improvement, combined with effective and efficient operations, drove strong performance year to date in 2025. Our ability to effectively allocate capital across our strong asset base provides us with a competitive advantage. This ability, combined with our accretive acquisitions, creates significant long-term value for our shareholders. Our culture of accountability and the strength of our assets is a unique advantage that results in both capital and operating cost savings and maximizes value for our shareholders. I will turn it over for questions. Thank you. Ladies and gentlemen, we'll now begin the question -and -answer session. Should you have a question, please press the star followed by the number one on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number two. If you are using a speakerphone, please lift a handset before pressing any keys. One moment, please, for your first question. Your first question is from Patrick O'Rourke from ATB Capital Markets. Please go ahead. Hi guys, good morning and thank you for taking my question. First question here is just with respect to liquidity management. As we look out, 2027 is a bit of a heavier maturity year between the term loan and one of your larger nominal debt notes that's outstanding here. Just thinking about the interplay of tight credit spreads and a sticky end of the long curve, how are you approaching this maturity as we head into 2026? Yeah, thanks Patrick, it's Victor here. Good question. I appreciate where you're coming at it from. You know, when we look at our balance sheet now coming out of 2025 and forecast end of 2026, cash flow generation in the period looks strong. I think our refinancing needs will probably be a little bit lower than what you might be anticipating. That said, we'll look to 2026 here and, to your point, look at our refinancing requirements and try to pick an opportune time to do so as we see fit. Okay, thanks. The second question is sort of more on the operational side. Obviously, you know, it's probably a smaller asset within the portfolio, but conventional multilateral drilling success here added 26 wells to the program. A lot of, you know, smaller peers that are out there are talking about secondary recovery, water flood. We hear a lot on the primary side from Canadian Natural. Can you maybe talk to potential opportunities set for secondary recovery and water flood in your portfolio there? Yeah, thanks Patrick, it's Scott here. We do look at those opportunities as well, some of the ones you're mentioning, both on the Palliser and the water flood side. We are commencing testing of a Palliser flood currently in the Clearwater, and we'll look to see how those results work out down the road here, but it looks very promising. We also looked at our Smith water flood and have that implemented as well in that area. That's the first area that we were in in the Clearwater as well, Patrick. Yes, we are undertaking those activities, along with the multilateral. Okay, thank you very much. Your next question is from Dennis Fong from CIBC. Please go ahead. Hi, good morning, and thanks for taking my question. My first one is, obviously the company has completed a few number of acquisitions over the course of the last several months. Can you talk towards your view of the A&D or M&A environment right now? Obviously, completing some of these acquisitions, do you mind touching also as well on kind of your comfort level around the policy environment, how comfortable you feel about adding these assets to your portfolio, as well as the opportunity to improve operations, bolster inventory, and any other opportunity sets from the acquired assets? Thanks, Dennis. I'd like to speak to the acquisitions that we just recently completed here in June and July. We've already talked significantly about the AOSP and the Dubinet acquisition, so we know a lot about that already. Recently with the two acquisitions, they've come at, very accretive for us. They add cash flow for us immediately. I think that's really important when you look at returns to shareholders. These assets do bring significant cash flow for us. That's really how we look at it in terms of on the M&A side. We're not buying something just to drill. We're buying something that adds cash flow, that adds inventory for development programs, and ultimately adds additional value for our shareholders. It's a balance between the organic growth opportunities and the accretive acquisition opportunities, Dennis. Great, thanks for that, Scott. My second question moves toward the oil sands mining and upgrading business unit. I guess on the Albion tour, you guys showcased your ability to be quite nimble in terms of opportunities to develop other areas of the mine and optimize mine progression, specifically referring to the SharkBite asset. I was curious as to how you think about Horizon, obviously, as you've layered on incremental land adjacent to existing producing projects, and how you're thinking about mine progression over the next few years, especially as you added again incremental land or developable opportunities in and around your existing operations. Sure. In terms of Horizon, Dennis, I think if you look at where we're at now for the next, call it, seven to eight years, we'll be progressing our way through the southern portion of the Horizon mine, which was acquired from Total several years back. Following that, we'll be moving up to the North Pit, the North Pit Extension area, and that's where we'll be moving in the next phase of development there to maintain the upgraded production levels to currently what they're at. In reference to your comments about the additional assets, whether that's Pierre River or the North Pit, Pit 6, those assets are not booked in terms of reserves. They're a resource for us, but they have significant bitumen in place, and they potentially would be assets that could be developed sometime down the road that would support significant oil sands mining development opportunities. Thanks, Scott. I'll turn it back. Your next question is from Greg Pardy from RBC Capital Markets. Please go ahead. Yeah, thanks. Scott, has there been a pronounced shift in your mind in terms of how Canada's Competition Bureau either assesses or processes acquisitions? I mean, obviously, you know, when you're spending, you know, 10% of your press release indicating that you've got these deferrals on deals and you guys do deals all the time, this feels like something's different that might not have been there a year or two ago. Yeah, thanks, Greg. No, I don't believe there's a significant difference there. Greg, the particular one that we have in the Palliser block was unique to a certain extent, just in terms of the amount of the facilities in the area, various different competitors in the area. I would call it a unique circumstance. I do agree with you. It took a longer process than it should have, longer than we would have anticipated. In the end, we were able to close the deal and move along. If we look forward, I don't anticipate we will see the same type of situation going forward. Okay, terrific. I'll shift gears maybe, you know, Victor and Scott, but I mean, obviously, the limited buybacks in Q2 obviously stand out as you're deleveraging. So, Mark, I just want to make sure I've kind of got the number, the targeted net debt number, is around $17 billion, I guess, or so year-end. Does that then put you in pretty good stead to achieve that $15 billion net debt target in, you know, like next year under futures? Would you expect getting there next year under futures? We're still right where we were on the last call. When we look at the back half of last year, we're looking at coming out of 2026 at that $15 billion target based on the current forecast, Greg. I think the rate of buyback, to your point, still remains fairly strong. We look at that on an annualized basis. The rate of buyback here in Q2 is very similar to what we saw in Q1. At current forecasts, we'd expect a strong rate of buyback here over the last half of the year as well. No real change in the policy there. Okay, no change in the policy, but I'm splitting hairs, but getting to $15 billion before December 31 is not unrealistic. Is that fair? That's fair, yeah. Okay, thanks very much. Yeah, we're looking at that in that $65 - $70 WTI range. Obviously, it depends on pricing you're saying coming into 2026. Okay, understood. Yeah, thanks for the question. Your next question is from Manav Gupta from UBS Financial. Please go ahead. Good morning. I have two questions. I'll ask them upfront. First, I wanted to see if you could help us understand the benefits of closing the AOSP deal, which shows how much volume comes in. Would that change the way you look at the mine also? Could you increase your bitumen output because you don't have to match the upgrader? The second question is, can I get your outlook on the AECO pricing going forward, especially with LNG Canada also starting up? Thank you. Yeah, thanks for the question. I'll answer the second part first. With LNG Canada coming online, you know, I think if you look at the forward strip, the pricing still does look soft in terms of AECO. I think the market's probably anticipating a certain amount of gas that will easily be able to be turned on. Our view, though, is that once the second train is brought online, there will definitely be a period of time that it'll take to fill up the full 2 BCF of capacity of LNG Canada. I would think that we're going to see ebbs and flows in terms of AECO pricing and its relativity to what the basin is able to produce for a total egress capacity. I think that'll ebb and flow over the next five-plus years. Sorry, could you repeat the first question for me? How does the AOSP transaction change the outlook, and is there a way you would change the mine also just because probably you can produce more bitumen? I'm just speculating because you don't have to match the upgrader, but if you could talk about how that transaction changes your ability to operate the AOSP mine once you do become the 100% owner. Right. Just to clarify for you, the swap involves Canadian Natural Resources acquiring 3,000 bbl a day of bitumen production. That's important to us. We see 100% ownership of the mine as important to us just from a synergies with Horizon perspective. We will no longer have a JV in terms of the mines. It's easier for us to be able to move our equipment back and forth, whether that's heavy haul trucks, cranes, people, and other types of assets that we can move back and forth to optimize. Warehousing is another one that we look at where we will no longer have to maintain two separate warehouses where you would have one at 90% and the other one at 100% working interest. Those are all items that are small in nature, but they do add up. We see some important synergies coming through that. In terms of going forward for production opportunities, I think we'll talk more about that probably later this fall. We'll have some more in-depth discussions that we can, and form of what our views are on the long term. Of course, all that's going to be relative to where we see pricing WTI and bitumen pricing over the long term. I can tell you that there are significant opportunities both at Horizon and AOSP to increase production. Thank you. Next question. Thank you. you. Our next question is from Neil Mehta from Goldman Sachs. Please go ahead. Yeah, thank you. I want to stay on the marketing theme here and just talk about the WCS heavy differential. Obviously, year-over-year, we tightened up nicely. We've seen it widen out here. Just your perspective on whether this tightening that we've seen more recently is structural post-TMX, and given the tightness of heavy on the Gulf Coast, or as OPEC brings barrels back online and Canadian production does seem like it is growing, that we're going to move back to, let's call it the $13 run rate you were at for the balance, you know, most of last year into early this year. Yeah, good question, Neil. I think the way to look at it is we would anticipate the WCS differential to vary in the range of $10 - $13. There's going to be times when it could be more than that or wider than $13. There's going to be times when it will be lower than $10. Yes, that will vary depending on OPEC's production potentially. It also has impacts just within North America in terms of the refinery turnaround timing. Those situations are going to impact it. The structural change happened when TMX came online in May of 2024. We anticipate the differentials will be in a pretty solid range bound at $10 - $13. Okay, that's really helpful. The same question on the SEO premium. We obviously had a lot of maintenance in the second quarter as it related to the upgrades. It had been kind of bouncing at a discount of a couple bucks up until this point. SEO also is influenced by the strength of distillate, which rates at a decent premium to MOGAS right now. How are you guys thinking about pricing relative to WTI? Again, the same type of scenario, probably, you look at a range bound of, you know, a - $1.50 to, you know, + $1.50. It'd be somewhere in that range, Neil. Of course, you mentioned on the distillate side as well. You'll have times of the year where we saw a strong, strong Q2, as you mentioned, related to maintenance. I expect the assets and flows to move on a go-forward basis, just like they have done in the past, relative to turnaround activities. If you look back over time, that differential has, you know, it has varied from, you know, - $2.00 to + $3.00. I don't think you'll see any structural shifts going forward here. That's really helpful. Thanks, guys. Your next question is from Menno Hulshof from TD Securities. Please go ahead. Thanks, and good morning, everyone. I'll start with a question on synthetic. You talked about 600,000 to 2,000 bbl a day for the month of July, with little to no turnaround activity tied to synthetic crude oil production in the second half. What could get in the way of your being able to maintain 600,000 bbl a day, or even a bit higher through the end of the year? Yeah, good question, Menno. I think, you know, we should be looking within that range. There isn't anything necessarily stopping us. We have the turnarounds that have been worked through at AOSP, and Horizon has, all things look really good at Horizon as well in terms of the upgraders' performance. You would have noted we had a very strong Q1, where everything went very well for us, really solid road conditions through the wintertime. You don't quite see those solid haul road conditions in the summer and fall that you do in the wintertime. In that range, in that 600 range, I think is probably a good run rate to consider now. Okay, thanks for that, Scott. Flipping over to turnarounds, you had the five-day acceleration at the AOSP in the quarter. That seems to be a trend. We've seen similar updates from some of your peers, including Canadian Natural Resources yesterday. My question is, what is driving better than expected turnaround execution for yourselves? On a related note, how much contingency is typically built into the timeline for a given turnaround? Yeah, really good question. You know, for us, I would say that the opportunities, especially that happened here with being five days early, AOSP, it's really just a matter of, you know, if you look at all the manpower required on site, we're driving for efficiencies, lots of labor required, taking units apart, doing inspections, doing cleaning of vessels, and so on and so forth. The teams that are driving those turnaround activities have that same continuous improvement culture that we do have with the rest of our operations in the company. They're expected, and they do look at ways of trying to find efficiencies in the middle. There isn't a lot of built-in contingency, probably in the 10% range of estimates when they're building their turnaround schedules. They're enticed, and we certainly encourage the teams to continue their opportunities that they look at to create those efficiencies and find ways to have the manpower on site be more effective and more efficient. Thanks again. I'll turn it back. Your next question is from Doug Leggate from Wolfe Research. Please go ahead. Hi, how's it going? It's Mackenzie Trust for Doug Ledick. Thanks for taking my call. I just wanted to get some insight and get your view on where do you see capacity to grow the dividend, especially in light of some of the acquisitions that were described in the press release and on a go-forward basis. Yeah, thanks for the question. Obviously, we've had a long history of growing the dividend every year now for 25 years. There's definitely some good incremental cash flow coming off the acquisitions. I wouldn't want to step into the Board's shoes there, but I would just say that as we go forward, I'd anticipate that there'd be some room for dividend growth here, into 2026 should the Board continue to pursue the track record that we have seen in the past. Nick, I would just add to that. If you look at the history of the company over the past 25 years, the opportunities for the Board to consider adding and increasing the dividend payout has come on the backs of both organic and opportunistic acquisition opportunities that the company's taken on over the past 35 years. I think that's really important to remember. The future doesn't always represent the past, Nick, but for a company with the strength of the assets that we have, it is extremely important to the Board and to the management team to maintain the dividend, the value of the dividend that has been brought to the shareholders. It's very important to us. We're going to make sure that we continue to operate our assets and grow organically and find opportunity acquisitions when we can to help support continued growth of that dividend. Thank you. For my follow-up, my follow-up kind of ties into that. Where do you kind of see your post-dividend breakeven right now for your metrics? Is there a threshold that you're comfortable, what's the, I guess, what's the threshold that you're comfortable kind of taking it from its previous, from its previous, I guess, dollar amount? You're asking what a breakeven is, Nick? What is the post-dividend breakeven currently? Is there a range that you're looking to stay within as you seem comfortable with maintaining your balance sheet? Yeah, currently, we're in that $40- $45 WTI breakeven range. The incremental cash flow from the acquisitions is keeping us there. We do that calculation post-dividend. The dividend is something that we consider very valuable to shareholders and shareholder returns, so we calculate it after the dividend. Is there a threshold in that sense that the targeted threshold you're looking to stay within the $40 - $45 range, essentially? We're comfortable in that range now. Essentially, the answer is yes, and obviously, we take a view to commodity prices going forward as the Board assesses that in future periods. Okay, thank you for taking my questions. Thank you. Ladies and gentlemen, as a reminder, should you have any questions, please press the star key followed by the number one. We will pause a moment for further questions. There are no further questions at this time. Please proceed with closing remarks. Thank you, operator. Thank you, everyone, for joining our call this morning. If you have any questions, please give us a call. Have a great day. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.