Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Second Quarter 2025 Earnings Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Kyle Sahni, Manager of Investor Relations. Please go ahead.

Thank you, operator, and welcome, everyone, to our second quarter 2025 earnings conference call. Yesterday, after the close, we issued a press release, a slide presentation and a quarterly stockholder update, which we will reference on today's call. These documents can be found on our website at murphyoilcorp.com. Joining me on today's call are Eric Hambly, President and CEO; Tom Mireles, EVP and CFO; and Chris Lorino, SVP, Operations. As a reminder, today's call will contain forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, please refer to Murphy's 2024 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of America. Eric will kick off the call with opening remarks, and then we will move to a question-and-answer session. We ask that you limit yourselves to one question and a follow-up. With that, I will now turn the call over to Eric.

Thanks, Kyle, and good morning to everyone joining us on the call. As Kyle mentioned, we released a new quarterly stockholder update last night in conjunction with our earnings release. This new format shares additional insights and leadership perspectives on our business, which we believe provides a deeper understanding of Murphy to our stockholders. I hope that everyone had the opportunity to read it and found it helpful. I would like to start by thanking our employees for their hard work and dedication in delivering the results that we will discuss on today's call. Now turning to second quarter results, I will emphasize 3 key takeaways. First, our second quarter results were underpinned by comprehensive execution across our multi-basin portfolio. We delivered a sequential increase in production to 190,000 barrels of oil equivalents per day, which was above the high end of our guidance on strong new well productivity from our Eagle Ford Shale and Tupper Montney assets. In the Gulf of America, we completed and returned to production the Samurai #3 workover in the second quarter. And early in the third quarter, we completed the Khaleesi # 2 workover. These operational results were delivered with strong capital and operating efficiency. Second quarter CapEx of $251 million and total company lease operating expenses of $11.80 per barrel of oil equivalent were both better than quarterly guidance. Lastly, our 2025 company-operated onshore well program is now complete. We brought online 10 wells in the Eagle Ford Shale and a 4-well pad in Kaybob Duvernay early in the third quarter. My second key takeaway this morning is that we remain on track to deliver our 2025 plan with CapEx at the midpoint of the annual guidance range, and we now see full year production trending at the midpoint of the annual guidance range. With the majority of the Gulf of America workover program behind us, we expect operating expenses in the $10 to $12 per barrel per BOE range during the second half of 2025. At Murphy, we are laser-focused on running the company with a competitive and rightsized cost structure. Since 2019, the company has achieved greater than $700 million of cumulative cash cost savings through a greater than 50% reduction in both our G&A and bond interest expenses. You can expect us to continue to have a relentless focus on managing our cost structure. My third and final key takeaway today is looking ahead to our high-impact exploration and appraisal activity in the second quarter of the year. Our global exploration teams will be exploring and appraising prospects across 3 different continents, testing more than 500 million barrels of oil equivalent to more than 1 billion barrels of oil equivalent in mean to upward gross, unrisked resource potential. These are key catalysts for the company, and we look forward to sharing more results with you in the coming months. And with that, we can open up the line for Q&A.

Your first question comes from Arun Jayaram with JPMorgan.

I was wondering if maybe you could highlight or maybe detail the near-term exploration program. You mentioned that you'll be testing 500 MMBOE of kind of resource potential, but maybe set the stage for the key prospects. We did note that you've contracted a Transocean rig for your West Africa program, we think, and also added some rig time on the Noble rig in the Gulf of America.

Sure. It's a great question. Thanks for the opportunity to talk about our program. As I've highlighted in my letter and in my comments just now, we're very excited about our exploration and appraisal program that we have in front of us. We're testing some significant volumes, and it's really an exciting time at Murphy. I'll kind of work through the calendar as we kind of go through the end of the year. So in the third quarter, likely in September, we will spud our first of 2 wells in the Gulf of America, the Cello #1 well in the Mississippi Canyon area. And we'll follow that by the Banjo well, which will be drilled beginning in the fourth quarter. In Vietnam, we have a very important appraisal well planned at our Hai Su Vang or Golden Sea Lion, this recent discovery. And that well will likely spud in September sometime, and we should have a result at some point in the fourth quarter. And then wrapping up the year, we should spud in the fourth quarter the first of our 3 wells in our r Côte d'Ivoire program in West Africa. The first well that we'll drill will almost definitely be the Civette prospect, which we've highlighted previously, which tests a mean over 400 million barrel potential resource on a gross unrisked basis. Pretty exciting times for us. You mentioned the rig. We did sign the rig contract for that program in Côte d'Ivoire. We're very happy that we were able to attract a very high-performing rig with experience operating in the region and at what we think is a competitive day rate, which, as you know, for deepwater wells, it tends to be a significant portion of the well cost.

Yes. I think you signed it for around $360, which is below where leading-edge rates have been. So that was a good price on that rig. The follow-up, Eric, I wanted to talk about kind of your strategy around the Chinook development well. Obviously, in 1Q, you announced the acquisition of the Pioneer FPSO, which I believe is in close proximity to Chinook. So talk to us about the broader strategy around that, maybe set the stage for that Chinook well because I think you have like an 86% working interest in that well.

Yes, that's exactly right. So we were very happy to acquire the FPSO what we think was a very accretive deal for us. It allowed us to lower our cost structure in the field and made the future development of the field much more economic. And so by itself, it was a good deal, but it really unlocked further development potential. This is a field that we acquired as part of our Petrobras joint venture deal, we call MP GOM, which represents our noncontrolling interest in the Gulf. We did that deal in 2018 and have been since studying opportunities for enhancing the value of the field. And one of the opportunities we identified was to drill another development well in the currently producing main pay in the Chinook field. And we're planning and very likely will include in our 2026 budget to drill a well that we expect to be quite a high rate. It should be on the order of 15,000 barrels a day. And as you've noted, our ownership is quite high. So the impact to us on a net basis will be significant. This is a field that's been producing. There have been 2 wells producing in the field in the past. There's currently one. So we're targeting an optimally placed additional development well to further develop that field, enhance the value. And again, it's very attractive economically, very low breakeven, as you can imagine, based on the rate and the costs. We expect that, that well, assuming that we do include it in our 2026 budget, will probably come online in the second half of 2026 -- our rig schedule.

What's your pre-drill on that Chinook opportunity?

We typically don't describe opportunity set like that for development wells, but I'll give you roughly, I think that it does 2 things for us. The well itself would sort of be what might be sort of a typical Wilcox opportunity. The well would probably produce in the 20 million to 30 million barrels ultimately and that it would also help extend the life of the rest of the field. So that might add another, say, 10 million to 20 million barrels of full life potential for the field. So it does create a lot of value, allows the field life to go out probably till 2040 or so.

Great. Appreciate the stockholder letter really makes our lives easier, really good way to communicate.

Thanks. I'm really glad you appreciate it. I thought it was a nice way to describe our business, which is relatively complex in a fairly simple way. So thanks for your feedback.

Your next question comes from Neil Mehta with Goldman Sachs.

I just want to start on the Gulf of America. It looks like production came in at a little higher than the quarterly guide. And am I right to characterize you guys having worked through some of the operational challenges that we saw earlier this year? Or is there anything left to derisk?

Yes, Neil, thanks for that. I would characterize your observation is accurate. We are -- I'm really happy that the team has worked through what was an unfortunately large backlog of workover activity in the Gulf America. We are almost done. We are working on the Marmalard 3 well and expect to have that online in August. So that's the last of the significant planned workover activity. Production did outperform a little bit in the second quarter, which we need. As you know, our Gulf of America business is quite oily. So oil volumes being supported by strong execution there are quite important to us. I would say that the workover activity should be wrapped up in the third quarter, although we may have sort of proactive workover activity that may be things that we identify to do that are kind of volume adders that haven't been built into our plan in the past. Those are things we are always evaluating, but they're not of the reactive type that we've experienced over, say, the last 18 months and more of things we may consider to do to create additional value.

And then the follow-up is just your perspective on return of capital. You guys are pretty close to your net debt target of around $1 billion. And so as you think about prioritizing debt repurchase -- debt paydown versus further stock repurchases, just talk about the conversation in the boardroom and where you lean on that.

Neil, as I pointed out in my stockholder letter, we are much more likely to prioritize share repurchase than further debt reduction at this time. I would caveat that with, we do have $200 million drawn on our unsecured revolving credit facility at the end of the quarter. I'm not a big fan of having a drawn credit facility. So we may, over the course of the next year or whatever, assess paying that down versus share repurchase. But the lower oil price goes, the lower our share price will likely go since we trade in tandem with oil price and the more likely we are to repurchase our stock instead of do any type of debt reduction.

The next question comes from Phillip Jungwirth with BMO Capital Markets.

You had some really strong results from the Eagle Ford and specifically Karnes County. You still have over 300 locations here, so which is quite large relative to the size of the program. So just wondering how derisked you feel like this inventory is? And with the more intense completions impact that running room at all? Or do you still feel good about that along with the higher -- potentially higher recoveries?

That's a great question. Let me do 2 things there. One is characterize our overall Karnes position and then come back to a more specific pad that we can talk about. As you know, and we featured in past calls, we're always trying to improve the performance of our onshore well program, and we make adjustments to our completion designs to try to accomplish that as well as our flowback strategies. And I was very impressed with our team after not having any Karnes wells in 2024, we delivered a pretty healthy program of Karnes County wells in the second quarter. We saw some exceptional performance. We're seeing 30% higher performance of Eagle Ford on a 2-month cumulative oil basis compared to our past activity. And when we benchmark against industry peers, which is some of the top-performing wells in Karnes County. And as you know, they're quite oily. So really happy that our adjustments to the way that we drill, complete and flow back are showing some strong performance, and the team has done a great job. I would also like to highlight one additional point, and that is one of our 5-well pads had 4 lower Eagle Ford wells and one Upper Eagle Ford well that were infill in the sense that they were all drilled around on top of nearby legacy, quite long-life original Karnes wells. And so why that's important is that of our 90-something remaining Lower Eagle Ford wells that we disclosed in the appendix of our slide deck and we refer to, 59 of those are Lower Eagle Ford infill wells. If you look at external data sources like Enverus, they give us no credit for the remaining inventory of those Lower Eagle Ford infill wells. And the wells that we brought online, the Turner pad were some of the best-performing Karnes wells we've had in our history, and there were 4 of those 5 were Lower Eagle Ford infills, which I think gives us even more confidence that what we thought we would be able to extract from the infill program is something we should have confidence in. And also, I think, something that the market should give us some credit for.

Okay. Great. And then I was hoping you could expand on the Vietnam appraisal well that you're going to spud here in the third quarter. What exactly you're looking to test or see? And at one point, Murphy had spoken about wanting Vietnam to be, I think, a 30,000 to 50,000 barrel a day net business. So I was just wondering if you think you have line of sight here now, including the current development and assuming a successful appraisal.

Yes. Thanks. The Hai Su Vang or Golden Sea Lion discovery that we've made, what we've said before was that, that well was drilled on significant pay in 2 different sands. Most of the pay was in one reservoir. The primary objective of the appraisal well that was spud in September is to test for continuity of reservoir and potentially deeper oil in that main pay reservoir. So the location of the well is designed to test what might be an expanded section of that sand and allow us to test very low on structure to see how much of that structure is oil filled. So that's specifically located around the development and assessment and appraisal of that specific reservoir, which is the main pay and has the most potential to give us confidence in a significantly larger resource than we've already disclosed. So it's a really exciting well for us. The volumes that we've already discovered in the fields that we have in our 2 blocks in Vietnam give us confidence that we should be able to develop a 30,000 to 50,000 net BOE per day business by the 2030s. Obviously, with more volume potentially proven up with appraisal of Hai Su Vang, we might be at the higher end of that range versus the lower end of that range. And that's really the primary objective of the appraisal well that we're drilling here.

Paul Cheng of Scotiabank.

Maybe the first one is for Tom. Tom, can you talk about your U.S. cash tax position going to look like given the new tax and act, the Big, Beautiful Bill?

Paul, I'm glad you referenced Tom because I was going to punt that question to him if you asked me. I appreciate that.

Yes. Thanks, Paul. The OBBBA, I think I got all the Bs in there. Yes, it was a great act that will help our industry for sure. We're not really currently a tax -- a big taxpayer in the U.S. So it will help in future years. It's not really something that we're going to benefit from this current year. But in future years, it could be with all the specific impacts, it could be a $40 million to $50 million shield for us going forward in the outer years.

And Tom, is that from 2026 to 2030 that we can think that the benefit is $40 million, $50 million a year?

Yes, that's probably a good number to think about it. It depends on what our tax position will be in the outer years. A lot of that's been driven by -- if we get a recovery in oil price, we might be a bigger cash payer, depending on how it plays out. But yes, that's potentially -- that kind of frames it for us.

Okay. And second question for Eric. With the well productivity that you've seen in Eagle Ford and you think that you have proof out in the Lower Eagle Ford, the opportunity set or the potential, does that change how you look at the development plan for Eagle Ford? I think up until now that it's always been, okay, we're going to keep Eagle Ford at 30,000, 35,000 barrels per day and then it's sort of like at the back burner until the deepwater production start to decline. And at that point, we will use it to ramp up. Does this new data change that view at all?

Great question, Paul. I would say that it doesn't significantly change the way we want to use the asset in our total company portfolio. I would expect to see us produce Eagle Ford in a 30,000 to 35,000 net BOE per day range in the coming years. We will preferentially invest in our offshore business for 2 reasons. One, the infrastructure that we access with offshore developments has a more defined life. And if we don't act on those investments, they may not be there in the future, whereas Eagle Ford wells will be there in the future. And also, we tend to have really strong returns from our offshore investment opportunities. So we do plan to preferentially invest offshore. Having said that, I think that the results that we're seeing from these recent infill Lower Eagle Ford wells give us confidence that the plan we have developed for the midterm to long term is something we should have even more confidence in the results.

I see. And that for Montney -- the Tupper Montney, I think you're saying that the 5 wells that bring on the average or the 10 wells that bring on the average is 19.2 million cubic feet per day for the 30-day IP. Do you think that, that is more of an exception or that you think with the new design that this is the average that you can expect so correspondingly that the future need to maintain the plant full, you need to spend even less at Montney?

I think we had really nice well performance. I think the completion design that we deployed, which had an enhanced proppant loading was very effective. We've modified our flowback strategy to allow the wells to be as productive as they can be. We were pretty thrilled with 10 wells averaging 19.2 million cubic feet per day. Some of those wells were actually constrained by plant capacity. We actually ran out of capacity and over had -- the wells allowed us to be over deliverability compared to plant capacity. Your question about how durable are those type of results, I feel quite confident that in the next 5 to 7 years, the wells that we will plan to drill to keep our Tupper West plant full have very similar geology to what we just developed and the completion style we deployed should lead to similar results.

Your next question comes from Carlos Escalante with Wolfe Research.

I'd like to actually follow on that same line of thinking on Canada. Considering how poorly AECO has been trading, is there a world or a commodity environment for that matter related to AECO pricing where it would make sense to dial down your Montney annual program in exchange of perhaps more oil leverage?

That's a very good question, Carlos. And it's something that we think about. The capital efficiency of our Montney business is quite high. We're able to bring on wells that at our tight curve have breakevens of gas prices that are significantly below AECO market. We also have a situation where we built -- we developed the plants that we currently flow through and then we sold them and are paying a throughput fee. So it makes sense for us at even extremely low gas prices to utilize the plants that we pay for anyway. And so between the capital efficiency of the new development and the low operating cost structure, we are advantaged to continue to invest in the asset even at extremely low AECO prices, even below what you have been seeing on the screen lately. On top of that, we deploy a fixed price forward selling and a diversification strategy, which has allowed us to realize gas prices that are in excess of AECO quite materially. I think we were something like $0.44 per Mcf above AECO in the second quarter. We'd like to continue to do that type of thing. We have long-term diversification strategies in place to help support the asset. And I think that will help us continue to have more profitability. The other thing I might point out just related to the asset because I think it's important is the LNG Canada facility that is ramping up on the West Coast of Canada is currently having throughput at a relatively low level and should ramp up from, I guess, 200 million or 300 million cubic feet a day to 2 Bcf a day in the coming year. We think that will help AECO quite a bit. And I'll point out that we are physically connected to that plant. And in fact, in the month of July, delivered gas through pipeline from our plants to LNG Canada as part of a commissioning or testing process for that new pipeline segment that allows us to flow there. So we're watching the whole Western Canadian natural gas market and think there may be an opportunity for us to either continue to be supporting the asset with plant level capacity or even in the future, possible expansions out past 2030 if the LNG global demand kind of matches our expectations.

That makes sense. And then back to exploration. So I mean, you've obviously been asked a lot about this specifically on Côte d'Ivoire, but the Eni discovery, which is adjacent to where you intend to drill your appraisal and exploration wells has had some success. So I wonder on the first part of my question, is there any read-through that this may be a similar depositional environment to what you're looking for? And then second part, if you could perhaps frame and benchmark this opportunity relative to what you see in Vietnam, acknowledging that Vietnam is obviously a step ahead, that would be helpful.

Sure. Great question, actually. The Civette prospect that we will drill first on Block CI-502 is testing the same play type as Eni's Murene 1X well Calao discovery. The same exact play type. It is a slightly shallower interval. And we also have a potential in the future to test the potential updip extension of the Calao discovery onto our Block 502. So it should be very similar geologically, has similar type of fluid type and potentially a little oilier, we think, but the same type of risk profile that they would have had. We're quite excited about it. Contrasting the opportunity set we have here in Côte d'Ivoire with Vietnam, there's 2 significant differences. I think that the fiscal terms that we have in Côte d'Ivoire in terms of the PSC contract and also our ownership structure at 90% working interest allows for with success, our Côte d'Ivoire exploration success to be a much more significant outcome for us as a company. We're excited about our Vietnam. We think we'll continue to find more oil in Vietnam. It will be a major contributor to us, as we've highlighted earlier, potentially having a 30,000 to 50,000 barrel a day business for us there. The Côte d'Ivoire with success of one or more of these prospects would be a significant adder to our resources. And the fiscal terms are very strong. So financially, they would be even more significant than the Vietnam business.

Your next question comes from Charles Meade with Johnson Rice.

I want to pick up right where you left off. And as I look at those Côte d'Ivoire prospects, obviously, the upside case is impressive. But also drilling those at 90%, can you give us an idea about -- I know this may be getting ahead. You've got to drill your first well, but I want to get an idea of what would the success case look like? Would you stay at 90% in the development scenario? How many appraisal wells would you need to drill? And what would the success case on one of these big prospects look like?

Great question, Charles. Obviously, we will be thrilled to make a discovery of the scale that we think we have to test here in the mean upward range. success case there, these are deepwater developments, and those obviously have a range of outcomes in terms of development costs. It would put significant pressure on us in terms of development CapEx. Near-term appraisal capital spending would be fairly modest, something that we would definitely be able to handle within our current ownership structure. If we were to make one large discovery here, it would be something we would easily be able to fund within the kind of range of annual CapEx that we've been talking about. We may make adjustments to the rest of our capital program to make room for a little bit of additional spending here. But it wouldn't overly stress us. More than one would be a significant draw on additional capital to develop. So again, near-term appraisal CapEx would not be something that's beyond what we kind of expect to do with our overall global exploration and appraisal program. Development CapEx would potentially be material. If you think about a range of deepwater development cost structures, you're probably $10 to $15 a barrel development cost. And obviously, if you find 1 billion barrels, that leads to a lot of CapEx. So we would consider with tremendous success, one of the things we would evaluate would be a farm down of some of our ownership to help fund development, but it's not something that we're predetermining we would do. It just depend on what kind of scale of results and the timing we wanted to move those forward. A couple of points I'll make. We are the operator of the blocks, which allows us significant flexibility in the pace of both appraisal and development. You contrast that with some other companies of our scale that were nonoperated in large developments that had less control over a CapEx program. I think it gives us some advantages in terms of being able to execute what we want. Your other question about how many appraisal wells would be needed? It really -- it's not an answer you probably want to hear, but it really depends on what we find. We don't know exactly how many wells would be needed. But I would say it's likely if you discovered a field that had the potential to be of this size, each of the discoveries would probably require at least 2 more appraisal wells, and that's only just ballparking it. That's not based on any overwhelmingly modeled science. It's just -- that's the kind of thing that makes sense based on historical type of performance. We see exploration well costs here in the $40 million to $60 million a piece, depending on well depth and water depth. So they're not too expensive and they allow us to test significantly large resource.

Yes. No, it's really great. And Eric, that's exactly the kind of answer I was looking for. I mean, I was trying to tie it back to you. You have to appraise in Vietnam and anything you find here, you're going to have to appraise. But that's a helpful elaboration on your thinking, and that's it for me.

[Operator Instructions] Your next question comes from Leo Mariani with ROTH Capital.

I was hoping you guys could talk a little about offshore Canada. I know you guys had an issue there with a barge, I think, in the first quarter. But looking at your volumes, it looks like they've kind of continued to run kind of low here of late. Just kind of wanted to get a sense of what's happened there? I think you guys were hoping to get some maybe higher run time and utilization on Terra Nova, but just looking at your guide, it sounds like maybe that's not happening in the near term.

Yes, Leo, thanks for that. I'll give a high-level comment and I may pitch it to Chris to give you additional context. The first one is the first quarter issue around the shuttle tanker was resolved in the first quarter. That's not an ongoing issue, not something to be concerned about. In general, we have been somewhat disappointed with the run time of the Terra Nova facility, but we had lower-than-expected uptime at both Hibernia and Terra Nova in the second quarter. As you look toward the second half of this year, we have less optimism around uptime in Terra Nova than we've had in the past, and that's affecting our third quarter guide for Canadian production, which unfortunately is 100% oil and therefore, impactful to our third quarter oil volumes. Chris, I don't know if you have any additional color.

Yes. Just to add to that, we've been -- they did have some planned downtime that did go over a little bit. So that's part of the reason as well. So it's been a little bumpy and like it's been in the past. But the wells have been strong when they're producing. So it's just a matter of kind of getting the mechanical side of the facility kind of smoothed out.

When they're up, they're performing very well. And when they're down, they're 0 or near 0. So it's disappointing.

All right. Okay. That's helpful. And I wanted to touch base on LOE. Obviously, you guys are planning to get the bulk of the near-term workovers behind you here and guiding to kind of this $10 to $12 per barrel LOE as we get into the second half. I wanted to kind of just touch base on how you're kind of seeing the sustainability of that? The LOE had been kind of a decent amount above that level. I guess it came in, in that range in the second quarter. But do you think is 10 to 12 the right run rate going forward? Or do you think there's going to be periods where maybe it's going to go sort of above that and maybe some of the workovers creep back in at some point?

Leo, I think $10 to $12 per barrel range for our company is a pretty good number for us. If you look at our second quarter of this year, if you normalize out the offshore workovers, our LOE would have been $9.07 a BOE. So if you get to a very low workover trend, which is what we expect on a typical year, you have a little bit of room for some workover activity. You could still be in the $10 to $12 per barrel range. Obviously, our production profile isn't perfectly flat from quarter-to-quarter. It's possible that in the first quarter of next year, you could see LOE trend just a little bit higher than that. But I still feel like notionally a $10 to $12 per barrel range is a pretty good number for us on a go-forward basis.

And I would just like to add that if you look at Eagle Ford specifically because that's where we got a lot of changes. We went from $13 a BOE down to just over $8. So we had very little fixed cost for these Karnes wells and just adding that volume made a significant difference from quarter-to-quarter.

Got it. Okay. It sounds like you feel like there's a structural change there in Eagle Ford.

Yes, absolutely. The Eagle Ford team did a tremendous job of cutting costs and which I featured in my stockholder letter. I think it's a really exceptional outcome for us and a durable outcome in terms of the reduced cost structure for Eagle Ford, which is quite helpful.

Your next question comes from Geoff Jay with Daniel Energy Partners.

I was just sort of wondering if, a, you could maybe give us a little more color on what changed in your completions in Karnes? And also if there's -- if the completion change by itself sort of explains this outperformance or if there are other factors that may have contributed?

Great. What we do in our completion design, we adjust quite a few things, our stage spacing, our perforation design, how we pump the job, how we ramp up the sand proppant loading, how we do fluid loading. We make adjustments to all of those things as we kind of fine-tune the completion design for each area of our operations. In the case of the Turner pad, which I mentioned was an infill pad, we actually dialed down the fluid loading and proppant loading compared to our typical design, which seem to lead to a better outcome, and that will be something that we'll continue to fine-tune going forward. In parallel with how we pump to completion, we're also optimizing our flowback strategy and using some tools to help guide in the early life choke bump progression of those wells to maximize both near-term rate and ultimate recovery.

There are no further questions from our phone lines. I would now like to jump the call back over to Eric Hambly for any closing remarks.

Thank you for your interest in Murphy Oil Corporation. I'd like to close by again recognizing our employees for their commitment to providing energy that empowers people. So thank you, and that concludes our call. Have a great day.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.