Good morning. My name is Erica, and I will be your conference operator today. Welcome to Murphy Oil Corporation Third Quarter 2026 Earnings Call. All lines have been placed on mute to prevent any background noise. After the presentation, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star one followed on your telephone keypad. If you would like to withdraw your question, press star one again. Thank you. I will now turn the call over to Atif Riaz, Vice President of Investor Relations and Treasurer. Thank you, Erica. Good morning, and welcome to our Third Quarter 2026 Earnings Conference Call. Joining me today are Eric Hambly, President and CEO, Tom Mireles, Executive Vice President and CFO, and Chris Lorino, Senior Vice President of Operations. Yesterday, after market close, we issued our third quarter earnings release, a slide presentation, and a stockholder update. These documents can be found on Murphy's website, and we will reference them today throughout our call. As a reminder, today's call contains forward-looking statements as defined under U.S. securities laws. 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 our most recent annual report filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements except as required by law. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interest in the Gulf of America. I will now turn the call over to Eric for opening remarks. Good morning, everyone, and thank you for joining us. When we spoke in August, I mentioned that years of technical work were starting to translate into multiple pathways for growth. This quarter, several of those opportunities materialized across our portfolio. Over the past three months, we advanced the appraisal program at Bubale, made a new discovery in Vietnam, delivered first oil at Lạc Da Vang, brought Chinook 8 online, and beat the top end of our production guidance. Our letter and earnings release cover these results in detail. What I want to focus on this morning is how these results and the strategy behind them are creating lasting value for our shareholders. Starting in the Gulf of America, we acquired the Pioneer FPSO in 2025 with opportunities like Chinook 8 in mind. On September 22nd, Chinook 8 came online through the Pioneer facility, adding oil-weighted production without the cost or lead time of new infrastructure. Because we own the FPSO, those incremental barrels now benefit from stronger economics and higher returns. Five days after bringing Chinook 8 online in the GoA, we achieved first oil at Lac Da Vang in Vietnam. This was our first operated development in the country. We brought it online in two years, 11 months, and 23 days from project sanction, safely, on time, and on budget. Beyond that strong project execution and initial startup, Lac Da Vang creates value for Murphy in multiple ways. First, it gives us local operating and development experience that we can build on as we grow our business in Vietnam. Second, it adds attractive oil barrels with some recent cargoes selling at a premium of more than $10 per barrel to Dated Brent. As production ramps up, Lac Da Vang's cash flow contribution becomes material. Third, Lac Da Vang establishes the infrastructure to support our broader hub-and-spoke strategy in the country. With a hub now in place, our Lac Da Trang North, White Camel North discovery, and other nearby opportunities can benefit from a lower economic threshold and a more capital-efficient path to production. Turning to Côte d'Ivoire, the Bubale West-1X well confirmed oil in the Turonian reservoir down dip from the original discovery and also encountered hydrocarbons in the deeper Albian reservoir. We are encouraged by the Bubale exploration, appraisal, and analysis work completed so far. The information from the Bubale West-1X well gives us even more confidence that the likely range of resources in the Turonian reservoir supports an economic development of the Turonian and helps narrow the range of uncertainty in the recoverable resources. I think it will help investors if I characterize the Turonian reservoir at a high level based on the data we have from the two Bubale wells and our seismic dataset. The Turonian reservoir is a generally east to west trending deepwater channel system, which is narrower at the discovery location and widens to the west and down dip toward the West-1X location. Pressure data from the wells indicate likely reservoir continuity between the two wells. Recall that the two wells are about 8 miles apart, and the West-1X well is about 1,100 feet structurally down dip from the discovery well. The Turonian appears to be a high-quality reservoir that contains high-quality oil. The Turonian oil is 37 degrees API, and the GOR is around 1,500-2,000 cubic feet per barrel. We collected a whole core at the discovery location and are analyzing the core now. The preliminary work indicates that the average reservoir permeability is in the 100 to hundreds of millidarcy range, with some reservoir over a darcy. More work is necessary to determine the variability of reservoir quality throughout the field. The West-1X well encountered oil-bearing and water-bearing Turonian reservoir sands. The water encountered in the West-1X well may represent a definitive Turonian-wide oil-water contact, but we need to do more work to confirm that. The fluid PVT properties suggest that the reservoir does not have a gas cap. In addition, as we previously disclosed, we encountered high-quality oil in the deeper Cenomanian and Albian reservoirs, which will need to be appraised. We clearly know much less about the Cenomanian and Albian reservoirs at this point, but here's how we're thinking of them. The Cenomanian is the same type of channel system as the Turonian, and it widens up dip to the north and is narrower at the discovery location and down dip to the south. The Albian extends up dip to the northeast and down dip to the southwest from the West 1X location. We believe the West 1X well encountered an oil-filled sand at the edge of the Albian channel system. We're currently working to incorporate all the Cenomanian and Albian well and seismic data to improve our understanding of the reservoir and help determine the optimal locations for future appraisal wells. I recognize that's a fair amount of technical detail, but many of you have asked for greater visibility into what we're seeing at Bubale. We want to be transparent about what we know today and what we're still working through. There is more work ahead, but each appraisal well gives us a clearer picture of what we have and helps guide where we go next. Our key achievements this quarter are not isolated events, and I'm proud of what our teams delivered. We were simultaneously bringing offshore projects online on opposite sides of the world, exploring and appraising in shallow and deep water across multiple basins, and operating our producing assets above expectations. This breadth of execution reflects capabilities built over decades, and those capabilities are creating significant value. At $80 Brent, Lac Da Vang and Chinook are expected to generate approximately $1 billion of combined free cash flow over the next five years, while the exploration and appraisal opportunities we advanced this quarter represent resource potential roughly twice the size of our current offshore reserves. The base business also continues to deliver, with Eagle Ford, GoA, and Tupper Montney all contributing to production above the high end of guidance and $515 million of operating cash flow in the quarter. Our results this quarter add both cash flow today and a broader set of investment choices for the future. As those opportunities mature, we will remain selective, prioritize the investments with the most compelling returns, sequence capital with discipline, and maintain an uncompromising commitment to financial strength. With that, we're ready to take your questions. We will now begin the question and answer session. At this time, I would like to remind everyone, in order to ask a question, press star, then the number 1 on your telephone keypad. To withdraw your question, press star one again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Arun Jayaram with JPMorgan. Your line is open. Please go ahead. Eric and team, good morning. Appreciate some of the key technical details around Bubale. I was wondering if you could maybe think about the bigger picture here. You mentioned that you believe that you've already reached a minimum threshold for development. I was wondering if you could maybe help us think about your big areal extent, about the size of the recoverable resource range, and a little bit more on the next steps in the appraisal program. Arun, thanks for that. I know everyone is anxious for us to give a new resource range for Bubale. What I'll tell you is, from where I'm sitting, we have two wells in the reservoir and still a fair bit of remaining uncertainty about the range of resources. Like you pointed out, I think we have quite a bit of confidence that we have de-risked through our appraisal program a volume that clears an economic development threshold, but I'm not really yet ready to describe a new range of resources from the Turonian, and we have a lot of work to do before we're ready to talk about the other reservoirs. What I expect is, as we progress our appraisal program over the next 18 to 24 months, we'll be in a better position to give a new updated resource range. I just don't know it yet. There's still quite a bit of uncertainty that we have. Obviously, from our release materials and my comments just now, we've learned quite a bit about the Turonian, but there's still quite a bit of uncertainty. How much of the Turonian system is filled in a lateral extent is still something that we have to think about. As we indicated, we don't expect that the reservoir above the discovery location in Turonian should contain anything other than oil, but we have two data points. We expect in these type of systems that we would have variability of reservoir thickness, quality, et cetera, and we need to know more before we pin down a resource range. I'm excited that we believe that we're at the point where we have a project to develop here, but I don't have confidence in a new range yet, so we'll be working on that. Obviously, we haven't described that we have an active appraisal program coming up. There are quite a few remaining things to learn. I anticipate that we will, between now and probably the second quarter next year, we will kind of hone in on the most impactful and helpful wells to drill to reduce our remaining uncertainty in all the reservoirs. The things that we're thinking about, we have about five, six locations that make sense today to learn more, and we're continuing to incorporate the data that we have recently collected from the wells. We're re-looking at our seismic dataset and incorporating the well data into the seismic dataset, and doing additional work to decide where to put the well locations to continue to reduce uncertainty in the most capital-efficient way. The kinds of wells we may drill in next year's program, the things that make the most sense would likely be an updip Cenomanian, that would be heading north of the discovery location. In the Albian, we could move updip or downdip in the Albian from the West 1X location. In the Turonian, there's still a potential to have a well north or south of the West 1X location, so testing lateral extent of the channel system. There's a possibility of a Turonian well between the two, the discovery and the West 1X location. There's still a possibility of a downdip Turonian well, although I think that's less likely now with the results of our West 1X well. It's still possible, but it's something we would pursue if we conclude that we have not encountered a definitive Turonian wide oil-water contact. We might be chasing oil downdip in some of the stacked Turonian channel sands. So, there's still a lot of work to do. The team, I'm really proud of. They're doing a great job of incorporating all the data, but we just are not yet ready to give a new resource range. We're trying to, as you heard from us this morning, we're trying to tell everybody what we know, what we don't know, and be pretty transparent about it. I know it's closely watched for the company. It's a really big deal for us. We're excited that this field, as we learn more about it, is looking more and more, giving us more and more confidence that we have a project here, because the project here is significant for our shareholders as we exit this decade, head into the next decade, as we likely looking to bring it online about six years from discovery to coming online, first oil. Great. Thanks for that color. My follow-up is in Vietnam. You're approaching an FID decision in about 12 months from now at Hai Su Vang. Can you give us a little bit of an update on just general thoughts around how that project is developing? Yeah, that's a really great question. What I'm really happy to tell you is that we are advancing our assessment and working with our partners and government at a faster pace than we have seen other companies be able to accomplish in the past in Vietnam. We have indicated that Vietnam is very supportive of our work there, and they want to push to move things faster, and we are seeing that happen. There are several steps in the process of going from discovery to an approved development and then executing it. The steps that we're executing there, we're moving through very rapidly. So, I think we're on track for a project sanction at the end, let's say the fourth quarter of 2027. It's moving along very well with partners and government, and no reason to have anything but happiness about how it's progressing. All right. Great. Thanks, Eric. Thanks, Arun. Your next question comes from the line of Doug Leggate with Wolfe Research. Your line is open. Please go ahead. Thank you. Good morning, everyone. Eric, a lot of geometry in your description this morning. I wonder if I could ask you to go a little deeper, pardon the pun, on the Albian feature. You haven't really talked anything about the extent of how that compares to the shallower tests you've already done. Can you offer any color? It sounds like you were saying it's an oil-filled sand, so it sounds like no oil-water contact in the Albian. What does that feature look like in terms of the scale? The areal extent of the Albian and the Cenomanian, assuming that they are filled and our current seismic interpretation is correct, which is a big leap from where we are today, are similar in extent to the Turonian. We think the Turonian is potentially longer and narrower, and the Albian could be shorter and wider. We did sample oil in the Albian. Like we indicated, we think it's on the edge of a channel system. We confirmed that we sampled oil. It's a nice-looking oil with a low GOR, or moderate GOR. I hate to press on this a wee bit, but you did give some permeability data on the Turonian, but you didn't mention anything about the sand quality in the deeper sections. Can you offer anything there? I wonder if what's behind my question really is, as we think about this moving towards a commercial development, one of the big challenges that that area has had in the past was the number of wells required to develop. I'm trying to just thinking in terms of what the capital intensity would be to bring something like this to market. Any color you can offer there would be great. Thank you. Yeah, Doug, so we are thinking about the same things that are on your mind, and that's why we're working through all the data. I'm not yet ready to share the data on the deeper horizons because we haven't yet done the work. We've collected core. We will analyze it. It's being analyzed. We haven't yet done that work. I think it is normal to expect, in many cases, that you would have lower reservoir quality the deeper you go. I think we have some indication that the Cenomanian, while not comprehensively yet assessed, the Cenomanian may be lower permeability than the Turonian. The limited data we have from the Albian, very limited data we have from the Albian, suggests that we found what maybe surprised us as even better reservoir quality than we would anticipate at this depth. Still a lot to learn, not yet ready. I'm very encouraged by the reservoir quality we've encountered in the Turonian with respect to how to efficiently and economically develop the field. We have more work to do before we have that same confidence in the other two reservoirs. Eric, would you mind if I just tagged on a quick follow-up? In your original range, was the Albian included in your original resource range? The range that we provided, the only range we provided so far was our pre-drill range for the Cenomanian. What we have said so far is, I don't want to reference that range anymore. Before you had any data drilled here, we said the Cenomanian might have a certain range of mean to upside volumes, not the range, the full range. That was for one reservoir. Like I said earlier, we don't yet know what a new range is. We contemplated one reservoir that was significant in its potential extent, and we encountered that reservoir, which is still significant in its potential extent, along with the Turonian and now an Albian that are significant in their extent. We have a lot of work to do. What I would hesitate to say or have anyone think is, we gave you a range for one that was a mean to upside, and now we have three reservoirs, and it's going to be three times that big. I don't expect that to be the case. I think we're honing in on a commercial-scale development with a very large range of uncertainty of how large this resource is, and I don't want anyone to start multiplying things by three, four, or five. I think we ought to just do the work, make an assessment, progress through the appraisal program, give a new range. Again, I'm excited that I believe we have a commercial development in Turonian, more resource to be fine-tuned in the other reservoirs. That's kind of what we know now, and we'll tell people more when we know more. Thanks so much, guys. I appreciate it. Thanks, Doug. Your next question comes from the line of Chris Baker with Evercore ISI. Your line is open. Please go ahead. Hey, good morning, guys. Eric, I appreciate all the detail. I guess maybe just a different angle on the same topic that has been asked. As you think about sort of a minimum resource you would need for the standalone development, given the encouraging signs that you have seen to date, what would that look like? I guess in terms of the timeline, when would it make the most sense to potentially bring on a partner, given your 85%-90% working interest there? Chris, great questions. Obviously, as we learn more about the Turonian, it will influence our exact assessment of the resource we need to be commercial. The better the quality, the more continuous, et cetera, the less wells are required for the development to recover the same volume. There is certainly work to be done to fine-tune. Our screening numbers suggest we need over 150 million barrels, roughly, to make it work. That is just developing standalone, a typical deepwater field with an FPSO and a number of wells. That is a fairly low bar, but it is actually a pretty significant amount of volume. That is kind of where we are sitting in terms of an early screening number of what we need to clear a commercial threshold. That is great. I also wanted to touch base on the Eagle Ford. Just curious how you are thinking about that within what seems like an opportunity-rich 2027 outlook here. In terms of a step-up in capital and the timing, anything you can share there in terms of what the growth profile could look like and what CapEx cadence could end up being? Yeah. We indicated a couple months ago that we were intending to ramp up our Eagle Ford. We added capital this year to resume drilling, which will allow us to accelerate bringing online wells earlier next year than our original plan for the year. That is the beginning of what I anticipate will be a multi-year ramp-up to some new plateau rate for the Eagle Ford. We will not bring online this year more wells in the Eagle Ford than our original plan, but we will have wells ready to be completed late this year, heading into early next year, which will increase our annual average production rate next year materially. We are planning next year to run a steady program, which would have a ramp through the year with a peak production in the fourth quarter, which is different than what we have done really for the last five years, where we are practically done with our program by the third quarter. That will lead to more capital deployment to Eagle Ford. Obviously, we have not yet formulated our budget. We are going to work on that between now and the end of the year, and we will present that in our fourth quarter earnings call in late January. But I think directionally, we are looking at Eagle Ford capital increasing from sort of the plus or minus $300 million mark in the last year or two to around $500 million, somewhere in that ballpark, in 2027. Again, more fine-tuning to be done. That is kind of how we are thinking about it. Great. Thank you. Your next question comes from the line of Leo Mariani with ROTH Capital Partners. Your line is open. Please go ahead. Hey, I just wanted to follow up on some of the comments that you made around Côte d'Ivoire. If I kind of heard you right, it sounds like still a lot of analysis to go, but perhaps you guys don't get to kind of the next appraisal well maybe till sometime in the second half of 2027. Is that reasonable? It sounded like you guys would really take your time and be thoughtful about where that next well goes. Leo, we are actively working to secure a rig to conduct that appraisal program. We're in an advanced stage on our tender process. We have uncertainty about when specifically it arrives. I expect now that we would start that program sometime in the second quarter of next year, but I'll know a lot more when we actually tender the rig. Okay. Thanks. I just wanted to follow up on Lac Da Trang North. Have you guys been able to do some more work on that discovery? Obviously, it's a good-sized discovery. Do you have a sense of whether or not you guys need to drill an appraisal well, or do you think at this point it's just going to progress towards a subsea tieback? Any more color would be great. The way we're thinking about it now is it's likely to be progressed as a subsea tieback without an appraisal well. We are likely to drill some exploration wells north of Lac Da Trang in the future, let's say in 2027 or 2028, in the Lac Da Cam complex, that's Orange Camel, and depending on how those wells come in, we would either develop Lac Da Trang, Lac Da Trang North, Lac Da Cam as a new hub, or more likely, they would be tied back to the Lac Da Vang infrastructure. We'll know more about that as we continue to progress our evaluation. We're happy with our Lac Da Trang, Lac Da Trang North discoveries. I think that their nice tieback scale will be developed very capital efficiently and likely will not have an appraisal well on Lac Da Trang North. Okay, that's helpful. On Eagle Ford, you obviously mentioned that you're going to spend more money next year. I think that's been very well socialized by you folks for a continuous program. It makes sense. How about any of the other kind of moving pieces? Do you see kind of the exploration and appraisal budget up, a decent amount year over year as well in 2027? It sounds like you're geared for more activity. It sounds like at least a couple wells in Côte d'Ivoire, maybe two or three there, and several more wells in Vietnam. Just kind of any high-level color you can provide on kind of activity set and some of the bigger offshore stuff next year versus this year. Sure. As we're thinking about our program next year, I expect our exploration program, which includes all of our seismic acquisition, reprocessing data, all that kind of, and drilling wells, will be in the 10%-15% of our total capital program. Our appraisal program at Bubale will be significant investment. The wells that we will drill appraising Bubale are likely in the $80 million-$100 million range per location, and that's assuming that we don't conduct an extensive evaluation program. If we conduct an extensive evaluation program, that could easily get to be $110 million type range per location. So, depending on the number of wells and how we progress them, there's significant uncertainty about our appraisal spend at Bubale, and that'll drive the bulk of our range of uncertainty in our capital program next year. What I can tell you as I'm thinking about where we're setting our budget for the year, communicating it in January, we're likely to give capital guidance next year differently than we have historically. We're likely to give you a range that's reasonably tight for our base business, and then indicate the range of Bubale appraisal spend, again, because it's material and every well we drill in Bubale will inform whether we want to drill more and how much there'll be, and just that range of uncertainty is today significant, will likely continue to be significant as we head into the early part of next year, and we'll try to communicate that a bit differently. Okay. Appreciate it. Thank you. Thanks, Leo. Your next question comes from the line of Noah Hungness with Wells Fargo. Your line is open. Please go ahead. Morning. For my first question here, I did want to touch on kind of the central funding requirements for a Côte d'Ivoire development and just how you're thinking about that. In the event of a potential farm-down or asset sale, if you were to explore those options, could you maybe talk about the decision tree between those and if a farm-down would be a farm-down of the Côte d'Ivoire asset or a farm-down of some of your currently producing assets? I would tell you that where we're sitting today, we don't have an answer of our best outcome for our shareholders, but that's how we'll be thinking about it. As we learn more about what we found in Côte d'Ivoire, we will form a view of, do we want to keep all of the ownership we currently have in Bubale and the associated potential other discoveries on the blocks, or do we want to do something else with our assets? We're coming into this with a great balance sheet, a lot of liquidity, and a really good financial position to figure out what we have and decide the best outcome for shareholders. We're aware that we have assets that other people would like, so asset monetizations are something that we will think about. We're not yet in a position where we need to make those choices. We're conducting an appraisal program over the next 18 to 24 months, and at the end of that program, we'll probably have a better view for funding needs, size of the opportunity, size of the capital program, and then determine, does it make most sense to farm down what we found in Côte d'Ivoire, or does it make sense to take on temporarily a bit of debt, or does it make sense to sell potentially assets in our onshore business, or potentially a combination of all those things. We're looking at that, we're modeling that. We don't have an answer to what the problem is yet, but we're aware that we have quite a few options to do it, and we're really excited to have all those options. Okay. For my second question, I was wondering if you could talk about some of the exploration projects in the GoA. Would these be greenfield exploration developments, brownfield expansions? Just some of your latest thoughts on that asset, too. Yeah, great question. The way we think about our opportunity set in the Gulf, we have a handful of hub-scale prospects and quite a few tieback scale opportunities that are near our existing infrastructure, mostly that we operate. You'll see us over the next three, four years in the Gulf conduct a program that occasionally tests a hub-scale opportunity exploration well, and more often does tieback scale things near our existing infrastructure. As we're thinking about our program next year, we have choices to make. I anticipate next year's program in the GoA will feature a hub-scale test, but we haven't formalized that yet. When we announce our budget in January, we'll let you know what our program is, but I think we're likely to test one hub-scale prospect in the Gulf, and in Vietnam, some tieback scale opportunities in the block that contains Lac Da Vang, 15-1/05. Great. Thanks. Thank you. Your next question comes from the line of Phillip Jungwirth with BMO. Your line is open. Please go ahead. Phillip? Your next question comes from the line of Josh Silverstein with UBS. Your line is open. Please go ahead. Yeah, thanks. Good morning, guys. I wanted to touch on the cost structure. LOE was very low this quarter, and you reduced the full year range, excuse me, to the bottom end of that $10-$12 per BOE range. Can you just talk about how this is trending into next year? I didn't know if there were any one-off items in there, but clearly a good result this quarter. Josh, thanks for that. Obviously, we haven't set our program for next year definitively. This quarter, we are choosing to have a pretty active workover program in the Gulf. We identified a number of wells that were either had a potential to produce at higher rates, or in the case of one well, not producing, that we were able to go in, do some workover activity, and add volumes as we either exit this year or head into next year. I think we'll see some of that activity continue into the first quarter of next year, but then the rest of the year is likely not to have significant workover activity. Again, we still haven't set our budget for next year, but I expect that some of the work we're doing in this quarter will carry into the first quarter of next year. Again, we've been communicating probably for a few years now that we anticipate operating expenses to be in the $10-$12 per barrel range. I would expect that that's a reasonable number for 2027 as well. Yes, that's kind of where we are. Got it. Okay. Just curious about the shareholder return thoughts as well. Obviously, there's a bit of uncertainty as to what the CapEx budget looks like for next year and what the long-term budget may be around potential development there. Are the buybacks on hold for now as you just kind of look to keep the balance sheet in good shape for potential bigger CapEx opportunities for you guys? I know you had previously done that, but you want to make sure the dividend's paid and keep the balance sheet in good shape. Just curious on that front too. Yeah, that's a great question, and it's something that I think about 12 times a day, Josh. The way I think about it is that we believe that our shares do not reflect the value of some of our expansion opportunities that we see in front of us for Hai Thong, does not reflect any value for Côte d'Ivoire. They partly don't reflect value for Côte d'Ivoire because we haven't been able to tell you how big it is, so how could anyone value it? I understand that. As we learn more, we will probably conclude that we anticipate a period of time between learning about the field and trying to communicate the potential value of it, that our share price may not move to reflect that because of discounting, risking, et cetera. It probably will encourage us to buy our shares because they'll be cheap relative to what we think intrinsic value will be. If we see periods in the next year or so that our share price pulls back significantly lower than even a fairly conservative view of intrinsic value, we're likely to buy back stock. I would like to reward our long-holding shareholders by concentrating the value of the company in less shareholders that are long holders, and buying back stock is a nice way of doing that. Having said that, we will protect the balance sheet. We'll be careful about debt level. That's very important for us. We have a bit of tension in the system between funding the appraisal program and understanding what we have, buying back stock. Those are intention, and we will be thinking about that, and we will be monitoring oil price, because our share price moves a lot with oil price, and be thinking about how do we win for our shareholders. Thanks, Eric. Your next question comes from the line of Phillip Jungwirth with BMO. Your line is open. Please go ahead. Yeah, thanks. Morning, Phillip. Sorry about that earlier. Morning. You made some really good progress on Eagle Ford well costs this quarter. I was just hoping you could hit on the drivers there. As you look to run a larger, and I assume more level-loaded program next year, do you think there could be incremental efficiencies that come out of it as a result? Just what are you seeing on the cost side, inflation at the moment? Thanks, Bill. Let me give you kind of high-level view. I will ask Chris Lorino to provide maybe a little bit of additional color. This year's program, we are really excited about our well cost coming down materially. We reduced our cost per foot to drill and our cost per foot to complete. The drilling work was about five different things the team really focused on. Completion, we are getting very efficient in how we are pumping these frac jobs. We are also tailoring every stage of the frac job to be the most capital efficient possible, operationally efficient, and 26% reduction year-over-year in well cost, drill and complete. It is pretty impressive. As I was prepping for our call this morning, I noted that our completion cost per foot realized in 2026 is the lowest completion cost per foot we have seen in our Eagle Ford business to date. Lower than 2016, when service costs were very low, lower than 2021, when service costs were low. We really nailed it out of the park. Part of that is long laterals. It is not just long laterals. It is also operational efficiencies. Chris, I do not know if you have any color to add to that. Yeah, you hit on it. The combination from the longer laterals and the completions efficiency. We keep continuing to be creative on how we get our cost per foot down, and really tailoring each pad to the best outcome and the best plan to get the BOEs out. We continue to see that improve, and you think it would start to flatline, but we're continuing to see improvement there by tailoring each one. It is a combination of the longer laterals with our completions efficiency. No, that's great. Bit more frontier than Côte d'Ivoire, but was hoping you could talk about the entrance into Mauritania and what drew you to this area. Next steps after signing the PSC, and just confirm, is the objective here oil, just because the country does have a large LNG project also? Yeah, great questions. Mauritania is, to us, what we've been communicating our portfolio needs, which is low-cost entry into material opportunities that we can assess relatively cheaply and test relatively cheaply. We're really happy with our entry here into Mauritania. We are exploring for oil. We do recognize there are gas discoveries in the area. We are looking for oil in the deep water in Mauritania, and we think it checks the box of those things. Low cost of entry, low cost to assess, relatively low cost to test, good financial, good fiscal regime, et cetera. After signing the PSC, which we've just done this week, we'll move forward to do some seismic reprocessing and studies work, and we'll decide at some point if our thoughts around our prospectivity are confirmed by reprocessed seismic and more assessment, and we'll make a decision about a potential well in the future. I would guess at this point that a well being drilled, exploration well, was probably not something we do until perhaps 2029 or that kind of timeframe. Very limited spend, mostly around seismic reprocessing and assessment work here over the next two years or so. That's great. Thanks. Thank you. Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open. Please go ahead. Yes, good morning, Eric, to you and the rest of the Murphy team there. I'd like to go back to the question around the Côte d'Ivoire appraisal. You got a really interesting challenge here in front of you, and probably no one path that's going to please everybody or satisfy all the kind of competing priorities. But I wonder if you could talk about your philosophy for the appraisal, maybe the relative priority of establishing a minimum threshold in the Turonian versus sizing an eventual development. I'm really wondering how that plays into your current thinking about perhaps the sequencing of the appraisal wells. Like, if you're more interested in clearing that minimum threshold upfront, or rather, you're more interested in sizing it perhaps with a Cenomanian or Albian test before then. Yeah, that's a really good question, and it gives us a chance to talk about how we think about our development strategy here as it relates to appraisal. What we have done with most of our developments over the last two decades at Murphy Oil is appraise enough to get to a point where we have confidence that we're not materially over or undersizing the development to efficiently develop the resource, but also not appraise to the point where we have no remaining uncertainty. What I would expect us to do here is to learn enough that we can build, we can design an FPSO that is not significantly too large or too small. It addresses a reasonable range of outcomes, both in total resource size and productivity of the wells. We move forward with development while we continue to learn more about the full potential of all the reservoirs in the field. We're going to need to get to a point where we're not committing large capital that is misdesigned for the resource that we have and the rates we can produce it. If you think about that, we're spending significant money appraising. Let's just say we'll spend another $300 million-$400 million of the ball. That's an estimate. I don't know if we'll do that, but if we keep finding oil, we'll keep doing that. That is a lot of money, but it is not of the same magnitude as a $10-$20 per barrel capital development of a material resource. It's important to us to get right the large capital investment by learning enough that we don't make a mistake and be significantly too big or too small. But we're not going to appraise and reduce all uncertainty and then commit to a development. We're going to, at some point, decide we have enough that we can be flexible and we can move forward, and we'll learn as we develop the field. Got it. That's helpful for the generalities. I'm going to try to drill in maybe one step further. Is your next appraisal going to be that Turonian, in between the discovery and the 1X, which you mentioned you prepared comments, you think you're in pressure communication, but I imagine that a test there could confirm that, possibly, which really raises the low end of the bar. Perhaps also, there is some potential for appraisal in the Cenomanian and Albian if you choose that in-between location. Is that next? As I mentioned earlier, we don't yet know the sequence of wells or which exact locations. We're doing that work now. By the time we start our appraisal program in the second quarter, we'll have an order that we'll know and we'll act on. I can't yet tell you what the next one will be because we're doing the work. I think, again, restating, Cenomanian updip, Albian updip or downdip, a Turonian well between a Turonian well north of the West 1X. Those are all likely places where we would drill the first well. Your assessment of the ability to learn more about the Turonian by putting a well in between is valid, and we are thinking about it the same way. I don't yet know if that's the next well. It's a well that we are considering doing. We're going to do more work to figure out the optimal thing to advance the project in the most capital-efficient way, and I don't have an answer yet, unfortunately. No, that's great color, Eric. It's going to be really interesting to watch this unfold. Thank you for the commentary. Thanks so much. Your next question comes from the line of Jack Cavanaugh with Goldman Sachs. Your line is open. Please go ahead. Good morning, team. I wanted to start on Lac Da Vang. It's a great milestone to bring that online in 3Q, but I was wondering if you could speak to the shape of what that ramp looks like to peak production in 2028, 2029, as well as the timing on when you could develop any one of these tieback opportunities in the area. At Lac Da Vang, we anticipate having a second well this year. We'll continue to deliver more wells through 2027, 2028, and 2029. Next year, production rate is probably net to us, probably 3,000-5,000 barrels a day. Exit rate is probably in the 7,000-12,000 barrel a day range. I'm sorry, exit of 2027, to be clear. And we anticipate peak production of 10,000-15,000 barrels a day net to us, probably in 2028 or 2029. Got it. I appreciate that. And maybe reflecting on the Devon Eagle Ford sale process, just curious what that told you about the market value of your asset, and if that changes any of the way you view kind of the optionality of holding that asset within your longer-term vision for the portfolio. I think what we learned from Devon's process was that the Eagle Ford is attractive to even more potential buyers than we might have previously thought, and confirms that we have an asset that other people value. We like our asset. We are happy that we have an ability to use the Eagle Ford to ramp it up to generate more free cash flow to help fund our appraisal program and other priorities for our company. We are very aware that it is valuable, and we are happy to have the flexibility that if, in the future, we chose to sell our Eagle Ford or part of our Eagle Ford, it could be a nice place of funding if we determine that is the best outcome for our shareholders and the most value-creating. Yeah, I think it is interesting to see an asset of that scale have so much attention from so many players, and reconfirms that we have a great asset here. Appreciate it. Thanks. Your next question comes from the line of Betty Jiang with Barclays. Your line is open. Please go ahead. Good morning. Thank you for taking my question. I want to ask about GoA. You guys delivered a pretty strong quarter in 3Q, but I think 4Q guide is not. There are some changes in the 4Q guide. Can you just maybe speak to the quarter-on-quarter variations, how much of the Chinook startup you're baking in, and how should we be thinking about the GoA production trajectory into next year? Yeah, thanks, Betty. I'll let Chris address that. Yeah, so just looking at our offshore only, obviously, we're very excited about the Chinook 8 well being online. It's going to provide about 9,000 barrels of oil per day for the quarter, so really strong well, and excited about that. That was, as far as quarter on quarter, that was offset a little bit by the weather and the hurricane that happened in the beginning of the quarter, which was around 3,700 BOE. In addition to that, Eric mentioned some of the workovers that are happening. Some of them do have production, so while we work on those wells, they'll be shut in as well. That includes a non-operated workover at Kodiak as well. That kind of offsets the impact, the big impact from the Chinook 8 well, which kind of gives you kind of a flattish or up about 1,200 BOE per day quarter on quarter for offshore. In addition to that, we also have some planned maintenance at Delta House that kind of also offsets that. I will assume the first half of next year, we'll start seeing the volumes go back to a higher level after the workover? Yes. Yeah, so we'll be done with all but one of the workovers. One will go into first quarter, and so we'll be done with them, and that'll be early first quarter is what it looks like. We'll have all that behind us very early in the year, and then we'll ramp back up for our Gulf production. Great. Thank you. My follow-up on LOE, I think the production cost management has been coming consistently lower. Maybe just speak to what's driving that lower LOE cost and how you think about the LOE cost range going forward, especially with now Eagle Ford expected to ramp into next year. Thanks, Betty. Our operating expenses offshore, excluding workover activity, tend to be very steady. Our onshore teams have been very focused, particularly our Eagle Ford team, on continuing to lower operating expenses to be more competitive. I'm proud of the work they've done. They have addressed that across multiple categories. They focus on labor costs. We optimize our labor costs all the time. They're focused on equipment rental, water disposal, chemicals. We have a remote operations center that we deployed in 2017 and continue to enhance its capability every year. They're focused on minimizing downtime by maximizing the best wells coming online when we do have upsets, and all of that's contributing to Eagle Ford operating costs improving materially. Within the Eagle Ford, from quarter-to-quarter, we have variability in the dollar per barrel OpEx, mostly driven by variability in our production profile, with a very nice effort from our team to lower total dollar operating expenses there. That's really the story. Great. Thanks. Thanks a lot, the caller. Thanks, Betty. Again, if you would like to ask a question, press star then the number 1 on your telephone keypad. There are no further questions at this time. Mr. Hambly, I turn the call back over to you. Thank you, operator. As we close today, I just want to thank our employees for their hard work and dedication. We have done a great job. We had excellent execution throughout the quarter across our entire organization, and I am really proud of what we delivered. As always, to our shareholders, we appreciate your continued trust and support, and that concludes our call for today. Thanks so much. This concludes today's call. You may now disconnect.