This call is being recorded on Thursday, May 8th of 2025. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead. Thank you, Operator. Hey, good morning, everyone, and thank you for joining us on our first quarter earnings call today. With me are Eric Hambly, President and Chief Executive Officer; Tom Mireles, Executive Vice President and Chief Financial Officer; and Chris Lorino, Senior Vice President, Operations. Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interest in the Gulf of Mexico. Slide two. Please keep in mind that some of the comments made during this call will be considered 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, see 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. I will now turn the call over to Eric Hambly. Eric? Thank you, Kelly. Good morning, everyone, and thank you for joining us on our call today. Looking back on the first quarter, I'd like to thank our employees for staying with it as we continue executing our plans. I believe we've turned a corner with our operations, and I'm pleased at our recent success. Turning to slide three, Murphy remains focused on our operational excellence, multi-basin portfolio expansion, and capital returns to shareholders. Murphy drilled our longest laterals in company history in the Eagle Ford Shale and Tupper Montney as we advanced our onshore program in the first quarter. Keeping our team safe while we execute our operations is extremely important, and I'm excited that early in the second quarter, we achieved 1 million work hours with no lost-time injuries on the platform construction for our Lac Da Vong or Golden Camel field development project. We also announced today further success in building our Vietnam business and expanding Murphy's multi-basin portfolio. During the first quarter, we drilled our second oil discovery in Vietnam at the Lac Da Hong 1X or Pink Camel exploration well, where we encountered 106 net feet of oil pay from one reservoir. The company also acquired the Pioneer Floating Production Storage and Offloading vessel in the Gulf of Mexico for $104 million net purchase price. Murphy upholds our commitment of returning cash to our valuable shareholders, and in the first quarter, shareholder returns totaled $147 million through $100 million of share repurchases and $47 million of dividends. Murphy has an exciting year ahead and will execute our plans through the lens of our strategic priorities. Slide four. Murphy has successfully achieved the core objectives of our capital allocation framework since we first announced it nearly three years ago. Looking ahead, we will continue to focus on rewarding shareholders for their support and remain committed to our strong balance sheet and disciplined strategy. Murphy will continue to allocate a minimum of 50% of adjusted free cash flow to shareholder returns, primarily through buybacks. We will assess the appropriate shareholder return allocation, including dividend increases under this modified plan, and any remaining adjusted free cash flow will be allocated to the balance sheet as we continue to target a long-term debt goal of $1 billion. Murphy has a long history of returning cash to shareholders, and we look forward to continuing this with $550 million remaining under our share repurchase authorization. Including our first quarter 2025 buybacks, I'm pleased to share we have repurchased 22% of our total shares outstanding since 2013. During the same period, Murphy has returned more than $4 billion of cash to shareholders through buybacks and dividends. Slide five. Murphy produced 157,000 barrels of oil equivalent per day in the first quarter, with 78,500 barrels of oil per day. We experienced approximately 6,000 barrels of oil equivalent per day of production impacts in the quarter due to non-operated, unplanned downtime in the Gulf of Mexico, production curtailments in non-operated offshore Canada due to temporary logistics challenges, and winter storm activity delaying first production at the new Mormont Number Four well and the Samurai Three well workover. Overall, we generated $636 million of revenue for the quarter, with an average realized oil price of $72 per barrel, natural gas liquids price of nearly $26 per barrel, and a natural gas price of $2.67 per 1,000 cubic feet. I will now turn the call over to our Chief Financial Officer, Tom Mireles, to share our financial highlights. Thank you, Eric. Good morning, everyone. Slide six. Murphy has made tremendous strides in strengthening our balance sheet over the past four years, which allows us to maintain our capital program and our competitive durable dividend while investing through the cycle. Further, our financial strategy incorporates a diverse marketing plan that enables us to capture natural gas price dislocations while also realizing premium pricing from our oil-weighted portfolio. I'm pleased that we have strong liquidity to support our investments with $1.5 billion as of March 31, as well as no near-term debt maturities. Our disciplined capital spending enables Murphy to prioritize adjusted free cash flow for share repurchases, potential dividend increases, and balance sheet purposes. Overall, Murphy maintains flexibility as we advance our strategic priorities. Slide seven. In the first quarter, Murphy acquired the Pioneer Floating Production Storage and Offloading Vessel for a $104 million net purchase price, as well as executed a new five-year operating agreement. This transaction creates tremendous value for Murphy and reduces our annual net operating expenses by approximately $50 million, thereby achieving a two-year payback. Additional benefits will be unlocked through further development and exploration in the area. We look forward to drilling and bringing online our Chinook development well in 2026, in addition to any potential third-party tieback opportunities around the FPSO. With that, I will now turn the call over to Chris Lorino, Senior Vice President, Operations. T hank you, Tom. Thank you, Tom. Good morning, everyone. Slide nine. Our Eagle Ford Shale asset produced 25,000 barrels of oil equivalent per day in the first quarter, with 83% liquids and one gross non-operated well came online in Karnes. As a result of our recently enhanced development plan to further improve capital efficiency, Murphy drilled the longest Eagle Ford Shale lateral in company history at 13,976 feet in our Catarina acreage, representing an 8% increase from the previous record. We are also testing two tight turn radius wells to capture additional volumes in the completions process and are excited to see the results later this year. For the second quarter, 18 operated Karnes wells are now producing, and we anticipate three operated Catarina and three operated Tilden wells to come online later in the quarter, as well as 11 gross non-op Karnes wells. Slide 10. Murphy produced 340 million cubic feet per day from the Tupper Montney in the first quarter and brought online five wells as planned. The remaining five wells of our 2025 program came online early in the second quarter, which wraps up our well delivery schedule in the area for the year. With our enhanced development plan, Murphy recently drilled our two longest lateral Tupper Montney wells in company history at more than 13,600 feet each, with the longest representing a nearly 4% increase from the previous record. Murphy is always striving to improve our operations, and we tried a new completion style with enhanced proppant loading in the Tupper Montney. We are pleased with the early results, as we've seen more than a 30% increase in initial production rates compared to our historical performance. I'd also like to highlight that with our new wells now online, we have reached our Tupper West plant capacity and are currently producing nearly 500 million cubic feet per day from our Tupper Montney asset. Slide 11. Murphy produced 4,000 barrels of oil equivalent per day from the Kaybob Duvernay in the first quarter, with 71% liquids. We are on track to bring four wells online in the third quarter, as well as drill two wells in the fourth quarter that will be completed in 2026. Slide 12. In the first quarter, Murphy's offshore assets produced a combined 71,000 barrels of oil equivalent per day, with 83% oil. We brought online the new Mormont Number Four well in the Gulf of Mexico during the first quarter and progressed the Samurai Number Three workover, which returned production early in the second quarter. While our plans were impacted due to winter weather activity, we are advancing work on the remaining two workovers and are on track to wrap up in the third quarter. Slide 13. Our Lac Da Vong or Golden Camel Field Development Project in Vietnam is progressing, and we're excited to have commenced construction on the floating production storage and offloading vessel in the first quarter. The team also reached a significant milestone early in the second quarter as we achieved 1 million work hours with zero lost-time injuries on the platform construction. Murphy recently signed a rig contract, and we will begin development drilling later this year ahead of first oil in the fourth quarter of 2026, with ongoing development through 2029. With that, I'll turn the call back to Eric. Slide 15. Murphy maintains a focused and meaningful exploration strategy with a near-field infrastructure-led program in the Gulf of Mexico and high-impact growth opportunities targeted internationally. We've made purposeful investments in the data behind our portfolio, allowing us to mature our understanding of the basins and support future leasehold expansion. Our current international priorities, in particular, offer a unique combination of development and exploration opportunities in offshore Vietnam and Côte d’Ivoire, and we are excited to advance these projects in the coming years. Slide 16. Murphy plans to drill two operated exploration wells in the Gulf of Mexico in the second half of this year for an estimated net cost of $18 million per well. We are targeting lower-risk opportunities near existing infrastructure and highlight that the Cello Number One and Banjo Number One prospects are located near the Murphy-operated Delta House floating production system. Slide 17. We're excited to announce that in the first quarter, we drilled an oil discovery at the Lac Da Hong 1X Pink Camel Exploration Well in Vietnam. The well was drilled to a total depth of 13,616 ft in 151 ft of water and accounted for 106 ft of net oil pay from one reservoir. Based on these results, we estimated preliminary mean to upward gross resource potential of 30-60 million barrels of oil equivalent. Murphy also conducted a flow test and achieved a maximum flow rate of 2,500 barrels of oil per day. Additional testing showed high-quality oil with an API gravity of 38 degrees. We are continuing to review the results of this discovery and highlight that it enhances the value of Murphy's growing Vietnam business when coupled with our nearby Lac Da Vong Golden Camel Development and recent Hai Su Vong Golden Sea Lion discovery. Slide 18. Earlier this year, we announced a significant oil discovery at the Hai Su Vong Golden Sea Lion Exploration Well, where we encountered 370 feet of net oil pay from two reservoirs and achieved a facility-constrained flow rate of 10,000 barrels of oil per day. I'm excited to drill the appraisal well in the third quarter to better understand the resource potential of Hai Su Vong Field. Slide 19. Another major component of our exciting exploration portfolio is our upcoming three-well program in Côte d’Ivoire beginning in the fourth quarter with the Savette Well on block CI-502. This well is targeting a mean to upward gross resource potential of 440 million-1 billion barrels of oil equivalent and is an opportunity for us to target significant resource potential at a relatively low cost. Following Savette, Murphy plans to drill the Cobus and Caracal exploration wells in 2026, which will also target potentially sizable resources while allowing Murphy to test a variety of exploration play types near recent peer discoveries. Slide 21. For the second quarter of 2025, we forecast production of 177,000-185,000 barrels of oil equivalent per day with 48% oil volumes, as well as accrued CapEx of $300 million. While this represents a 15% increase over first quarter production, we've brought online nearly 30 onshore wells in the past two months, as well as two key Gulf of Mexico wells, and I'm pleased that we are today producing well over 180,000 barrels of oil equivalent per day. We are reaffirming our 2025 accrued CapEx range of $1.135 billion-$1.285 billion, which includes net acquisition CapEx of $104 million for the FPSO and $1.4 million for non-operated working interest near the Zephyrus field in the Gulf of Mexico. Murphy maintains our full-year production range of 174.5-182.5 thousand barrels of oil equivalent per day with 50% oil volumes. Due to the first quarter impacts we experienced in the Gulf of Mexico, we anticipate full-year production to be toward the lower end of this range. Slide 22. I'd like to highlight that Murphy's strategy over the next two years is unchanged as we deliver low single-digit production growth from our existing assets as we execute high-returning oil-weighted offshore projects while maintaining Eagle Ford Shale and Tupper Montney production. We will look to achieve organic growth from Vietnam, as well as potential development at Pawn in Côte d’Ivoire. Murphy's team will also continue our plan to drill several meaningful international exploration wells over the next 12 months, which will test prospective unrisked resources that equal five times our current offshore proved reserves. Overall, we're committed to returning cash to shareholders through our capital allocation plan and achieving our $1 billion debt goal. Slide 22. Our existing business, coupled with what we plan to accomplish through our growth opportunities, creates a long runway of success for Murphy. Our multi-basin portfolio allows us to achieve our goals of oil-weighted growth and excess cash flow generation for shareholder returns. We also have multiple exciting high-impact international projects ahead while we continue infrastructure-led Gulf of Mexico exploration in our own backyard. Exploration will remain a key differentiator and value creator for Murphy for many years to come, and I'm excited for what is ahead. With that, I will now turn the call over to the operator for questions. Thank you. Ladies and gentlemen, we will now conduct a question-and-answer session. If you have a question, please press the star key followed by one on your touch-tone phone. You will hear a one-tone prompt acknowledging your request. Your questions will be polled in the order they are received. If you would like to decline from the polling process, please press the pound key. Our first question comes from the line of Arun Jayaram from JPMorgan. Your line is open. Yeah, good morning, Eric and team. Eric, it appears that you're sticking with your capital allocation for 2025. My question is for you and Tom, how do you think about your game plan in a lower oil price environment? Call it, if things settled out, call it in a mid-50s kind of environment. How do you think about your program, which has generally been citing, call it $1.1 billion-$1.3 billion of CapEx as you move some of these development projects through the queue? Yeah, thanks, Arun. Obviously, a very logical question considering where we are today. At this time, as you can see from our release, we think it's appropriate to maintain our 2025 capital plan. We've made significant progress in delivering our balance sheet. In general, we want to position ourselves to continue investing in high-returning exploration and development projects through near-term volatility and be positioned to capture upside to commodity prices in the future. We think it's important that we balance the trade-offs between investing in our assets, returning value to our shareholders, and protecting our solid, really industry-leading balance sheet. We will continue to monitor the situation carefully, monitor oil price environment, and as we've demonstrated in the past, we'll continue to act with financial discipline. While we're not recommending or proposing a change in our 2025 capital plan now, we're aware and we're watching, we have identified opportunities to significantly reduce spending in 2025, and we will be more likely to implement those changes if it looks like oil prices will be below $55 a barrel for the remainder of the year. At $55 a barrel for the remainder of the year, we see average price around $60 a barrel, which is very comfortable for us with our dividend and our capital plan. If we see lower prices and we think they're going to be longer, then we would be more likely to move on some of the things we've identified. Some of the opportunities we've already identified to reduce spending in 2025 include not drilling Eagle Ford Shale wells in the third and fourth quarter, which are designed to come online in early 2026. We could delay those. We could not complete our four-well Kaybob Duvernay pad that we're nearly done drilling. We could not begin drilling in the Tupper Montney and the Kaybob Duvernay in the fourth quarter, which is our plan for the year to kind of get a head start on winter drilling season. We could also drop our planned development well activity in the Gulf of Mexico and go to a very limited program of activity offshore in our operated business. Those changes that I just ran through would have very limited impact to our 2025 production profile, but they would have a more significant impact to 2026. We're going to kind of watch the situation carefully and evaluate, again, trying to have a balance and try to assess whether oil prices are short-lived or longer-lived. Now, having said all that. Great. Thank you. Where we are not likely to make some change, I'll just highlight. We are unlikely to stop our development program in Vietnam on our Lac Da Vong development, the Golden Camel. We're likely to see that through. Remember that first oil is expected there in the fourth quarter, second half of 2026. We're also, because we see the value creation potential of our Vietnam appraisal of the Hai Su Vong discovery and our Côte d’Ivoire exploration program, we think that the value creation potential there is really significant, and we're unlikely to not do those. Those are things that we think are really worth doing considering the long-term, mid-term value creation there. When we think about 2026, if we expected average oil prices in 2026 to be below $55 a barrel, then we would likely come up with a capital plan in 2026 that had a reduction of CapEx by, say, 20%-40% from the $1.1 billion-$1.3 billion level that we've previously communicated to expect from us kind of on a long-term basis. The types of cuts that I talked about for 2025 would be the sort of thing that we would do in 2026. We could have a very limited onshore program, for example. Hope that helps, Arun. That's super helpful. Thanks for going through your thought process. It makes a lot of sense to us. Maybe a follow-up. I wanted to get your thoughts, Eric, on how the recent discovery in Vietnam impacts the LDV development plan. I know you're setting the platform, the A platform in 2026, and then you're scheduled to do the B platform in, call it the 2028 time frame. How does this discovery impact the development plan of the LDV? That's a great question. We're really happy with this discovery. It's a nice size, 30-60 million barrels, and just a few miles away from the Lac Da Vong development. The way that this will likely unfold, of course, we still have work to do with field development planning, but the way this will likely unfold is we'll probably set a wellhead platform at our recent discovery, Lac Da Hong, and have wells drilled there and have production be processed from the Lac Da Vong A platform, which we will bring online in 2026. It's going to be a very capital-efficient project with an ability to probably get online faster rather than slower. We're going to be moving rapidly to develop and get approved from partners and government a field development plan to do that work. I'd hesitate to give you exact timing of when that would happen because we have a long way to go with the approval process, but I would imagine before the end of the decade that we'd have that online. Great. Thanks a lot, Eric. Thank you. Our next question comes from the line of Greta from Goldman Sachs. Your line is open. Good morning and thank you for taking my questions. I was just wondering if you could speak a bit about how the Khaleesi Number 2 and Marmalard Number 3 workovers currently underway are trending, what operational steps are remaining, and if there's any incremental color you could provide on their timing. Yeah, I might have Chris Lorino dive in there and give you some details on that if you do not mind. Yes. Yeah, I'll talk about the Khaleesi 2 first. We just got on the Khaleesi 2 and the Marmalard 3 workovers. We mentioned the kind of winter storms that pushed back Samurai 3. We are kind of toward the beginning stages, but things are moving along like we had hoped. As far as our OpEx goes for our workovers, we did have some OpEx slide in from Q1 to Q2, but even with Marmalard 3 slipping into Q3, we're looking at getting back to our normal OpEx run rate around $10-$12 per BOE for the back half of the year. Yeah, we feel comfortable about the Khaleesi #2 being done in the second quarter and the Marmalard #3 well being done in the third quarter and making good progress. Great, thank you. For my second question, I was wondering if you could comment on your OCTG exposure to current prices for the remainder of the year and into 2026. About how many months out do you procure your steel for your onshore operations, and what sort of impact to oil costs are you currently embedding in your outlook? I may get some high-level comments, and then maybe Tom can provide additional detail since he runs our supply chain organization and has done a fabulous job. I would characterize in general, with all the pluses and minuses in our supply chain, we feel that our onshore wells effectively have flat total costs for the year compared to prior year. We do see some pluses and some minuses. Rig rates in 2025 for Eagle Ford are lower than 2024. We do see a little bit of pressure on tubular goods maybe in the second half of 2025, but it's fairly limited. I I think we're thinking of a 3%-5% type of impact on potential exposure. In Canada onshore, our program, of course, is nearly done, but we saw effectively flat cost year over year, so we don't see an issue there. On offshore, we're seeing a reduction in drill ship cost. We'll see a reduction in diesel cost, which is material. Probably seeing slight pressure on OCTG. In general, I think our team has done a great job of securing the equipment that we need, and most of the things that we need are already in country and not subjected to tariff pressures this year. I don't know, Tom, if you want to add any more commentary on that. Eric, I think you covered it. In 2025, we're in really good shape, in particular with our onshore plans. Even in 2026, offshore, we have a lot of long leads that we'd already locked in place. In 2025, I would say 70% of our spend is in the U.S. The remainder is outside of the U.S., which isn't really subject to tariffs. In 2026, it might be similar, even a little bit more spending outside the U.S. Great, thank you. Our next question comes from the line of Devin McDermott from Morgan Stanley. Your line is open. Hey, good morning. Thanks for taking my questions. I wanted to ask about the production profile for this year. We look at one Q, and I think it was a mix of non-operated activity in Canada impacting results. The full-year guide implies a step up in the back half oil production relative to the first half. I was hoping you could talk through some of the key drivers of that, the two Q step up, and then the incremental growth in the back half, and just the confidence in achieving kind of the implied full-year oil guidance range. Yeah, that's a great question, Devin. One of the things that I'm really happy with is the bulk of our onshore program is online right now. Our Karnes wells, which are highly productive, are all flowing today, and they're performing really well. Our Tupper Montney 10-well program are all online and, frankly, exceeding our expectations. I'm really feeling very confident that we've turned a corner operationally here. The production rates that we're already seeing in this quarter give me quite a bit of confidence in our ability to deliver our guide for the second quarter. If you move through the rest of the year, we'll bring on the remainder of our onshore wells so that it'd be more operated, non-operated Eagle Ford wells in the third quarter, and also our Kaybob Duvernay four-well pad. You see production in the third quarter increase a bit from the first. Then the fourth quarter, probably start to see a little bit of a decline from the high of the year, which would be in the third quarter. Got it. Okay. It's really helpful. You provided a lot of great detail in response to one of the earlier questions on just capital allocation and thoughts about where you could trim capital in a lower oil price environment. In a world where oil softens, but natural gas prices stay strong or improve further, you have a tremendous amount of gas resource in Canada. What milestones or what benchmarks do you need to see in order for that to become more competitive for further growth? Understanding there's capacity constraints on the processing plant right now, are there environments where that would actually compete for capital more and not be an area where you trim when you look out over the next few years? Yeah. I think what you mentioned is really important. We do have a plant capacity issue that we currently have a plant full at Tupper West, which is where the bulk of our Tupper production comes from. The ability to add more there in the really short run is limited. Although, and I've mentioned this in maybe past calls, I think we could see a commodity price signal there that would cause us to have more investment in wells so we maintain the plant full for a longer part of the year. Our typical plan over the last few years has been to fill the plant and the plant stay full for a while, and then after many months of no new wells, we decline from the peaks. We could potentially have another pad of wells, another five wells or three wells that could allow us to maintain our plant at a higher capacity. That is something that we could do on a fairly short cycle. That is something that we think about, we model, we evaluate. We will be watching that as we think Canadian gas prices may improve materially in the second half, 2025, with LNG Canada finally taking some volumes to the west. It is something we will watch and monitor. The capital efficiency of our Tupper wells is tremendous. We are getting wells this year that are producing early days at 17-25 million cubic feet per day. These wells cost us about $5 million, $5-$5.5 million. It is pretty easy to spend that, highly capital-efficient to bring on gas if we saw a high enough gas price. The concern I have and that we've been fairly careful about is historically, with a high price signal, every single player in Western Canada has pretty significant capital efficiency, and they spend money to bring on new wells, and gas price is negatively affected. It is something that we're going to be watching carefully. If we think there's a durable higher price, then we have a great opportunity to short-cycle invest into that. We are going to be watching the larger macro issues pretty carefully before we make that decision. Makes a lot of sense. Thank you. Thank you. Our next question comes from the line of Paul Cheng from Scotiabank. Your Your line is open. Hey, guys. Good morning. Morning, Paul. Eric, and maybe I do not know whether this is a fair question. Looking at the first quarter, your free cash flow negative and you spend $100 million in buyback. Just curious that, I mean, how we contemplate or that the board is thinking about a buyback is it really such a great idea, especially given the uncertainties that we are seeing to buy back stock and borrowing money, which you draw down on your credit facility? Obviously, with the uncertainty, it could also come with opportunity. Should we try to have a stronger balance sheet so in the event that you have opportunities that come up that you can strike? I mean, given Murphy actually has a very good track record in terms of acquisition. That is the first question. Thanks. Paul, that's a great question. The draw on our revolving credit facility is primarily driven by our $100 million share repurchase and the capital weighting of our first quarter capital weighting of our program, including the purchase of the FPSO. I think we did a really good deal with that FPSO. It's an oil price independent, about two-year payout, and it really helps us unlock an opportunity there. Pleased with that. We purchased $100 million of our stock in the first quarter, and we had pretty significant oil prices in the first quarter and a view at the time that they were going to remain to be fairly significant. We felt where our shares were trading at the time represented a significant disconnect in intrinsic value, and it made sense to do that. Obviously, commodity prices have softened since, and it's something that we've been watching carefully. We do, in general, want to be very disciplined around protecting our balance sheet. We are not likely to spend at a point where we would take on significant debt. We are going to be very careful about that. We will also potentially be opportunistic if we see a very large disconnect between our share price and what we think it is worth. I do not want to get in front of a board decision around what we might do about further share repurchase. Obviously, there would be limited adjusted free cash flow, which is a number after our dividend with oil prices in the low $50s. Taking on debt to buy back our stock is something that we would consider, but it is probably not likely. Okay. Second question, that the BW Pioneer, at least that looked to us that it's a great deal, I mean, two-year payback. A lot of pushback that we heard from Kyle is that, hey, normally that no one will sign a deal from a seller standpoint that to do a two-year buyback. Is there any kind of colors additionally that you can provide? What incentivizes the seller to sell at this price? Yeah. The seller was looking for two things: certainty in what to expect from potential ability to make money there, and also to raise cash for other issues in the rest of their business. It is the only FPSO operating for them in the Gulf of Mexico. At some point, they decided it was not something they wanted to keep on owning. We were happy to do a deal there that we think was a good deal. We did award a contract to the seller to continue to operate. They have been a very good operator for us on the asset. We are paying them to operate on our behalf, and they are making a little money doing that, and they are happy with that, the certainty that that cash flow provides for them, and they were able to address other corporate needs for cash. I think it was a win-win deal for both parties, and we're pretty pleased with it. All right. Will do. Thank you. Thank you. Our next question comes from the line of Charles Meade from Johnson Rice. Your line is open. Yes. Good morning, Eric, Tom, Chris, and the whole Murphy team there. I wanted to go back to what's happening in the Gulf of Mexico. If I'm understanding things correctly, it's your activity, including your planned activity with these workovers. That's really the big variables about how the 2025 production will play out. Can you talk a little bit more about what those two workovers are at Khaleesi Mormont? I'm thinking along the lines of, are these relatively simple zone changes moving up the hole, or are they more complex things where you're trying to remediate sand or water production or something like that? Okay. Yeah. Let me tell you what we're doing there, and then I'll go back and talk about the production impact of the year. The Khaleesi #2 well is investigating what we believe is a failed safety valve. That's a fairly simple thing to fix. We pull tubing out of the well and rerun tubing with a new safety valve in the well. So something that is routine. It's frustrating and disappointing that we have to do that. Obviously, that's not something we expect, especially from a relatively new well, but it's a pretty quick fix. The Samurai #3 is to do a sidetrack and new completion of an existing well. That's a slightly more involved activity, and that's why it'll take a little more time, and we'll wrap it up in the third quarter. The production impacts for the year, we highlighted some of the downtime we had in the Gulf of Mexico from non-operated assets and also from offshore Canada. That is driving, obviously, a first quarter impact. The other issue, which maybe is a little more nuanced, is the rigs that we had doing work at Mormont 4 and Samurai #3 that are now online. We were a little slower in conducting the work that we had been doing on those because we had winter storm activity that made periods of time where we could not be productive with the use of the rig. So we had non-productive time, which delayed them coming online. Now, the Marmulaard and the Khaleesi well activities are using the same two rigs. The rig got to the Calesia 2 and Marmulaard 3 later than we originally expected for the year, and then we just have to execute those, and they're going well now. It is hard to go back and make the rigs show up earlier. It happened already. I hope that helps. No, that does help. That's the kind of thing that wouldn't necessarily be obvious if you just looked at the presentation. I appreciate that. I want to ask a question on my follow-up on Vietnam. This most recent discovery, look, I think it's obviously going to be a good piece of business in shallow water nearby an existing development. I wanted to ask, it looks like it came in a little smaller than your pre-drill. I wondered if you could tell if there's any, what the relationship, if any, is between what you found in this zone and what you found in the two zones you found in your earlier Vietnam discovery. If anything you saw in this most recent one is going to affect or inform how you design your appraisal well on that earlier larger discovery. That's a great question, Charles. We did have a post-drill result that we believe is a bit lower than the pre-drill. We expected that we pre-drill, we expected that we would encounter oil in multiple paysands. We ended up encountering what's a nice discovery in one paysand. That paysand is the same age reservoir as our Hai Su Vong or Golden Camel discovery. What is significant about the relationship between the two is that the Lac Da Hong, the most recent discovery, Pink Camel, was drilled at a depth that is now deeper than Hai Su Vong discovery in the same paysand. They are structurally separated from each other, but encountering oil deep in the overall system and demonstrating that that Lac Da Hong recent discovery was able to flow at commercial rates is very encouraging for us. Distribution of sand, depth of oil, productivity of the well, reservoir quality, all those things are encouraging for further appraisal at Hai Su Vong. Got it. Thank you. Thank you. Our next question comes from the line of Carlos Escalante from Wolfe Research. Your Your line is open. Hey, good morning. Good morning, Eric. And team. Look, I guess I'd like to ask about Vietnam as well. Resonating one of my colleagues' comments, the results are certainly encouraging, and I think that it continues to direct a development at scale. Just along those same lines of what you just said, Eric, the reservoir quality, if you compare and contrast both HSV versus LDH, I think on your opening remarks, you mentioned that the flow rates for this latest well came at 2,500 at max flow rate capacity. Whereas if I compare it to your HSV comments where you mentioned that the 10,000 barrels of oil per day were facility constrained, not sure if we're reading too much into this, but was hoping that you guys can perhaps elaborate a little bit on what you're seeing in terms of an apples-to-apples comparison of the flow rates and also qualify for how long did these wells flow at such rates because that matters as much as the size of the flow rate. Carlos, I appreciate that. When we do these flow tests, the wells will flow for days. We conduct flow tests at a variety of production rates, and we do pressure buildup testing to learn as much as we can about the reservoirs. Typically, toward the end of one of these tests, we do flow the wells at a maximum rate just to get a sense for the total deliverability that's possible. The wells flow for days, but the highest production periods are hours long. They're not minutes long. They're hours long, and they're not days long. We're pretty comfortable that they tell us quite a bit about the ability of the reservoirs to produce. I'll note that the pay thickness of the recent discovery, Lac Da Hong, Pink Camel, is about one-third of the thickness in the main pay sand that we tested, flow tested at the Hai Su Vong discovery. Because we found a thinner pay, we would expect it to produce at a lower rate. If you adjust for pay thickness, they're similar. The Lac Da Hong may be slightly less productive per foot than Hai Su Vong, but we're really happy with it. It's clearly commercial. Typical production rates in this basin are 1,000-1,500 barrels per day per well. We're really pleased, obviously, with the strong flow rate from Hai Su Vong and the really quite compelling flow rate from Lac Da Hong. Just to clarify, both flow rates are at facility constraint levels, correct? No, the Hai Su Vong that we announced a result earlier in the year was at a facility constraint level, 10,000 barrels a day. Lac Da Hong produced what the well could deliver. It was less of a production rate, primarily because it's three times thinner. You would expect the thickness driving partly the production rate potential. Gotcha. All right. Makes sense. For my second question, on Côte d’Ivoire, we can talk about that for a minute. What are you looking for on those three exploration successes and knowing that there has been some adjacent success in the recent times with other companies? What are you looking for there, and how do you benchmark that and plan for 2026 and 2027 in the event of a successful campaign up there? Carlos, we provide on our slides quite a bit of detail around expected resource ranges for the three prospects that we expect to test. We provide details on those. The CIVET, the mean is 440 million barrels with a potential up to 1 billion. The COBUS is expected to be fairly similar with a bit higher, maybe over 1.2 billion. The Caracal prospect, which is a Malane lookalike, is probably 150 million barrels up to 360 million barrels. These are really sizable opportunities for us. We still have to award a rig there to do the work and finalize our well costs. We are talking about wells that are around $50 million-$60 million a piece. To test these types of volumes with that kind of well cost is really compelling for us. The fiscal terms, while I cannot give you all the details, they were very strong. The fiscal regime in Côte d'Ivoire has metrics, financial metrics that are not very different from the United States, which is the best fiscal regime in the world. We are really happy with the potential here to find significant resource tested with low well cost and with success can be very profitable for us. The CIVET prospect, which is likely to be our first well, which we will drill later this year, is geologically very similar to Eni's Moraine 1X or Kalau discovery that was announced in March of 2024. The Caracal prospect is very similar to the Malane producing field, which obviously gives us quite a bit of confidence that we have some nice-looking prospects here. The COBUS prospect is more frontier, testing two different plate types in one well, and we are really excited that the potential there is material. The other thing I'll point out is with success here, there's significant running room on other prospects on these blocks. Potentially, this could be really exciting for us if we have success in any of these prospects. Thank you, Eric. Thank you. Our next question comes from the line of Tim Rezvan from KeyBanc Capital Markets. Your line is open. Good morning, folks, and thank you for taking my questions. I just wanted to kind of close the loop on repurchases, obviously following a pretty heavy first quarter. Just to clarify, is it safe to say you are still in the market, but you're obviously keeping an eye on negative free cash flow for the year? Just trying to understand. I know you won't talk about amounts and timing, but is it safe to say that you're still going to remain active to some extent going forward? Tim, the way I would characterize it is we will not preclude being opportunistic, but we are very attentive to paying careful attention to our balance sheet. We like our industry-leading balance sheet. We're going to protect our industry-leading balance sheet. We think we have a good dividend policy. We're happy with the share repurchase we've done in the past. We won't preclude doing it, but we're probably not leaning into it too heavily. Okay. That's a perfect answer. Thank you. And then just again, one more on Vietnam. As the platform construction continues, I know it's easy for me here in the U.S. to say this, but why wouldn't you kind of incorporate this exploratory success from LDH, given it's three miles away? Are you sort of set in stone with the process you have in place? And why wouldn't you kind of pull that value forward if it's just a three-mile tieback to that facility? I guess the bigger question is sort of how we should think about gross flow rates at that facility from startup in 4Q 2026. Just trying to kind of get a little more context on that. Thank you. Yeah. Great question, Tim. The recent discovery, Lac Da Hong or Pink Camel, like I said earlier, we expect that that'll probably be developed with a wellhead platform tied into the production facility at Lac Da Hong A, which is the first platform that'll come online. We will need another platform to be able to drill wells that we can produce. We do not expect we'll be able to drill wells from the Lac Da Hong A platform to develop the Lac Da Hong discovery. A fairly simple wellhead platform, which we can see that the basis of the location of the drilling wells is likely the development concept there. Now, we can incorporate that into the production platform and the FPSO that are already part of the Lac Da Hong development, which should allow us to speed up the development. If it was a standalone with its own processing platform and own oil storage, then it would be a slower development. In a sense, what we're saying is we believe the forward plan will be an accelerated version of a development. That's why I think it's possible that we could be producing there before the end of this decade. Total capacity of the facility is probably 30,000 barrels a day, gross. Okay. Okay. I appreciate that. Thank you. Thank you. Our next question comes from the line of Leo Mariani from ROTH Capital. Line is open. Hi, guys. I wanted to follow up a little bit on activity levels. I appreciate all the commentary around looking to cut activity if oil's below $55 a barrel sustainably. You talked about a potential rather substantial cut of 20-40% next year, but I just wanted to kind of investigate potentially a middle ground scenario. I mean, what if oil is closer to $60? Do you guys kind of hold firm on sort of that capital spending range of the $1.1 billion-$1.3 billion, or is there kind of somewhere in the middle where maybe there's some more modest cuts as we look forward here? Leo, that's a great question. We really feel comfortable with the kind of capital level that we've been guiding, the $1.1 billion-$1.3 billion at oil prices that are anywhere from the high $50s to low $60s a barrel WTI. That's a good question. I think that if we thought we would have sustained 2026 oil prices that would be $60-$58, something like that, we would probably have a more significant capital program closer to what we've been guiding long term. With that type of oil price, we're able to easily manage our dividend and the capital program at that level. We would likely not have material free cash flow beyond that for debt reduction, but we'd be happy with that. I think considering that quite a bit of our capital investment is middle or longer cycle, and if you think that oil prices toward the later half of the decade are going up because of exhaustion of top-tier shale, then we think it would make sense to kind of invest through the cycle, especially with oil kind of in the low $60-high $50s range. Okay. That's helpful. I guess just on offshore Canada, obviously you guys had a bit of a hiccup there in the first quarter where you lost some volumes. It seems like it's kind of been an ongoing problem for a while where volumes I don't think have been what you guys wanted them to be. Can you maybe just give a little bit more kind of color and sort of a little bit more detailed update on kind of what you see happening there? Also just on LOE, you guys talked about LOE coming down in the second half of the year. Do you expect it to still be elevated kind of in the second quarter? Great questions. In Canada, offshore, what happened has really nothing to do with the assets themselves, the Hibernia, Terra Nova. The issue was an oil shuttle tanker had a collision with the port, and it became unavailable. The operators there had to come up with alternative methods, alternative tankers to deliver the oil from the facility to the tanker. It had nothing to do with the operators or the assets themselves. It was a short-lived issue. It did impact us, unfortunately. It impacted everybody producing offshore Canada. We're happy with the performance of the assets other than that. It's an unfortunate incident that affected us a bit. It's not something that is expected to be ongoing. It's very unusual, and it was fairly short-lived. If you look at operating expenses for the second quarter, because of the ongoing workover activity, I think that you'll see operating expenses continue to be elevated above sort of our long-run level. I think you'll see something in the $14 range for the second quarter. I think you'll see that drop into the $10-$11 range for the last two quarters of the year. Thank you. Thank you. Ladies and gentlemen, if there are any additional questions at this time, please press star followed by the number one. As a reminder, if you are using a speakerphone, please lift the handset before pressing the keys. Our next question comes from the line of Josh Silverstein from UBS. Your line is open. Yeah. Thanks. Good morning, everybody. Everybody's trying to talk about some kind of added flexibility to their programs. I'm curious how you kind of think about your Eagle Ford program. It's clearly kind of weighted to two quarters from a turn-on-line standpoint. As you go forward, is this the most efficient way to operate this asset, or do you think there could be a little bit more of a balanced approach across the year? Josh, thanks for that. The way that we've been managing our Eagle Ford business, if you go back to, say, 2021 through 2023, we were running a program that was very heavily weighted to the first two quarters. In 2024, we shifted our program to have steady drilling operations throughout the whole year. We're repeating that in 2025. It turns out, just based on the amount of activity of drilling in the fourth quarter and the later half of the third quarter we had planned, that we won't get to completing those wells that we drilled late 2025 until early 2026. The cadence of onlines is still a little bit more weighted to the first three quarters, but our rig activity is constant through the year. At the capital level we're investing, we really can't do more to smooth it out than that. Got it. Understood. As you guys are starting to contract out the offshore rigs for exploration and development programs kind of later on this year into next year, what's the current availability look like, and how are the discussions on pricing relative to maybe what you saw three and six months ago? For our Côte d'Ivoire plans, we are close to awarding a rig contract there. I'd rather not describe exactly what the rig rates are because we haven't awarded the contract. We are comfortable that you'll be happy, I think, with the rate there. It won't be particularly high. The rig availability is significant. I think we had over 10 rigs participate in our tender process. Quite a bit of rig activity is possible in Africa. When we get to the point of being able to award a contract, we'll probably be able to say more there. In Vietnam, the appraisal program that we have coming up, we have a rig contract that is nearly ready to be signed, and the rig rate is quite low. It's significantly lower than the rig rate we had during the exploration program. When we have those contracts awarded, I'd rather be able to talk about it later, but we're seeing some softening in rig rates, both in jackup and in drill ships. Pretty happy with that development as it relates to our ability to efficiently execute our exploration programs. Got it. Appreciate the call. Thanks, Josh. Our next question comes from the line of Brian Welly from Capital One Securities. Your line is open. Hey, good morning, everybody. I thought that I had jumped out of the queue, or at least I tried to. Leo kind of beat me to the punch with his LOE cadence question. So thank you for those comments. Happy to hear from you, Brian. Thanks. All right. Yeah. Thanks. There are no further questions from our phone lines. I would now like to turn the call back over to Eric Hambly for any closing remarks. Thank you for listening to our call today. If you have any additional questions, please follow up with our outstanding IR team. Have a good day, everyone. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we may ask that you disconnect your lines.