Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2024 Earnings Conference Call. [Operator Instructions] I would now like to turn the conference over to Ms. Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, operator. Good morning, everyone, and thank you for joining us on our fourth quarter earnings call today. With me today 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 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 2. 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 2023 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.

Thank you, Kelly. Good morning, everyone, and thank you for joining us on our call today. Slide 3. Before I get started today, I would like to thank our employees for all their hard work this past year, and I'm looking forward to the exciting things we have ahead at Murphy. As we turn to Slide 3, I'd like to start with an update on our priorities of delever, execute, explore and return, which we first announced four years ago. Roger, Tom and I work closely to develop these priorities with Murphy's Board, and I'm pleased to continue our strategy as Murphy's newest President and Chief Executive Officer. We continue to delever in 2024 with $50 million reduction in senior notes through open-market repurchases. Since 2020, we've reduced our total debt by approximately 60% and reached our lowest net-debt in more than a decade at approximately $850 million at year-end 2024. Importantly, Murphy remains committed to achieving our long-term debt goal of $1 billion. In 2024, we produced 177,000 barrels of oil equivalent per day as we brought online 36 operated and 20 gross non-operated onshore wells and executed our offshore development plans. We also saw the non-operated St. Malo waterflood initiate water injection concluding a significant multi-year project. Overall, across our assets, we maintained our 11-year reserve life with 713 million barrels of oil equivalent approved reserves at year-end 2024. I'm pleased at the exciting news we shared earlier this month that Murphy drilled an oil discovery at the Hai Su Vang-1X exploration well in Vietnam. We'll share further details in a few minutes, but for now, I'll say that our partner group is very excited about the results and we're preparing to drill an appraisal well in the third quarter of this year. In the near-term, we will…

Thank you, Eric, and good morning. Slide 6. In the fourth quarter, Murphy recorded net income of $50 million, or $0.34 per diluted share and adjusted net income of $51 million, or $0.35 per diluted share. Overall, we generated adjusted EBITDA of $321 million with accrued CapEx of $186 million, excluding non-controlling interest. Other impacts in the quarter included $19 million of interest expense related to the early redemption of senior notes as well as a $28 million asset impairment for a field in the Gulf of Mexico. Slide 7. As we shared on our last call, Murphy executed a series of capital markets transactions in the fourth quarter, which ultimately extended our debt maturity profile and increased our senior unsecured credit facility by nearly 70%. Since year-end 2020, we have reduced total debt by approximately 60%, resulting in an approximately 50% reduction in annualized interest expense. We ended 2024 with $1.8 billion of liquidity, positioning Murphy Well to achieve our strategic priorities in the coming years. Slide 8. As our Tupper Montney -- natural gas production has increased the past few years, we have equally enhanced our natural gas marketing strategy to mitigate our price exposure to AECO as well as protect against volatility for our total natural gas volumes. Looking back at Murphy's 2024 total natural gas production, approximately 36% of our volumes were protected by AECO fixed-price forward sales contracts in Canada. Another 33% of volumes were sold at Henry Hub U.S. Midwest and U.S. Gulf Coast sales points. Overall, only 17% of our total natural gas volumes were sold in the open AECO market. We believe this marketing strategy is a key differentiator for Murphy. As the demand for natural gas in Canadian and Asian markets increases in future years and with multiple Canadian LNG export projects currently in progress, our Tupper Montney asset is strategically positioned with significant remaining locations to support this demand. Slide 9. Our preliminary approved reserves totaled 713 million barrels of oil equivalent at year-end 2024, representing an 83% reserve replacement ratio. Continuing to the -- contributing to the increase was approximately 12 million barrels of oil equivalent for the non-operated St. Malo field, primarily attributed to the waterflood project. In 2024, total approved reserves were 59% proved developed and 42% liquids-weighted. And we maintained our proved reserve life of 11 years. And with that, I will turn the call back over to Eric.

Thank you, Tom. Slide 11. As we previously announced, Murphy drilled an oil discovery at the Hai Su Vang-1X exploration well in Vietnam in the fourth quarter. The well was drilled to a total depth of 13,124 feet in 149 feet of water and accounted approximately 370 feet of net oil pay from two reservoirs. Ultimately, it was in line with our pre-drill mean to upward gross resource potential of 170 million to 430 million barrels of oil equivalent. I'm very excited to share our flow test results today as we achieved a facility-constrained flow rate of 10,000 barrels of oil per day from one reservoir. Additional testing showed high-quality 37-degree oil with a gas oil ratio of 1,100 standard cubic feet per barrel. We're continuing to review results and are planning to drill an appraisal well in the third quarter of 2025 to further establish the size of the resource. Slide 12. During the fourth quarter, we completed our seismic reprocessing project in Côte d'Ivoire and we are incorporating the final seismic data into our prospect assessments. We're excited at the opportunities across various exploration types on our five blocks. And we are preparing to begin a three-well exploration program late this year. Murphy also remains on track to submit a field development plan for the PON discovery by year-end 2025. With that, I will now turn the call over to Chris Lorino, Senior Vice President, Operations.

Thanks, Eric. Good morning, everyone. Slide 13. In Eagle Ford Shale, Murphy produced 30,000 barrels of oil equivalent per day in the fourth quarter with 85% of liquids. We brought online four operated wells in Catarina as planned and initiated drilling for our 2025 well delivery program with six operated wells and one non-operated well in Karnes. As we continually optimize our completions methods, we tested a revised design on the Catarina pad that was less successful than anticipated, which unfortunately resulted in nearly 2,000 barrels of oil equivalent per day impact to production for the quarter. In Tupper Montney, we achieved fourth quarter production of 387 million cubic-feet per day and drilled two wells that will be completed and come online in 2025. Our Kaybob Duvernay asset produced 4,000 barrels of oil equivalent per day with 71% liquids. Slide 14. In the Gulf of Mexico, we produced 68,000 barrels of oil equivalent per day during the quarter. We experienced operated production impacts of 1,800 barrels of oil equivalent per day due to a mechanical issue at a Khaleesi well, and 1,400 barrels of oil equivalent per day as a result of an offshore rig delay for the Samurai number three well workover. Additionally, our non-operated assets were impacted by late season hurricane causing 2,400 barrels of oil equivalent per day of weather downtime. On a positive note, we found additional pay when drilling operated Mormont number four well, which caused a small production impact due to the time required to evaluate and complete the additional pay. This well is now forecast to come online in first quarter 2025. Our offshore Canada assets produced 7,000 barrels of oil equivalent per day in the fourth quarter as we closed the first year of the non-operated Terra Nova field resuming production following…

Thank you, Chris. Slide 22. We're progressing our Lac Da Vang field development project in Vietnam, and I'm pleased that in the fourth quarter, we commenced construction of the LDV-A platform as well as executed the contract for the floating storage and offloading vessel. Our next steps will be to initiate construction of the FSO this quarter and begin development drilling in the second half of the year. Overall, we remain on track to achieve first oil in late 2026 with ongoing development through 2029. Slide 23. Murphy plans to drill two operated exploration wells in the Gulf of Mexico this year called Cello number one and Banjo number one. We remain focused on lower risk opportunities near existing infrastructure and highlight that the -- that these next prospects are located near the Murphy operated Delta House floating production system. Each well has an estimated net cost of $18 million and we are targeting to spud Cello number one in the second quarter with Banjo number one to follow in the third quarter. Slide 24. Following the success at Hai Su Vang in the fourth quarter and additional time needed for evaluation, the timing of our Lac Da Hong-1X exploration well in Vietnam shifted and we now plan to spud next month. Additionally, we're making preparations to drill an appraisal well at Hai Su Vang with a targeted spud date in the third quarter of 2025. We're looking forward to the results of this well as it will help determine the high-end of our resource estimate. Slide 25. Our 2025 plans also include initiating a three-well exploration program in Côte d'Ivoire beginning in the fourth quarter with the [indiscernible] well on Block CI-502. This well is targeting a mean to upward gross resource potential of 440 million to 1 billion…

[Operator Instructions] Your first question comes from the line of Arun Jayaram from JPMorgan. Please go ahead.

Good morning, Eric.

Morning, Arun.

Yes. I wanted to maybe start with maybe Slide 28, you've highlighted kind of the annual a planned CapEx program of $1.1 billion to $1.3 billion to deliver the low-single digit production growth. I guess one of the buy-side questions is, does that CapEx range kind of contemplate in the plan of development at Paon? And obviously some of the positive drill bit news at the HSV field. And just help us put that $1.1 billion to $1.3 billion into context given those two potential development projects?

Thanks, Arun. I think that's a really important question to help us clarify what's included here and what's not included. To be clear, our current long-range view that we're communicating involves developing our existing assets in line with what we're stating here on the slide and what we intend to do with our onshore assets. It also includes the full development of the Lac Da Vang field. It does not include any development costs related to Paon in Côte d'Ivoire, nor does it include costs related to developing Hai Su Vang in Vietnam. The recent discovery we made, which hopefully you spotted our tremendous flow rate from that well.

That's great. I just wanted to clarify that. And just maybe the follow-up to that is, can you give us a sense of further Paon development? I think you're submitting a plan of development to the government by year-end. And help us think about maybe the CapEx around that project, if you sized that? And we've been thinking in Vietnam around F&D costs in that, call-it $10 to $15 range. But I just wondering if you could maybe help us give us some initial thoughts on how CapEx could trend for those projects?

Okay. Thanks for that very much. Well, I'll start with Paon and then I'll touch on Vietnam. The Paon development is one that is an interesting field for us in Côte d'Ivoire. So we got involved in our acreage position in Côte d'Ivoire for exploration. We're exploring for oil. We have identified a number of really nice prospects that are quite sizable and we can test them with pretty low well costs. If you can test upwards of 400 million barrels for $40 million to $60 million gross well costs. That's a pretty exciting piece of business to be involved in. The Paon discovery happened to be in one of the blocks and our work commitment for that production sharing contract is to develop a field development plan by the end of 2025, and we're well on track to accomplish that. The field at Paon is an oilfield with a relatively small oil column and a large gas cap. For that reason, negotiating the terms of a gas sales agreement are quite important to whether or not that development moves forward. We're actively involved with various Ivorian government parties on negotiations around what that can be. And at this point, we're not 100% sure we'll have a project. We think that there's an opportunity. We believe that natural gas is needed in the country and there will be significant demand -- domestic demand in Côte d'Ivoire the resource that Paon can develop. Because we're in an active negotiation and there's a lot of different moving parts around how we might develop the field, timing, all that, it's really a little premature to say how that might look. I would tell you that I would not expect a near-term CapEx of significance for Paon. The typical timing for something like that…

Yes. Super helpful, Eric. Thanks a lot.

Thanks very much.

Thank you. And your next question comes from the line of Neil Mehta from Goldman Sachs. Please go ahead.

Yes, good morning, Eric and team. Just a couple of quick questions. First one is just clarifying on Q4, numbers become a little softer on production than I think where the Street was expecting and you called out some downtime onshore and offshore due to some mechanical issues and some delays. So could you just help us understand what happened in Q4 from a volume perspective and any lessons learned from that?

Sure, Neil, and thanks for joining our call. We had a pretty rough fourth quarter. We really would prefer to execute quite a bit better. I would characterize quite a few of those things as short-lived and they should mostly be resolved as we get toward the end of the second quarter this year. We had significant amount of downtime offshore for a few wells that are offline. We call out specifically the Samurai 3 workover, which we had -- we had been working on in the fourth quarter and expected to be able to return to production in the fourth quarter. So it should have contributed more. We had some delays executing that work because of some downtime with a rig and some winter storm activity, which delayed the work. So that well is now scheduled to come online in the first quarter. It's a significant well, about 4,500 barrels net comes online in the first-quarter. We had a well at Khaleesi that was offline for part of the fourth quarter because we were diagnosing what we think is a safety valve issue. As we look now with more clarity heading into the year, we're going to need to put a rig on that well, do some work on it and that well should come online in the second quarter. We also had a bit of downtime in our non-operated Gulf of Mexico business, primarily because of storms, we had a number of platform shut-ins for a late in the quarter, later than our typical storm season shut-ins and are primarily again in our non-operated Gulf of Mexico deepwater assets. That was a pretty significant impact for us. The other two -- couple of things we highlighted, which I'll just touch on briefly, we had our Eagle Ford Shale…

That was really helpful color. And then I wanted to stick on the Eagle Ford here, which as we look at your '25 CapEx guide for onshore, big driver of the growth does seem like it is in the Eagle Ford. So can you talk about how do you define success this year? What are you looking to accomplish and that revised completion design sounds like it was something that you work through and shouldn't affect your well performance here in '25?

Yes, that's a great question. Let me give you some context around that. In the Eagle Ford business, we've highlighted in the past that we sort of shifted our program to be a more steady well delivery. So instead of running a very concentrated two rig program early in the year, last year, we ran a rig all year long and it allowed us to set up for earlier in '25 completions than prior years. We intend to kind of keep that steady operation going. The impact of that is about a 3,000 or 10% increase 3,000 barrel a day or 10% increase in production year-over-year. So we're pleased with how we're on track to deliver that. We're allocating a little bit more capital because we had that program and we're going to continue drilling toward the end of the year. So if you look at well cadence, 2024, we had 20 operated wells. 2025, we have 35 operated wells and for only about $65 million more capital. So significantly better looking program for us. We have a fairly significant Karnes component to our '25 program, which is different than last year, which was fairly unique. In terms of how we're trying to execute, we're always trying to improve our operations. Over the last few years, we've been very successful in both our onshore Canada and our Eagle Ford business in trailing and deploying new completion styles, new adjustments, new operational things. And we've done really well with improving our operations, not just through supply cost matters, but also through operational improvements. One of the things that the team worked on, which I think is really significant over the past year, which we're disclosing on our call here is we've also reworked our future development program, so we can take advantage of those operational improvements, but also design a full-field development that's more efficient. Specifically in our Eagle Ford, we have a future plan of development that has 10% less wells, but those 10% fewer wells are completing 9% more rock. And so they're significantly more efficient from a capital leads to approximately 6% lower capital to develop the remaining resource. And we have similar type of improvements in our other onshore assets. So we're really excited about how we can continue along with our peers to try to strive for better and better performance from our shale business.

Thanks, team.

Thank you.

Thank you. And your next question comes from the line of Neal Dingmann from Truist Securities. Please go ahead.

Good morning, all. My first question is on the Gulf of Mexico, Eric. Maybe specifically, could you speak to how you all have risked and maybe how active of workover program will be needed in the play and maybe along with that, how active a development program will be needed in order to keep production relatively flat as I don't know, I think you were indicating it sounds like workover activity will remain relatively high. So I'm just kind of trying to get a sense of how we should think about workover maybe even development activity?

Okay. Yes, thanks, Neil. I'll start with that and I may have Chris help me out with some of the details. We have a fairly active first two quarters of workover activity. The Samurai 3 workover, which we expected initially to complete last quarter has drifted in to be completed in the first quarter. We have planned a Marmalard workover in a Delta house facility to drill a sidetrack and new completion of a well that's been offline for about a year. And we have, as I just mentioned in the Khaleesi field, a safety valve issue with one well that will fix in the second quarter and that's really the bulk of our activity from a workover perspective. We highlighted in the past year that we've had an abnormally large amount of offshore workovers affecting significant wells, which has hurt our business. And the way we think about it, we're near the end of that program and should expect it to be resolved by the end of the second quarter. Maybe Chris can provide just a few details on sort of the rates of those wells to help you think about the walkup of restoring the production from those. Right.

Right. Thanks, Eric. The -- for the Samurai well, first-off, we had some rig equip -- equipment issues that pushed us in Q4 into Q1. That's all behind us. We've got that fixed and moving forward. So we're looking at Q1 online data as we mentioned with about 4,000 to 5,000 net barrels of BOE per day for us. And then we have the Marmalard 3 and the Khaleesi 2 that we've mentioned. Marmalard 3 should be about 1,600 BOE nets in Q2 and Khaleesi 2 should be somewhere around 3,500 BOE net. So one thing to note, it's been a frustrating run of bad luck, but there's nothing that connects to all these, all these issues. They're all kind of unique in their own way. So it doesn't concern us long-term. And so it's -- at least here. It doesn't bother us. So -- and also we have nothing -- once we finish the Khaleesi 2 well, we're actually have no more planned for the second half of the year. So we'll have those behind us come mid-year.

Thanks, Chris. Hopefully that helps.

That -- it does answers that. And then you touched on it sort of my second question is just on Vietnam. I just want to make sure I'm clear. Can you give a sense of timing and the magnitude of capital spend around just want to make sure you've talked a bit about the development activity that's going to be coming there as well as the exploration. And I'm just wondering, again, make sure I have a sense of or unclear with the timing and maybe magnitude of the -- of the spend?

Okay. So for the Lac Da Vang development project, we are allocating $110 million of net capital to execute that this year. We'll have more capital to get the first oil in 2026. I believe 2026 capital is a little bit lower than 2025. If you look at the exploration and appraisal activities, we have a $10 million net cost for the Lac Da Hong well, which we will execute in the first quarter. And the appraisal well, we have a bit of work to do to define exactly what the cost of that will be, but I would ballpark it in the $20 million net cost range, something on that order.

Perfect. Perfect. Thanks for the details, Eric.

Thank you. And your next question comes from the line of Paul Cheng from Scotiabank. Please go ahead.

Hi guys, good morning. Eric, the -- can you share with us that what is the workover expense going to look like in the first quarter and second quarter? And what it was in the fourth quarter?

Paul, that's a really good question. And I don't know that I have that number handily in front of me. Do we have it? I don't see. No. I can talk to you a little bit operating expenses and the impact they have on that pretty handily, but the exact dollars, give me a second, if you don't mind.

Sure.

Clinical topics. Let -- Paul, instead of give you the exact dollars, let me frame it in the context of operating expenses. So --

Okay.

I expect the first quarter operating expenses for our company to be fairly elevated, maybe in the $15 to $16 per barrel range because we wrap up a lot of that work in the second quarter, then we have -- I should -- we should expect operating expenses to be more normal for us, probably in the $10 to $12 per barrel range.

And how about in the second quarter?

Again the second through fourth quarter should be sort of in the $10 to $12 a barrel range.

So even in the second quarter, because I thought you still have workover spill into the second quarter.

We do, Paul, but we also have a significant increase in production across the company. And so that's why you see that dollar per barrel operating expense come down to kind of a typical run rate for us in $10 to $12 barrel range.

Okay. In your presentation, you're saying that $1.1 billion to $1.3 billion annual CapEx that gives you the low-single digit. And if we do the math based on this year number, you don't really get to the 210, 220, which I think the company seriously has been targeting saying that by 2027, '26, '27, you get today. So we -- those target is now off or that we misunderstand the communication here?

No. So what we're trying to do with our longer range view here is sort of guide that we are allocating a certain amount of capital and that represents a certain reinvestment rate. When we do that in our plan in the '26 through 2030 timeframe, we do get to a production level in excess of 200,000 barrels a day and oil-weighted. And we do have some, some years that are maybe slightly higher than really low-single digit, a little higher growth numbers. But -- the plan that we have previously communicated that has us getting into the 200,000 barrel a day range and higher is consistent with our current view. It's the same as we were communicating in the past couple of years.

And so maybe that you can help us where that the growth going to come from? I mean, in the offshore business that I think you are probably targeting -- excluding Vietnam, you are targeting about flat and Vietnam is adding about 10 to 15, but it's probably not going to come on stream. And ramp up to full until 2029. And Eagle Ford doesn't seems like you are increasing the production and Duvernay doesn't look like you are increasing the production. So how we get to from 180 up to, say the 210 and 220.

Okay. Yes, thanks. So in 2026, we'll bring online a high rate well in our Samurai field and early in the year and we're planning an activity at a very high rate -- high ownership field in the Gulf of Mexico, which we'll disclose later that helps us significantly increase our Gulf of Mexico production. And then along with that, we have an execution through the end of this decade of our long list of Gulf of Mexico development projects that we sort of steadily execute within that capital allocation of $1.1 billion to $1.3 billion. And then Lac Da Vang production begins late in '26, and as we head through '27 and '28 ramps-up to plateau, which we maintain through 2029 with ongoing development. So if you look at significant high-rate wells with high ownership, in our Gulf of Mexico business, our long list of projects that are high return Gulf of Mexico, subsea tieback type of work and our Lac Da Vang development, we get to be over 200,000 barrels a day in the last and full of years of the decade.

I see. Okay. We do it. Thank you.

Thanks, Paul.

Thank you. And your next question comes from the line of Leo Mariani from ROTH Capital. Please go ahead.

Hi, I wanted to touch base a little bit on your offshore Canadian production. Looking at your guidance for first quarter in 2025, your offshore oil steps up a decent amount. Can you just kind of just speak to that? I mean, obviously I think the Terra Nova fields had significant downtime for a while. Have there been some operational changes made where you guys are expecting that to kind of have better run time going forward? Maybe you can just describe that a little bit.

Thanks, Leo. I'm very happy to say that Suncor has made significant improvement in the operation of Terra Nova as they exited last year. They worked with a lot more internal resource and some third-parties to enhance their operational reliability and they're doing quite well right now. And so for the first quarter of 2025, we're expecting that trend to continue and that's helping us have more confidence in Canadian total production offshore and also Terra Nova. So pretty pleased with the turn they made towards the latter part of last year with their operational reliability.

Okay. And then just jumping over to the Eagle Ford here. So you guys described kind of a completion design sort of SNAFU on four wells that cost you around 1,900 BOE per day. I mean that 1,900 seems pretty significant for a change in a completion design. I mean, were those wells just incredibly poor performers at the end of the day where maybe the rates were kind of a fraction of whatever your standard completion design is? Just seemed a little unusual at this point in the shale kind of evolution to sort of hear that. And then I guess just also just wanted to confirm, I think you guys sort of alluded to this, but you're obviously seeing Eagle Ford growth here in 2025, that 33,000 barrels a day, just to be clear on that, is that kind of more just somewhat of an anomaly on the growth this year and that's more like the type of number we could see on the out years as we get into '26, '27?

Okay, great questions. Yes, unfortunately that four-well pad that we tried, a new completion style, it did significantly underperform. The exact underperformance is material. I mean it's something like 50% to 60% of the rate we expected from the wells, which is unfortunate. We'll learn from it, we'll continue to try and improve. It is isolated to something we tried on one four-wheel pad. So it's not something that we're overly concerned about, but it is -- it is a disappointing impact to our fourth quarter. Because we're planning to run a steadier program in Eagle Ford over the next few years, you could expect to see our production probably in the higher end of our 30,000 to 35,000 barrel a day range. And if you go back and look at 2024 was around 30,000, but the few years before that were in the 33,000 to 35,000 range. So we are heading more back to a little bit higher in the range we've been guiding.

Okay. It's very helpful. Thank you.

Thank you. And your next question comes from the line of Charles Meade from Johnson Rice. Please go ahead.

Yes. Good morning, Eric to you and the whole Murphy team there.

Thank you.

You guys have touched on a lot of this Gulf of Mexico stuff and I think, I think Chris offered kind of a summary on this, but I would just want to go back and make sure I'm understanding and kind of synthesizing it right. So a lot -- it looks like a lot of the CapEx surprise, the higher capital spending in 1Q is Gulf of Mexico, but even kind of one-step more than that and really looks associated with the -- with the King's K fields there. And I'm wondering if, if -- I think you guys have made the case that it's going to be transient, but you look at things and in this case, it seems like a positive with Mormont, that you found another pay there. And so I'm curious, is your view of that set of fields changing or are we on some kind of different CapEx, but also volume trajectory there? Or is this you know just can you elaborate if that's the right understanding or what -- what's changed for the Gulf of Mexico in that field -- is the set of fields specifically?

Thanks, Charles. We are overall very happy with the performance of King's Key. We have continued to find more and more pay to develop. We -- as a, as a course of that, we've developed more wells, including the Mormont 4. The Khaleesi and Mormont fields in particular have done tremendously well. We are completing now ocean bottom node seismic survey over the Khaleesi, Mormont, Samurai fields and surrounding area, which we think will help us identify even further future development opportunities there, infield drilling zones that are not obviously imaged with our current seismic that we can develop. Very happy with those. But Khaleesi well with what looks like a safety valve problem is a very temporary thing. We'll fix that and we'll get it back online in the second quarter. These are very high rate, high-performing wells. We have high ownership. And when they're offline for a period, it is unfortunately fairly painful. In the Samurai field, we've highlighted in the past that one of the wells we had previously been producing from two zones, we shifted to produce from one zone at a time. All the resource that we expected originally is there, we'll get it. We'll just get it a little bit lower rate because we'll produce one zone and then the other. And as we talked about this morning, the Samurai 3 is quite a high rate well that's offline for a suspected tubing leak and we're working through that and should have the well online in the first quarter. And then we're adding a Samurai well that will come online early in 2026. And so Samurai well in '25 has some issues by '26, which should be back in line with kind of our life -- our expectations for the field. And just kind of emphasize, the reservoirs are performing as expected, mechanical issues have impacted our rate at times and we've also had extremely high rates in the past with really significant outperformance.

Got it. Thank you for that, that detail, Eric. And then if I could go to, to Vietnam, I was wondering if you guys could just kind of give us the narrative of, of that flow test you had. And I imagine that once you hit the facility constraint rate of 10,000 barrels a day, which is great. Your attention starts to go to some other metrics, whether it be pressures or flowing pressures or pressure transients. And so I wonder if you could just give us the narrative of that flow rate or rather that flow test and your reaction to it and how that's informing your decision with the appraisal well, how far to step-out and go down depth?

Great question. So we are really excited about the result. When you have a well at 13,000 feet that can flow 10,000 barrels a day in shallow water, that's a really strong. It's really indicative of a high-quality reservoir. We're excited about it. The well potential is a little bit higher than that, obviously. We are continuing to evaluate all of the well test that we did there and understand the implications of it. What I can say preliminarily is everything from the test is positive and we have more work to do to figure out what the total resource is, and that's why we plan an appraisal well for the third quarter 2025.

Got it. Thank you.

Thank you. And your next question comes from the line of Carlos Escalante from Wolfe Research. Please go ahead.

Hi, good morning, Eric and team. I guess I'd like to shift gears real quick to your Canada asset. You mentioned during your opening remarks that Cedar LNG has made some recent progress on securing pre-financing and whatnot. And we know that LNG Canada Phase 1 is due to start-up soon and Phase 2 is a possibility in the near term future. Now, that as well with the con -- with the U.S. context in which we've had a very cold winter so far, in which we've hit actually 9 Bcf per day of Canada imports to the U.S. I wonder if your strategy changes at all with your money asset and then how you see it moving forward?

Thanks, Carlos. So one of the things I think is important to understand about our Tupper Montney asset is with our well delivery program in 2024, we reached the plant capacity that we have and a plant capacity expansion project is a multi-year thing probably on the order of three years. We do have and are considering and evaluating currently the possibility of putting more capital to work to have deliverability of wells in excess of plant capacity that would allow us to have a higher total throughput for the year because as our plan is now with our 10-well program, we will return to plant capacity, but then in parts of the year with production decline, we drip below capacity. So near-term, something we're thinking about and evaluating. We would need to see a durable commodity price signal there that would cause us to push up our capital allocation to be able to accomplish that. Something we're thinking about and evaluating. I'm not there yet, but it is something that's on our horizon. Any more significant expansion would be again a multi-year project from permitting, engineering, construction, commissioning, all that.

Got you. Thank you. Appreciate the color there. Now going back to Vietnam and not to beat the dead horse, but on the latest HSV discovery, so it is my understanding that the -- one of the reservoirs that you hit is - one of the sandstones that you hit is a [indiscernible] will take kind of our geological characteristics. And that to me at least, it means that there may be a chance or a high probability that you may hit good quantities of oil, but that they may not necessarily be interconnected. The concern obviously would be that you'd need to have a separate -- a given amount of wells that would probably be higher than you need if the reservoir was more connected or the reservoirs rather will be more connected to each other. So all that to say and ask, how do you think about the development of the HSV reservoir if you do find that the -- they're not necessarily connected in the way that maybe or perhaps your LDV would be under the fractured granite reservoirs that you have.

Okay. That's a great question. The Hai Su Vang well found pay in two zones. Most of the pay was in one deeper zone, which is the zone we flow tested. That zone is expected to be laterally very extensive and that's what we're testing with our appraisal well. The other zone that we found nice looking high-quality net pay in is expected to be less laterally extensive and would be in volumes on top of the range we've already communicated. So we have work to do to appraise and assess those. Over time, those fields -- those reservoirs likely all get developed, but the core development would be the larger zone with more significant amount of pay we've demonstrated and have flow tested.

Thank you. Appreciate the color, Eric.

Thanks, Carlos.

Thank you. And your next question comes from the line of Geoff Jay, Daniel Energy Partners. Please go ahead.

Hi, guys. Just one quick one for me. Just can you provide any details on what didn't work with the new Eagle Ford completion design? And I guess, what's the path forward? Is it just going back to the old design? Or did you learn some things that may lead you to a different conclusion? Thanks.

Geoff, I think I'm going to let Chris handle some of that detail.

Okay. Yes, thanks for the question. We -- it really was just down to the sand intensity and the water is what we tinkered with. So those were the main components that, that got us. You can say we kind of found the point of diminishing returns, which for us, we've got a lot of running room in Catarina. We have a lot of inventory. So on the positive side, it helps us kind of moving forward to be more capital efficient in Catarina.

Great. I really appreciate it.

[Operator Instructions] Your next question comes from the line of Betty Jiang from Barclays. Please go ahead.

Hi, good morning. Thanks for taking my question. So I want to ask about the offshore development opportunities that you guys have that slide -- it's Slide 41. It seems like you guys have done a rework of the portfolio. So would love to hear about what has changed, what got added, what got removed. Did notice that the resource number has gone, gone up, but the CapEx has also gone up from $380 million to $450 million. So what's driving that? Is that cost inflation, project mix, anything along that line would be helpful. Thanks.

Okay. Thanks, Betty. We have -- as, we always continue to assess the remaining opportunities in our portfolio, team works all year. The way that we typically release these slides is we work them at the end of the year, beginning of the year and then we kind of lock them in for the year. So we talk about them all year long, but they're really driven by our annual process of identifying all the opportunities in our assets and our long range planning process. And so I would characterize it as probably slightly more opportunities that we've identified, but not dramatically different. With our long range planning process that was we've highlighted in the past, we, we have built into our plan that if we don't have offshore opportunities to fund, we pivot longer term to our onshore business. So as we identify more offshore opportunities, we pivot our longer-term allocation of CapEx to the offshore opportunities and not to the onshore. So, if you look at the total capital for the company, our guide of how that is deployed over the long range is a similar number. But as we've identified more opportunities offshore, we plan to put more capital to work there and we have the optionality to not invest as much in the outer years onshore because those onshore opportunities will be there when we want them beyond the end of this decade and the offshore opportunities, most of them have a use it or lose it type of component to them where the infrastructure or other issues related to the development of them won't be waiting around for us in the later 2030s.

Got it. So should I interpret this increase in the offshore CapEx, the longer-range offshore CapEx, a function of just more projects in the backlog? And that's…

Exactly.

Okay.

Exactly.

Got you. Okay. And then are those projects also seeing a higher breakeven price because the breakeven price has also moved up a bit.

We've assessed the costs and the development of all of them and the economics from time to time move around. The costs are probably up a little bit. One thing I'll highlight in terms of cost structure, major components for our offshore, particularly our subsea type of work, which dominates this driven by rig rates, which have been pretty stable. We have seen some cost escalation in subsea trees, subsea tieback installation type of work and we update our economics to reflect that and it probably pushed the breakevens up, I don't know, $2 a barrel.

Got it. No, that's really helpful. Thank you. My follow-up is on the HSV capital. And appreciate the color you -- the numbers, the bookend the $5 to $10 that you mentioned earlier this call. But would love your thoughts on how you think about your long-term corporate CapEx over time, that if this is a significant discovery, which it looks like it might be, we're looking at potentially this $1 billion-to-$1.5 billion type of capital just based on that range. How do you see that getting folded into the corporate spending level? Do you see that as an incremental, but certainly will still get high-return on that project? Or do you want to maintain the capital that's similar to current but back-out spending somewhere else?

Yes, it's a great question. I think we're fortunate with the timing of our current Vietnam project and the typical timeframe it takes to develop something new that as about the time we're ramping down our spending at Lac Da Vang, we could continue on with development of Hai Su Vang. And so if you just think about typical timeframe for appraisal and field development planning, field development plan approval and execution of something like Hai Su Vang, you're looking at a four-year to five-year type of timeframe. And so about the same time, we'd be pulling down capital allocation to Lac Da Vang, we could be ramping-up in Hai Su Vang. It's all manageable within our program. And as I highlighted a few minutes ago, the -- we have an ability to flex our onshore spending at the later part of the decade. In our long-range plan, we typically don't plan -- we don't include any exploration success. So when we have exploration success, it can take the place of the onshore ramp-up that we model long-range. We just delayed the ramp-up of our onshore business. So we're comfortable with the guide. I will caveat that with if we made a major discovery in Côte d'Ivoire, it would be likely beyond the CapEx that we're showing in this guide.

Perfect. That's really helpful. Thank you.

Thank you. And your next question comes from the line of Chris Baker from Evercore ISI. Please go ahead.

Hi, good morning. Eric, I appreciate you facing a lot of these, you know, unexpected issues head-on. I'm just curious, as you reflect on last year and put together this year's plan, is there -- should we think about any additional sort of conservativism baked into the guide beyond the typical gone weather items?

Well, I think that we're pretty happy with the way we typically guide weather. Obviously, we faced in the fourth quarter a later than normal storm impact. I would characterize that as quite abnormal. We have over the last several years, we've conducted multiple analyses of the impact that weather may have on us. We feel that the methodology that we have for accounting for storm activity in the Gulf of Mexico represents sort of a typical year. We've had some years with no storm activity. We've had some years with significant storm activity and we typically in our guide will use something that aims for the kind of mean expectation. For this year, that's about 1,700 barrels annual average of the storm activities typically in the third quarter and fourth quarter and about 80% of it we allocate to the third quarter and the rest of the fourth quarter.

And I guess -- sorry, just to put a finer point on it. Given some of the more unexpected items, you know, Gulf weather aside, just wondering if, if that you know impacts how you're thinking about guiding the rest of the portfolio outside of -- outside of gone weather?

Yes. So we did, as we've talked about previously and also this morning had a significant amount of workover activity for mechanical issues with wells in the Gulf of Mexico. We've included what we know we need to do here in our '25 plans, and we talked about them now this morning. It's not common to have this. So we don't think it makes sense to forecast ongoing workover activity every year in our business because quite a few of these wells have been producing for years, some of them decade without any issues. And so it's not something we think is systemic or requires an allocation or an assumption of ongoing workover downtime or costs.

Great. And then I appreciate you squeezing me in here. You know, last year, obviously significantly exceeded the cash return minimum that you guys have set? Maybe just any color in terms of how to think about the potential to see you guys exceed again this year and just sort of how to think about that, I guess, almost 80% cash return last year, how that was, how you guys came to that being the right sort of cash return outcome for the year?

Yes, thanks. Let me just make a few comments and then I'll have Tom jump in and provide a little more color. I think if you characterize what we've done with our business over the last few years, we're really happy with our performance. We've reduced our long-term debt significantly from $3 billion to under $1.3 billion. We've materially increased our dividend to now up to $1.30 a share. Really happy with how it's going. And over the last couple of years have picked-up the pace of our share repurchase program. And I think that's quite admirable and we've made a really great progress and happy with that. We're really happy to be in the Murphy 3.0, which gives us quite a bit of flexibility. And I'll let Tom kind of talk through how we think about the impact of that and how we think about timing of that.

Thanks, Eric. I appreciate the question, Chris. Yes, last year, we leaned pretty heavily into share repurchase. We thought it was the right thing to do under Murphy 3.0, given where our share price was trading at the time. That's something we'll continue to watch this year as well. We'll go in with the base you know minimum plan for share repurchase with our adjusted free cash flow, but maintain that flexibility throughout the year of making that call when we feel like there's a significant dislocation in our share price. Now keep in mind, our CapEx is a little bit more heavily loaded to the front half of the year. So we take our targets as an annual basis rather than quarter-by-quarter. So that may help you think through maybe the timing of when we might do something around our framework.

Makes sense. Thank you both.

Thank you.

Thank you.

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

Thank you for listening to our call today. Should 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 ask that you disconnect your lines.