Murphy Oil Corp Q4 FY2024 Earnings Call

Good morning, everyone, and welcome to the Murphy Oil Corporation Fourth Quarter 2024 Earnings Conference Call. I would now like to hand the conference over to Ms. Kelly Whitley, Vice President of Investor Relations and Communications. Please proceed.

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. 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. Before I get started, 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. I would 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 a $50 million reduction in senior notes through open-market repurchases. Since 2020, we've reduced our total debt by approximately 60% and have 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 about 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 soon spud the Lac Da Hong-1X exploration well in Vietnam, and our team is also actively preparing to drill two operated exploration wells in the Gulf of Mexico, initiating a three-well exploration program in Côte d'Ivoire later this year. Looking at our fourth priority of return, I'd like to remind everyone that in the third quarter of 2024, we entered Murphy 3.0 of our capital allocation framework, which increased returns to shareholders. Last year, we repurchased $300 million of stock, or 8 million shares. Today, we also announced an 8% increase in our quarterly cash dividend with our new annualized rate increasing to $1.30 per share. The capital allocation framework remains key to the Murphy team and we look forward to executing a full year according to the parameters of Murphy 3.0 with a minimum of 50% of adjusted free cash flow allocated to share buybacks. In 2024, we allocated nearly 80% of adjusted free cash flow to share repurchases, and we had $650 million remaining under our share repurchase authorization as of January 28, 2025. In the fourth quarter of 2024, we produced 175,000 barrels of oil equivalent per day with 85,000 barrels of oil per day. We saw nearly 11,000 barrels of oil equivalent per day of production impacts in the quarter across our operated and non-operated assets with the largest components being non-operated Gulf of Mexico downtime due to a late-season hurricane, lower performance due to a revised Eagle Ford shale completion design, a mechanical issue at an offshore well, an offshore rig delay and a small production impact due to the time required to evaluate and complete additional pay found in the Gulf of Mexico development well. Our assets generated $629 million of revenue in the fourth quarter with an average realized oil price of $70 per barrel, a natural gas liquids price of just over $23 per barrel and a natural gas price of $1.84 per 1,000 cubic feet. I will now turn the call over to our Chief Financial Officer, Tom Mireles to share our financial results, marketing update and a preliminary year-end reserves.

Thank you, Eric, and good morning. 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 capital expenditure 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. 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. As our Tupper Montney natural gas production has increased over the past few years, we have 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. Our preliminary approved reserves totaled 713 million barrels of oil equivalent at year-end 2024, representing an 83% reserve replacement ratio. 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. 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 for 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. 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 about the opportunities across various exploration types on our five blocks. We are preparing to begin a three-well exploration program late this year.

Thanks, Eric. Good morning, everyone. 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. 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 the 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 the first quarter of 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 the life extension project. Our 2025 CapEx is forecast to be in the range of $1.135 billion to $1.285 billion with approximately 60% of spending to occur in the first half of the year. Overall, approximately 85% of our capital plan is for development spending with the vast majority directed towards Murphy operated assets, giving us control over timing. Murphy is allocating nearly half of its capital plan to offshore assets, with 30% directed towards the Eagle Ford Shale, consistent with previous years. Approximately 12% or $145 million is dedicated to exploration spending for the year. Additionally, it's important to note that as part of our 2025 CapEx program, we are increasing spending in Vietnam as we advance our Lac Da Vang field development project.

For the first quarter of 2025, we forecast production of 159,000 to 167,000 barrels of oil equivalent per day with 83,500 barrels of oil per day. This range is notably lower than the fourth quarter due to approximately 7,000 barrels of oil equivalent per day of natural production declines across our onshore assets. We have not brought wells online since last May in Canada and October in the Eagle Ford Shale. Additionally, this range is impacted by 4,400 barrels of oil equivalent per day of planned operated onshore downtime and 2,900 barrels of oil equivalent per day of planned offshore downtime, primarily at non-operated assets. With our planned capital program for 2025, Murphy forecasts full-year production of 174,500 to 182,500 barrels of oil equivalent per day with 91,000 barrels of oil per day. This represents 11% production growth or nearly 20,000 barrels of oil equivalent per day from the first quarter to the fourth quarter. In the Eagle Ford Shale, Murphy plans to spend $360 million in 2025 to bring online 35 operated and 28 gross non-operated wells, with more than 50% of operated wells located in Karnes and nearly all wells scheduled to come online in the second and third quarters. We forecast production of 33,000 barrels of oil equivalent per day for the year as a result of these plans. Our team recently optimized Murphy's onshore development plans given ongoing results from improved completion designs, resulting in improved capital efficiencies. We are now employing an average 9% increase in laterals, which ultimately enables us to complete more rock more efficiently.

Murphy plans to spend $85 million in Tupper Montney in 2025 to bring online 10 operated wells with production forecast at 375 million cubic feet per day for the year. Now that we have reached processing plant capacity, we can scale down future development as fewer wells are needed to offset natural production declines. Our optimized development plan reduces Murphy's capital investment requirement while achieving a 15% increase in single-well EUR and growing our undiscounted cash flow by nearly 20% for the life of the field. As we continue monitoring the development of Canadian LNG projects in the area, we are encouraged by the recent news that the nearby Ksi Lisims LNG project has secured necessary funds for its facility and the related Prince Rupert Gas Transmission pipeline. With 750 remaining locations in Tupper Montney, Murphy is well-positioned to support the capacity needs as the project comes online over the next decade. Approximately $55 million has been allocated to Kaybob Duvernay in 2025, with four operated wells planned to come online in the third quarter. We forecast producing 5,000 barrels of oil equivalent per day in 2025. Murphy also intends to drill two wells in the fourth quarter, which will be completed and brought online in 2026. While we have maintained a small well program in this area over the past few years, we have improved our future field development plans, similar to the Eagle Ford Shale. Looking at our Kaybob Duvernay locations, we have increased lateral links and well spacing, which will enhance our capital efficiency by 20%. Our offshore capital budget includes approximately $410 million allocated to the Gulf of Mexico for development drilling, drilling and field development, including long-lead spending on development wells coming online in 2026 and 2027. We are also conducting an ocean bottom node seismic survey across our Khaleesi, Mormont and Samurai fields to better understand the reservoir and plan future development wells. Murphy plans to spend approximately $110 million in Vietnam on the Lac Da Vang field development project in 2025 as well as approximately $5 million on the Paon field development activities in Côte d'Ivoire. The remaining $20 million of Murphy's 2025 offshore capital budget will be allocated to offshore Canada, primarily for non-operated Hibernia development drilling. Overall, we forecast total offshore production of approximately 78,000 barrels of oil equivalent per day in 2025, with 68,000 barrels of oil equivalent per day from our Gulf of Mexico assets.

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. 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 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. 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. Our plans for 2025 also involve starting a three-well exploration program in Côte d'Ivoire in the fourth quarter, beginning with the well on Block CI-502. This well aims for a mean to upward gross resource potential of 440 million to 1 billion barrels of oil equivalent and presents an opportunity for us to target significant resources at a relatively low cost. Murphy intends to drill the next two exploration wells in 2026. While we are still deciding the specific order, we have identified the prospects as Hibou on Block CI-709 and Caracal on Block CI-102. These exploration wells will also aim for potentially large resources and will enable Murphy to assess various exploratory play types near recent peer discoveries. As we turn to Murphy's strategy over the next two years, I'd like to highlight that our plans remain essentially unchanged. The company will continue to deliver low single-digit production growth from its existing assets as we execute high-return oil-weighted offshore projects while maintaining Eagle Ford Shale and Tupper Montney production. We also look to achieve organic growth from Vietnam and potential development from Paon and Côte d'Ivoire. Murphy's team will also be drilling several meaningful international exploration wells over the next 18 months that will test prospective unrisked resources that equal five times our current offshore approved reserves. Overall, we remain committed to returning cash to shareholders through our capital allocation framework and achieving our $1 billion debt target. The foundation of our existing business and what we plan to accomplish across our growth opportunities in the next couple of years creates a runway for long-term success. The optionality of our existing multi-basin portfolio allows us to achieve our overall goals of oil-weighted growth and excess cash flow generation for shareholder returns. We have multiple high-impact international projects on our horizon while we continue infrastructure-led Gulf of Mexico exploration and our own backyard. It is an exciting time at Murphy, and exploration will remain a key differentiator and value creator for our company for years to come. With that, I will now turn the call over to the operator for questions.

Your first question comes from Arun Jayaram at 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 planned capital expenditure program of $1.1 billion to $1.3 billion to deliver 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 capital expenditure 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. 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 is 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. 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 domestic demand in Côte d'Ivoire for the resource that Paon can develop. Because we're in active negotiations and there are 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 capital expenditure of significance for Paon. The typical timing for something like that might be if you can negotiate agreements this year, you might have a sanction at the latest, very late in '25, more likely in '26. It's likely to be a multi-year project like a three-year type of timeframe, something on that scale. So it may impact capital allocation in the later part of the decade, '27, '28, '29, that's a little premature to say that. In Vietnam, we're really excited about the progress that we have made on our Lac Da Vang development project that we released today some details around timing of key activities. We started our platform construction in the fourth quarter of 2024, and it's moving along very nicely. We'll start construction of the FSO in the first quarter and development drilling in the fourth quarter. For the Hai Su Vang discovery we made, obviously, we have a lot of work to do to figure out how large it is. Our appraisal well, rather than we plan for the third quarter is targeted to understanding the upside size of the resource. As we highlighted today and earlier in the month, the results of the well are in line with our pre-drill range of 170 million to 430 million barrels. It's possibly a little larger. When we drilled the Hai Su Vang-1X well, we drilled it near the crest of the structure and we found oil in two zones. Most of the oil was in one zone. In that one zone, if we look at just what we found with the oil down to the lowest oil found in that well, that's consistent with our pre-drill estimate. We did not encounter any water level. So an appraisal well will be targeted to identify how much oil might be there below the well, lower on the structure, and the resource has significant upside potential. So if we think about how we would develop the field, it's a little early to say what the total resource would be. Obviously, we're excited about the flow rate potential, which we demonstrated with our drills and tests. If I was trying to frame an early assessment of capital to develop the field, there still needs to be a pretty broad range. I would think of $5 to $10 a barrel for development cost and probably $5 to $10 a barrel for operating costs. I think if you look at those and consider them in the context of deepwater developments, then it looks really attractive. The shallow water development with high flow rates is looking to be a very attractive project for us. I gave you a little bit longer than you asked for, but I think it helps frame sort of what we're looking for there.

Yes. Super helpful, Eric. Thanks a lot.

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 downtime offshore for a few wells that were offline. We called out specifically the Samurai 3 workover, which we expected initially to complete last quarter, has drifted into the first quarter. 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 later in the quarter 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 things we highlighted, I'll just touch on briefly, we had our Eagle Ford Shale four-well pad in Catarina that we tried a new completion style and it underperformed our expectations that will have a lingering effect into 2025, but pretty minimal because the wells declined relatively steeply the shale wells. So we have factored that into our guidance, of course. The last thing, which is really a positive for us is that the Mormont 4 well encountered significantly more pay than we expected and more zones. We ended up having to complete more zones, or having, I should say, the opportunity to complete more zones and it takes a little longer to complete more pay compared to less pay. And so the timing of that Mormont number four well drifted into the first quarter of this year. So I'll give you a lot of detail. I'll step back and sort of characterize. We don't expect storm downtime in the Gulf to repeat. The timing of well delivery again should be significantly resolved as we progress through the first and second quarters of 2025 and then we continue to deliver our production. I'll frame a little bit around production growth. Obviously, the guide for the first quarter is relatively low. We highlighted why and if you think about the cadence for the rest of the year, the delivery of our new onshore wells is very heavy in the second and third quarters. So we'll see our production growth to be significantly over 180,000 barrels a day in the last three quarters of the year.

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, a 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 it 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've 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 keep that steady operation going. The impact of that is about a 3,000 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. If you look at well cadence, in 2024 we had 20 operated wells; in 2025, we have 35 operated wells and for only about $65 million more capital. So a significantly better looking program for us. We have a fairly significant Karnes component to our '25 program, which is different from 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 processes. We've done really well with improving our operations, not just through supply cost matters, but also through operational improvements. One thing the team worked on, which I think is really significant over the past year, which we're disclosing on our call here is that 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% fewer wells, but those 10% fewer wells are completing 9% more rock. They're significantly more efficient from a capital perspective, leading to approximately 6% lower capital to develop the remaining resource. We have similar type of improvements in our other onshore assets. 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. 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. Could you speak to how you all have risked and maybe how active of workover program will be needed in the play and how active a development program will be needed to keep production relatively flat? It sounds like workover activity will remain relatively high, so I'm just trying to get a sense of how we should think about workover and 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. We have, as I just mentioned in the Khaleesi field, a safety valve issue with one well that we'll 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. 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 walk-up of restoring the production from those.

Right. Thanks, Eric. For the Samurai well, first-off, we had some rig equipment issues that pushed us from 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. One thing to note, it's been a frustrating run of bad luck, but there's nothing that connects to all these issues; they're all kind of unique in their own way. So it doesn't concern us long-term. And so, at least here, it doesn't bother us.

Thanks, Chris. Hopefully that helps.

That it does answer 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 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. 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, can you share with us what the workover expense is 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. I don't know that I have that number handily in front of me. Let me talk to you a little bit about 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.

Instead of giving you the exact dollars, let me frame it in the context of operating expenses. 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. 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 the $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. 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 there. So those targets are 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. We do have some years that are maybe slightly higher than really low-single digit, a little higher growth numbers. The plan that we have previously communicated 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 seem like you are increasing the production and Duvernay doesn't look like you are increasing the production. So how do we get 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 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. 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. 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. If you look at significant high-rate wells with high ownership in our Gulf of Mexico business, along with 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.

Thank you, 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 resources and some third parties to enhance their operational reliability and they're doing quite well right now. 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 issue 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 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-well pad. So it's not something that we're overly concerned about, but 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. If you go back and look at 2024, it 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 have covered a lot regarding the Gulf of Mexico, and Chris provided a summary on it, but I want to ensure I'm grasping and consolidating the information correctly. It appears the significant portion of the unexpected capital expenditures and increased spending in Q1 is linked to the Gulf of Mexico, particularly the King's K fields. I'm curious whether you believe this will be a temporary situation. It seems positive with the discovery at Mormont indicating another productive area. Has your perspective on these fields changed, or are we seeing a different trend in capital expenditures and production volumes there? Can you clarify if my understanding is accurate and what has shifted for the Gulf of Mexico in that area?

Thanks, Charles. We are very pleased with King's Key's performance. We have continued to discover more pay to develop, leading to the development of additional wells, including Mormont 4. The Khaleesi and Mormont fields, in particular, have performed exceptionally well. We are currently conducting an ocean bottom node seismic survey over the Khaleesi, Mormont, Samurai fields, and adjacent areas, which we believe will help us identify more future development opportunities in drilling zones that our current seismic does not clearly reveal. We are very pleased with these developments. However, the Khaleesi well is experiencing a temporary safety valve issue, which we will address and expect to have it back online in the second quarter. These wells have high rates and performance, and any downtime is unfortunately challenging. In the Samurai field, we have previously mentioned that we adjusted our approach to production from one well by shifting to produce from one zone at a time, rather than two. All the resources we initially anticipated are still there; we will obtain them, albeit at a slightly lower rate as we alternate between zones. As we discussed earlier, the Samurai 3 well, a high-rate well, is currently offline due to a suspected tubing leak, but we are working to resolve that and expect to have it online in the first quarter. Additionally, we will be bringing another Samurai well online early in 2026. Although there are issues with the Samurai well in '25, we anticipate getting back to our expected performance levels for the field by '26. To emphasize, the reservoirs are performing as anticipated; we have faced mechanical issues that have affected our rates at times, but we have also experienced exceptionally high rates in the past with significant outperformance.

Got it. Thank you for that detail, Eric. If I could go to Vietnam, I was wondering if you guys could just kind of give us the narrative of that flow test you had. 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. 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. 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 tests 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 Canadian asset. You mentioned during your opening remarks that Cedar LNG has made some recent progress on securing pre-financing and whatnot. 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 along 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 how you see it moving forward?

Thanks, Carlos. 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 an evaluation underway to consider putting more capital to work to have deliverability of wells in excess of plant capacity. This would allow us to have a higher total throughput because as our current plan is with our 10-well program; we will return to plant capacity, but then in parts of the year with production decline, we drift below capacity. This is something we're considering and evaluating. We would need to see a durable commodity price signal there that would cause us to push up our capital allocation. Any more significant expansion would be again a multi-year project from permitting, engineering, construction, and commissioning.

Thank you for the clarification. I would like to revisit the situation in Vietnam, particularly regarding the recent HSV discovery. My understanding is that one of the sandstone reservoirs you encountered exhibits specific geological traits. This suggests that while there could be a significant amount of oil present, the reservoirs might not be interconnected. The challenge here is that you would require a greater number of wells than you would if the reservoir were more interconnected. With that in mind, how do you plan to approach the development of the HSV reservoir if it turns out that the reservoirs are not interconnected, as might be the case with your LDV under the fractured granite reservoirs?

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. We have work to do to appraise and assess those. Over time, those fields and reservoirs likely all get developed, but the core development would be the larger zone with more significant amounts of pay we've demonstrated and have flow tested.

Thank you. Appreciate the color, Eric.

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? 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.

Thanks for the question. It really came down to the sand intensity and the amount of water we adjusted. These were the main factors that affected us. We seem to have reached a point of diminishing returns, but we have a lot of potential for growth in Catarina and ample inventory. On the bright side, this positions us to be more capital efficient as we move forward in Catarina.

Great. I really appreciate it.

Your next question comes from 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. 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 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, the 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. 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. I would characterize it as probably slightly more opportunities that we've identified, but not dramatically different. With our long-range planning process that we've highlighted in the past, we've 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 guidance for how that is deployed over the long range is a similar number. As we identify more opportunities offshore, we plan to put more capital to work there. 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?

Exactly.

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; 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. I appreciate the numbers you mentioned earlier in this call regarding the $5 to $10 range. I would love to hear your thoughts on your long-term corporate CapEx over time. If this turns out to be a significant discovery, which it appears it might be, we could be looking at potential capital in the range of $1 billion to $1.5 billion based on that. How do you envision that integrating into your corporate spending? Do you consider this an incremental addition while still expecting high returns from that project, or do you plan to maintain a capital level similar to the current one but reduce spending in other areas?

Yes, it's a great question. We're in a fortunate position with the timing of our current Vietnam project and the usual timeline for developing something new. As we begin to reduce our spending at Lac Da Vang, we can simultaneously continue the development of Hai Su Vang. While we are pulling back on capital allocation for Lac Da Vang, we can start increasing investment in Hai Su Vang. This is manageable within our overall program. As I mentioned earlier, we have the flexibility to adjust our onshore spending towards the end of the decade. In our long-term plan, we usually do not factor in any exploration success. Therefore, when we do achieve exploration success, it can replace the projected onshore ramp-up we have planned for the long term. We would simply postpone that ramp-up for our onshore business. We're comfortable with the guidance provided, although I should note that if we discover something significant in Côte d'Ivoire, it could exceed the capital expenditure outlined in our guidance.

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 addressing many of the unexpected issues directly. As you reflect on last year and develop this year's plan, should we consider any additional caution in the guidance beyond the usual weather-related factors?

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 conducted multiple analyses over the last several years of the impact that weather may have on us. We feel that the methodology we have for accounting storm activity in the Gulf of Mexico represents 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 storm activities typically in the third and fourth quarters with about 80% of it allocated to the third quarter and the rest of the fourth quarter.

I just want to clarify something. Considering some of the unexpected factors, aside from the Gulf weather, I'm curious how that affects your guidance for the rest of the portfolio outside of the weather-related issues.

Yes. 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 this morning. It's not common to have this. 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 for a decade, without any issues. 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. Over the last couple of years, we've picked up the pace of our share repurchase program. I think that's quite admirable, and we've made really great progress. We're happy to be in the Murphy 3.0, which gives us quite a bit of flexibility. I'll let Tom kind of talk through how we think about the impact of that and how we think about the 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 a 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 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.