Participants

Kelly Whitley; Vice President, Investor Relations and Communications; Murphy Oil Corp

Eric Hambly; President, Chief Operating Officer; Murphy Oil Corp

Thomas Mireles; Chief Financial Officer, Executive Vice President; Murphy Oil Corp

Chris Lorino; Senior Vice President Operations; Murphy Oil Corp

Arun Jayaram; Analyst; J.P. Morgan

Neil Mehta; Analyst; Goldman Sachs & Co. LLC

Neal Dingmann; Analyst; Truist Securities.

Paul Cheng; Analyst; Scotiabank Global Banking and Markets

Leo Mariani; Analyst; ROTH Capital Partners

Charles Meade; Analyst; Johnson Rice

Carlos Escalante; Analyst; Wolfe Research.

Betty Jiang; Analyst; Barclays

Chris Baker; Analyst; Evercore Group LLC.

Presentation

Operator

Good morning, ladies and gentlemen and welcome to the Murphy Oil Corporation fourth quarter, 2024 earnings conference call. If at any time during this call, you need assistance. Please press star zero for the operator. I would like to turn the conference over to MS Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Kelly Whitley

Thank you, operator. Good morning, everyone and thank you for joining us on our fourth quarter earnings call today with me today are Eric Hembly, President, Chief Executive Officer, Tom Mireles, Executive Vice President and Chief Financial Officer.
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 noncontrolling 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 1,995. 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 Hamley.

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 worked 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 water flood initiate water injection concluding a significant multiyear 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 soon spud the Lac Da Vang 1X exploration well in Vietnam and our team is also actively preparing to drill two operated exploration wells in the Gulf of Mexico and initiating a three well exploration program in Cote d'ivoire later this year. Looking at our fourth priority of return. I'd like to remind everyone. Then 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.
Slide 4, 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 28th, 2025 slide 5.
In fourth quarter, 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 from 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 natural gas liquids price of just over $23 per barrel and natural gas price of $1.84 per 1,000 cubic feet.
I will now turn the call over to our Chief Financial Officer, Tom Morales to share our financial results marketing update and a preliminary year end reserves.

Thomas Mireles

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 a crude CapEx of $186 million excluding noncontrolling 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 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 ACO 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 were protected by ACO fixed price forward sales contracts in Canada. Another 33% of volumes were sold at HDRI hub, us Midwest and us Gulf Coast sales points overall, only 17% of our total natural gas volumes were sold in the open ACO 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. Nine, 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 water flood project.
In 2024 total proved reserves were 59% proved developed and 42% liquids weighted and we maintained our pre reserve life of 11 years.
And with that, I will turn the call back over to Eric.

Eric Hambly

Thank you, Tom slide 11. As we previously announced Murphy drilled an oil discovery at the Hai Su Vang One X exploration well in Vietnam. In the fourth quarter, the well was drilled to a total depth of 13,124 ft in 149 ft of water and encountered approximately 370 ft of net oil pay from two reservoirs. Ultimately, it was in line with our predrill means 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 code of Loi and we are incorporating the final seismic data into our prospect assessments. We're excited at the opportunities that 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 pond discovery by year end 2025. With that, I will now turn the call over to Chris Lorino, senior Vice President operations.

Chris Lorino

Thanks Eric, good morning, everyone. Slide. 13 enable for Shell 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 planned and initiated drilling for our 2025 well delivery program with six operated wells and one non operated well in cars. As we continually optimize our completions methods, we tested a revised design on the Cana pad that was less successful than anticipated, which unfortunately resulted in nearly 2000 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 Kop 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 1800 barrels of oil equivalent per day due to a mechanical issue at a Kle 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 a 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 equipment per day in the fourth quarter as we closed the first year of the non operated Terranova field resuming production following the life extension project.
Slide. 16, 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 majority allocated to 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 Shell consistent with previous years. Approximately 12% or $145 million is dedicated to exploration spending for the year.
Additionally, it's more important to note that as part of our 2025 CapEx program, we are increasing spending in Vietnam as we advance our lock. The Bang build development project. Slide 17 for first quarter, 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 as we have not brought wells on line since last May in Canada, in October in the Eagle Ford Shell.
Additionally, this range is impacted by 4,400 barrels of oil equivalent per day. A plan 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 forecast full year production of 174.5 to 182.5000 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. Slide. 18 in Agle for Shell 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 CORS 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.
Slide 19 Murphy plans to spend $85 million in Tupper Montney in 2025 to bring on line 10 operated wells. The production forecast at 375 million cubic feet per day for the year.
Now that we have reached processing plant capacity, we are able to scale down future development as fewer wells are needed to offset natural production declines further. Our optimized development plan reduces Murphy's capital investment requirement while achieving a 15% increase in single well 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 nearbys Sims LNG project has secured necessary funds for its facility and the related Prince Rupert gas transmission pipeline with 750 remaining locations in Tman.
Murphy is well positioned to support the capacity needs as the project comes online within the next decade.
Slide, 20 approximately $55 million has been allocated to K Bob Duvernay in 2025 with four operated wells planned to come online in the third quarter. We forecast producing 5,000 barrels of old equipment 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.
The past few years, we have improved our future field development plans similar to the Eagle Ford shale looking at our K by Duvernay locations. We have increased lateral links and well spacing which will enhance our capital efficiency by 20%. Slide 21 our offshore capital budget includes approximately all 410 millionocated 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're also conducting an ocean bottom node seismic survey across our Khaleesi, Mormont and Samurai to better understand the reservoir and plan future development wells.
Murphy plans to spend approximately $110 million in Vietnam on the Lac Da Vang The field development project in 2025 as well as approximately $5 million the pond field development activities in Cote D'Ivore 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 with that. I'll hand it back to Eric.

Eric Hambly

Thank you, Chris slide 22. We're progressing our lokt on field development project in Vietnam. And I'm pleased that in the fourth quarter, we commenced construction of the LD VA 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 lock, the Hong One X 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 aspiration program in Civette beginning in the fourth quarter with the Civette well on block CI-502 this well is targeting a mean to upward gross resource potential of 440 million to 1 billion barrels of oil equivalent. And it is an opportunity for us to target significant resource potential at a relatively low cost.
Murphy plans to drill the next two exploration wells in 2026. While the specific order is still being determined, we've identified the prospects as Hibou Block-C-709 and Caracal Block CI-102. These exploration wells will also target potentially sizable resources and overall allow Murphy to test a variety of exploratory play types near recent peer discoveries.
Slide 27 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 Pond and Co of Noi Murphy's team will also be drilling several meaningful international exploration wells over the next 18 months that will test perspective, unrisked resources that equal five times our current offshore proved reserves.
Overall, we remain committed to returning cash to shareholders through our capital allocation framework and achieving our $1 billion debt target. Slide 28 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 multibasin 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 both 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.

Question and Answer Session

Operator

Thank you. (Operator Instructions)
Arun Jayaram from JP Morgan.

Arun Jayaram

Good morning, Eric. Morning room. Yeah, I wanted to, maybe start with maybe slide 28. You've highlighted kind of the annual plant CapEx program of $1.1 billion to $1.3 billion to deliver the low single digit production growth. I guess one of the by side questions is does that CapEx range kind of contemplate, the plan of development at payone and obviously some of the positive drillbit news at the HSV field and and just help us put that $1.1 billion to $1.3 billion into context, given those two, potential development projects.

Eric Hambly

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 of 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 pawn in Cote D'Ivore . Nor does it include costs related to developing Hai Su Vong in the recent discovery made, which hopefully you spotted our tremendous flow rate from that.

Arun Jayaram

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

Eric Hambly

Okay, thanks for that very much. I'll start with pa and then I'll touch on Vietnam. The Paw development is one that is an interesting field for us in Cote D'Ivore . So we got involved in our acreage position in Cote D'Ivore 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 cost. That's a pretty exciting piece of business to be involved in the box 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 pond is an oil field 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 significant demand, domestic demand and include about four of the resource that pond 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, I would not expect a near term CapEx of significance for pawn.
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 multiyear project like a three year type of time frame, something on that scale. So it may impact capital allocation in the later part of the decade '27 '28 '29. That's it's a little premature to say that. In Vietnam, we're really excited about the progress that we have made on our lokt development project we released today. Some details around timing of key activities. We started our platform construction in the fourth quarter of 2024.
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 heist on discovery that we made. Obviously, we have a lot of work to do to figure out how large it is, our explor our appraisal. Well, rather that 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 predrill range of 170 million to 430 million barrels. It's possibly a little larger when we drilled the Hai Su Vang -1X, 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 what we say is consistent with our predrill estimate. We did not encounter any water level. So an appraisal well will be targeted to identify how much oil might there be below the well lower on the structure and the resource has significant upside potential.
So we think about how do we 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 drill test. 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 costs 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.

Arun Jayaram

Yes, super helpful, Eric. Thanks a lot.

Eric Hambly

Thanks very much.

Operator

Neil Mehta from Goldman Sachs.

Neil Mehta

Yeah, good, good morning, Eric and team just a couple quick questions. First one is just clarifying on Q4. Numbers did come a little softer on production than I think where the street was expecting. And you called out some downtime onshore and offshore, do some mechanical issues and some delays. So could you just help us understand what happened in Q4 from a volume perspective and, and any lessons learned from that?

Eric Hambly

Sure, Neil and thanks for joining our call. We had a pretty rough fourth quarter You know, we really would prefer to execute quite a bit better. I characterized quite a few of those things as short live and they should mostly be resolved as we get toward the end of the second quarter of this year. We had significant amount of downtime offshore for a few wells that are offline. We call out specifically the samurai three work-over 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 the rig and some winter storm activity which delayed the work so that wealth is now scheduled to come online in the first quarter. It's a significant, well, about 4,500 barrels of net comes online in the first quarter. We had a well at [Kle] 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. We 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 the storms. We had a number of platform shut ins for a late in the quarter later than our typical storm season. Shut ins in our, again 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 an 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 it, we have factored that into our, our guidance, of course.
And then the last thing which is really a positive for us is that the Mormont Forwell encountered significantly more pay than we expected and more zones and 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 than, than less pay. And so the timing of that, mt number four well drifted into the first quarter of this year. So I'll give you a lot of details, 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 1st and 2nd 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 2nd and 3rd quarters. So we'll see our production grows to be significantly over 180,000 barrels a day in the last three quarters of the year.

Neil Mehta

That was really helpful color. And then Eric you want to stick on the Eagle Ford here, which is 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 in that revised completion design? Sounds like it was something that you work through and shouldn't affect your well performance here in '25.

Eric Hambly

Yeah, 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 barrels a day or 10% increase in production year over year.
So we're, 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 Carnes 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 trialing 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.

Operator

Neal Dingmann with Truist Securities.

Neal Dingmann

Morning. All. My first question is on the Gulf of Mexico. Maybe specifically, could you speak to, you know how you all have risk and maybe how active of workover PCA will be needed in the play. And maybe along with that how active of 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 work or activity will remain relatively high. So I'm just kind of trying to get a sense of how we should think about work over, maybe even development activity.

Eric Hambly

Okay. Yeah, thanks Neil. I'll start with that. 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 three workover which we expected initially to complete. Last quarter has drifted to be completed in the first quarter.
We have planned a marmalard workover in the 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 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 hurt our business and we, 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.

Chris Lorino

Thanks Eric. The for the samurai. Well, first off, we had some, rig equipment issues that pushed us in Q4 to Q1. That's all behind us. We've got that fixed and moving forward. So we're looking at Q1 online date as we mentioned with about 4,000 to 5,000 net barrels a week per day for us. And then we have the Marmalard three and the Khaleesi 2 that we've mentioned. Marmalard three should be about 1,600 BOE Nets in Q2 and Khaleesi two 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 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 two well, we actually have no more, no more planned for the second half of the year. So we'll have those behind us come mid year.

Neal Dingmann

Thanks Chris. Hopefully that helps. Does that answer that? And then you touched on this earlier, my second question just on Vietnam, I just want to make sure I'm clear. Can you give a sense of the timing and the magnitude of, of capital stand around? I just want to make sure you, 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 I'm clear with the timing and, and maybe magnitude of the of the Stand.

Eric Hambly

Okay. So for the Lac Da Vang development project, we're 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 $10 million net cost for the Lac Da Vang. 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.

Operator

Paul Cheng from Scotia Bank.

Paul Cheng

Hey 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?

Eric Hambly

Paul? That's a really good question and I don't know if I have that number handily in front of me. Do we have it? I don't, no, I can talk to you a little 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.
Paul, instead of give you the exact dollars, let me, let me frame it in the context of operating expenses. So 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.

Paul Cheng

And how about in the second quarter?

Eric Hambly

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

Paul Cheng

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

Eric Hambly

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.

Paul Cheng

Okay? In your presentation, you're saying that the $1.1 billion to $1.3 billion annual CapEx that give 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 previously 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.

Eric Hambly

No. So what we're trying to do with our long 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 time frame, 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 with 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 what we were communicating in the past couple of years.

Paul Cheng

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

Eric Hambly

Okay. Yeah, 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 Vangproduction 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 lock deong development, we get to be over 200,000 barrels a day in the last and full of years of the decade.

Operator

Leo Mariani from rock capital.

Leo Mariani

Hi 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 terranova fields had significant downtime for a while. Have there been some operational changes made where you guys are expecting that to kind of have a better run time going forward? If you can just describe that a little bit.

Eric Hambly

Thanks Leo. I'm very happy to say that Suncorp 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 toward the latter part of last year with their operational reliability.

Thomas Mireles

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 1900 BOE per day, I mean that 1900 seems pretty significant for a change in a completion design. I mean, with 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. You know, completion design, you know, is just seemed a little unusual.
You know, 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, you know, just somewhat of an anomaly on the growth this year. And that's more like the type of number we could see in the out years as we get into '26 '27.

Eric Hambly

Okay, great question. Yeah, unfortunately that four wheel pad that we tried a new completion style, it did significantly underperform. The exact underperformances 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 [14W 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 can 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 was around 30 but the few years before that were in the 33 to 35 range. So we are heading more back to a little bit higher in the range we've been guiding.

Leo Mariani

Okay. It's very helpful. Thank you.

Operator

Charles Meade from Johnson Rice.

Charles Meade

Yes, good morning Eric to you and the whole Murphy team there, you guys have had touched on a lot of this, this Gulf of Mexico stuff and I think, I think Chris offered a 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 Q1 is, is Gulf of Mexico, but even kind of one step more than that, it really looks associated with the you know, with the King's K fields there. And and I'm wondering if, I think you guys have made the case that it's going to be transient but, but you look at things and you know, in this case, it seems like a positive with Mormont that you found another pay there.
And so I'm curious, is, is your view of that set of fields changing or are we on some kind of kind of different CapEx but also volume trajectory there or is this, just can elaborate if that's the right understanding or, or, or what, what's changed for the Gulf of Mexico in that field set of fields specifically.

Eric Hambly

Thanks Charles. We're 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 four, the Mormont fields in particular have done tremendously well. We are completing now ocean bottom node seismic survey over the Lac Mormont.
Samurai field and surrounding area, which we think will help us identify even further future development opportunities there in field 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 belt 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 off line 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 three 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.

Charles Meade

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 you know, once you hit the, once you hit the facility, constraint rate of 10,000 barrels a day, which, which is great, Your attention starts to go to some other metrics, whether it be, pressures or, 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 their appraisal. Well, how far to step out and go down dip?

Eric Hambly

Great question. So we are really excited about the result. When you have a well at 13,000 ft 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've planned an appraisal. Well, for the third quarter, 2025.

Charles Meade

Got it. Thank you.

Operator

Carlos Escalante with Wolfe Research.

Carlos Escalante

Hey, good morning American team. I guess I'd like to shift gears real quick to your Canada asset. You mentioned during your opening remarks that [Cr L&G] has you made some recent progress on securing prefiling scene and whatnot? And we know that Lng Canada phase one is due to start up soon and phase two is a possibility in the near term future. Now, that as well with the US context in which we've had a very cold winter so far in which we've hit actually nine BCF per day of Canada imports to the US. I wonder if your strategy changes at all with your money asset and, and then how you see it moving forward?

Eric Hambly

Thanks Carlos. So, one of the things I think it's 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 multiyear thing probably on the 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 drift 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 of 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 multiyear project from permitting engineering construction commissioning. All that.

Carlos Escalante

Got you. Thank you. I appreciate the color there. Now, going back to Vietnam and, 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, is a auvi go take kind of 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, of wells. That would probably be higher than you need. If the reservoir was more connected or the reservoirs rather would be more connected to each other. So all that to say and ask, how do you think about the development of the H&V reservoir? If you do find that the they're not necessarily connected in the way that maybe your, perhaps your LDV would be under the fracture granite reservoirs that you have?

Eric Hambly

Okay. That's a great question. The high speed 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.

Carlos Escalante

Thank you. Appreciate the call.

Operator

[Jock Jay] Lia energy partners

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 you know, 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.

Eric Hambly

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

Chris Lorino

Okay. Yeah, thanks for the question. We, it really was just down to the sand intensity and the water as what we tinkered with. So those were the main components that that got us. You know, you can say we kind of found the point of diminishing returns, which you know, for us, we've got a lot of running room in Catarina, we got 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

Betty JiangBarclays

Betty Jiang

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 we'll 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 to 450]. So what's driving that is that cost, inflation, project mix? Anything along that line would be helpful? Thanks.

Chris Lorino

Okay, thanks, Betty. We have, as we always continue to assess our 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 they, 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 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, 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.

Betty Jiang

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 as a result?

Chris Lorino

Exactly.

Betty Jiang

And then, and are those projects also seeing a higher break even price because the break even price has also moved up a bit.

Eric Hambly

We've assessed the costs and the development of all of them and the economics that 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, a few dollars a barrel.

Betty Jiang

Got it. No, that's really helpful. Thank you. My follow up is on the HSV Capital N Appreciate the color the numbers, the book and 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 if this is a significant discovery, which it looks like it might be, we're looking at particularly at this bill to bill and half 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 we still get high return on that project. Or do you want to maintain a capital that's similar to current but back out spending somewhere else?

Eric Hambly

Yeah, that's a great question. I think we're fortunate with the timing of our current Vietnam project and the typical time frame 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 Soong.
And so if you just think about typical time frame for appraisal and field development planning, field development plan, approval and execution of something like Hai Su Vong, you're looking at a 4 to 5 year type of time frame.
And so about the same time, we'll be pulling down capital allocation to lock the long we could be ramping up in Hai Su Vong. 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 delay 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 Cote D'Ivore , it would be likely beyond the CapEx that we're showing in this guide.

Betty Jiang

Perfect. That's really. Helpful. Thank you.

Operator

Chris Baker from Evercord. I si please go ahead.

Chris Baker

Hey, 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 conservatism baked into the guide, beyond the you know, typical [gom] weather items?

Eric Hambly

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 analysis 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, and our guide will use something that aims for the kind of mean expectation for this year. That's about 700 barrels annual average. The storm activity is typically in the third and fourth quarter and about 80% of it, we allocate to the third quarter and the rest of the fourth quarter.

Chris Baker

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

Eric Hambly

Yeah, so we did as we talked about previously and also this morning had a significant amount of work-over 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.

Chris Baker

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 you know, 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 you know, sort of cash return outcome for the year.

Eric Hambly

Yeah, 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 reduced our long term debt significantly from $3 billion to under $1.3 billion. We've materially increased our dividend to now up to a $1.30 per 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.

I think sir, I appreciate the question, Chris. Yeah, last year we leaned pretty heavily into share re-purchase, 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 we'll go in with the base, minimum plan for share repurchase with our adjusted free cash flow, but maintain that flexibility throughout the year of making that call. 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 that may help you think through maybe the timing of when we might do something around our our framework.

Chris Baker

Makes sense. Thank you both

Operator

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.

Eric Hambly

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.

Operator

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