Murphy Oil Corporation

This morning, I will begin by sharing some key insights about our performance and then focus primarily on the year ahead. Before we dive in, I want to thank our employees. Their hard work and commitment made last year's impressive exploration and operational successes possible. Looking back, 2025 was underpinned by strong execution across our assets, despite a challenging commodity price environment. Our production, both for the fourth quarter and full year, exceeded guidance as we delivered some of the best performing onshore wells in company history and maintained strong uptime at our key offshore facilities. We also managed costs closely, reducing lease operating expenses by 20% year over year and capital expenditures below guidance, partly due to realized efficiency gains in our Eagleford Shale program. Exploration and appraisal results were certainly the highlights of 2025 as we advanced more exploration and appraisal wells across three continents in the fourth quarter alone. Knowing that many of you were keenly anticipating the results from these wells, we released updates as they became available. We reported a highly successful appraisal result at Hai Su Vong, Golden Sea Lionfield. Oil discoveries at both of our exploration wells in the Gulf of America and unfortunately, a dry hole at Savette in Cote d'Ivoire. Although the results for Savette were disappointing, we remain optimistic about the next two prospects in the program, Caracol and Boubal, as all three wells were strategically chosen to target independent plays. In Vietnam, the Hai Su Bong Golden Sea Lion appraisal found 429 feet of net oil pay without encountering the oil-water contact. indicating a resource that is significantly above our initial midpoint of 170 million barrels of oil equivalents. Although we're continuing the appraisal campaign with two additional wells, results to date suggest a significant new growth business for Murphy in Vietnam. To put that into context, our exploration results in Vietnam will help us build a business that, by the early 2030s, will surpass the scale of our current Eagleford shale operations. This outcome exemplifies the long-term organic value creation capability that makes us unique. In 2026, we will strategically invest in development, exploration, and appraisal activities in the Gulf of America, Vietnam, and Cote d'Ivoire that will grow our portfolio and enhance shareholder value in the mid to long term. Let's be upfront. We do not expect 2026 to be without its challenges. We're all aware of the unpredictable market environment and softening commodity prices. However, at Murphy, we've spent the last few years positioning the company to withstand a downturn. So this year is about making intentional strategic investments that set the groundwork for growth far beyond the next few quarters. Something that differentiates us from our peers. From an operational perspective, Our 2026 net production will be lower at 171,000 barrels of oil equivalents per day versus last year's 182,000 barrels of oil equivalents per day. Most of that production decrease is Tupper Montney natural gas volumes driven in part by higher gas prices and therefore higher royalties. So the cash flow impact will be muted. It's noteworthy that we'll maintain our Eagleford shale production flat with 25% less capital spend this year. Additionally, our lease operating expenses will stay in line with the $10 to $12 per barrel range that we have previously guided. We continue our focused exploration and appraisal program in the first half of 2026 with two appraisal wells in Vietnam's Hai Su Vang golden sea lion field and two exploration wells in Co To Voa. In addition, as I mentioned in my stockholder update, We have expanded our exploration portfolio with an entry into offshore Morocco and acquisition of seven new blocks in the Gulf of America. Bid results are pending for another seven blocks in the Gulf of America, where we were the apparent high bidder in the December 2025 lease sale. With industry's average reserve life at 12 years and Tier 1 shale inventories declining, our proactive approach to securing new blocks in diverse basins reinforces our exploration pipeline, demonstrates our unique ability to partner globally, and provides optionality for sustained growth in the decades ahead. Through all this, our balance sheet remains solid with a low leverage ratio and over $2 billion in liquidity. Our eye is on the long game. However, we have the ability, we have the flexibility to adjust if necessary to protect our balance sheet. we see an extended period of low commodity prices. We're ready to tighten the purse strings and pull back on capital spending. To sum it up, following a successful 2025 marked by robust operational execution, ongoing financial discipline, and an outstanding 80% success rate in our exploration efforts, we view 2026 as a year to invest in future growth and long-term shareholder value. We're navigating uncertainty by investing with intention sharpening our operations, and setting up Murphy for sustainable organic growth. With that, we're now ready to take your questions.

Thank you, ladies and gentlemen. We will now begin the question and answer session. Should you have a question, please press star followed by the one on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. Your first question comes from Paul Chang with Scotiabank. Your line is now open. Hey, guys. Good morning.

Good morning. Just curious that on the Hei Su Van 2X STEM test, the 12,000 bill per day, is it the equipment constraint or is choke or that this is the natural flow rate? And the second question is that if we're looking at your 2026 ethics are you saying that you you're ready if the condition needed you could adjust it so what portion of your capex in 2026 is considered flexible thank you great questions paul thanks for that at our high suvang appraisal well we encountered pay in two reservoirs

There's a shallow reservoir and a deeper reservoir that we're referring to lately as the primary reservoir, which is where we've been kind of guiding a range of resources. In our test program for the Hai Su Vong 2X well, we tested the primary reservoir in two intervals, so two different flow tests. The first flow test followed by a second flow test. Both of them had test rates around 6,000 barrels a day. They were not conducted together. They were conducted in sequence because of the mechanical nature of the well, the way we had to test it. We had to do two different tests. Collectively, they produced at 12,000 barrels a day. If we were to have a producing well that had the same sort of completion interval where we were producing the entire primary reservoir together, we expect that the well would flow about 12,000 barrels a day. That is not constrained by facilities. That's really what the reservoir was able to deliver. If you compare that, for example, to the test rate in our discovery well, which was a facility-constrained 10,000-barrel day, at the time, we communicated that we expect that was facility-constrained. And we had kind of internally estimated it might have been able to produce up to 12,000 barrels a day. And so we were happy to confirm without facility constraints that we're getting that type of productivity out of these wells. I think for context, that's extremely high production rates for this basin. A typical well in the Kulong in one of these reservoirs similar to what we have is historically probably been producing in about a 2,000 barrel a day range. So we're seeing what we think is very good reservoir quality, high productivity from our tests so far. So really compelling result there so far for us at the Hai Su Bong or Golden Sea Lion. Moving to your second question around CapEx. I would say admittedly for 2026, our capital is constrained mostly because we are choosing to constrain our flexibility around our CapEx for several reasons. We have investments that we're making that we believe make sense in nearly any oil price, and I'll kind of walk through those, and then I'll come back around to what is more flexible. The things that we expect to do because we think they create significant shareholder value this year and longer term are our LactaVong or Golden Camel development project. We have first oil in the fourth quarter this year. We're not going to stop investing in that. We're going to see that investment through and continue to bring that field online and ramp it up as we move through 2027. Our exploration program in Cote d'Ivoire, we have two remaining prospects to drill. They're very compelling, large resource with low well cost. Those are things we're going to do in nearly every oil price looking forward. The other significant investments we have to make are our appraisal program at High Subang, which we just talked about. Two more appraisal wells planned this year. Those are things that we will do almost definitely. And the last is the Chinook development well that we've talked about in our materials and in my stockholder update is a significant investment, which will take quite a bit of rig time this year to bring online in the second half of the year as very robust economics and We're a high owner and it's expected to be a high-rate well, so it'll have a significant impact in our second half of the year production rate and should help us exit the year with solid oil trajectory in our Gulf of America business. Those are the things that I look at our program and I say, what are we likely to do in almost every oil price scenario? There are other parts of our business that we have flexibility around. We could choose to do a lot of different things with the last three to four months of our rig program in the Gulf of America. In our Eagleford program, we have flexibility. In our onshore Canada, we have flexibility in what we might do. However, I will caveat that with a note that most of our onshore activity is very front half of the year weighted. So as we move through the year, the flexibility around 2026 onshore program starts to go away. So we might be able to flex down without significant onshore changes. We might be able to flex down our capital by 10% in 2026. If you think broader, you go into 2027 and say we have very low oil price in 27, which I don't think will be the case. But if we did, those things that I said we're almost definitely likely to do will not repeat. And then we have a lot of flexibility in a significantly lower capital program if we chose to do so. And significantly lower is probably a 30%, maybe 40% reduction in our annual capital program if we wanted to do that. And so I hope my comments kind of frame this year and then kind of the longer picture view of our flexibility around capital deployment.

No, it's great. Thank you.

Thanks, Paul.

Your next question comes from Carlos Escalante with Wolf Research. Your line is now open.

Good morning, Eric, Tom and Chris. My first question would be around the the drilling of Cevet. So if I may, could you perhaps detail to us what the exact failure mechanism was and how do you think that impacts the probability of success at Caracal and Buhbal? And the reason I ask this is, you know, I acknowledge that the geology is completely distant from one another, just how you're targeting separate structural prospects. But you were testing a concept, and I think I'm quoting you from prior calls, where you were testing something different that had been done since the dawn of Jubilee, the discovery of Jubilee. So wondering how your probability of geological success looks based on that, and if you're going to test anything different in terms of how you approach the targets and whatnot.

That's a good question. Thanks, Carlos. So at Cervet, we were testing multiple objectives. Going to your last details of your question around the age of the reservoirs, we're testing the Cervet. We were fortunate to be able to test multiple objectives, both younger and older than the kind of traditional play in the basin. We did find oil pay in multiple reservoirs, which is what we expected. We did not find oil in quantities to be commercial, which is, of course, disappointing. We will take what we learned from our evaluation program there and assess the future prospectivity on the block. I will say that the three prospects that we have planned for this year are all independent, test different age reservoirs. They're fundamentally very different. They do not have any dependence between each other. So what we learn about Cevet is important for learning about the prospectivity that remains near Cevet. but it doesn't have any implication to the Karakal and Bubal prospects. So we remain just as excited about those prospects as we were before learning anything about Savette. Just a little more color. It's always disappointing to drill a dry hole. It is nice, however, that the model we put together about trying to understand the geology and what's happening held together and that we found sands and we found oil pay. Would have loved to have found enough oil pay to have a commercial discovery. We do have more work to do to understand why we didn't find the oil in quantities that we expected, and that's something that we'll work on as we incorporate all the data we've collected from the well. It's just a little too early to be able to talk very clearly about it because the work is ongoing, and I don't have an answer yet.

Very clear and helpful. Thank you. And then on my follow-up, so alluding to your opening remarks about how big the Vietnam business could be, and also I think even Roger would say that back in the day, you think this could be larger than the Eagle Ford as it stands today. It's roughly more than 35, 40, perhaps, KBOE per day, oil-weighted, obviously. But Considering that you'll produce 15,000 or so net to you through LDV, you have a discovery in your hands four times as large with HSV, at least from our vantage point. Are you selling yourself short or am I missing something here?

Well, I think the short answer is we're not attempting to Um, at this point with what we know, we're not attempting to be overly aggressive in what we think may happen from the field. We have more work to do to appraise it. We've communicated before we drilled the well, uh, a range of resources that was significant. And then lately with appraisal results, we're saying we believe in the primary reservoir, we're probably closer to the high end of that initial range. We have two more appraisal wells to go, which are important to understand the field. And at the end of collecting data from those two appraisal wells, we think we're going to be in a position to give a much better range of recoverable resource from the primary reservoir and secondary reservoir, the shallower one. And so I'm hesitant to continually provide updates to the resource range. I think what we've said is indicative of what we expect to find. There's definitely upside, and that's why we're continuing to appraise. From a production rate perspective, there's a number of things happening. I believe because of a large resource that we expect in Hai Su Vong, that it'll take time to develop it. It won't have, for example, we don't anticipate that every development well in the Hai Su Vong or Golden Sea Lion development will be online on the first day. There'll probably be a sustained phase development campaign. that may impact the peak rate. I feel like, from what we know now, to say that our Loch de Vong Golden Camel plus our High Sioux Vong Golden Sea Lion fields collectively should produce 30,000 to 50,000 net BWE per day range in the early 2030s is a pretty good number. And if we know more or we think that number could move higher at the end of our appraisal campaign, we'll certainly talk about that in upcoming investor presentations and earnings calls. Right now, I feel like it's a pretty good assessment of what to expect. I'll just note that we're 40% working interest in both blocks. So the ability for it to go dramatically higher is limited unless we have a very, very heavy upfront, lots of wells producing on day one program, which I think is not the thing to do to create maximum shareholder value.

Very helpful, Eric. Thank you.

Your next question comes from Neil Mehta with SACS. Your line is now open.

Yeah, thanks so much, Eric. I appreciate the perspective. And I think just to unpack the oil volume point a little bit more, it did come in softer than I think expected. But I think a lot of that's just timing, as you said. In the back half of the year, we should get that ramp. So I know it's too early to talk about 27 for oil, but can you help us think about that exit and As people kind of try to square the 27 number, any advice you can provide would be super.

Yeah, great question, Neil. Just around the oil profile for the year, I think you've characterized it correctly. Our offshore business in 2026 annual average will be a little bit lower than it was in 2025. There's a number of, I guess, moving parts there. One, in 2025, we had no weather downtimes. We have a provision in our 26 for one and a half thousand barrels a day, roughly, of weather downtime. I would love to have no repeated weather downtime. So if that happens, we basically have flat boil year over year, which would be nice. This year, we actually have a little more planned downtime at primarily our non-operated facilities, which impacts us a little bit. And then we have a compelling investment at Chinook, which just takes a while to bring online. And so the timing of well's It kind of explains the other difference. Having said that, I think because the Chinook well is expected to be high rate and expected to come online the second half of the year, we ought to see from our offshore business a pretty decent exit rate. And then as we continue to layer on expected activity at the end of the year heading into 2027 from our offshore business and ramp up our Vietnam development, Loc De Vang, we should start to see some modest growth in our production profile and particularly our oily profile there. I've been hesitant, as you know, to give very specific numbers. I think you could think of our kind of midterm ramp in production to be low single digit feels good. Depending on what we choose to do and when we do it, you may see some years where that growth is very low single digit, 1%. You may see that it's 5%. It can get a little lumpy, but I think if you think about what we're doing with our assets, we're investing in the projects to have stability to modest growth. You layer on top of that our growing Vietnam business. When you look a little farther out, you see more material growth with that organically created Vietnam business coming. As you point out, it's a little early to talk about 2027, but in the context of what we're doing with our assets, it's fair to see similar or slightly higher production, and especially oily production, with growth in the Gulf and our Vietnam oily business growing.

Eric, that would be similar production to the full-year guide or to the exit rate?

I would say to the full-year guide.

Got it. And then, just on Chinook, can you just talk about de-risking it? It sounds like... It'll come on later this year. What are the gaining items there and confidence interval around that production?

Sure. The Chinook 8 development well is targeting a reservoir that is currently developed and producing, but is effectively an underdeveloped reservoir. So the well will be near a well that used to produce in the field at a rate similar to what we've quoted about 15,000 barrels per day gross. So we expect that there is very limited uncertainty in terms of the subsurface. In terms of production rate, you always have a little bit of uncertainty around just exactly how much pay thickness you find and how good the completion is. So from an execution perspective, the main issue is around timing of delivery. It's a deep well, it's gonna take a little while to drill and complete. So production outcome for the year The uncertainty is primarily driven by timing. We always have on a new well, a new deepwater well, you probably have a plus or minus 25% type of rate you could see on the initial production rate. I feel good about this one because it's basically replacing a well that had already produced in the field. So I would characterize it as relatively low uncertainty and nearly zero risk.

Yeah, very clear. Thank you, sir.

Your next question comes from Charles Mead with Johnson Rice Company. Your line is now open.

Good morning, Eric, to you and the rest of the Murphy team. Good morning, Charles. I wanted to ask on the royalty mechanism up in the Tupper Mountain, can you give us a sense of what the year-over-year delta in your NRI is and also remind us, How exactly that works, whether the 26 rate is based on the realized or an index price in 25 and how often it resets? Just fill out the picture there. Sure.

The royalty that we pay in our Tupper Montney asset is a sliding scale driven by the commodity price that we realize. And it moves fairly quickly as gas prices move up. So our royalty rate that we paid in 2025, annual for the year was 4.6%. And we're projecting with expected prices in 2026, an 8.4% rate, 8.6, one of those numbers, 8.4, I think. So it's roughly doubling the royalty rate. Having said that, it is still lower than 25% that everyone pays in the United States. So it does create a little bit of noise in our net gas volumes with prices moving around, but it is still quite low. There is one caveat to all of that is that is new wealth that come online, have a fixed royalty at 5% for a period of time. I think it's a couple of years.

Got it. Got it. And all things being equal, you'd be happy to pay a higher royalty rate with the better prices. Um, I want to ask a question about the Hai Su Vong in Vietnam. And I know with good reason, you've really been focused on the primary reservoir so far. But with the next two appraisal wells, is there an element of those appraised wells that's designed to assess that shallower secondary reservoir in addition to the deeper primary? And I guess... The real aim of that is what's the path or what's the chances that that secondary shallow reservoir will be considered real resource and can add to the overall resource in place and perhaps even the production race down the line?

Yeah, that's a great question. The Haisey-Vong 3X and 4X wells will both test that shallow reservoir. And that's one of the reasons why I'm hesitant to give a resource number just yet on it. We have two well penetrations in it where we found nice looking pay and we need to assess the aerial extent of that reservoir and it'll really help us come up with a resource range from that. I would say that what we believe we've found so far or the range of what we may have found so far in that shallow reservoir represents a commercial development. We're just hesitant to give a number on the resource range just yet because we have quite a bit of work to do. But both of the two remaining appraisal wells will assess that. And at the end of the program, as I mentioned earlier, I think we'll be in a position to give resource ranges on both the primary and secondary reservoir.

Eric, just a quick clarification. Those two appraisal wells, they're going to assess both the shallower and the deeper? Yes, that's correct. Got it. Okay, thank you.

Your next question comes from Chris Taker with Evercore. Your line is now open.

guys um thanks for the time you know just want to go back to that comment about 2027 i know it's still really early but eric i think you were saying low single d oil growth despite um you know obviously ramping volumes in vietnam just want to make sure i heard that correctly and what that kind of uh implies in terms of the gulf maybe coming off a little further uh in 27. yeah

I hate to get overly focused on exact numbers for 2027 because we haven't put together a budget for 2027. But I think if you look back at when we develop long range plans for our business, what we've communicated about what we can do with those assets over a midterm is to have low single digit growth. The comment I tried to make earlier around Chinook was that it is a high rate well that comes on in the second half of 26 and will produce all of 2027. And then we have a growing Vietnam business. And so I'm hesitant to give you an exact production growth number from 26 to 27, first of all, because we haven't built a budget for that yet. But when we do build long-range plants and we kind of model how we develop our different investment options across our portfolio, I expect that we'll have modest oil growth from 26 to 27.

Okay, great. Thank you.

Your next question comes from Leo Marani with Roth. Your line is now open.

Hi, I was hoping to dive into Vietnam a little bit more here, but could you talk about kind of the ramp-up period for Loc Duong? You guys have talked about 10,000 to 15,000 barrel-a-day peak. You know, roughly when do you think that peak will occur? And is this kind of a bit of a linear ramp-up over a handful of years? Just could you give us a little bit more... Call it on what that looks like.

Yeah, sure. Great question. So just a reminder, our Loctavong, our Golden Camel development, is a two-phase development. The initial production will come from the Loctavong A platform. We will drill half of the development wells from that platform. And in 28, we'll install a new substructure, a new jacket, Loctavong B platform, and begin drilling wells in 28. Then the top sides for that second platform will be installed in 2029 per our current plan. And so the full development will take place over the current period and end in 2029. I expect that we'll have a production ramp at Lac du Vent that moves up significantly from 26 to 27 and a peak likely in the later part of 27 or early part of 28 when we bring online a lot of wells. When we finish the development in 29, we'll start to see production decline after no more wells are online at the end of 2029. So exact timing will a little bit depend on well performance and how things go around the execution of how fast we drill the wells, bring them online. But I think you could see kind of a late 27, maybe early 28 peak rate there.

Okay. So maybe just to clarify, so that would be that 10 to 15,000 net peak rate. And it sounds like the The second platform is more just going to hold production maybe flat for a period of time before you start to go and decline, and maybe that provides a shallower decline with the second platform. I just want to make sure I understand that.

Yes, you're understanding it correctly, Leo.

Okay, thanks. And then just also on Vietnam, you kind of talked about the goal, obviously, over time, bringing on a high sous-vang of 30,000 to 50,000 barrels a day. Are you not, when would you roughly expect HiSumon to start contributing? Is this kind of like 2031 roughly to where you start to see that material jump up in sort of Vietnam? And I would imagine in a similar fashion may take a couple years also to kind of hit that peak rate. Can you just provide a little bit more kind of color on the high level thinking there?

Sure. It's a great question, actually. And I'll give a leave in a little more context around how to think about the timing and the key milestones to realize production from Hai Su Vong. So we're appraising now. We expect to complete our appraisal program at Hai Su Vong in the middle of this year by the end of the second quarter. And then we'll move into a field development plan process where we'll assess the field and come up with an optimal development. We'll work with our partners on that and get government approval for our field development plan. That will take some time. I would imagine it's about a year long process. And so we're looking at a targeting a project sanction or an FID likely in 2027 or by the end of 2027. And then what we've demonstrated with our development or similar developments in the past is sort of a three to four year execution timeline. And so what I think is reasonable is first oil in 2031 and If things go faster, it's possible to catch maybe the second half of 2030. Somewhere in the early 2030s feels like it's reasonable from what we know now about the high-speed long development. I think if I was just guessing, I would say 2031, but I'll be pressing my team to make it happen even faster. 2030 would be nice. And when we know more about the field, we'll definitely tell you what we think the timeline is.

Okay, that's super helpful, Eric. And just lastly on Morocco, obviously you guys introduced it. I know there's no obligation wells over the next handful of years, but can you maybe just outline kind of what your plans are over the next handful of years and, you know, how close do you think you are to being, you know, sort of drill ready? Is there seismic? Are you still analyzing things? Just any high-level color on that.

Sure, great question. We're pretty excited about this Morocco entry. It is providing an opportunity to test a very large untested four-way structure. The fiscal regime in Morocco is extremely good, primarily because there's hardly any oil production in Morocco. So the terms are really good in places where there's no oil. But we really are excited about the play here, very large four-way structure, and the cost to enter is extremely low. And the cost to figure out whether or not we want to go drill a well is also low. There is existing seismic data that we will reprocess and assess the prospectivity after reprocessing seismic over the next few years. Our expenditure there is going to be quite low, probably on the order of $5 million maximum over the next three years. Thank you. Very helpful.

Your next question comes from Tim Rezvan with KeyBank. Your line is now open.

Good morning, folks. Thank you for taking our questions. I wanted to ask about slide 13 in your deck. You call out a number of prospects across the Kulong Basin on that page, both inside and outside of Hai Su Vang. Your 2026 plan calls for the two HSV appraisals as well as a well at Lac du Trang.

do you can you kind of talk maybe more about the medium-term appraisal of plan and how we should think about the prospects you you call out here thanks yeah great question so do we ever characterize what we know about our business so far in vietnam is that we have kind of two hubs that are emerging the lot of vong or golden camel development that comes online later this year should be a kind of a northern hub and our high siu vong golden sea lion will likely function as a southern hub. We have other discoveries, which you note on the slide, Lac de Tronc, Lac de Nau and Lac de Hong. So that's white, brown and pink camel for those who are tracking camel colors. Those will likely be tied into those other facilities in the future. And then we have other prospects to drill. We're going to drill a Lac de Tronc north well, which will test kind of the northern extension just to the north of Lac de Vong with an exploration well this year. And then the remaining prospectivity, we're currently thinking about when do we test it and kind of sequencing that. And we have plenty of time to do it. We do not yet have a plan in place that's firm around when we'll test them, although I think that it's reasonable to expect that between 2028 and 2029 that we'll likely test a significant part of the remaining prospectivity on those blocks.

Okay, that's helpful context. I appreciate it. And my follow-up, in the release last night, you gave preliminary year-end 2025 reserves. We were a little bit surprised to see the decline. It was about 7% approved developed reserves. Oil, almost 13% year-over-year decline. Can you give some context on that change? Was that all price-related, or was there something else driving those numbers? Thank you.

Yeah, just give you my thoughts around the reserve situation as a whole. We had 103% overall reserve replacement on proved, which is pretty strong. We've maintained our reserves in similar level for over a decade, around 700 million barrels. So we had pretty solid reserve replacement, which I'm pretty pleased with. Over the last few years, we have proved developed reserves. that have kind of moved somewhere in the 50 to 57% of total proved. And so I'm happy with what we've done there. I think we have pretty solid outcome. We do have in our offshore business, sometimes we have a little bit of lumpiness in things that are in proved undeveloped moving to proved developed. So for example, the Chinook 8 well is booked as proved undeveloped. It'll move to proved developed this year. It'll represent a significant move. We did move proved developed significant ads in prior years for the sanction of Lac du Banc. We added significant reserves when we acquired the FPSO, which supports Cascade and Chinook fields. So there's a little bit of lumpiness sometimes in our offshore business, what's improved total versus proved developed. I wouldn't characterize any of that as abnormal for us. I think we're in a very good spot. And moving our total company from around 50% proved developed up to 57% proved developed is a very positive thing.

Okay. Appreciate the context. Thank you. Thanks.

Your next question comes from Philip Jungworth with BMO. Your line is now open.

Thanks. Good morning. I guess building on the approved reserve question, in the offshore resource disclosure part of the deck, you did shift more projects to the sub-$40 breakeven category than than you had previously. And we often see this with shale, but was just wondering if you could talk about the drivers of the improvement in the offshore inventory and then separately just how you see the seven new blocks in the Gulf of America adding to this, whether it's more focused on tieback potential to existing infrastructure or a bit more exploration. Sure.

I'll start with your last part there. The blocks that we picked up in the lease sale are exploration They're all oriented around exploration. One of the blocks is in the Ocotillo field where we have already made a discovery. It kind of represents the northern extension of Ocotillo. And so that's something that we're going to be working on trying to monetize with our partners. The overall update on project economics for our offshore business, there may be a little bit of movement. We update this once a year. So we update our costs and our resource estimates for all of our projects. I wouldn't characterize any of it as moving significantly. There might be minor changes. I wouldn't say that we've kind of wholesale reassessed our portfolio, that there's a dramatically different cost structure or resource. I think that maybe just slight movement around kind of fine-tuning what we expect of the projects and the timing of the projects.

Okay, great. And then the market's seen a pretty significant re-rate of Montney valuations over the past six months. I'm wondering how core you view the onshore position in Canada, whether it could make sense to take advantage of a strong A&D market, recycle capital to high return areas, or maybe some kind of drilling partnership carry is also possible just given the deep inventory and improving egress we're seeing.

That's a great question. To provide even bigger context, I think I would say we're very internally active at assessing what our assets do in our portfolio and how they may be viewed by the market. I meet once a week with a business development team and my executive leadership team, and we walk through opportunities for M&A. That includes buying things at an asset or company level and selling things at an asset level. And so we constantly are thinking about Does it make sense for us to have this asset? What does the asset do in our portfolio? Is it better that someone else has that asset and we do different things with the capital we might raise from selling it? So we're very actively looking at it. We're very aware of what we think our assets are worth to other people in the market. Right now, I don't look at an asset and say, we think we could transact where we would sell that and have an ability to deploy it to something that we think is even better. The Tupper Montney is somewhat unique in that the resource is tremendous. If you value the Tupper Montney business or our Tupper Montney business on discounted cash flow type of metric or any other assessment of the NAV, it's unique in that the number you calculate now is basically the same number you get a decade from now because the resource length is so long that it effectively doesn't change in value, which is an interesting thing and a nice thing to have. We like it. Because in high periods of high gas price, it can generate nice cash flows. In periods of low gas price, we break even or do a little better. It's very capital efficient, and it's a giant resource that provides long-term optionality where we think that the world will need more and more natural gas going forward. So we like it, but we are also aware other people like it, and we consider opportunities for the assets all the time, as we do with all of our assets. I hope that gave you more context. Maybe I can clarify if you have a follow-on.

No, that's great. Really helpful. Appreciate it, guys.

Ladies and gentlemen, as a reminder, should you have a question, please press star one. Your next question comes from Betty Jang with Barclays. Your line is now open.

Good morning, Eric. Thank you for taking my question. I have my question on one on legacy asset and one on on Vietnam. On legacy, on GOA, I'm not going to ask about 2027, but I was wondering how to think about the base decline rate for GOA assets with the offshore resource in the deck. GOA is also a smaller percentage of that offshore resources than a year ago. Just wondering with Vietnam growing, what is GOA doing longer term in that single-digit oil growth number?

Yeah, great question. So first question around decline rate. It's difficult to give you an exact number. When we've looked at this before and kind of in aggregate, if you invest nothing in the deepwater Gulf of America, you should expect about 18% annual decline rate. That's kind of what we've seen. Some fields have shallower decline, like, say, MOLO. Other fields are slightly steeper on balance. If I was guessing and I was putting it in my model, I would put an 18% decline rate. The projects that we've identified in our development set that we put in our appendix of our slide deck on slide 37, the Gulf of America projects, most of them of significant scale get developed by the end of this decade. So what I expect is our ability to to maintain scale, to have potentially slight growth in our GOA volumes through the end of the decade, and then have significant decline post-2029 with basically running out of things to do in our existing portfolio of discovered fields and developed fields. Those things are new wells or workovers, various opportunities in existing fields. Our pipeline of exploration activity is designed to help extend that runway So things like we just discovered, like Cello Banjo won't be in there yet. Ocotillo, I believe, is in there. So there are things that we've just discovered that will make their way into that over time, and they're not there yet. So I expect those will help us push out that plateau a little bit farther for the overall Gulf business. There's work to be done, obviously. And then we maintain a fairly robust portfolio of exploration opportunities in the Gulf that's a balance between near infrastructure opportunities that are higher chance of success, likely smaller volume, and larger opportunities that we'll probably test in the 27, 28 timeframe that could help extend the runway here. And so I think that helps characterize what to expect, kind of our core already identified business, and then what may happen with our drill bit through exploration.

No, that's very helpful, Connor. Thank you. Follow up on the Vietnam number. So you mentioned earlier that you expect first oil, maybe in 2030 to 2031 for HSV. Is it fair to say that you get to that 30 to 50,000 barrel per day number a few years into that, like by mid 2030s, since it's a phase approach? And then with the two appraisal wells that you're drilling, what would you characterize as the most meaningful drivers of upside that you're looking for that could result increases to either the resource or the production number?

Sure, I would say if we if we achieved high Siu Vong first production in 2031, obviously we don't yet have a exact plan of how we develop the field, but going on what kind of historically makes sense, I would expect that we would see peak production there by 2033. That's a guess. It'll probably be fine tuned. By the time we have this call a year from now, we probably know what we, a lot more we know there, but it's a reasonable to expect from first oil 2031 and production peak 2033. That's a guess. It's a reasonable guess. I think if I were you and trying to model it, that's probably what I would do. The appraisal wells at the Hai Su Vong 3X and 4X are designed to test the shallow in the primary reservoir and to prove the lateral extent. and also potentially deepen the known oil-water level in the field. As we pointed out, we did not encounter oil-water contact in our Hai Su Bong 2X appraisal well. We deepened the known oil-water level. There's still potential room on the structure to have more oil below the level we identified in the 2X, and we're definitely chasing that with the 3X and 4X wells. They'll also help us with the shallower reservoir I understand lateral extent, resource range. And again, I think by the time we get through our appraisal program and do a little updated modeling work later this year, we'll have a really good feel for what the range of resources for the field is and how we want to optimally develop it.

That's great. Thank you for that, Claire. There are no further questions at this time. I will now turn the call over to Eric Hambly for closing remarks.

Thank you, operator. I'd like to close by thanking our employees for the tremendous dedication and hard work and our shareholders for their ongoing trust. Thank you. And this concludes our call.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating in SIU. Please disconnect your lines.