Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2025 Earnings Conference Call and Webcast. [Operator Instructions] This call is being recorded on Thursday, January 29, 2026. [Operator Instructions] I would now like to turn the conference over to Atif Riaz, Vice President, Investor Relations and Treasurer. Please go ahead.

Thank you, Joelle. Good morning, and welcome to our fourth quarter 2025 earnings conference call. Joining me today are Eric Hambly, President and CEO; Tom Mireles, Executive Vice President and CFO; and Chris Lorino, Senior Vice President, Operations. Yesterday after market close, we issued our fourth quarter earnings release, a slide presentation and a stockholder update. These documents can be found on Murphy's website, and we will reference them today throughout our call. As a reminder, today's call contains forward-looking statements as defined under U.S. securities laws. 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, please refer to our most recent annual report filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements, except as required by law. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of America. I will now turn the call over to Eric for opening remarks.

Thank you, Atif, and thank you, everyone, for joining us. I trust you have reviewed my quarterly stockholder update released yesterday, which covers our fourth quarter results, highlights for 2025 and our detailed plans for 2026. 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 Eagle Ford Shale program. Exploration and appraisal results were certainly the highlights of 2025 as we advanced 4 exploration and appraisal wells across 3 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 Vang, Golden Sea Lion field, oil discoveries at both of our exploration wells in the Gulf of America and unfortunately, a dry hole at Civette in Côte d'Ivoire. Although the results for Civette were disappointing, we remain optimistic about the next 2 prospects in the program, Caracal and Bubale, as all 3 wells were strategically chosen to target independent plays. In Vietnam, the Hai Su Vang, Golden Sea Lion appraisal found 429 feet of net oil pay without encountering the oil-water contact, indicating…

[Operator Instructions]Your first question comes from Paul Cheng with Scotiabank.

Just curious that on the Hai Su Vang-2X stem test, the 12,000 barrels per day, is it a equipment constraint or your stopover that this is the natural foray? And the second question is that if we're looking at your 2026 CapEx, you're saying that you are ready, if the condition needed, you could adjust it. So what portion of your CapEx in 2026 is considered flexible?

Great questions, Paul. Thanks for that. At our Hai Su Vang appraisal well, we encountered pay in 2 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 Vang-2X well, we tested the primary reservoir in 2 intervals, so 2 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 2 different tests. Collectively, they produced that 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 a 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 Cuu Long in one of these reservoirs similar to what we have is historically probably been producing in about a 2,000 barrel a…

Your next question comes from Carlos Escalante with Wolfe Research.

My first question would be around the drilling of Civette. 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 Bubale? And the reason I ask this is, 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 Civette, we were testing multiple objectives. Going to your last details of your question around the age of the reservoirs we're testing, the Civette, 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 3 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 learned about Civette is important for learning about the prospectivity that remains near Civette, but it doesn't have any implication to the Caracal and Bubale prospects. So we remain just as excited about those prospects as we were before learning anything about Civette. 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 have that -- 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. 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 it back in the day, you think this could be larger than the Eagle Ford as it stands today. It's roughly more than 35,000, 40,000, perhaps BOE per day oil weighted, obviously. But considering that you have -- you'll produce 15,000 or so net to you through LDV and you have the discovery in your hands 4x as large with HSV at least from our vantage point. Putting -- are you selling yourself short or am I missing something here?

Well, I think the short answer is we're not attempting to -- 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, 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 2 more appraisal wells to go, which are important to understand the field. And at the end of collecting data from those 2 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 Vang that it will take time to develop it. It won't have -- for example, we don't anticipate that every development well in the Hai Su Vang or Golden Sea Lion development will be online on the first day. There will probably be a sustained phase development campaign. And that may impact the peak rate. I feel like from what we know now to say that our Lac Da Vang, Golden Camel, plus our Hai Su Vang, Golden Sea Lion fields collectively should produce in that 30,000 to 50,000 net BOE 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 1 program, which I think is not the thing to do to create maximum shareholder value.

Your next question comes from Neil Mehta with Sachs.

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 is 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 get -- try to square the '27 number, any advice you can provide would be super.

Yes. 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 '25, we had no weather downtime. We have a provision in our '26 for 1,500 barrels a day roughly of weather downtime. I would love to have no repeated weather downtime. So if that happens, we basically have flat oil year-over-year, which would be nice. This year, we actually have a little more planned downtime at primarily our nonoperated 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 wells, 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 in the second half of the year, we obviously 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 Lac Da 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. And so as you pointed 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'm sorry?

I would say to the full year guide.

Got it. And then -- and just on Chinook, can you just talk about derisking it? It sounds like it will come on later this year. What are the gating 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 of 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 going to 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.

Your next question comes from Charles Meade with Johnson Rice Company.

I wanted to ask on the royalty mechanism up in the Tupper Montney. Can you give us a sense of the -- what the year-over-year delta in your NRI is? And also remind us how exactly that works, whether it's -- 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 at 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 wells 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. I want to ask a question about your -- about the Hai Su Vang in Vietnam. And I know with good reason, you've really been focused on the primary reservoir so far. But with these -- with the next 2 appraisal wells, is there an element of those appraisal 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 are the -- what's the path or what's the chances that secondary shallower reservoir will be considered real resource and can add to the overall resource in place and perhaps even the production rates down the line?

Yes, that's a great question. The Hai Su Vang-3X and 4X wells will both test that shallower reservoir. And that's one of the reasons why I'm hesitant to give a resource number just yet on it. We have 2 well penetrations in it where we found nice looking pay, and we need to assess the aerial extent of that reservoir, and it will really help us come up with a resource range from that. I would say that what we believe we 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 2 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 2 appraisal wells, they're going to assess both the shallower and the deeper?

Yes, that's correct.

Your next question comes from Chris Baker with Evercore.

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-digit oil growth despite obviously ramping volumes in Vietnam. I just want to make sure I heard that correctly and what that kind of implies in terms of the Gulf maybe coming off a little further in '27.

Yes. 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 developed 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, '27, first of all, because we haven't built the budget for that yet. But when we do build long-range plans 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.

Your next question comes from Leo Mariani with ROTH.

I was hoping to dive into Vietnam a little bit more here. But could you talk about kind of the ramp-up period for Lac Da Vang? You guys have talked about 10,000 to 15,000 barrel a day peak. 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 color on what that looks like?

Yes, sure. Great question. So just a reminder, our Lac Da Vang or Golden Camel development is a 2-phase development. The initial production will come from the Lac Da Vang 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, Lac Da Vang B platform and begin drilling wells in '28. Then the topsides 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 in 2029. I expect that we'll have a production ramp at Lac Da Vang 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 and 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 10,000 to 15,000 net peak rate, and it sounds like the second platform is more just going to hold production may be flat for a period of time before you start to go and decline and maybe that provides a shallower decline on the second platform. I just want to make sure I understand that.

Yes, you're understanding it correctly, Leo.

Okay. And then just also on Vietnam, you kind of talked about the goal, obviously, over time, bringing on Hai Su Vang of 30,000 to 50,000 barrels a day. Are you -- when would you roughly expect Hai Su Vang 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 of 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 lead and a little more context around how to think about the timing and the key milestones to realize production from Hai Su Vang. So we're appraising now. We expect to complete our appraisal program in Hai Su Vang 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 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 3- to 4-year execution time line. And so what I think is reasonable is first oil in 2031. If things go faster, it's possible to catch maybe the second half of 2030. But somewhere in the early 2030s feels like it's reasonable from what we know now about the Hai Su Vang 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 time line 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 how close do you think you are to being sort of drill ready? Is there seismic? Are you still analyzing things? Just any high-level color around that.

Sure. Great question. We're pretty excited about this Morocco entry. It is providing an opportunity to test a very large untested 4-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. And -- but we really are excited about the play here, very large 4-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 in the order -- on the order of $5 million maximum over the next 3 years.

Your next question comes from Tim Rezvan with KeyBanc.

I wanted to ask about Slide 13 in your deck. You call out a number of prospects across the Cuu Long Basin on that page, both inside and outside of Hai Su Vang. Your 2026 plan calls for the 2 HSV appraisals as well as a well at Lac Da Trang. Do you -- can you kind of talk maybe more about the medium-term appraisal plan and how we should think about the prospects you call out here?

Yes, great question. So the way I would characterize what we know about our business so far in Vietnam is that we have kind of 2 hubs that are emerging. The Lac Da Vang or Golden Camel development that comes online later this year should be a kind of a northern hub and our Hai Su Vang, Golden Sea Lion will likely function as a southern hub. We have other discoveries, which you note on the slide, Lac Da Trang, Lac Da Nau and Lac Da 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 Da Trang North well, which will test kind of the northern extension just to the north of Lac Da Vang 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. Appreciate it. And then 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% proved 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?

Yes. Just -- I'll 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 a 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 a 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 will move to proved developed this year. It will represent a significant move. We did move proved developed significant adds in prior years for the sanction of Lac Da Vang. We added significant reserves when we acquired the Cascade FPSO, which supports Cascade and Chinook fields. So there's a little bit of lumpiness sometimes in our offshore business, what's in proved 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.

Your next question comes from Phillip Jungwirth with BMO.

I guess building on the proved reserve question. In the offshore resource disclosure part of the deck, you did shift more projects to the sub-$40 breakeven category than you had previously. We often see this with shale, but I 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 7 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 oriented. 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 a 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 it may be 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 has seen a pretty significant re-rate of Montney valuations over the past 6 months. 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 from -- I meet once a week with the 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, 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.

Your next question comes from Betty Jiang with Barclays.

I have my question on one on legacy asset and one 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 pie you disclosed 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?

Yes. Great question. So the 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 St. Malo. 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 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 don't 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 time frame 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 color. 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 30,000 to 50,000 barrel per day number a few years into that, like by mid-2030s since it's a phased approach? And then with the 2 appraisal wells that you're drilling, what would you characterize as the -- like the most meaningful drivers of upside that you're looking for that could result in increases to either the resource or the production number?

Sure. I would say if we achieved Hai Su Vang first production in 2031, obviously, we don't yet have an 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 will probably be fine-tuned. By the time we have this call a year from now, we'll probably know what we -- a lot more we know there. But it's 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 Hai Su Vang-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 Vang-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, 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.

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 and ask that you please disconnect your lines.