Earnings Call Transcript
Murphy Oil Corp (MUR)
Earnings Call Transcript - MUR Q4 2025
Operator, Operator
Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2025 Earnings Conference Call and Webcast. This call is being recorded on Thursday, January 29, 2026. I would now like to turn the conference over to Atif Riaz, Vice President, Investor Relations and Treasurer. Please go ahead.
Atif Riaz, Vice President, Investor Relations and Treasurer
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.
Eric Hambly, President and CEO
Thank you, everyone, for joining us today. I hope you had a chance to review my quarterly stockholder update released yesterday, which covers our fourth quarter results, highlights for 2025, and our plans for 2026. This morning, I will share some key insights about our performance and focus primarily on the year ahead. First, I want to express my gratitude to our employees; their hard work and dedication made last year's impressive exploration and operational successes possible. Looking back, 2025 was supported by strong execution across our assets, even amid a challenging commodity price environment. Our production for both the fourth quarter and the full year exceeded guidance as we delivered some of the best onshore wells in company history and maintained strong uptime at our key offshore facilities. We managed costs effectively, reducing lease operating expenses by 20% year-over-year and keeping capital expenditures below guidance, partly due to efficiency gains in our Eagle Ford Shale program. Exploration and appraisal results were highlights of 2025 as we advanced four wells across three continents in the fourth quarter. Knowing many of you were eager for these results, we provided updates as they became available. We reported a successful appraisal result at Hai Su Vang, oil discoveries at both exploration wells in the Gulf of America, and a dry hole at Civette in Côte d'Ivoire. While the Civette results were disappointing, we remain optimistic about the next two prospects in the program, Caracal and Bubale, as all three wells were strategically chosen to target independent plays. In Vietnam, the Hai Su Vang appraisal found 429 feet of net oil pay without encountering the oil-water contact, indicating a resource significantly above our initial midpoint of 170 million barrels of oil equivalents. Although we are continuing the appraisal campaign with two additional wells, results to date suggest a significant new growth opportunity for Murphy in Vietnam. Our exploration results in Vietnam will help us build a business that could surpass the scale of our current Eagle Ford Shale operations by the early 2030s, showcasing our long-term organic value creation capability. In 2026, we will strategically invest in development, exploration, and appraisal activities in the Gulf of America, Vietnam, and Côte d'Ivoire to grow our portfolio and enhance shareholder value in the mid- to long term. We understand that 2026 will come with its challenges. The unpredictable market environment and softening commodity prices are well-known. However, at Murphy, we've spent the last few years positioning the company to weather a downturn. This year is focused on making strategic investments that lay the groundwork for growth well beyond the next few quarters, distinguishing us from our peers. Operationally, our 2026 net production is projected to be lower at 171,000 barrels of oil equivalents per day compared to last year's 182,000 barrels of oil equivalents per day. Most of this decrease is due to Tupper Montney natural gas volumes, driven by higher gas prices and increased royalties, impacting cash flow minimally. Notably, we will maintain our Eagle Ford Shale production with 25% less capital spending this year. Our lease operating expenses will remain within the previously guided $10 to $12 per barrel range. We will continue our focused exploration and appraisal program in the first half of 2026 with two appraisal wells in Vietnam's Hai Su Vang field and two exploration wells in Côte d'Ivoire. Additionally, as mentioned in my stockholder update, we have expanded our exploration portfolio by entering offshore Morocco and acquiring seven new blocks in the Gulf of America. We expect results for another seven blocks in the Gulf of America, where we were the apparent high bidder in the December 2025 lease sale. With the industry's average reserve life at 12 years and Tier 1 shale inventories declining, our proactive approach to securing new blocks in various basins strengthens our exploration pipeline and showcases our ability to partner globally, providing options for sustained growth in the future. Our balance sheet remains solid with a low leverage ratio and over $2 billion in liquidity. We are focused on the long game but also have the flexibility to adjust as needed to protect our balance sheet. If we encounter an extended period of low commodity prices, we are prepared to tighten spending. In summary, following a successful 2025 marked by strong operational execution, financial discipline, and an impressive 80% success rate in exploration efforts, we see 2026 as a year to invest in future growth and long-term shareholder value. We are navigating uncertainty by investing with intention, enhancing operations, and positioning Murphy for sustainable organic growth. With that, we are now ready to take your questions.
Operator, Operator
Your first question comes from Paul Cheng with Scotiabank.
Paul Cheng, Analyst
Just curious that on the Hai Su Vang-2X stem test, the 12,000 barrels per day, is it an equipment constraint or your stoppage 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?
Eric Hambly, President and CEO
Great questions, Paul. At our Hai Su Vang appraisal well, we found pay in two reservoirs: a shallow one and a deeper one, which we now call the primary reservoir, where we’ve been estimating the resource range. In our testing program for the Hai Su Vang-2X well, we evaluated the primary reservoir in two separate intervals, conducting two different flow tests. The first flow test was followed by a second, with both achieving test rates around 6,000 barrels a day. These were not conducted simultaneously but rather in sequence due to the well's mechanical nature, which necessitated two distinct tests. Together, they produced 12,000 barrels a day. If we had a producing well with the same completion interval and produced from the entire primary reservoir at once, we anticipate it would flow about 12,000 barrels a day, not limited by facilities, reflecting the reservoir's capability. In contrast, the test rate from our discovery well was constrained by facilities, yielding 10,000 barrels a day. At that time, we indicated it was facility constrained and estimated it could have produced up to 12,000 barrels a day. We are pleased to confirm that without facility limitations, these wells are demonstrating that level of productivity. For context, these production rates are exceptionally high for this basin, where a typical well in the Cuu Long region has historically produced around 2,000 barrels a day. So far, our tests indicate excellent reservoir quality and productivity at Hai Su Vang, or Golden Sea Lion. Regarding your second question about capital expenditure for 2026, I acknowledge that our capital is somewhat limited mainly because we are deliberately constraining our flexibility in this area for several reasons. We are making investments that we believe are wise at almost any oil price, and I will detail those before addressing more flexible options. Our key projects that we intend to progress this year and in the long term include our Lac Da Vang or Golden Camel development project, which saw its first oil come in the fourth quarter of this year. We will continue investing in this project to bring it online and ramp it up through 2027. Additionally, our exploration program in Côte d'Ivoire has two remaining drilling prospects that are compelling, with large resources and low well costs. These are also projects we will pursue regardless of oil price conditions. Another major investment is our appraisal program at Hai Su Vang, where we plan to drill two more appraisal wells this year. Finally, the Chinook development well, highlighted in our materials and my stockholder update, represents a significant investment that will require substantial rig time in the second half of the year and is expected to be a productive well, positively impacting our production rates for the latter part of the year and reinforcing our Gulf of America business trajectory. These are the items I strongly believe we will pursue in almost all oil price scenarios. There are, however, other areas of our business where we have some flexibility. For instance, we can make various decisions regarding the last three to four months of our rig program in the Gulf of America. Similarly, we have flexibility in our Eagle Ford and onshore Canada programs. However, it's important to note that most of our onshore activity typically occurs in the first half of the year. Consequently, as the year progresses, our flexibility for 2026 onshore programs diminishes. We might be able to reduce our capital by 10% in 2026 without significantly altering our onshore plans. Looking ahead to 2027, even if we encounter a very low oil price—something I don't anticipate—projects I mentioned that we are nearly certain to pursue this year would not be repeated, allowing for a greater reduction in our capital program if necessary, potentially a 30% to 40% cut. I hope my comments clarify our approach for this year and provide a longer-term perspective on our capital deployment flexibility.
Operator, Operator
Your next question comes from Carlos Escalante with Wolfe Research.
Carlos Escalante, Analyst
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?
Eric Hambly, President and CEO
That's a good question. Thank you, Carlos. At Civette, we were testing multiple objectives, including reservoirs both younger and older than what is typically seen in the basin. We found oil pay in several reservoirs as expected, but unfortunately, not in commercial quantities, which is disappointing. We will take the insights gained from our evaluation program and consider the future potential of the block. The three prospects we have planned for this year are independent and test different aged reservoirs, which are fundamentally different from each other. The information we gained from Civette is valuable for understanding the nearby prospectivity, but it does not affect the Caracal and Bubale prospects. We remain just as optimistic about those as we were before learning about Civette. While it is always disappointing to drill a dry hole, it is reassuring that our geological model proved accurate and we identified sands and oil pay. It would have been ideal to find enough oil pay for a commercial discovery. We still need to do more work to understand why the oil was not found in expected quantities, and we will address that as we analyze the data collected from the well. It is a bit early to discuss this in detail since the work is ongoing, and I don't have an answer yet.
Carlos Escalante, Analyst
Very clear and helpful. On my follow-up regarding your opening remarks about the potential size of the Vietnam business, would you agree that it could surpass the Eagle Ford as it stands today? Currently, it's producing around 35,000 to 40,000 barrels of oil equivalent per day. Considering that you'll generate about 15,000 net through LDV and that you have a discovery four times larger with HSV, am I right in thinking you might be undervaluing yourself, or am I missing something?
Eric Hambly, President and CEO
I think the short answer is that we are not being overly aggressive in our predictions based on current knowledge. We still have work to do to assess the situation. Before drilling, we communicated a significant range of resources, and with recent appraisal results, we believe we're likely closer to the upper limit of that range for the primary reservoir. We still have two more important appraisal wells to drill to better understand the field, which will help us provide a more accurate estimate of recoverable resources from both the primary and shallower secondary reservoirs. I'm cautious about repeatedly updating the resource range, as our current estimates should give a clear idea of what we expect to find, and there is potential for upside, which is why we continue to appraise. Regarding production rates, several factors are at play. Given the substantial resource expected in Hai Su Vang, development will take time. For instance, we don’t expect every development well in Hai Su Vang or the Golden Sea Lion development to be operational from day one. It will likely involve a sustained phased development approach, which may affect peak production rates. From what we know now, I believe a collective production of 30,000 to 50,000 net barrels of oil equivalent per day from Lac Da Vang, Golden Camel, Hai Su Vang, and Golden Sea Lion in the early 2030s is a reasonable estimate. Should our understanding change and suggest higher production, we will share that information in future investor presentations and earnings calls. Currently, I view this as a solid estimate. I should also mention that we hold a 40% working interest in both blocks, which limits the potential for a significant increase unless we adopt a very aggressive upfront development strategy, but I believe that wouldn’t be the best way to maximize shareholder value.
Operator, Operator
Your next question comes from Neil Mehta with Sachs.
Neil Mehta, Analyst
I appreciate your perspective. To elaborate on the oil volume point, it came in lower than expected, but much of this is due to timing. In the latter half of the year, we should see an increase. While it's premature to discuss 2027 for oil, could you provide some insights on that timeframe? Any advice on how to interpret the 2027 numbers would be greatly appreciated.
Eric Hambly, President and CEO
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 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 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.
Neil Mehta, Analyst
Eric, that would be similar production to the full year guide or to the exit rate, I'm sorry?
Eric Hambly, President and CEO
I would say to the full year guide.
Neil Mehta, Analyst
Got it. Can you discuss the derisking of Chinook? It appears it will come online later this year. What are the key factors influencing this, and what is your confidence regarding that production timeline?
Eric Hambly, President and CEO
The Chinook 8 development well is aimed at a reservoir that is currently underdeveloped but producing. It will be located near a previously producing well that had a similar output of about 15,000 barrels per day gross. Therefore, we expect minimal uncertainty regarding the subsurface conditions. However, there is always some uncertainty concerning the pay thickness and the quality of the completion when it comes to production rates. From an execution standpoint, the main concern is the delivery timing, as it is a deep well that will take time to drill and complete. The uncertainty surrounding the production outcome for the year is mainly linked to this timing. For a new deepwater well, the initial production rate could vary by about 25%. I am optimistic about this well since it is essentially replacing a well that has previously produced in the field, so I would describe it as having relatively low uncertainty and nearly zero risk.
Operator, Operator
Your next question comes from Charles Meade with Johnson Rice Company.
Charles Meade, Analyst
I wanted to ask about the royalty mechanism in the Tupper Montney. Can you provide insight into the year-over-year change in your net revenue interest? Also, could you clarify how this works, specifically whether the '26 rate is based on the realized price or an index price from '25, and how often it resets? Please help us understand this better.
Eric Hambly, President and CEO
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.
Charles Meade, Analyst
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 about the Hai Su Vang in Vietnam. I understand you've been focused on the primary reservoir so far. With the next two appraisal wells, is there a component of those wells intended to evaluate the shallower secondary reservoir along with the deeper primary? The main question is what are the chances that the secondary shallower reservoir will be recognized as a significant resource and could potentially increase the overall resource and possibly even the production rates in the future?
Eric Hambly, President and CEO
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 two 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 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.
Charles Meade, Analyst
Eric, just a quick clarification. Those two appraisal wells, they're going to assess both the shallower and the deeper?
Eric Hambly, President and CEO
Yes, that's correct.
Operator, Operator
Your next question comes from Chris Baker with Evercore.
Christopher Baker, Analyst
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.
Eric Hambly, President and CEO
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.
Operator, Operator
Your next question comes from Leo Mariani with ROTH.
Leo Mariani, Analyst
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?
Eric Hambly, President and CEO
Yes, sure. Great question. So just a reminder, our Lac Da Vang or Golden Camel development is a two-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.
Leo Mariani, Analyst
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 maybe 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.
Eric Hambly, President and CEO
Yes, you're understanding it correctly, Leo.
Leo Mariani, Analyst
Okay. Regarding Vietnam, you mentioned the goal of bringing on Hai Su Vang with a production capacity of 30,000 to 50,000 barrels a day. When do you expect Hai Su Vang to start contributing? Is it around 2031 when we might see a significant increase in production from Vietnam? I assume it will take a couple of years to reach that peak rate as well. Can you elaborate on your high-level thoughts on this?
Eric Hambly, President and CEO
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 timeline. 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 were 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.
Leo Mariani, Analyst
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.
Eric Hambly, President and CEO
Sure. We're really excited about entering Morocco as it's giving us the chance to explore a significant untested 4-way structure. The fiscal conditions in Morocco are very favorable, especially since there is minimal oil production there. This makes for advantageous terms in areas without oil. The 4-way structure is quite large, and the entry costs are very low. Additionally, the expenses to determine if we should drill a well are also minimal. We have existing seismic data that we plan to reprocess and evaluate for prospectivity over the next few years. Our anticipated expenditure there will be relatively low, likely around $5 million at most over the next three years.
Operator, Operator
Your next question comes from Tim Rezvan with KeyBanc.
Timothy Rezvan, Analyst
I wanted to ask about Slide 13 in your presentation. You highlight several prospects in the Cuu Long Basin on that slide, both within and outside of Hai Su Vang. Your plan for 2026 includes two HSV appraisals and a well at Lac Da Trang. Could you discuss the medium-term appraisal plan and the prospects you've mentioned?
Eric Hambly, President and CEO
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 two 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.
Timothy Rezvan, Analyst
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?
Eric Hambly, President and CEO
Sure. I'll share my thoughts on the overall reserve situation. We achieved a 103% reserve replacement on proved reserves, which is quite strong. For over a decade, we've maintained our reserves at a similar level of around 700 million barrels. I'm pleased with our solid reserve replacement. In recent years, proved developed reserves have been in the range of 50% to 57% of total proved reserves, and I'm happy with our progress there. Our offshore business does experience some variability with the transition of proved undeveloped reserves to proved developed. For instance, the Chinook 8 well, currently classified as proved undeveloped, will move to proved developed this year, representing a significant change. Additionally, we had notable additions to proved developed reserves in previous years with the sanctioning of Lac Da Vang and with the acquisition of the Cascade FPSO, which supports both the Cascade and Chinook fields. While we do see some fluctuations in our offshore reserves between proved total and proved developed, I wouldn't describe it as unusual for us. Overall, improving our total company from around 50% proved developed to 57% proved developed is a very positive development.
Operator, Operator
Your next question comes from Phillip Jungwirth with BMO.
Phillip Jungwirth, Analyst
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 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.
Eric Hambly, President and CEO
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.
Phillip Jungwirth, Analyst
Okay. Great. And then the market has seen a pretty significant re-rate of Montney valuations over the past six 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.
Eric Hambly, President and CEO
That's a great question. To provide some additional context, I would say we're very active internally in evaluating what our assets contribute to our portfolio and how the market might perceive them. I meet weekly with the business development team and the executive leadership team to discuss M&A opportunities, which include both acquisitions and divestitures at the asset level. We are constantly considering whether it makes sense to retain an asset, the role it plays in our portfolio, and if it might be better for another party to own it while we reallocate capital from its sale. We're actively monitoring our assets' perceived value in the market. Currently, I don’t see any assets we believe we could sell and effectively reinvest in something superior. The Tupper Montney stands out because its resource potential is significant. When valuing the Tupper Montney business using discounted cash flow or any net asset value assessments, the value remains consistent now and even a decade down the line due to the longevity of the resource. This stability is favorable for us; during periods of high gas prices, it generates healthy cash flows, and during lower prices, we generally break even or fare slightly better. It is very capital-efficient and offers a substantial resource that provides long-term flexibility, especially as we anticipate growing demand for natural gas in the future. While we appreciate its value, we are also aware that others see its potential too, and we continuously evaluate opportunities related to all our assets. I hope this adds context, and I’m happy to clarify further if needed.
Operator, Operator
Your next question comes from Betty Jiang with Barclays.
Wei Jiang, Analyst
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?
Eric Hambly, President and CEO
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 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.
Wei Jiang, Analyst
No, that's very helpful. I wanted to follow up on the Vietnam numbers. You mentioned earlier that you expect first oil around 2030 to 2031 for HSV. Is it reasonable to anticipate reaching the 30,000 to 50,000 barrels per day target a few years after that, perhaps by the mid-2030s, considering it's a phased approach? Additionally, regarding the two appraisal wells you're drilling, what would you identify as the key drivers of upside that could lead to increases in either the resource or production numbers?
Eric Hambly, President and CEO
If we see first production from Hai Su Vang in 2031, we don't have a definitive plan for field development yet. Historically, I would expect peak production around 2033. This is just an estimate and will likely be refined by our next call next year, where we should have more information. It's reasonable to anticipate first oil in 2031 and peak production by 2033. In modeling this, I think that's a reasonable approach. The appraisal wells at Hai Su Vang-3X and 4X are intended to evaluate the shallow primary reservoir and determine the lateral extent, while also possibly deepening the identified oil-water contact in the field. As noted, we did not find oil-water contact in our Hai Su Vang-2X appraisal well, and we have deepened the known oil-water level. There's still potential for additional oil beneath what we found in the 2X. We are actively pursuing that with the 3X and 4X wells. These wells will also assist us in understanding the shallower reservoir, lateral extent, and resource range. By the time we complete our appraisal program and carry out some updated modeling later this year, we will have a clearer understanding of the resource range for the field and how best to develop it.
Operator, Operator
There are no further questions at this time. I will now turn the call over to Eric Hambly for closing remarks.
Eric Hambly, President and CEO
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.
Operator, Operator
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.