Murphy Oil Corporation Aktie

[Audio Gap] exploration has been repeatedly coming up in all of our conversations so far during the conference. And Murphy is really in the middle of a lot of exploration activity. So Eric Hambly, President and CEO of Murphy Oil. Thank you so much for coming to the conference and doing the fireside. And so Eric, I want to start the conversation sort of rolling back and maybe a bit of historical perspective of where Murphy is and how you think about the future from here.

So I look this up. You started Murphy in 2006 when the company was still pretty right on the cusp of the TK development in Malaysia. And I think the company today is in a pretty similar transitional phase where you have Vietnam and also pursuing different exploration opportunities. So how do you think about the opportunity set today that you see today compared to what you have seen in the last 2 decades?

Yes. Thanks, Betty, and thanks for having us here. Happy to be here. I think in some ways, what the company is facing today is very similar to what we had in 2006, but I also think there's some significant differences. So maybe I'll kind of talk through that. I joined the company in September of '06, so almost exactly 20 years ago, my anniversary is coming up. It's been a great ride. It's been a fun company to work for. We've done a lot of things around the world and I think created a lot of value for our shareholders.

When I joined the company, it was right at a time when there was significant deepwater Gulf of America success. So a lot of success exploring in an early phase of Miocene and [ Plio-Pleistocene ] activity in the early kind of deepwater exploration in the Gulf and Murphy had a number of fields that they had discovered and had just brought online, or bringing online, Front Runner, Medusa, Thunder Hawk, there are others. And so an early very successful push into deepwater for Murphy, primarily as an operator in the Gulf. And then a big emerging business in Malaysia, Sarawak business was producing its first field in 2006.

Teekay had been discovered, was under development. Teekay started producing in 2007 and kind of ramped up when oil price really rose quite high. The Sarawak business in Malaysia was being explored, and we had a lot of success. So I would characterize the company when I joined it as a tremendous offshore explorer with a great track record in deepwater Gulf and a Malaysia business that was probably a generational success, like really, really tremendous, great success. Then if you look at sort of what the rest of the company, there wasn't too much happening. We had a little bit of an onshore Canada business which was primarily a heavy oil business, Syncrude ownership and also heavy oil assets. And those were -- okay, they were just kind of okay. If then you look at what we did in the decade following 2006.

So for my first 10 years with the company, we executed and developed basically everything we found in Malaysia, tremendous success, built a big business and ended up selling that ultimately later on. But in that decade, what we also did was build a significant onshore business, primarily organically and primarily the Montney and the Eagle Ford. So we got into the Montney in 2006 and we got into the Eagle Ford 2009, '10, mostly through leasing, a few small acquisitions, but really built in through leasing.

So we went from a tremendous success exploring offshore. In the next decade, we had what I would characterize as less than ideal success offshore. We had tremendous ongoing success in Malaysia. But basically everywhere outside of Malaysia, we weren't that successful. We were disappointing ourselves in our pace of our success exploring. In the Gulf of America, we made almost no discoveries. I think 2 discoveries in the decade that followed. In West Africa, we drilled a lot of dry holes. We had what I would characterize as a less than perfectly focused exploration program, which was driven more by access to opportunities where we had large well commitments. When you get into blocks that you haven't yet shot or reprocess seismic and you have well commitments, you end up drilling a lot of dry holes. And that's what we had going on.

But while we had no success exploring outside of Malaysia, we had a lot of success building an onshore business. So that's what makes us a little bit different now is that we have significantly more optionality in our portfolio. So we've had recent success exploring and then developing in Vietnam with our first field to come online in the fourth quarter this year, Lac Da Vang (Golden Camel). Recent success exploring in Cote d'Ivoire. And those are things that are happening in a company with a significantly more flexible portfolio, which I think helps us.

We have a strong balance sheet. We had a very strong balance sheet when Malaysia was ramping up. We're back to that after a period of time where it wasn't as strong and very well positioned to capitalize on success with an emerging Vietnam business and what we think from Cote d'Ivoire early on looks very promising.

Great. And that leads to you'll have a high-class problem to solve when there are so many opportunities in the portfolio or that -- whether that's onshore or developing Vietnam and exploration across multiple basins. So how do you think about pursuing these opportunities, and this is a capital allocation question while balancing other the priorities that company have been talking about, which is cash return or preserving the balance sheet.

Yes, it's a great question. I think when we look at our business, the onshore business has an ability to basically be relatively stable, relatively flat. Spending similar capital program that we have over the last, say, 5 to 7 years. The Vietnam business, we've been investing in it to get our first field online and exploring and appraising and pretty soon when our production starts to ramp in Hai Su Vang. We think our Vietnam business will effectively self-fund.

So future development of Hai Su Vang likely happens within or similar to the cash flows that we generate within Vietnam. So it won't be an additional heavy call on capital. The big obvious thing we have happening in the near term is understanding how large the Bubale discovery is. We're at a point where we believe we've made a commercial discovery, but we need to appraise it to confirm that and also to find out just how big is it and how do we optimally develop it. And that's going to be the biggest call on our near-term capital. So sort of priorities for us are maintaining the scale of our cash flow generating assets by reinvesting in them. That would be our producing assets.

Next kind of priority for us would be likely our dividend. After that, we'd be looking at share repurchase. And all of those things we'd be doing in the context of trying to protect our balance sheet. So we want to be very disciplined about where we're spending money, how much money are we spending. We've got our balance sheet in a great spot, which positions us well to invest in finding out what Bubale looks like, finding out what the other prospects on the block look like before we commit to what would likely be even larger development, which would be development CapEx.

We have a portfolio that allows us to think about how we monetize the development if we get to that point. We have a possibility of bringing in a partner, farming down some of our ownership. We have ability of using our strong balance sheet and liquidity we have a possibility of selling pieces of our onshore assets or other. And we'll be thinking about those things as we learn more as our understanding of Côte d’Ivoire opposition evolves over the next 18 to 24 months, we'll be thinking about how do we create the most value for our shareholders. Right now, we don't really know how that will happen.

We want to find that what we have first, what the requirement of capital will be, and then we'll come up with an optimized plan to create value for shareholders. We do have a long history of investing at high ownership, like our Malaysia business, where we had really great success. We developed those fields at 80% and 85% working interest. We're at 90% and 85% in Côte d’Ivoire now in Vietnam, we're at 40%. So we already kind of have built-in partners. So I think we have a pretty exciting opportunity set in front of us with a lot of optionality. It's not like we have the one thing to do and it either happens or doesn't happen. Our core business has been generating strong cash flows, delivering great returns. We've made a dividend since 1961. We have a really great position to be pursuing the optionality in front of us. And I think it's an exciting time to be an owner of Murphy.

And I want to get into some of the assets before we get there. Sort of talk about how, given exploration is really in focus now and how you think about the appraisal process for communication of the resource potential and how -- what you see internally and how that gets communicated to the Street, along sort of coming on the back of the HSV appraisal update, does that process change how you think about evaluating the future appraisal opportunities that's ongoing in the company.

Yes, thanks. That's a fair question. I think we go over to Vietnam first and then maybe come around to Côte d’Ivoire. In Vietnam, we announced a discovery about 1.5 years ago and it's pretty exciting. We found pay and we did not find the limits of the field. And then we followed that up with an appraisal well, which encountered more pay and also demonstrate a deeper oil level in the field. At the time, we knew we had only tested sort of this middle kind of core of the field, and it was a large structure, and we've talked about how we had 2 roughly 8-inch holes in the structure of the size of Manhattan. And so we knew we needed to learn more and how did the reservoir properties vary across the larger structure.

We haven't identified the limits of the field. And so we communicated that we needed to do 2 more appraisal wells almost certainly, 3x and 4x, which tested the Northeast and Southwest extensions of the field. We expected that we would learn things when we did that. That's why we did them. We were trying to get to a point where we understand the limits of the reservoir, the variability of the reservoir properties across the structure and then importantly, how do we optimally develop that. And so we designed that program to do that.

The 3X tested what we thought would be a thinner primary reservoir, which will be encountered. The 4X was testing what we thought would be an expanded primary reservoir which had a potentially deeper oil level than we had previously demonstrated. What we found in the 3X was largely in line with what we expected. In the 4X, we were somewhat surprised in that we found non-reservoir quality sands. We found the same sand package we had predicted, but we found it at such low quality that it wasn't storing oil effectively or oil that would flow.

And that was somewhat of a surprise to us in that we thought the limits of the field were driven more by how much of the structure will be filled and now our view is a combination of how much of the structure is filled in terms of depth and also the variability of the reservoir properties across the structure, which is why we appraised it. I think what we communicated at the time we had the results from the 2X well was encouraging because we were quite encouraged and we felt it was material enough that we should communicate it. It felt like the right thing to do to say we still don't know how big it is, but it has potential to be toward the higher end of our prior range or even beyond.

I think some people interpreted that as maybe we were being ultra conservative and that they were not our communicated views, but other people we were hearing communicate extremely large numbers for Hai Su Vang and commonly, when we met of people we said, we don't think it's that big. It could be, but we don't think it is. And so I think what we've said was consistent with what was appropriate and fair as we learned. And I think you'll see us do that going forward. If you think about where we are in the Bubale, which is sort of following just a couple of years later following in the same path, we discovered oil pay in 2 reservoirs,the Turonian and the Cenomanian.

We drilled the discovery well where the Turonian, Cenomanian crossed. So we were able to test the one place where the 2 features cross. We are fortunate to find oil in both. We still have a lot of uncertainty about how much of those features are filled. We don't know for sure what's down dip or up dip. The Bubale West-1x Well that we're drilling now the first appraisal well is testing down dip Turonian and we chose that location because we think it's the location that allows us the best chance of quickly understanding if we have a very high confidence of a developable scale field.

We think we do from the first well, but there's uncertainty. And so we're drilling that. It's 8 miles west of the discovery well, which is a significant step out and down structure. And we're interested to see what we find, obviously. If we find oil to base, then we'll probably drill another appraisal well further down dip, if we find a wet well that it would likely infer that the column height is somewhere between the 2 wells. If we find a water contact, then we'll know where it is. That's helpful. Those -- that well and an analysis that will follow will help us determine what's the in-place volume, what -- how connected are the reservoirs that has implications for how much we recover. And we will be a little while from knowing what to communicate in terms of a resource range.

We will still have a broad range of resources. So after the next well result, depending on what we find, of course, but we're likely not to have a definitive view of the field because we still haven't tested updip Turonian or updip or downdip Cenomanian. So I think what you'll see from us is communicate will be found kind of factually in the well the implications that has for the future with probably not a quantitative reset, but probably an indication of is it good or bad. And then next year, as we conduct our appraisal program, we'll learn more information about the field and when we have more confidence that we have a commercial development, we'll probably communicate that and maybe be able to guide a size of resource range.

It depends on what we find. We're not going to be overly cautious or overly optimistic. We're going to just methodically step through, let the wells tell us what we know about the field and when we gain a high confidence, then we'll try to communicate that.

No, that makes sense. And that's really helpful context because Bubale is such a -- it could be a really meaningful discovery, but also has multiple steps and appraisals, which could be a pretty meaningful capital commitment as well. I think you've laid out previously like a 3 to 5 well appraisal program and depending on what you see, you can decide how much to advance that. Like what do you need to see? And you talked about every single while help you understand the reservoir a bit better. But I guess if you can range bound what do you need to see to feel confident enough to advance and what will be an upper or low-end range of how you think about that appraisal program?

Yes. So when you develop a deepwater oilfield, you do not know everything about the field when you sanction the project. You typically have a handful of well penetrations and you make a model of what happens, everywhere you do not have well data, you make a model of what's happening in the reservoir. You use seismic data, you use other information. And so the appraisal program is doing several things, like I said, it's testing to see how much of the structures are filled with oil, how connected are they? Thus that has implications on production rates and recovery.

So those are really critical things to understand. But as we step through our appraisal program, we'll gain more confidence, more confidence. At some point, we'll probably determine that we have enough confidence to commit large scale capital to do a development while also continuing to have some uncertainty about aspects of the field. We may have an untested segment of the field, a reservoir or we may not test updip in one of the reservoirs, but we have a high confidence that there's a core development area that justifies the development and also importantly, that we do not plan a development scenario, the facilities, the well count, whatever that won't work economically.

We don't want to overcapitalized, and we don't want to dramatically undercapitalize. If we want to have some confidence that what FPSO or FPS and FSO, we build will be suitable for the fuel development. We will likely, as we have in almost all of our historical deepwater developments, we will likely have kind of a core development and then additional phases and additional understanding as we learn more. When you drill more wells, you learn more and you kind of have additional phases of development. That's very common for us. So we're not going to appraise the point where there's no uncertainty. We're going to appraise to the point where we have a high confidence that a large investment will make a lot of money. These deepwater developments they're $10 to $20 a barrel CapEx to develop. And the resource size could be significant here as we've talked about historically.

That's a very large range for a company of our scale. When we've been deploying $1.2 billion, $1.3 billion of capital in recent years, this year, a little more, obviously, with the success we've had, how we pace that investment, how we understand that it will be important for us. I think just to point out, we're fortunate to be the operator in Vietnam and Côte d’Ivoire. So we control the pace of our appraisal investment and our development investment if we get to that point. It's a nice position to be in because we're not going to be partnered with someone that's much more capitalized than we are, and we lose control, which I think is important from creating value for shareholders.

That makes sense. Now it's interesting, like you -- the decision that you have to make without perfect information, the maybe with the very high interest you currently have in Bubale, how -- like at what point would you consider farming out some of the interest? Like is it -- is it like where, within where you feel there is enough to go forward with a full development?

Yes. I think when we have a full understanding or a reasonable understanding of Bubale's potential we will then have more confidence that we know sort of the value that, that would be to us and to someone else if they were to come in, but we also have significant undrilled prospectivity on our blocks. And we may consider understanding the value of that prospectivity before thinking about bringing in a partner. So typically, when you have someone farm into your block. It's the whole block and not one field. It's the entire block that they come into.

We have not tested many significant prospects on the blocks where we're likely to have a Bubale all development of the 2 blocks. And so at some point, we'll get comfortable that we either really need the external funding to make that happen and it's the right thing to do for shareholders or that we don't want to do that, and we're going to keep our existing interest and develop it. I wouldn't be surprised if we do not ever bring a partner in. We have a partner that's built in that already has an option of increasing their ownership. That's something that it's not public what their ownership could be, but it is a significant ability to -- with our existing partner, which is a national oil company to increase their ownership.

So we're likely to already have a kind of a built-in funding partner if we have a successful development. But I'll be cautious about giving away ownership in something that hasn't been fully evaluated. And there's a lot of prospectivity still to think about on the blocks. So it's a key thing. As I was trying to indicate before, it's going to take us a little while to figure it out. So we're probably looking at an 18- to 24-month process before we have kind of that sort of confidence of knowing that we know enough to make a decision about the right steps to create the most value for our shareholders relative to ownership in Bubale or any of our other assets that we call upon to help fund the development.

That's helpful. So in the meanwhile, or I have to think about funding this development and Eagle Ford as a strategic asset has been brought up, and that's an area that you're growing or accelerating activity this year with the potential to add more. So how do you think about Eagle Ford as an asset to drive free cash flow to fund the expiration for the rest of the portfolio?

I think the way we thought about our Eagle Ford asset in maybe the past 5 or 6 years was we were using the asset or producing it in a range of 30,000 to 35,000 barrels a day net to us, and we were using the free cash flow to fund offshore activity. We had a Vietnam business that was growing. We had a bunch of activity in the deepwater Gulf, and we were also using that cash flow to reduce debt and buy back stock. And we've gotten to a point now where we feel good about our debt level.

We would obviously ultimately love to have lower debt, but we're faced with a very rich opportunity set to invest into. And we look at our Eagle Ford business. We've had better and better Eagle Ford wells coming online in the last few years in an industry that Eagle Ford well productivity and capital efficiency is getting worse. Our very best wells have been in the last few years. Our operating expenses in the Eagle Ford have gotten to be really quite a bit better than they were. The cash flow generating potential of the Eagle Ford is better now than it has been maybe in the history of the asset, and we have a lot of life left into it. So we've been putting online about 30 new wells, 25, 30 wells operated to keep the asset relatively flat.

The last couple of years, we were attempting to deliver 35,000 barrels a day, and we delivered 37,000 barrels a day last year and probably 38,000 barrels a day or more this year. So the asset is outperforming, delivering strong cash flows. And when we look at it and we say, we have a significant need to invest in Bubale appraisal while hoping to maintain investment in our producing assets to maintain or maybe modestly grow the scale of the other parts of the business. The Eagle Ford is an area where we can -- with very fine control, ramp up our activity level, spend a little more capital, generate more free cash flow by growing more production and allow us to further improve our balance sheet and protect our balance sheet.

We have more call on capital, we can generate more free cash flow from Eagle Ford. And we can do it without significantly shortening the runway of Eagle Ford in our portfolio in our -- if we don't ramp up our Eagle Ford, we have a healthy inventory to be investing into the middle of the 2040s. Ramping it up, that will pull out a little bit closer. But I think in the -- compared to a pure shale peer companies, they'd be pretty envious of having inventory that runs into the 2040s, the mid-2040s. And if we shorten it into the late 2030s or say 2040, I think we still have a pretty healthy business.

The other thing that it does for us is as we ramp it up, we will likely -- we haven't set a policy around this yet. We're still thinking about it. We're going to likely ramp it up through next year. We probably won't stop if we have supportive commodity prices, we'll probably keep ramping Eagle Ford up to some future plateau rate. I don't know if that's 50,000 barrels a day or 60,000 barrels a day, but somewhere kind of around there likely makes sense. If we get to that point, then we'll probably even do more free cash flow harvesting at that point. But we'll grow it over a gradual period of time, likely over the next few years and get to a new plateau rate.

And it also provides us some optionality of we decide by the time we figure out what we want to do with Côte d’Ivoire, if there's more potential to develop in Côte d’Ivoire and the call on capital is really high, then we have an Eagle Ford asset with a lot of remaining life into it, and quite a bit more production, which is quite valuable. And so it could potentially provide us with an optionality to sell part of that Eagle Ford business, which would probably attract a higher valuation with higher production rate was still a lot of remaining life up. So I see it was a nice near-term option to provide cash flow while providing more long-term optionality that could create more value.

No, that makes sense. So in the same vein, where does the Canadian business fit in Canadian onshore or offshore. It's relatively smaller in the portfolio. What's their strategic role in the portfolio?

Yes. So we have 2 key assets in onshore Canada. The Tupper Montney is the largest one from our resource size and also production rate. The Montney is producing to 2 gas plants and the gas plants are full. And so a significant further growth there would require a plant expansion, which is something that would probably from committing to do it to happening would be about a 3-year process. Right now, the way I look at the market with AECO, it's not super supportive of spending additional capital in the Montney. We're likely to continue to invest in that to periodically refill the plants and keep them full for part of the year.

Last year, we brought online 10 wells and kept the plant full for -- I think it was 5 months. This year, we brought online 8 wells and have the plant full and expected to be on full for quite a while. So optionality to invest there and grow it materially is limited, especially with the current commodity price. Having said that, that Montney asset has over 700 remaining locations if you look at us putting on 10 or 8 a year to maintain the scale, we have over 5 decades, maybe depending on how you do the math, 7 decades of drilling inventory. So the asset is strange in that it is just as valuable now as it would be 20 years from now.

If we keep the plant full for 20 years and we do a discounted cash flow analysis 20 years from now, assuming commodity prices are the same, it's worth just as much. It's practically for all purposes for us. It's an infinite resource. So that makes it a little more long-term strategic. And so while you might say, well, you're not really investing heavily into it, you're not generating massive free cash flow from it today. If you're a believer in long-term North American natural gas, we have one of the most capital-efficient dry gas assets in North America with huge optionality for the future. It's not something that we're likely to do something with strategically, but we could.

So we were aware of the value of it. We're very conscious of that. But I like that we've been running this business for over 100 years, and we're planning to run it so that we can be around for more than 100 years. And so that Tupper Montney asset, while it's valuable, it could be even more valuable in the future. And our holding cost of it is making a little bit of money every year. And so as we think about that as probably more strategic than our Kaybob Duvernay asset, which is basically an appraised and not developed shale oil play that is not generating huge cash flows because we haven't been investing into it. We got into the Kaybob Duvernay because we thought as we work through our best Eagle Ford inventory that we would want to have the next go to shale play, and that's what the Kaybob really is for us.

We've chosen in recent years not to prefer to invest into it because we have a wealth of offshore investment opportunities, we've been preferentially investing there. And so that's an asset where you look and say, if we were to transact something nearer term, that's probably the one that would be most likely to go because it's valuable in the market, and it's not supporting a lot of our free cash flow now, which, of course, we need to fund all of this activity.

That makes sense, which then lastly, but not for the least for sure, is the GoA assets. That's your foundational asset today. But then, we're in a shift where GoA is not necessarily the not the growth asset, it's also longer term or resource constrained compared to the growth exploration areas. So how do you think about GoA evolving from here? Where is the opportunities? And is it running for maintenance? Or is there room where you're seeing growth elsewhere?

Yes. So we're investing in our existing assets. We have an opportunity set of additional wells, workovers, zone changes like that. And those investments in existing fields will likely allow us to keep our production level in the GoA relatively flat, maybe modest growth basically through the end of this decade, assuming no other discoveries. This year, we were fortunate to make some discoveries near our Delta House field, Cello and Banjo.

Those will come online in the fourth quarter of '27 and add some significant production growth for us. We're also maintaining an active exploration program there. That program will focus on near infrastructure prospects that are likely to be a high chance of success and admittedly, probably not very large but they're very valuable. They're high rate return, subsea tieback type projects. And occasionally, in our portfolio, we'll pursue one of our larger riskier prospects in the Gulf that have the potential to be their own hub scale or maybe near hubscale class.

We won't have too many of those. There aren't that many in our portfolio. We have a handful. We'll occasionally have one of those. If we're successful in one of those, that would be a big breakthrough kind of significant additional resource. Of course, it would come with significant capital demands as well. So we're not -- the gold remains core to us. It's a lot of production. It's also going to continue to be a focus area for exploration for us.

Great. To wrap, I think we touched on a lot of topics, a lot of assets existing and future. If we were to say, what are one thing that you think is most misunderstood about the Murphy story?

I think there's 2 -- they're sort of the same theme, but sort of 2 different areas. I do not think that the cash flows that we generate and the durability of those cash flows that we generate out of our offshore GoA business and our Eagle Ford business are properly captured by the market. I think there's a bit of mispricing there. I think every CEO, you would ask would say they're undervalued. But I think we do disclose quite a bit of information that allows people to model free cash flows. And I think there's some significant discounting of the durability of the GoA and Eagle Ford cash flows. And I think if people take a harder look at that, that they would probably see that we're probably worth a little more than we're trading for.

Okay. Great. Well, thank you very much, Eric [indiscernible]. Appreciate the conversation.

Thank you so much. Appreciate it. Thank you.

Good morning. My name is Fern. I will be your conference operator today. [Operator Instructions]

I will now turn it over to Atif Riaz, Vice President of Investor Relations and Treasurer.

Thank you, Fern. Good morning, and welcome to our second quarter 2026 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 of Operations.

Yesterday, after market close, we issued our second 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 thanks to everyone for joining us. We released detailed earnings materials yesterday, so I will keep my comments focused this morning. I want to spend most of my time on the key developments in the quarter, including what we learned through our exploration and appraisal program, how those learnings are shaping our capital allocation and why we believe these investments strengthen Murphy's long-term outlook.

The most important development this quarter was the Bubale discovery in Côte d'Ivoire. Just as important as the result itself is the disciplined exploration process that led us here. We entered Côte d'Ivoire with a clear thesis and a 3-well exploration strategy. And although the first 2 wells were noncommercial, we remain confident in Bubale's prospectivity and continuing to execute the plan. That patience and technical conviction paid off as the well encountered oil in both the Turonian and Cenomanian reservoirs.

Now we want to be very clear about where we are in the process. While Bubale has the potential to become a significant growth driver for Murphy, there is still important appraisal work ahead. The next step is to understand the scale, quality, continuity and economics of the resource. That work is now underway with the Bubale West-1X, which we spud in July to begin appraisal of the Turonian reservoir. It is the first of up to 5 potential appraisal wells. I emphasize potential because this will be a staged data-driven process over the next 18 to 24 months with each well determining the scope and direction of the remaining appraisal program.

An 18- to 24-month appraisal program may sound lengthy, but this is how we protect value. In our business, value can be destroyed long before a development well is ever drilled by misunderstanding the resource, overbuilding the project or committing capital too early. Appraisal helps us avoid those mistakes by giving us the technical confidence to rightsize the development and make disciplined capital decisions.

Hai Su Vang in Vietnam exemplifies the importance of that discipline. Hai Su Vang-4X was a dry hole. And based on the new data, we have reduced our resource estimate. There is no sugar coating it. This is not the outcome we were hoping for. However, the appraisal program gave us critical insights, allowing us to now calibrate the field development plan before we commit significant capital in the coming years. Following the Hai Su Vang resource estimate revision, I want to emphasize 2 important points. First, even at the revised estimate, Hai Su Vang remains a material 200 million to 300 million barrel oil equivalent opportunity, approximately 2 to 3x the size of Lac Da Vang.

And second, our Vietnam peak production outlook of 30,000 to 50,000 barrels of oil equivalent per day remains unchanged. We may come closer to the lower end based just on what we know today, but the final outcome will depend on what additional tieback opportunities we identify as we move forward. The key takeaway is that we now have greater clarity around our opportunity set with many compelling projects competing for capital. That brings me to our revised capital program and how we're thinking about investments going forward.

We're increasing the midpoint of our 2026 capital expenditure estimate from $1.25 billion to $1.55 billion. This is not about chasing activity or reacting to price. It's a deliberate decision to fund specific high-value opportunities now in front of us with almost all of the increase supporting Murphy's organic growth. Roughly $190 million relates to Bubale, including $100 million of incremental spend on the discovery well and $90 million for the first appraisal well. Another $70 million is going into the Eagle Ford, which is expected to add approximately 5,000 to 6,000 barrels of oil equivalent per day in 2027.

I want to take a minute to talk about the Eagle Ford decision because it highlights the key role this asset plays in our portfolio. As our offshore opportunity set expands, we can fund part of that growth through near-term, high-return production and cash flow. Eagle Ford is one of our best assets to do that. It is flexible, oil-weighted and capable of efficiently translating capital into production. Going forward, we expect the Eagle Ford to become an increasingly important source of cash flow and financial flexibility across the business. This is the strength of our multi-basin portfolio in action, not a change in capital discipline.

Our ability to fund growth through our base business while maintaining financial strength was evident this quarter. We generated $110 million of free cash flow, returned $50 million to shareholders through the dividend, maintain leverage below 1x and ended with approximately $2.5 billion of liquidity. Even with the revised capital program at current commodity prices, we expect to generate positive free cash flow for the full year.

Operationally, second quarter production averaged 169,000 barrels of oil equivalent per day, above the midpoint of our guidance, led by stronger performance at Tupper Montney and continued outperformance in the Eagle Ford. In the Gulf of America, Chinook #8 is now through drilling after reaching a total depth of 26,000 feet and remains on track to come online in the fourth quarter. Lac Da Vang is also on schedule for first oil in the fourth quarter with the pipeline, topsides and FSO milestones now complete.

As we look ahead, years of capital discipline and technical rigor are beginning to translate into a portfolio with multiple exciting pathways to growth. This is the Murphy model in action, identify the opportunity, test it with discipline, develop it safely and efficiently and fund it through resilient cash flow and financial strength. This full cycle capability and track record across geographies, asset types and development stages sets Murphy apart and positions us to convert the opportunity ahead into lasting shareholder value.

With that, we are ready to take your questions.

[Operator Instructions] The first question is from the line of Arun Jayaram with JPMorgan Securities.

I appreciate the comments in the shareholder letter. Exploration as is investing can be humbling, but did want to maybe get your thoughts on next steps at HSV, what needs to happen in terms of kind of moving to that FID decision in 2027? And can you give us a little bit of an update on how you are thinking about kind of the development options for HSV?

Arun, thanks for that. Great question. Obviously, we're disappointed that the 4X well was a dry hole. But I will say that we're still very excited about what is a very significant development for us, 200 million to 300 million barrel field in shallow water will have very attractive economics. I would have loved for it to be larger. We now have a lot of confidence in the size of the resource and gaining increasing knowledge about how we're going to develop the field in terms of the well count, well spacing and the type of facility concept is something we'll be evolving over the coming year or so.

We are looking at a number of options for the development. One option would be an FPSO. The other option would be a processing platform with a series of wellhead platforms tied to an FSO similar to our Lac Da Vang project. Those are things that we will assess as we plan a development of the field over the coming 12 months or so. We're going to work closely with our partners on a series of approvals required to achieve an approved field development in Vietnam. And after we do that, we will take the project to our Board for a final investment decision.

As we highlighted in our letter, we're targeting that in the fourth quarter of 2027. And I think we're well on track to do that. Really happy with this significant discovery that will help us build a really material business in Vietnam. And I think we're going to create a lot of value for our shareholders. And I don't think we're getting a lot of recognition of that value creation today, and we're happy to demonstrate our ability to continue to execute developing projects 40% faster than the industry.

Great. And maybe my follow-up, you've spud now Bubale West in July. It looks like you'll be appraising the Turonian. Maybe just give us a sense of what your concept is for this appraisal well? And what will be the governor of the next -- the development or the appraisal program, which could include up to 5 wells?

Yes. Thanks for that. As we've featured before, we drilled the discovery well in a position where the Turonian and the Cenomanian cross. There was one location where we could test both reservoirs. We were fortunate to be able to find oil in both Turonian and Cenomanian. And that leaves us with a need to understand the lateral extent of the field, the variability in reservoir quality and thickness across 2 different reservoir intervals and also importantly, learn how much of those structures are oil field.

So the next well that we moved to Bubale West-1X is moving down dip in the Turonian. The main objective of the well is to test for continuity and variability of reservoir sands and also hopefully determine to prove a deeper oil level than is proven at the base of the Bubale-1X well. We're very intentionally targeting the well to give us high confidence that we have a resource in the Turonian that is in line with or in excess of the volume we need to have a commercial development. As we sit today, we think what we found is a commercial, but we don't have high confidence because we have 1 penetration in 2 reservoirs, very large reservoirs to test, very large lateral extent, and we're hoping this well gives us high confidence that we'll be able to then move forward with the development as quickly as possible while we continue to assess and appraise the full size and value of the field.

Your next question is from the line of Neil Mehta with Goldman Sachs.

Eric, I want you to unpack a little bit of the decision to pull forward activity in the Eagle Ford. You alluded to it a little bit in your comments, but maybe you talk about why you thought this was the right environment and what kind of incremental returns you're going to get on the incremental CapEx associated with the $70 million acceleration.

Yes. Thanks for that. Before I get just into the Eagle Ford, I want to back up a bit and talk about how we've been thinking about our overall company business. What we said over the last few years is we thought we could develop our kind of base business, continue to develop that and also our emerging and growing Vietnam business with a capital program that's sort of in a $1.2 billion to $1.3 billion range. And that any additional spending to develop something like Bubale would likely be additive or largely additive.

And I would say where we sit today, that is still true. So as we look forward and think we want to maintain our Canadian onshore business effectively flat, maintain the scale of our Gulf of America business relatively flat through the rest of this decade. We look at additional need for CapEx for appraising and developing Bubale and the place that we found was most optimal to help provide part of that is through accelerating our Eagle Ford. If you look at our Eagle Ford business, we've had increasingly strong well performance over the last few years, generating strong free cash flows even in periods of fairly low oil price in the past couple of years.

And so the reliability of it and the flexibility of it, we look at it and say, this is a great place to invest a little bit more that will generate more free cash flow next year and likely through the end of the decade that will help us fund the appraisal of Bubale. And then as we move into additional volume growth out of Vietnam, we'll have even stronger cash flows. So it's the best place to find oily production, and we can do it scalably, and we've had very strong returns and increasing well performance from Eagle Ford. So it's kind of the go-to place to do it.

And I think you'll see us, as we highlighted in our materials, increased spending this year, which leads to increased free cash flow next year. And while we haven't formulated a plan that we've released for '28 through 2030, I think you'll see us increasingly lean into that if it allows us to continue to generate more free cash flow. So really about creating shareholder value. I think it's nice to be able to generate incremental oily production growth in the short run. But the primary reason is it's free cash flow generative and can help us fund what we think is an exciting opportunity in Côte d'Ivoire.

Yes, Eric, that's the follow-up. So the new CapEx plan is $1.5 billion, $1.6 billion in accrued CapEx for this year. Any advice on what we should put in as a placeholder for '27? I know there's a lot of moving pieces, but just any thoughts on the market there so we can calibrate accordingly.

Yes, that's a fair question. We don't have a number to give you for next year's CapEx, but I'll talk just about how I think about it. I think that you should expect us to increase slightly more in the Eagle Ford than in the past. With that alone without any change to investing in Côte d'Ivoire, that would likely put our typical capital program toward the high end of our kind of previous $1.2 billion to $1.3 billion range, maybe slightly above. That's still something we're going to work on. And then spending on Bubale is likely additive to that. So we'll probably see a higher CapEx in '27 than you've seen from us recently. I don't know the number.

And importantly, I want to kind of go back to the comment we made about the appraisal program. We're going to drill -- we're drilling a well in Bubale West-1X now. Depending on what we find, we may have no appraisal program or a limited appraisal program. We're going to learn from every well. And next year's capital spending will be materially driven by what we continue to find. If we keep finding more oil at Bubale, we'll likely keep spending. If we have less wells required to define the size, scope and quality of Bubale, then we'll spend less.

And so there's a pretty big range around that. We're going to still work on that. The results from the Bubale West-1X well will probably materially shape our view of likely spending and spending ranges for 2027. But I think I don't want to try to make you feel like we're likely to come in below $1.25 billion next year. It's going to be higher. I don't know how much higher, but we're going to be disciplined, focused on creating shareholder value and investing in things that are going to be very valuable for our company and our shareholders.

Your next question is from the line of Carlos Escalante with Wolfe Research.

I want to go back to HSV very quickly to clarify a few things and then move on from there. So it looks like HSV-4 was a dry hole, which, in my view, it implies that you didn't find an oil-water contact that's presumably more up dip. So just wondering what's stopping you from testing an additional well that where you can find that threshold and what gives you the confidence that you don't need to? And perhaps we can speak more broadly about what you found in HSV -3 in terms of the discovery pay or any kind of really property around the well and the discovery.

Yes. Thanks, Carlos. I'm happy to provide more context there. Let me go back to where we were at the end of the 2X well. So we drilled 1X, 2X. We had extremely encouraging results, strong DSTs. We had a view at the time that the field was likely toward the high end of our previously guided, which was a predrilled range of resource. And we told everyone that because we wanted to inform and keep everyone appraised of how we were thinking about it. And we said at the time, we thought it was possible that the resource could be even larger.

But importantly, we had drilled a fairly central area of the field, and we needed to test the Northeast and Southwest extensions of the field, which is what the purpose of the 3X and 4X wells was. So with the 3X, we were testing for lateral extensions in the Northeast, how continuous are the sands, are they the same quality? We weren't really chasing a deeper oil-water contact there. We were just chasing for continuity. And then with the 4X well, we were testing what we thought would be an expanded reservoir section with potentially a deeper oil-water contact. And what we found from the program from the 3X and the 4X was that the reservoir thickness was not as extensive as we expected over the entire structure, which tightened up the resource estimate.

With the 4X, we found the interval we were looking for, but the reservoir quality was low. So we didn't have any net pay. So the story for 4X was not really about oil-water contact. It was really about the extent of productive reservoir being limited. So now that we have bounded the reservoir with these 4 wells, we have high confidence in developable resource that we're going to move forward with the field development plan.

I appreciate that. So yes, presumably a 4-way closer. So you don't need to test the other bounds. And then my follow-up and maybe a follow-up to Neil's question. For next year, again, very difficult for you to talk about '27, where we are today. But can you at least frame for us how you're thinking on what is senior to what in terms of the levers you can pull if you needed to have a more lean program, if you will, in 2027? Obviously, it sounds like you're going to prioritize the appraisal at Bubale, if you find any kind of success. But wondering what it means for the broader onshore portfolio and maybe the Gulf of America, if you need to, again, be leaner on your '27 program?

Yes. I think what you'll see from us is investing in our Gulf of America business to try to maintain production relatively stable there. And in our Eagle Ford, likely incrementally more spending than historical. And in Canada onshore, stable investment, stable production. Vietnam, obviously, we're working through additional development drilling in our Lac Da Vang project. We won't have likely additional drilling in Hai Su Vang next year. So we're moving to engineering studies, which is not a lot of spending. And then in Côte d'Ivoire, what we spend will be driven by what we keep finding, as I mentioned before with Neil. And that's really driving a significant uncertainty in our spending. But as I said, we're going to learn from every appraisal well, and we'll decide what does that mean about the next well. And so there's a probably broad uncertainty.

If we needed to pull back spending for some reason, if oil prices went to be extremely low, we could change our plan for practically any part of our business. We are fortunate in Vietnam and in Côte d'Ivoire that we operate so we can control the pace of any spending. We believe it is valuable for shareholders to quickly appraise Bubale, determine if we have a commercial project definitively and determine the extent of it so we can move on for field development planning. But if we needed to, we could slow the pace of appraisal. We could go as low as 0 appraisal wells in Bubale next year if we chose to. And so we have a lot of flexibility. We're going to continue to spend money where we think it's value creating for shareholders and maintain flexibility to spend less if it's necessary.

Your next question is from the line of Phillip Jungwirth with BMO.

Coming back to the Eagle Ford, which will be a larger part of the program. I know you've always had Austin Chalk in the location count, but it has gotten more attention late across both the East and West portions of the play. I was just hoping you could talk about how large a contributor the Chalk is to your program, go-forward program? Or is it largely lower Eagle Ford focused still and just how you see the opportunity set here overall?

Sure. Our Eagle Ford inventory has fairly limited amount of Austin Chalk. Our development programs in Karnes, over part of our Karnes position will include an occasional 1 or 2 Austin Chalk wells in a 10- to 12-well pad that is mostly Lower and upper Eagle Ford locations. So we have been developing them. They're limited to part of our Karnes position in terms of what we're investing in, in near term. And so they're not a huge feature for us. We like them where the reservoir quality is good. So we co-develop them where it makes sense. I don't think it's a big driver for our program. So it's not something that is really worth calling out or highlighting as unique. It's fairly limited. But where we do have them in part of our Karnes position, we really like them.

Okay. Great. And then on the Bubale West appraisal well, I was hoping you could kind of just speak to the confidence in the $90 million well cost or maybe just break down the incremental costs from the first well and why you think these won't repeat just to have confidence as the play moves forward in the overall well cost and ultimate F&D.

Sure. Before we drilled the Bubale-1X well, we estimated that a dry hole cost for the well was $65 million. When we drilled the well, we encountered section in the shallow Turonian above the discovered Turonian interval that was slow to drill. We had fairly slow rate of penetration as we drilled it. It's slower than we had anticipated. And we've incorporated that learning into our dry hole cost estimate for the Bubale West-1X well. So instead of assuming a $65 million, we're moving it to $90 million.

If we encounter hydrocarbons in the West-1X well, we're likely to spend additional funds with formation evaluation, logging core, fluid samples, et cetera. And that might push the well cost above $90 million, which is normal how we conduct our business.

Your next question is from the line of Tim Rezvan with KeyBanc.

I want to ask on Vietnam more broadly. You've now wrapped the HSV appraisal program. You talked about drilling LDT. I believe it's a 40 million to 80 million barrel resource potential area. Given the large size of your position across several blocks, can you talk about longer-term exploration aspirations in Vietnam, maybe 2027 and beyond? And do you ultimately see this asset sort of self-funding future exploration once you get LDV online?

Yes, that's a really good question. We are drilling the Lac Da Trang North-1X well now. And as you mentioned, it has a predrill mean to upward resource range of 40 million to 80 million barrels, which is a nice prospect to drill. And with success, it likely sets up a development as a tieback of Lac Da Trang North and Lac Da Trang to the infrastructure at Lac Da Vang. As Lac Da Vang comes online in the fourth quarter, we'll generate revenue over the course of a few years. We'll recover the costs of our historical investment in the block. That will be all of our exploration costs in Block 15-1/05 and also our development costs of Lac Da Vang.

And then we'll be able to use the revenue from Lac Da Vang to recover costs from the exploration that we're doing going forward, what we're doing now and in future years. We have significant remaining prospectivity on both Block 15-1/05 and 15-2/17 and we'll test those likely between now and the end of this decade and stage in a development with stand-alone developments where the resource size is large enough to be necessary or tiebacks to existing infrastructure in what are likely to be 2 key hubs, a Lac Da Vang and Hai Su Vang hub in kind of a north and south position.

So we're really excited about the potential there. We had a pretty strong record of having successful exploration here to keep finding oil, and we need to find about 8 million to 10 million barrels for an economic tieback. So if we can find 40 million to 80 million, we'll be very happy. It will be very value creating for us and will allow us to maintain a long production plateau of our overall Vietnam business. So we're creating a lot of value here with our shareholders, spending very little money to do it.

Okay. That's good context. As my follow-up, I just wanted to go back to the Eagle Ford. You're spending $70 million. Can you just talk -- is this like a spot rig that's going to come and drill a couple of pads over 6 months? And then as we think about that, should we be thinking over the medium term that maybe you're going to run this at a 40,000 to 45,000 barrel a day level? Just trying to kind of contextualize the ramp you're anticipating.

Yes. So where we sit today, we do not have a rig actively drilling in the Eagle Ford. We completed our drilling program that we had originally contemplated and are working through the last of our completions and well on lines. And what we've decided to do is resume drilling instead of resume drilling in January to pull that forward to begin in October, we'll drill a pad in Karnes and a pad in Catarina this year. We'll probably begin completing the Catarina pad at the end of the year, and we'll bring those new wells online early in 2027. And I think what you'll see is it's just the beginning of an active program next year. I think your range of rates for Eagle Ford next year is reasonable. I would assume we're a little toward the higher end of what you said than the lower end, but we still have to formulate exactly what our 2027 program is.

Your next question is from the line of Josh Silverstein with UBS.

I want to see how we should be thinking about using the balance sheet and the shareholder return profile in this period of higher spending. Are you willing to use the balance sheet to support all these projects getting incremental capital? And then as far as the shareholder return profile, is this really just limited to the base dividend going forward as you examine everything here?

That's a great question, Josh. The way I would frame it is we have not changed our capital allocation plan or framework at all. We still have the exact same priorities. We plan to prioritize investing in our assets to maintain or grow the scale, pay dividend, focus on balance sheet and occasionally share buybacks when it makes sense. And so we really have no change in that. Our plan, as we've been very clear about, is based on adjusted free cash flow, which is after our dividend and a few other things, including M&A.

We will likely, going forward, have modest free cash flow. There may be periods between now and first oil at HSV or potentially if we're so fortunate at all that we have periods of time of negative free cash flow for the whole company. We're going to be measured in our pace, and we're going to be very conscious of protecting our balance sheet. We're not afraid of using our liquidity and our balance sheet as necessary, but we're going to keep ourselves in a strong balance sheet position at all times. That's a priority for us. So we will definitely be maintaining our dividend. That's core to us. We paid a dividend since 1961. We're going to continue to pay a dividend, I would imagine, going forward for the entire tenure of me being here.

And as -- if we encounter situations where we think our share price is significantly out of whack with intrinsic value, then we'll be active in share buyback. So I think that's the same story you've heard from us in the past. We're fortunate to have even more organic growth opportunities than we had a few years ago. It provides us more challenges in terms of how we choose to allocate capital, but we're in control of the pace as operator everywhere, and we're going to do what we think is best for shareholder value going forward. Again, not being afraid to use our balance sheet, but always with an eye toward protecting a strong balance sheet at all times.

Got it. And then I just wanted to see what's potentially on the exploration horizon next year since you've added some new exploration opportunities across West and North Africa and how you would classify them relative to what you've done in Vietnam and Côte d'Ivoire?

Yes. Thanks for that. I think you'll see next year that we'll invest in the Gulf of America and exploring in 1 or 2 wells. You'll likely see us invest in Vietnam and our Cuu Long blocks, most likely in 15-1/05, the inventory that we were just talking about a few minutes ago. And I don't expect other than appraisal drilling in West Africa, we'll have more West Africa drilling activity. We're intentionally phasing in opportunities in West Africa that have -- that are at different parts of our prospect maturation time frame. So we signed a block in Morocco recently. We're going to reprocess seismic there. That's very little spending.

We're hoping to finalize agreements for Cameroon and Mauritania in -- by the end of this year and next year, spend small money with studies, maybe the beginnings of seismic reprocessing, small dollar spending, drilling in Cameroon, Mauritania or Morocco is probably a 2028, 2029, 2030 thing depending on what we find. We're going to follow our recipe of very detailed regional study leading to detailed prospect maturation and drill or not drill based on the merits of the prospects. That takes some time. And as you saw, it led to some success here for us in Côte d'Ivoire.

So we think we're setting up for a repeatable business model of exploring in emerging on frontier basins and doing it with low entry cost, relatively low well cost, targeting large resource, and that's very value creating if we can continue to have some success.

Your next question is from the line of Leo Mariani with ROTH.

You spoke to this a bit earlier, but clearly, you're making a decision to put more capital in the Eagle Ford to ramp it. Presumably, that is probably more of a higher oil price type of decision. I would venture a guess that if oil is lower for whatever reason, then perhaps that asset does not see a real increase in free cash flow from putting more capital into it, which obviously will generate more production. Can you just provide any kind of thoughts around that? I mean it just seems like, obviously, now with higher oil prices, that investment will generate incremental free cash flow in the next couple of years, but perhaps there's some kind of breakeven where that starts to go away if oil is low enough.

Yes, Leo, our decision to invest more in Eagle Ford is not driven by near-term higher oil price. It's driven by ability to generate strong free cash flows with a significant range of oil prices. If we saw oil price below $50 for a year, we would probably pare back our investment in a lot of places, including Eagle Ford. But with even a significant range of oil prices in line with what we've seen over the last 3 years, we feel that Eagle Ford investment makes sense. We generate strong free cash flow over the last few years doing it. We have increasingly strong well performance. And at even modest oil prices, we'll be investing in it to generate strong free cash flows.

So we're not reacting to oil price. We're saying we now have a strong portfolio of organic growth to invest in. And part of the way we can fund that is by generating more free cash flow from the Eagle Ford by investing more in the Eagle Ford.

Okay. Appreciate that. And then just on Vietnam, obviously, you guys are going to have first oil here in the fourth quarter. Just looking at your guidance, you kind of expect a relatively small amount, but presumably, that's going to ramp nicely in 2027. Can you just provide maybe a little color around kind of the thoughts on that potential ramp on Vietnam oil next year?

Sure. As you mentioned, we'll have fairly limited contribution to production this year because of a fourth quarter online first oil for Lac Da Vang. We will continue to drill development wells through this year and into next year. If you look out towards the end of 2027, Lac Da Vang net production is probably in the 5,000 to 9,000 barrel a day range. And as we continue to drill the remaining development wells in our phase development program through '28 and '29, we'll ultimately ramp up to 10,000 to 15,000 barrels a day.

Okay. So just to be clear, is that 5,000 to 9,000 barrel a day kind of like a '27 exit rate and then obviously it continues to ramp in '28, '29?

That's exactly right.

Okay. Helpful for sure. And then just last one for me, Eric. You talked about this a little bit, but you guys have really gotten into a number of new exploration plays recently, a lot of which are in Africa, and you kind of rattled off sort of the plans, which seem a little bit limited in terms of capital in the near term. But presumably, those plays could require more capital as you get into '28, '29. I imagine there might be a shot clock on some of those to get some wells drilled eventually if you think prospects are maturing in the right way. Does this set up for like just a lot higher capital later this decade and kind of the success case? And then just if that's right, just thoughts on how you would kind of handle that, fund that.

The way I would characterize that, Leo, is if we are conducting our typical sort of assessed opportunities and drill an exploration well occasionally, then that would not materially push our capital higher. Obviously, Bubale is likely to push our capital higher with success. Exploring and drilling an occasional well is something that fits into our overall exploration program kind of in line with what we've been spending. If we are fortunate to have a discovery in Morocco, Cameroon, Mauritania, then that would lead to additional appraisal drilling and then development drilling, which would be great. That's obviously a long way away.

And as you know, exploration wells tend to be dry holes. So I'm not too worried about it yet. I think we'll continue to expose ourselves to opportunities that are at various stages and I'm not concerned about a strong draw for capital between now and the end of this decade in any of those new entries, but excited for the potential that they may help us continue to have opportunities to develop and grow as we exit the 2030s and head into the 2040s.

[Operator Instructions] Your next question is from the line of Charles Meade with Johnson Rice.

I'd like to go back to the -- excuse me, the appraisal effort at Bubale, and I apologize if I missed some of the earlier detail. But I think what I heard you say is that -- you said this, the Bubale West is -- it's a down dip Turonian appraisal. But I guess I want to ask 2 things. When -- I guess, the design of the appraisal well and then the plans for the Cenomanian, for the design of the appraisal, is this -- there's a lot of competing, I guess, priorities or competing ways that you design appraisal well. Is this -- for 8 miles out, is this just -- is the dominant thing to test the extent of the structure? Or are you really trying to -- are you perhaps instead looking for more reservoir development and more pay thickness? And then how would you answer that same sort of question for the eventual Cenomanian appraisal test?

Okay. Thanks, Charles. So the West-1X well is designed to Turonian down dip. It is testing for variability of reservoir, that would be reservoir thickness, reservoir quality. We're hoping to get confidence that where we drill the Cenomanian at that location is connected to the Bubale-1X location and also hoping to demonstrate an oil-water or an oil level deeper than the oil down to in the Bubale-1 well. So it's doing multiple things. And we think that location is important because with significant oil presence in that well, in the Bubale West-1X well, to be clear, that we'll have high confidence that we have a commercial development, but still significant uncertainty about the range of resource.

So the location of the 1X well was drilled in a position where there was significant up-dip reservoir in the Cenomanian and the Turonian and potentially significant down-dip potential in both. And the reservoir and the Turonian and the reservoir in the Cenomanian, they cross -- if you were looking at them from above, they cross like an X. We drilled the 1X well right where they cross. So like I said, potential up-dip and down-dip from that in both reservoirs. And ultimately, if we have success, we'll continue to identify and drill appraisal wells that will, over time, reduce uncertainty and give us high confidence in what we need to develop, how we need to develop it. So this next well is really key for us to having high confidence in a commercial discovery.

Got it. So it gets you with confidence over the low end, but with the upper end maybe still more unbounded.

Correct.

Going to Vietnam, and I appreciate your comments earlier about the basis that if I understood right that within the 4X, HSV-4X, you basically just didn't find reservoir quality rock. I'm curious, does that affect the prospectivity for some of these other blobs you have on your map in Block 15-2/17, I think they're labeled like [ Cozam ] and Hai Su Vang. Does this diminish your appetite to drill those somewhere down the line?

Those other prospects, we obviously will have learned a little bit from drilling Hai Su Vang through various reservoirs, and we will incorporate that into our understanding of those. I would say because of the diversity of different play types there and different reservoirs that those prospects are targeting that we probably still have quite a bit of confidence that they make sense. But again, there's a little more work to do to plan an exploration program there. In 15-1/05, we have, I would say, very well characterized and the learnings from HSV don't significantly impact our prospectivity there. So you'll see us focus on exploring in 15-1/05 in the next couple of years with probably activity in 15-2/17 maybe in '28, '29, not in '27.

There are no further questions at this time. I'll turn the call over to Mr. Hambly for closing remarks.

Thank you. I'll close by thanking our employees for their commitment and execution. To our shareholders, we appreciate your continued trust and support. This concludes our call.

This concludes today's call. Thank you for attending. You may now disconnect.

Okay. We're going to keep moving. We're heading into the back 9 on day 1 of our Energy Conference. Again, this is Arun Jayaram from JPMorgan's E&P OFS and Integrated Oils Research team. Delighted to have our next presenter, Murphy Oil. Murphy is a diversified -- truly diversified E&P who has operations onshore, offshore, U.S. internationally plays that span the Eagle Ford, Gulf of America, Canada, Vietnam and a growing international exploration portfolio.

Very happy that Murphy decided to put out some breaking news yesterday on some favorable results with the drill bit offshore West Africa. We'll probably spend some time on talking a little bit about that just because it is really important to the story. Eric, how are you?

I'm doing really well. Thank you. It's always nice to be able to come to a like this and talk about oil discoveries.

Well joining us today is Eric Hambly, who's the President and CEO of Murphy. Eric, before talking about some of the recent developments, I was wondering if you could talk a little bit about the macro picture and how you're thinking about what's happening in the Middle East in terms of Murphy and your capital allocation decisions.

Arun, we've been fortunate enough to pretty much stay the course with our capital program here. We're not affected by any type of disruption from the Middle East. We don't have a Middle East business or a business that's materially affected by anything happening in the Middle East. We benefited as quite a few E&Ps have from higher oil prices, and we're using that to generate more cash.

We haven't been able to use that cash to do much more than just kind of stack it up on the balance sheet. We did some bond deals recently, which make it very hard for us to reduce our debt. And we've been fortunate enough to have success with the drill bit, which led to more spending on appraisal success at the Bubale discovery. And we'll get into it, but likely another appraisal well coming on the back of the discovery well, which will eat up a little bit of that cash, but we should still generate really strong cash flows this year on the back of quite high oil prices compared to our budget expectation.

All right. Why don't we just go ahead and dig in. Yesterday, you updated the market about your drilling progress in Bubale, which is in Côte d'Ivoire. This is part -- maybe you could just set the stage about your exploration program in West Africa and maybe next, talk about what you learned from your test at Bubale.

Sure. We put together a 3-well exploration program where we were testing 3 independent prospects. And we announced the results from those first 2 wells earlier this year. Both of those wells found noncommercial hydrocarbons. So we expensed those wells as dry holes. We learned a bit from the wells, and we'll continue to incorporate learnings from those wells into future prospectivity on all the blocks. We were fortunate to have a discovery at Bubale.

Bubale is an interesting well because we were able to test a Turonian objective and a Cenomanian objective where they are stacked on top of each other. So Turonian system crosses through the block in one kind of axis and the Cenomanian sand goes to another, and they happen to cross and they look like an X, one Turonian sitting on top of Cenomanian. So we were able to put the well right where they cross and test 2 objectives in 1 well, which is one of the reasons why we chose that well because we thought they both look prospective.

We were fortunate to find oil in both of them and are happy that the well found enough oil that we believe it is a commercial discovery. The features of the Turonian and the Cenomanian are very large and will require some appraisal to help us narrow the range of resource potential.

Before we drilled the well, we released a resource estimate of 340 million to 850 million barrels of oil equivalent on a gross basis. Right now, we're not in a position with what we know in the well to do any kind of updating on that. We're not saying we know it's smaller or know it's bigger. We're saying we need to learn more. We're happy with what we found. We think we found at least a minimal threshold to have a commercial development, and we're moving right away to appraise.

So the potential outcomes in terms of resource is still very broad. Again, 2 very large features. The wells were drilled not in the exact middle of the column in terms of crest to downdip, but in the upper part, not in the middle, but a little bit above the middle. So there's a lot of potential volume to find downdip. We're still working an appraisal plan, but we're likely to have a well test downdip either the Cenomanian or the Turonian, and we'll move from when we finish operations on the Bubale 1X well soon in the coming week or so, we will move immediately to be able to test that.

We set ourselves up in this 3-well program with an ability to add a fourth well with success. Obviously, we were hoping to have success on all the wells, but that's not how exploration works. But what we found so far in Bubale suggests that it makes sense for us to move quickly to go appraise. And so we'll do that well. When we're done with that appraisal well, be the Bubale-2X well, the rig will not long after we're done, leave to go do work for another operator in Australia. So that's a Transocean Skirose rig.

We will likely come back in 2027 with additional appraisal activity. We will be probably appraising as we go there. So we'll learn from the next well. If we find oil to be in a downdip position, it would suggest you need to go even further downdip to keep seeing oil.

If you think about the configuration we have, 2 reservoirs, 2 discoveries, you may, at some point, need to appraise up dip in both and downdip in maybe multiple locations in both.

So today, we look and think it's likely that in addition to the discovery well, you may need 3 to 5 appraisal wells to fully understand the resource size and importantly, what does the development concept look like, how you develop it? What kind of CapEx program do you have to develop it? What's the exact development concept, all that. It's going to take some time to evolve. We think what we found is significant, and we're going to move quickly because we think moving quickly will help shareholders realize value. So we're pretty excited about that.

We did spend a bunch of money on the well, of course, right? So when we went into the well, all of our exploration program, we assume that -- when we budget for exploration wells, we assume that they find nothing. So dry hole, it's pretty easy to have minimal evaluation and get off the well. When you find hydrocarbons, you typically spend a lot more time evaluating them. So we collected whole core, we collected sidewall cores, we collected pressures and fluid samples in multiple zones and fairly advanced wireline logging programs.

And because of that, the Bubale-1X well, when we finish it, instead of being around $65 million, we're probably going to be closer to $140 million and so then we're going to add another appraisal well. So we're definitely, with this activity going to go beyond the previously guided high end of our CapEx guidance. I don't have a new CapEx range to communicate today, but I believe on our August second quarter earnings call, we'll have done the work to have a better view toward how to guide a new CapEx range for our 2026 program.

Got it. Got it. And then just any sense in terms of timing of when you would have the appraisal well down? Or is it too early to say?

I think we'll move to the appraisal well in the coming weeks, and I would expect it to be less than 3 months to execute. So sometime later in the year, sometime probably third quarter, fourth quarter, we ought to have a result depending on how it goes. And I think it's likely that we'll need more appraisal, as I said, beyond that well. And so we'll probably be collecting data on Bubale well into next year before we kind of have enough information to know how to develop the field optimally and what's the resource range.

Okay. Eric, you've had a really strong exploration track record going back to what you've been able to do in Vietnam, now potentially significant discovery at Bubale. What's different at Murphy? What's driving what's been this really, really strong success with the drill bit?

We had a fairly disappointing run in exploration at Murphy that we work to turn around. So if you go back and look at our activity, if you exclude Malaysia, where we had just tremendous repeat success, the rest of our exploration effort was pretty disappointing from 2015 through to the early 2020s. And we recognized that and wanted to change something, and we made a lot of change. We changed our leader of our exploration organization. We went out and intentionally recruited top exploration talent in key skill sets and brought them in and put them to work.

And also importantly, we sort of changed the way we were prioritizing what we focus on and what we spend money on in our exploration effort. And what we did was try to have a regional study-based approach to deciding where might there be oil, where does it make sense to target and then collect additional data.

So instead of drilling on limited data, we were very intentional about getting a comprehensive set of 3D seismic data everywhere and also having all the reprocess seismic data you need in order to evaluate whether or not you want to drill prospects and having the discipline around regional study, driving specific block, driving specific data set, driving good work allows you to take really reasonable risk, very disciplined risk taking, where the resource you're exposing yourself to and the cost it takes to do it makes sense. And our track record since then has been really good.

So if you look at our program in Vietnam and in the Gulf of America and if you just leave off Côte d'Ivoire recently, over a 3-year period, we had a 60% success rate exploring, which is really, really good. In Côte d'Ivoire, we had a 3-well program. We had 2 unsuccessful wells. We had 1 discovery. And that 1 in 3 is something you might expect typically. We've been fortunate in our Cuu Long Basin Vietnam blocks to have 100% success rate. That likely will not continue forever, but we're happy with it.

So really quality team with a very disciplined approach, making good decisions and being restrained and taking the right risk makes a lot of sense, and that's led to our success, I believe.

Yes.

We get a lot of questions from how do you compete exploring with super majors. They have huge budgets and huge teams. You don't need huge budgets and huge teams. You need really skilled people with the right data and creative thinking in order to lead to discoveries, and we've shown that, that can work.

I'm going to perhaps try to put the cart before the horse so excuse me. But one of the questions we've gotten from investors, what are some potential development options down the road? Obviously, you need successful appraisal here. I know Eni is active in the Côte d'Ivoire, but can you maybe discuss that? And what are the time lines to kind of first oil if you do have a successful appraisal here?

Sure. The most likely development scenario for Bubale is an FPSO with a gas pipeline to shore. So oil would be processed and stored in the FPSO for offtake by trading tankers. The gas would go to the shore and feed a domestic gas market, which is fairly strong. There's a lot of need for natural gas there. That is the most likely outcome. Obviously, if we found a very large volume, you're talking about FPSOs, not an FPSO. We're way too early in the game to say that we're anywhere close to that. I think we'll be happy to appraise and see what we have.

But that's the most likely outcome. There are potential scenarios where you can look to the market and say, is there an FPSO that's available to redeploy, which might be the permanent solution or it might be an early solution in a phased development with something like Eni has done with Baleine. It depends on how big it is and how long it takes basically to drill all the wells and ramp up. That's kind of how we're thinking about it right now.

We tend to be a pretty efficient player from moving from discovery to first production. When we look at benchmarking our recent developments, so the last development in Malaysia, the current development in Vietnam and our most recent deepwater major project in the Gulf, we are executing from sanction to first oil in 3 years. That's about 40% faster than the industry average, and we're going to try to do the same here.

So if you look at the time it takes from discovery to appraise to field development plan and sanction all that, I think we're looking at a roughly 5- to 6-year time line from discovery to first oil with obviously a lot to learn before we can kind of commit to do that.

Okay. And given your drill bit success at Bubale, what does this mean for capital allocation going forward?

Yes. So this year, we have very limited ability to flex our capital program except up, right? So Bubale additional spending and additional well, which we think makes a lot of sense. The rest of our program, I don't want to say it's locked in, but our onshore program is almost behind us. Our offshore program is dominated by a really high-impact Chinook 8 well, which should come online in the second half of the year and very limited other capital to do anything with.

So for this year, it's going to increase. And as I said, we'll end up probably with a new range of CapEx this year or later this year. In terms of what we do longer term, we're going to have some choices to make, right? Do we -- we've been managing our onshore business, both Eagle Ford and Tupper Montney to be effectively flat production year-over-year. It doesn't take huge capital to do that, but it is significant.

We plan to explore additionally in Vietnam, and we'll have to make some choices about our future capital. For several years, we've been guiding a fairly narrow band of capital of our total company. And we've said that our Vietnam appraisal and development fit in nicely with that. The Vietnam program as Lac Da Vang development, that's Golden Camel, as it kind of winds down, our Hai Su Vang, our Golden Sea Lion development spending will kind of come up. So that Vietnam business can kind of fit in the overall range, a super active exploration -- sorry, appraisal program in Côte d'Ivoire and development of success in Côte d'Ivoire probably doesn't fit in that range.

So we have to think about where we have trade offs. I don't have answers for that yet. Obviously, the more we learn about Bubale, the more that we can kind of pin that down. I will just highlight that we have been over the years, especially with oil prices that are pretty supportive, we've been funding our capital program and had extra cash flow that we're using to do occasional stock buybacks. We have been on a debt reduction journey, and we're not in a rush to reduce our debt from where we are today. We're at about $1 billion of net debt. So near-term use of cash for debt reduction is probably not material.

Buying back our stock with cash flow is something that we'll be thinking about. If you think about an E&P company that trades roughly 4 years of cashflow and you have a line of sight to a materially growing business in Vietnam in the 2030s and what looks like an emerging growing business in Côte d'Ivoire, those things we think will be valued more materially as they get closer to ramping up in terms of significant production.

And so using cash to buy back stock makes sense to reward our current shareholders, but we need to balance that with the need to spend money to appraise and develop Bubale. So we have a lot of unanswered questions so far, but a lot of optionality, and we love that our portfolio provides that flexibility. Not many companies have an ability to pivot up or down an onshore business and an offshore business and choose to allocate exploration dollars to deepwater Gulf or Vietnam or Côte d'Ivoire.

Great. How does this impact your plans for Paon in that neck of the woods?

That's a really good question. So in the Paon development, we had a work obligation to complete a field development plan, which we did, and we submitted that in 2025. In parallel with preparing that field development plan, we were negotiating with the Ivorian government on a gas pricing structure that would make sense to make Paon a commercial development on a stand-alone basis. We didn't get to an agreement because the government wasn't willing to pay what it took to make that happen. And it's understandable for them because they did not want to pay more for the gas, which would lead to a higher electricity price, which they would pass on to a consumer.

And we were about to start drilling wells near Paon. And so what it looks like is going to happen is the Bubale discovery, if we end up building an FPSO with a gas pipeline, that gas pipeline is going to go right by Paon. So Paon has an ability to be commercial because of Bubale because we're going to develop Bubale for oil and have gas as a secondary product. And Paon is an oil field with a large gas cap. So a lot of the volume at Paon is gas.

And so combining the gas resources will help justify the cost of the gas pipeline, and it should make the gas price required to make it viable a lot lower. So that's work we have to do going forward, and it should be really good for the country.

Eric, hindsight is 20/20, but you made the decision as CEO to maintain a 90% interest in Bubale and high working interest across your Côte d'Ivoire. Maybe when oil was below $60, maybe some were questioning that move, but it seems like that was a great decision. And so thoughts are on will you continue to appraise at this high working interest or thoughts on maintaining that level of ownership?

Yes. I'm pretty sure we'll continue to appraise at this ownership. I will tell you, after 2 dry holes or noncommercial wells and having personally the recommendation to not just maintain 90% working interest, but we're paying 100%. I felt pretty bad. But now I'm feeling pretty good about it. And the decision around it was large resource exposure for relatively low well cost. So it's the kind of risk you want to take relative to other opportunities in the portfolio.

So I'm pretty happy with that. I think the appraisal program almost certainly conducted our current ownership. I think it's likely in most scenarios that we end up developing into our current ownership as well. That's been our long-run norm. When we find something we really like, like in Malaysia, we were in our various blocks, we had big resources to develop at 85% and 80% working interest and spending money on those was the best thing for our business. And so it's likely it heads that way. But if we end up with an extremely large resource, it may strain our ability to fund it.

I will say being the operator of Côte d'Ivoire, being the operator of Vietnam and being the operator of almost everything in the Gulf of America is a great position to be in because we're in control of the appraisal pace, the development pace. And we've seen some peers where they've been at the beck and call of super majors, and it can be challenging. And we're fortunate to be in control of the time line.

Yes. Maybe one question I want to go back to on Bubale. Can you talk about the complexity of this reservoir that you've -- one penetration, but with thoughts on that?

Yes. So what we found so far is very nice-looking light oil, moderate gas oil ratios, which I think is important. If you look at other Turonian discoveries in the country, they tend to be very gassy. I think the Marlin and Marlin South wells are very gassy. Paon is an oil field with a large gas cap, so gassy kind of volumes. What we've seen so far and what we think we understand about Bubale so far is oily with moderate GORs, which is really nice. It's what our regional studies suggested we would find, and it's nice to find that.

Gas is great, but oil is better when you're in a frontier environment like this. So pretty happy. We need to appraise the field to understand the lateral extent of all the reservoirs, how do the reservoir properties vary over a very large area in multiple directions, up dip, downdip in both reservoirs. We drilled the well where we could stack 2 objectives. We didn't drill the well in the best Turonian location or the best Cenomanian location. And so now we'll have to go drill other locations and see from what we interpret on seismic to be potentially a thicker sand, is the sand actually like that and what we're modeling in our seismic, does it prove out to be.

In terms of reservoir complexity, honestly, we don't yet know. I think that these look like broad, well-developed kind of channel-type sands, fan type systems, and they look really good. But we won't really know more until we put another well or 2 in the ground and see how does it vary.

And then the next obvious question is, for this play type, do you see other opportunities? I know Petrobras has been acquiring some acreage EOIs in there. But what kind of running room do you see here for other exploration prospects?

We have quite a few remaining prospects in the same age intervals and some other intervals like Albian intervals. So we're going to learn from all of our 3 wells, what can we glean from all the results? And what does that mean for future prospectivity? I think that near-term focus will be on appraising Bubale and moving it to a development as quickly as possible, but we'll likely be back here drilling additional exploration wells, testing the prospects that look really good after the data we've collected from this first 3-well program.

Okay. Great. I'm going to shift gears a little bit. Let's talk a little bit about the Chinook #8 well. This is going to be a really important well for your Gulf of America program?

It sure is. So we are progressing that per our plan. What we've been saying is the well is a fairly deep, significant Wilcox well. We're developing this well in an existing field, and it will be tied back to an FPSO that we own. And we're on track for that well to start producing in the second half of the year, which is in line with our plan. I'm very happy with the progress. That well is likely a 15,000 barrel oil equivalent per day on a gross basis when it comes online, and our ownership is high at 86.6%. And so we're thinking that likely 10,000 to 12,000 barrels a day on a net basis.

So that's a pretty big add to our volume. Current Gulf of America production is around 60,000 barrels a day. So this is a pretty big add, and it will help offset what is otherwise natural decline from all the other fields and a pretty big oily add of volume in the second half of the year. Super happy with our progress is right on track.

Okay. And then just a quick update on the Gulf of America. You sanctioned Banjo and Cello, I believe. And what are the things that should investors be in the lookout in terms of Gulf of America?

Sure. So on Banjo and Cello specifically, we're really happy with those. I think they help demonstrate that the strategy we put in place, which is a combination of more significant frontier and emerging exploration combined with some near infrastructure exploration in the Gulf is a thing that's working for us. So having a discovery that we announced early this year, sanctioned months later with a target to bring them online in the fourth quarter of 2027. That's really industry-leading execution time line. And those will contribute, we think, about 4,000 barrels a day net to us in 2028 when they're online for a full year.

So pretty happy with that. We have in our portfolio the same type of opportunity set that we'll continue to pursue and also an exploration portfolio in the Gulf that has an occasional larger kind of hub scale thing. So we're pretty pleased with that. And then also in the Gulf, outside of those exploration successes in our existing assets, we have a pretty significant high-return oily opportunity set to continue to invest in additional wells, workovers, things like that, that keep our portfolio in the Gulf probably production roughly flat. It may increase and decrease from quarter-to-quarter, whatever.

But between now and roughly the end of the decade, I think we'll see stability of that business. And then effectively without more discoveries, we'll basically run out of things to do. And that's okay. We're going to continue to explore it. I'm sure we'll find things as we've been doing. But also one thing I think investors sometimes miss is when you're done spending capital in a business that's strongly free cash flow generating like the Gulf of America and all you have is production with no CapEx, you generate tremendous cash flow, which will be a good outcome. So we've been heavily invested in the Gulf for decades. We're likely to continue to do that. But just our kind of core business we've identified now with even no more discoveries is a tremendous business.

Great. Let's talk a little bit about Vietnam. Maybe an update on the LDV development project?

Sure. Our Lac Da Vang and Golden Camel development is right on track, executing everything per our timeline. So key milestones that we've been asking people to pay attention to there would be the construction of the FSO, which is on schedule to sail to Vietnam in July. The construction of topsides modules in Vung Tau, Vietnam, on track to be heading out to the field for installation per schedule.

Pipeline campaign just completed in the second quarter. We're drilling development wells. Everything is on track for first production in the fourth quarter. Very happy with how it's going. I think it's important. This is our first development project where we used a heavy Vietnamese oilfield services and they did a tremendous job. And that's great because we have success at Hai Su Vang and 3 other camel colors in Block 15-1/05 that will all get developed at some point, and we're very likely to use Vietnamese contractors.

And when you can do your first project and have success, it gives you confidence that when you sanction a development of Hai Su Vang and say you're going to deliver in a certain time frame, you really have confidence in the workforce there to make it happen. And so we're super thrilled with how it's going so far.

Yes. And I was wondering if you could give an update on the Hai Su Vang appraisal program, I think you're keeping a couple of the wells as titles for now, HSV 3X and 4X are you going to -- maybe anything you could comment on those?

Sure. I'm happy to. So what we're doing, we had a discovery that we announced about 1.5 years ago. We had a second well that gave us a lot of confidence in a larger resource. We went out and said, okay, we've tested a small part of the field. We need to design an appraisal program that tests the Northeast extension of the field and the southwest extension of the field. It's a large structure. A couple of holes tells you a little bit, you need to cover more of the field. And you also need to test to see which of the potential reservoirs are prospective beyond kind of the primary.

So our 3X and 4X wells are designed to do that. We're in the middle of that program. I think it's going well. We're learning what we sought to learn from the appraisal program. I think if things continue to go well, we will be able to give some updated guidance on resource range in our August second quarter earnings call. It's possible that we may need a little more time, and we may be a little later into the third quarter before we're done with everything and have done the work necessary to give an update there.

And is it at that time that you'll be in a position to talk about development options and things like that?

That's how we're currently thinking about it is we'll move from that point to a field development plan, and we'll probably try to sanction the development before the year-end 2027 and try to bring it online as quickly as we can.

Yes. And then my last question is you've highlighted how Vietnam could be a 30 to 50 equivalent kind of business, 30,000 to 50,000 barrels of equivalent business for Murphy. Talk to us about that kind of target and what that can mean for the story?

Sure. I think that our Lac Da Vang, Golden Camel development that comes online later this year, as we continue to execute that into the second phase, it will ramp up in production. We think that's 10,000 to 15,000 barrels a day when it peaks, it will start to decline when we're done drilling likely. What we think we know about Hai Su Vang will add to that. So depending on how big it is, you may be higher in that 30 to 50 range or lower in it or you may be in that range for a shorter period of time.

So just those 2 fields, I think, gets you into the -- when Hai Su Vang gets ramped up, you're probably in the 30 to 50 range. And then the other discoveries we made will likely continue to be bolted on to them. So tie back into the existing infrastructure. We're imagining a hub near Lac Da Vang and a hub near Hai Su Vang and future and current already made discoveries will get bolted into them and help that runway go longer into the next decade. So we think that Vietnam business has a potential to keep growing and look great for us.

Great. Eric, thank you so much for your time today. Really appreciate it.

I appreciate it.

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2026 Earnings Conference Call and Webcast. [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, Rebecca. Good morning, and welcome to our first quarter 2026 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 first 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 thanks to everyone for joining us this morning. I hope you've had a chance to review our stockholder letter, which provides a detailed overview of our first quarter operational and financial performance.

Before turning to results, I want to touch on the broader context. Ongoing geopolitical developments, particularly in the Middle East, contributed to elevated volatility across energy markets during the quarter. While Murphy does not have direct exposure to the region, these global dynamics influenced realized pricing and reinforce the importance of operating with discipline and a long-term mindset. On today's call, I will briefly discuss this market environment, review our first quarter performance and provide an update on our exploration and appraisal program.

Against the backdrop of significant commodity price volatility, Murphy delivered a strong quarter. Our oil-weighted unhedged portfolio allowed us to fully capture prices as they moved materially higher. We generated cash flow of $429 million and adjusted net income of $47 million, including $67 million of exploration expense related to 2 unsuccessful wells in Cote d'Ivoire.

Cash flow was supported by higher oil prices late in the quarter with realized prices exceeding $90 per barrel in March. It's worth noting that March prices were not representative of the full quarter as prices rose roughly 50% from January to March. Our average realized oil price for the full quarter was $72 per barrel.

Given the ongoing commodity price uncertainty, we view flexibility as a competitive advantage and have chosen to remain unhedged at this time. This reflects the strength of our balance sheet and our ability to manage through cycles without relying on market timing or hedging for financial stability.

On activity and capital, our approach continues to be driven by market fundamentals and our long-term strategy, not short-term price movements. Accordingly, we are maintaining our capital guidance range of $1.2 billion to $1.3 billion. Externally, as our non-operated partners evaluate how to respond to the current environment, we're seeing a range of approaches emerge. We're engaged with our partners on their plans, and we'll assess the merits of participating in any new activity on a case-by-case basis where it clearly creates shareholder value.

Turning to operations. What stands out most this quarter is our execution, and that execution starts with our people. I want to recognize our teams for once again delivering robust, consistent execution across our portfolio. We delivered production above the high end of guidance, operated efficiently and advanced key projects across the globe in line with schedule and within budget.

Our production outperformance was driven roughly evenly by our onshore and offshore operations. Onshore, Eagle Ford exceeded expectations by nearly 3,000 barrels of oil equivalent per day, supported by strong performance from the 15 new wells brought online during the quarter. Longer laterals and continued innovation in drilling and completions are delivering strong wells efficiently, reinforcing the quality of this asset.

Offshore, the Gulf of America also outperformed by about 3,000 barrels of oil equivalent per day, driven by high facility uptime and efficient execution of planned maintenance.

Turning to exploration and appraisal. We are making meaningful progress across our program. In Cote d'Ivoire, drilling continues at the Bubale exploration well. We recognize the interest in this well and remain committed to disciplined, transparent communication. We will provide an update once operations are complete and the data have been fully evaluated.

In Vietnam, at our Hai Su Vang, Golden Sea Line field, we are finishing operations on the HSV-3X appraisal well and we will move next to the HSV-4X well, the final well in the appraisal program. Together, these wells will help define the field's full potential and inform next steps on development. As we have previously communicated, we will provide results and an updated resource range at the conclusion of this appraisal program.

To close, this quarter was a real-world test of our strategy. In an environment defined by rapid price movement and elevated uncertainty, our focus remains unchanged. We executed with discipline, exceeded production expectations and delivered solid financial results while continuing to create long-term shareholder value. Looking ahead, our strong balance sheet positions us effectively across a range of outcomes, providing resilience in a weaker environment and full participation if prices remain strong.

With that, we will open the call for your questions.

[Operator Instructions] Your first question comes from the line of Arun Jayaram with JPMorgan.

Eric, totally understand how you're not yet at TD and Bubale. But I was wondering if you could maybe comment a little bit on just your overall geologic concept for that well. And we did note that it is taking a bit longer to reach TD. So I was just wondering if you could provide just a little bit more color on your geological concept, how drilling is going and just overall, how you'd characterize progress on that well?

Yes. Thanks, Arun. Thanks for the question. We are actively drilling Bubale. We have -- the main objective of the well is the Cenomanian target. There is a secondary objective in the Turonian, which is shallower. We are currently drilling the well in the Turonian section. We have experienced slightly slower drilling progress than we had hoped for. So the well is taking a little longer to announce a result because we're still drilling it, and we've had a little bit slower rate of progress drilling. It's just a bit of hard rock to drill in part of that Turonian section. It's taking a little longer than I had hoped.

I can assure you, there's no one in the world who would like more than to be able to give an update on Bubale because I'm watching it very closely. I'm happy with our team's progress. We just don't have a definitive result to talk about as we're actively drilling it and have not yet reached the primary objective.

I was wondering, as we look forward to your updates on the third and fourth well in Vietnam, and appreciate, obviously, the 3-part series that you held on exploration and the PSC, et cetera. But talk to us about some of the development options that you're thinking about in Vietnam for HSV, which obviously has a lot of promise at this point.

Yes. We talked a little bit about this on our webinar series. So for anyone who's listening, if you haven't listened to our webinar series, I'd recommend you do that. The concepts that we're currently evaluating for HSV, while it's still early days, are 2 primary opportunities. The first would be an FSO paired with a series of platforms that would be processing platforms and/or wellhead platforms. And the alternative to that would be an FPSO concept, either a new build FPSO or a potential redeployment of an existing FPSO.

We don't yet know the ideal approach forward. But we're hoping after we collect the data from our appraisal program, we will use that information we collect to design a field development plan. We will seek an optimal development based on capital efficiency and timing. And we'll probably about a year from the conclusion of our appraisal program, we'll likely have clarity on our path forward. So FPSO or an FSO with some wellhead platforms and processing platforms.

Your next question comes from the line of Carlos Escalante with Wolfe Research.

I'd like to ask first on your reinvestment rate framework moving into the end of the year into 2027. It looks like the collective aggregate of the estimates of my peers and I have you at around 185,000 barrels of oil equivalent per day for 2027. I know I'm being very specific here, and I'm not asking you for any type of guidance. But if I layer in Chinook first oil at LDV and then you recently sanctioned Banjo and Cello plus your incremental efficiencies in the Eagle Ford, it starts to look like a very conservative read into your 2027 number.

So I would ask you to help us calibrate the production versus capital efficiency equation, particularly as nonproductive CapEx converts into producing assets that are free cash flow positive in 2027. So help us think about your reinvestment rate into 2027 relative to 2026.

Yes. Obviously, Carlos, we don't have a budget for 2027 yet, but I'll give you a little color around what I think is going to be constructive for us as we head toward the end of this year and into next year. The volume addition from the Chinook 8 well that we expect to come online in the second half of this year will be significant. And Lac Da Vang Golden Camel field starting up in the fourth quarter of 2026 and ramping through 2027 will add to additional volumes in 2027.

What we haven't yet come up with is a detailed plan for exactly what to do with our onshore assets. I think we have a lot of thinking to do around how much we spend on exploring next year. We have a target-rich environment to explore in Vietnam and some exciting opportunities to test in the Gulf of America in 2027. So we have work to do before we form a 2027 budget around how much we spend on exploration in the Gulf and Vietnam versus deploying for investing in Eagle Ford, Tupper Montney, Kaybob Duvernay.

So I don't have clarity yet on exactly what our forecast of production will look like for '27 because we have a lot of choices to make. I think we're fortunate to be in a mode where we can choose all those trade-offs. But just circling back, I think production additions are pretty significant from Chinook and then ramping up with the addition of Lac Da Vang field being online. And then Cello and Banjo is, we expect that will be a 4,000 barrel a day net contribution in 2028, not 2027 because we're expecting to bring it online late in 2027, just for clarity.

That actually does help a lot. And then if I can come back to Cote d'Ivoire real quick. Following your development plan submitted to the Ivorian government in 2025 for Paon specifically, is that in your mind still -- well, first of all, can you give us a brief overview of what may be taking a bit longer than you expected? What's the sticking point perhaps you're having with conversations with the government?

And then second, is that still progressing in your mind as a stand-alone development? And I know this is too much to ask because it's hypothetical, but in the event of a discovery at Bubale, would that underpin a joint development to add scale?

Yes. Great question, Carlos. So we did submit the field development plan as part of our work obligation. We -- in parallel with preparing and submitting that field development plan, we negotiated with various Ivorian parties to try to come up with a gas pricing arrangement that would allow that development to move forward.

The Paon field is an oil field with a relatively thin oil column and a large gas cap. So roughly 2/3 of the BOEs produced from the field, based on our estimation, will be gas and the rest will be oil and gas liquids. So gas pricing is really critical for that project having economics that meet a threshold that we're willing to invest. We were so far unsuccessful in agreeing with the Ivorian government on a gas pricing structure that would inspire us to sanction the project.

So while we know what we'd develop, how we would drill the wells and the facilities we would install, pipelines we would install, et cetera, we didn't get to a point where we were ready to move forward with the development. We're not obligated from our agreements with the Ivorians or the PSC to do the project, we are obligated to submit a development plan, which we've done. We're interested in doing the project if it can make money at a threshold we're willing to invest in.

Going back to your question in a bit more detail, any resource that is discovered near Paon could help add scale that could make the project commercial at a gas pricing structure that could be maybe lower price, which is in line with Ivorian desire and make the project move more economically. Resource density would help justify the cost of a gas pipeline from the field or fields to the shore to deliver gas for power generation in Cote d'Ivoire. So any discovery even by third parties nearby might also be helpful for bringing that project forward at some point.

Just to clarify, so would -- does Paon lower the threshold of your consideration of commercial hydrocarbons at Bubale?

It would, yes.

Your next question comes from the line of Chris Baker with Evercore ISI.

Eric, hoping you could just maybe help frame up the opportunity in Cameroon, what you guys are seeing there and what sort of next steps we should expect?

Yes. Thanks, Chris. We are interested in Cameroon for a few reasons. It has attractive geology and allows us to do what we are -- in communicating we're trying to do with frontier and emerging international exploration, which is get into opportunities that are at a relatively low cost of access and allow us to test prospects with relatively low-cost wells that target large resource. Cameroon is a bit interesting and unique in that it offers both shallow and deepwater exposure with a variety of play types, attractive geology, a proven source rock system and discoveries in the country, particularly in shallower water.

And it also -- we recently acquired and analyzed some newly reprocessed seismic data, which points to some prospectivity that was not obvious to us when we were previously in Cameroon about a decade -- over a decade ago. And so we see some opportunity that's attractive, and we get into the country relatively cheaply and can assess it. And at some point, if we decide to drill a well, we think we can test large opportunities with low well cost, which is what we're trying to accomplish. That's kind of the setup, Chris.

That's great. Just as a follow-up, the macro has obviously changed quite dramatically here. It sounds like for the most part, the '26 program has been seeing some early wins and remains largely on track. I guess one of the big themes you've seen from some of your peers this quarter is a focus on flexibility when it comes to cash returns. I'm just curious, as you guys look out for the rest of the year, under a strip scenario, there's obviously quite a bit of excess cash. And I saw in the release, obviously, remain committed to the 50%. Can you just help frame up some of the flexibility and how you're kind of thinking about share buybacks from here and how that fits into the story for the rest of the year?

Yes, it's a great question. We are committed to delivering a competitive dividend to our shareholders as we've done since 1961. And we also have a desire to be a somewhat consistent repurchaser of our stock so that we can concentrate wealth in our existing shareholders. Having said that, we are not attempting to be very rigorous around a target of share buyback per quarter. We will likely approach share buyback with a bit of a more opportunistic assessment. And if we think that our share price is really cheap, then we'll probably move more quickly. If we think our share price is a little higher in the range, we may be a little more patient. So we'll sort of watch where we think that's heading.

If you look at Murphy's share price trading performance over the last several years, even maybe longer, we tend to trade in a very tight correlation with oil price. I think that most prognosticators would guess that oil price will likely come down after resolution of the conflict in the Middle East. And so we're going to kind of watch that and see, does it make sense to move quickly or does it make sense to wait because I anticipate it's likely oil price falls significantly that our share price may come down with it. And so it maybe makes sense. So we're going to be a bit careful and disciplined around that, and we'll act if it makes sense, and we'll wait until a better opportunity if we think that is coming in the future.

Your next question comes from the line of Greta Drefke with Goldman Sachs.

My first, I'm just wondering is if Murphy has any exposure to the Gulf specific crude pricing that has seen an outsized positive move in recent weeks and months? And if so, what's the lag on earnings impact to realized pricing that we should be mindful of?

So we don't have any direct exposure to crude in the Middle East. We benefited from higher oil prices, and we've seen a little bit around pricing differentials move a little bit.

I may let Tom, our CFO, who also oversees our marketing team, just give a little more color around differentials and part of our production from the U.S.

Yes. We are definitely seeing some more constructive pricing in the U.S. Gulf. Some of our crudes that benchmark to WTI, but the differentials are starting to show more strength than where we were a few months ago. So those lag by about a month. Usually with WTI, our benchmarks, we see those average prices as we market our crude. But the diffs -- the differentials are set. There's a bit of a lag on those. So through April, going forward, we'll start benefiting from those more constructive diffs in our crudes.

Great. I appreciate that color. And just my second question is just if you can speak to how the exploration blocks that Murphy was awarded for the new federal lease sales compete for capital relative to other prospective areas in your existing Gulf of America position.

Yes. The blocks that we picked up in the most recent lease sale from December of last year are a combination of blocks near our existing infrastructure where we'll target what are likely high chance of success, but not very large opportunities that allow us to put additional future volumes over facilities that we own and operate today. And the other part of the blocks we picked up are a little more sort of emerging part of the basin. And we are going to assess and evaluate the optionality we have there and think about an exploration program in '27, '28 that balances near field versus a little more emerging part of the Gulf.

Your next question comes from Leo Mariani with ROTH Capital.

I wanted to just follow up a little bit on Bubale. I think, obviously, the well is taking longer than expected. You did mention there was some kind of harder rock in Turonian. Was that kind of the primary driver around the well taking longer? Is it just slower drilling? Or was there any other kind of like mechanical snafu or did it get started late? Anything like that?

And then I also wanted to ask, it sounds like you're drilling through the Turonian, have you seen any shows in that zone at this point? And do you have kind of an updated estimate in terms of when you think the well is done? Are we just a couple of weeks away? Is it relatively imminent? Just any more color would be great.

Sure, Leo. Unfortunately, the issue is we've had slower drilling than we'd hoped for. It's not shocking because there are offset wells drilled by other people that have also seen some slow drilling in the section. It is a little slower than we were hoping for. And as I said before, we don't have any definitive conclusive results to talk about, and I don't want to speculate as we're still drilling through and have not even seen the primary objective. So we'll wait until the well is done, and we'll give you an update.

Got it. Okay. And then just sticking with exploration. Obviously, you announced Cameroon. It seems like it wasn't too long ago where you guys talked about Morocco as well. So it definitely seems like the company is kind of stacking up some opportunities internationally. Clearly, you've had success in Vietnam, which looks very promising. Should we really be thinking about just Murphy kind of continuing to, maybe I'll just say, move some of these exploration priorities come up in the stack. I know you're drilling with more exploration dollars this year. And obviously, that will depend on the oil price environment, but should people just generally think that perhaps over time, Murphy will continue to spend a little bit more on exploration than maybe it has in past years?

Yes. I think this year, we're spending a little more than typical because we were quite excited about the prospectivity in Cote d'Ivoire, and we felt it made sense to drill those prospects at 100%. So our spend this year is a little higher percentage of our overall capital. And then if you pair that with our Vietnam appraisal program, which is quite active, it's just a bit of a heavier year than normal.

I think if you look longer then we're likely to spend probably 10% to 15% of our capital program on exploration, and that would be all forms of spending, that would be on our people, our seismic data and our drilling wells. So that could change if we had a compelling reason in the future, but I think that's a pretty good way of modeling us.

We're trying to keep opportunities in front of us. So where we find attractive entry points, where we can do what I said before, which is get in relatively inexpensively and test prospects that have large resource with relatively low-cost wells, we want to set up a stack of opportunities that can do that for us. And these things take time to progress and mature. So we want to have a program where every other year or so, we have a new thing we're testing because we think the world needs ongoing exploration and exploration success to supply demand growth that's expected in crude oil. So that's what we're trying to do.

Okay. That makes sense. Maybe just last one for me here, Eric. So obviously, Murphy had a bit of a rigorous capital return framework that was laid out a handful of years ago. You commented on this on the call. It sounds like you're kind of moving a bit away from that when maybe that framework made sense when oil was a little bit more range bound. Now that oil has seen just tremendous volatility, should we kind of assume that the rigorous framework is somewhat abandoned here and you guys are just going to be kind of opportunistic and not necessarily give 50% of adjusted free cash flow back?

Yes, Leo. I think I wouldn't characterize our framework as still fully in place. The only thing that I think we'll try to do is be a little more opportunistic around timing of execution of our framework. We still want to buy back our stock. We still want to occasionally increase our dividend. We still want to use part of our cash flow to target to our balance sheet. Obviously, with our debt towers now, it's very difficult for us to remove -- reduce long-term debt, but we can build cash on the balance sheet to affect net debt. Those are all things we want to do. There's no change to our framework, although I think that we are in the face of what I would characterize as extreme commodity price volatility, we'll probably be a little more opportunistic around timing of executing what we desire to do.

Your next question comes from Phillip Jungwirth with BMO Capital Markets.

I had a couple of questions on the Eagle Ford, where well performance continues to be really strong. First, can you just talk about what's changed in the program over the last year to drive the better results? Would it make sense to kind of revisit the 30,000 to 35,000 a day plateau for this asset given the inventory? And then just lastly, I wanted to ask if the planned Catarina wells later this year are mostly Lower Eagle Ford? Or does this also again include the Upper and Austin Chalk?

Yes. I'll give you my high-level thoughts around how we're allocating capital, and then I'll let Chris Lorino provide more context on what's driving well performance. So we have guided kind of a midterm perspective of Eagle Ford in the 30,000 to 35,000 barrel a day range net to us. Last year, we exceeded that on the back of really strong new well performance. This year, our guide is also higher than 35,000 barrels a day, around 38,000 barrels a day because we're kind of carrying that performance in from last year. We did allocate less capital to Eagle Ford in '26 than prior because we saw strength of performance, and we've seen some early strong performance from our Eagle Ford program this year. So really happy with how that's going.

We haven't decided yet if we're going to allow that asset to decline back down to a 30,000 to 35,000 range in future years or if we'll try to keep it at 38,000 barrels a day or close. I have a guess that we're likely to try to keep it a bit higher, but that's something that we have choices to make on as we formulate a budget for next year.

And so that's kind of how we're thinking about the asset. It's not quite clear to us yet the best use of capital. It will compete for capital with other opportunities we have across our portfolio. So we have to think about that as we formulate a budget for next year.

And I'll let Chris Lorino give a little context on what's driving well performance and maybe the well mix that's left the rest of the year.

Phillip, yes, the performance has been a pretty simple story. It's been a lot around the capital efficiency improvements that we've made, a lot about longer laterals and taking advantage of the additional footage and driving down our cost per foot. So -- and also, we continue to tailor each location to specifics around the rock and all the things that go into what's nearby and what adds up to those locations. So that's -- we've really got down to where we've got it down to a science in each location and continue to see surprises to the upside.

And if you look on the earnings deck, you can see some of the Catarina performance, a really great shallow decline that we're seeing there. So we've got a lot of running room in Catarina and continue to have some running room for longer laterals as well to take advantage of these capital efficiency stories.

And then I also wanted to ask about the Gulf of America lease sale, but more specific to those Alaminos Canyon blocks that you kind of referenced there. I know it's early, but I was wondering if you could at least be able to talk about what drew you to this part of the basin as far as seismic or anything else just because it is a newer area.

Yes. We acquired some seismic data in advance of the lease sale that pointed us to some opportunities that we thought were compelling enough that we should target those blocks. And we're excited about the potential. We have more work to do to work through our exploration prospect assurance process and get comfortable that we've done everything we can to make a decision around drilling what looks like an interesting prospect or 2, and that work is ongoing. And I think there's a good chance that we may have a well out there in Alaminos Canyon in our '27 or '28 exploration programs.

Your next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

I want to ask first on expected oil prices in Vietnam. Eric, when I last saw you and the team in Houston in March, you mentioned a $12 premium to Brent you were seeing for oil in Vietnam. And you sort of suggested this wasn't sort of a one-off issue with like refinery demand. So I know volatility is really high across the globe. But can you kind of give some context on what you're seeing on oil pricing in Vietnam and maybe how you think that could look by the time you get first production there?

Yes. I really wish I knew what oil prices would do in the future. What we expect from Vietnam on a long-run basis is based on location and crude quality, we would expect Brent plus maybe $2 or $3. Right now, there is a significant disruption to oil flows to Asia and physical deliveries of crude in the region have been seeing elevated differentials to Brent. So Brent plus $12 was what was on the market in March, which obviously, that's a fairly -- we expect that to be a short-run thing.

I don't know what Brent pricing will be when we come on stream in the fourth quarter. And I don't know how limited physical cargoes will be in Asia in the fourth quarter of this year when we come online. But I do think that we expect to see Brent plus something. I don't know if that will be Brent plus $2 or $3 or Brent plus $12. I think we are fortunate to have a growing business in Vietnam, where there's strong demand for crude. And I think the world is likely to price in crude deliveries to Asia with a little more geopolitical risk premium than maybe they were before the conflict. So I think that sets us up for some success.

Okay. I appreciate the context there. And then as my follow-up, I just want to ask on the CapEx cadence for the year. It's very front-end loaded. It looks like about 68% of the spend in the first half, those of us with gray hair are used to seeing companies really struggle to hold the line on spending when they have such a heavy front-loaded skew. So can you talk about your confidence that you can stick to that budget? And perhaps I know you talked about non-op opportunities, like what may cause you to deviate if Brent does hold at such a high price?

Sure. I'm very confident in our ability to deliver a capital program that's in line with our guided range. I think if you look at our performance over the last few years, we've been pretty good at coming in really close to the range. Last year, we actually underdelivered on the range. We came in a little lower on CapEx.

Our program is front-loaded a bit for 2 reasons, we have a heavy onshore program that's weighted to the first half of the year in terms of drilling and completing wells. And our exploration and appraisal program in Vietnam and Cote d'Ivoire is heavily weighted to the first half of the year. So I feel good about the things that are in our control allowing us to deliver capital within the range.

We do think it's possible there may be non-operated opportunities in our Eagle Ford business that come up that may be something that makes sense for us to participate in. I think those things would not be very significant. And I think today, when I look at what may develop, I feel good that our range covers what is likely to happen.

I will caveat that with one thing, if we are fortunate enough to have a success at Bubale, we are likely to drill an appraisal well at Bubale immediately. We have a rig available and equipment available to do that. We've signaled that in the past investor engagements that that's something we would likely do if we were fortunate to have success. I don't know what we have yet, so I don't know if that will happen. But another well at Bubale this year is not in our capital range, and it would push us either to the high end or maybe perhaps beyond the high end of that range. [ indiscernible ]

Your next question comes from the line of Josh Silverstein with UBS.

In Vietnam, I wanted to see if you could talk a little bit about the LDT exploration prospects there. I think you guys are set to spud in the back half of the year. Maybe just some similarities and potentially if a discovery, a quick tieback opportunity to LDV.

Yes. The LDT North prospect is White Camel North. That prospect is targeting the same age reservoir as the Lac Da Trang or White Camel discovery that we made in 2019. It's a different compartment, but the same age reservoir. We are expecting it to have a mean to upside gross recoverable resource range of 40 million to 80 million barrels oil equivalent. Again, our expectation in this basin is it's quite oily.

With success there, it would likely be a tieback to the infrastructure that we're developing for Lac Da Vang or Golden Camel. If it happened to be extremely on the large end, it could anchor an additional hub. But I think the most likely outcome is that it will be tied back to the FSO that we're using to develop the Lac Da Vang field, which will be installed later this year.

And then just maybe on the new country entry front, Cameroon this quarter, Morocco earlier this year. Can you just talk about kind of broadly the strategies for entering these new countries and areas versus, say, doing a bit more in the Gulf versus, say, Alaska or other parts of Africa that have kind of established basins there? And maybe along the same lines, how would you kind of think about the risking of these prospects versus, say, what you were doing in Cote d'Ivoire?

That's great. What we're trying to do is use regional study to guide entry into opportunities that we like. So instead of saying, hey, there's a prospect in one block in one country, let's go get it. We're actively assessing opportunities over a large geography, doing detailed regional study and identifying opportunities where we think we can assess -- cheaply assess and test large opportunities. Those are going to be mostly in what we would characterize as emerging basins. So there's a working petroleum system identified by either past discoveries or other exploration wells that allow us an opportunity to test large resource with low well cost. That's what we're trying to do.

If I characterize our portfolio today, I would say that we have a limited ability in the Gulf of America to identify large opportunities. The well costs in the Gulf are expensive because of the complexities of drilling, either the depth or the sub-salt, et cetera, and the resource ranges are becoming smaller and smaller in the Gulf as a trend. We do have some compelling larger prospects in our portfolio. Most of our opportunity set in the Gulf is going to be smaller opportunities near infrastructure, whereas internationally in Vietnam, and Cote d'Ivoire, in Cameroon and Morocco, we have an ability to test larger things with cheaper wells, which is kind of what we're trying to do. I think we're fortunate to have a capability that we've maintained to be an international explorer and we execute generally quite efficiently in our well programs.

If you look at the risk profile across our business, the near infrastructure prospects in the Gulf of America are our highest chance of finding hydrocarbons. The opportunities we're drilling in Cote d'Ivoire and the kind of things we'll test in Cameroon are likely to be kind of the next up on the risk profile. I would characterize the Morocco opportunity as frontier and the highest risk profile in our portfolio now. We are planning to do some seismic reprocessing in Morocco, which may help us derisk that prospect. And that's kind of the setup for how we're going to move through assessing the portfolio we have to explore in West Africa and in the U.S.

Your final question comes from the line of Charles Meade with Johnson Rice.

Forgive me if I'm -- I missed the few minutes of your call, I don't know hard time getting on, but -- so forgive me if I'm asking something you already covered. But I wanted to ask you to speak kind of at a high level about Chinook because it's going to be at that 15 MBOE a day gross, that's going to be a big increment to your Gulf production. And I think an earlier caller was asking about that. But can you give us the big setup here? I mean, this field has been producing over a decade. It used to produce a lot more. This looks like it's going to be a big new producer. Can you just give us a reminder, what is the setting of this -- of your reservoir here? Are there follow-up opportunities that are contingent on how this #8 well performs? And how much capacity is there available at the Pioneer FPSO?

Yes. So the well is targeting the Wilcox, 2 Wilcox sands that are currently producing in another well in the field in the same fault compartment, the same reservoir section. There was a well that had produced back in 2019, and that well had a mechanical issue, and we have not produced that well since. And we believe that the well is something that we cannot effectively produce going forward. So we planned a development well to go develop the reservoir. I would characterize the reservoir as having a large in-place volume and a low current recovery factor. It is underdeveloped and needed additional wells to produce the field.

We have identified this opportunity many years ago, but we didn't want to act on it for a couple of reasons. First was we were leasing the FPSO that is used to produce the field. And we identified that the terms were not that great after we took on the assets from our Petrobras joint venture deal, MP GOM. When we got it into our operatorship, we realized it wasn't a great lease agreement, and we worked to purchase the FPSO, which we did last year, which allows us to have improved economics on any future activity in the field.

We also have a very expensive well that takes a long time to drill and complete. And while we were on a debt reduction journey to get close to our ultimate debt target, we didn't want to allocate capital to this just because it was a singular very large thing, and we wanted to wait until we had the FPSO purchased. So we've really done a great job, I think, of setting up this field to have a good financial outcome.

Again, it's a development well in an existing reservoir. It will add additional production from the same reservoir that's already producing. So we don't really have a contingency plan. It's just an additional development well, kind of effectively replacing a well that had previously been producing in the field, but in a more optimal location.

There's probably additional opportunities in this field, both exploring untested fault blocks and maybe an additional production well that we are currently evaluating and the results from this well will also help inform whether or not we think an additional well will be necessary.

Got it. That is great color. And then just as a quick follow-up. I think it was a couple of years ago, we were wondering what was going to happen with the Petrobras assets, your NCI volumes. And that just kind of seemed like it fizzled out. Is there still any process underway or any chance for you guys to acquire that? Or would you have a pref on that if someone else announced a deal for it?

Yes. We would love to acquire it at the right price. Today, I don't believe that Petrobras is actively marketing their ownership in the joint venture. We do have a pref right if such a deal was struck. So at the right price, it would be great.

I will now turn the call back over to Eric Hambly for closing remarks.

Thank you all for another engaging Q&A session. Paul Cheng, if you're listening, we had expected you to pop up with a question on this call. Paul covered Murphy as an analyst for over 30 years and just retired from Scotiabank in March. We always appreciate his thoughtful questions, and I'm sure the incoming team will be happy to carry the baton. Thank you all for tuning in, and thank you to our shareholders for their ongoing trust. This concludes our call.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.

Hello. My name is Sarah, and I will be your conference operator today. [Operator Instructions] I will now turn it over to Atif Riaz, Vice President of Investor Relations and Treasurer.

Thank you, operator. Good morning, and welcome to Murphy's 3-part Educational Webinar series. This series has been designed to highlight the company's exploration and development strategy with a specific focus on our growing Vietnam business. Today's webinar will feature prepared remarks by members of Murphy's senior leadership team, followed by a live question-and-answer session. A copy of the presentation for today's webinar is posted on the Investor Relations section of Murphy's website. As a reminder, our webinars may contain 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 webinar, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of America. Any references to the terms or modeling of production sharing contracts in today's webinar are for illustrative purposes only and do not reflect the terms of any actual contract.

This information is not a forecast or indication of Murphy's strategies, business plans or future events and should not be relied upon when making an investment decision with regard to Murphy.

I will now turn the call over to Eric Hambly, our President and Chief Executive Officer.

Good morning, and welcome to the third and final session of our offshore webinar series. I hope the first two webinars provided valuable insights into how we deliver differentiated value through exploration and development and clearly illustrated the importance of our growing Vietnam business. Today, we will take a closer look at the contractual framework that underpins Vietnam, the production sharing contract, also known as the PSC. Understanding the mechanics of a PSC is essential to valuing offshore projects in Vietnam and many other countries around the world.

Before we dive in, here's a quick recap of where we've been in this series. In our first webinar, we discussed Murphy's unique approach to exploration and development, our strong track record in this space and how our strategy positions us to compete and win offshore. In our second session, we highlighted Vietnam's favorable economic and political climates, strong geology in its Cuu Long Basin and the potential for our asset base there to become Murphy's next engine of long-term shareholder value creation. In today's session, we will start with an overview of the history and fundamentals of PSCs, why they exist, how they're structured, and the key components that define the fiscal framework.

We will walk through a simplified fictional PSC model and build it step by step using example numbers to show how cash flows and entitlement production evolve over the life of a project. The final section today will touch on important structural considerations, including multi-field development and how it can help optimize free cash flow. You will also see the effect of commodity price changes on free cash flow under both PSC and concession frameworks. By the end of today's session, our goal is for you to have a clear understanding of how PSCs work and how they fit into the broader offshore value story we've discussed throughout this webinar series.

I will now turn it over to Chris to frame the history and basic structure of PSCs.

Thanks, Eric. Let's start with historical context around the origin of the production sharing contract, or PSC. Before PSCs, the widely accepted model between an oil company and host government was the concession agreement, which effectively offered a tax royalty structure where the contractor realized the majority of upside benefits. PSCs were developed as an alternative to concession agreements, driven by host countries wanting to attract foreign investment while also retaining more control around timing of development and capturing more of the upside from their produced hydrocarbon resources. The first modern PSC was implemented in the 1960s in Indonesia, and the model rapidly gained traction internationally. During the 1970s, the PSC had become widely adopted across emerging petroleum provinces around the world.

Today, about 1/4 of the world's producing countries use PSCs as the governing contract between governments and operators. Production sharing contracts are designed to attract investment by balancing risk and reward between parties, and this balance is a defining feature of PSCs. The structure is particularly suited to capital-intensive projects as built-in mechanisms benefit the contractor during the early years of investment. Before we go further, let's take a moment to clarify how we will use the term contractor as we will refer to it throughout today's discussion.

In a production sharing contract, a contractor or contractor group refers to the international oil company or the consortium of companies that hold interest in a block or permit and who are responsible for carrying out the exploration, appraisal, development and production activities. For example, in the PSCs for our 15-1/05 and 15-2/17 blocks in Vietnam, the contractor or contractor group are comprised of Murphy, PetroVietnam or PVEP and SK Earthon. With that, there are several key elements to the PSC. These elements serve to protect the contractor from downside risk, deliver competitive returns and provide government profitability over the life of a project.

So let's dive in a little deeper. First, once production is realized, PSCs offer cost recovery, which acts as a protection floor for the contractor. During cost recovery, the contractor receives disproportionate access to early revenue streams, allowing them to recover eligible exploration, appraisal and development costs. For the contractor, this limits downside during the most capitally exposed phase of the project by prioritizing return on investment. Second, governments and contractors participate in profitability through profit share splits, limiting contractor upside as projects become more profitable. Most modern PSCs have a progressive sliding scale, whether price-based, volume-based or linked to an R factor, which is a ratio of cumulative revenues to cumulative cost.

These mechanisms increase government take as project profitability improves and serve to offset the disproportionate share of revenue that the contractor receives during cost recovery. On the right, we show how this compares to a generic concession agreement. Under a concession agreement, the contractor typically owns the produced hydrocarbons and bears most of the subsurface and project risk. Under a PSC, the government retains ownership of hydrocarbons and risk and reward are more evenly shared. In summary, the PSC structure creates a stable and predictable contractual and fiscal framework that incentivizes contractor investment while simultaneously ensuring that governments receive increasing value as projects progress. Investors are often concerned about government take.

A useful way to think about it is that government take is really a function of risk, reward and negotiation dynamics. In the early stages of a basin's life, the uncertainty is high, the geology is less understood and the investment risk is significant. So governments typically offer more competitive fiscal terms to attract capital into those more frontier investment phases. But over time, as the basin matures, when discoveries have been made, infrastructure exists and technical risk drops, the fiscal terms naturally tighten. The graph to the right shows this through a range of modeled scenarios for different countries and illustrates why countries like Morocco and Brazil plot where they do.

Morocco is high risk but offers unproven frontier upside, while Brazil's offshore basins are already proven and prolific. As mentioned during webinar 2, a higher government take does not imply weak project economics. Well-structured PSCs are designed so that early returns are protected through cost recovery and over time, profit share mechanisms scale with project profitability. This means the contractor can still generate strong returns even where government take is relatively high. This is how we approach our portfolio at Murphy. We're not optimizing for the lowest government take, we're optimizing for the strongest full cycle returns.

We target and are actively building a portfolio of projects that delivers globally competitive project economics. Fiscal terms are just one component in doing so. What truly matters is how the geology, development plan, cost profile and contract structure work together to deliver that value.

I will now hand it over to Franc for a detailed discussion on PSC models.

Thanks, Chris. On this slide, you will see the core building blocks of a model PSC in Vietnam. Although contract confidentiality restricts us from disclosing specific terms of our contract, today, we'll guide you through the key components of a typical Vietnam PSC. In Vietnam, certain components of the PSCs such as royalty and profit oil share vary based on negotiated production tiers. Over the coming slides, our discussion will primarily focus on revenues, and then we will take this revenue back to net barrels. First key component is royalty. Royalties levied on gross revenue and the royalty rate is calculated based on an incremental sliding scale linked to revenue generated from daily production.

In the top graph, we use a fictional sliding scale to show how the royalty rate evolves as production and associated revenue increases. The sliding scale is incremental. If the additional barrel produced falls into a higher band of the scale, the royalty rate for that barrel steps up accordingly. This is the marginal rate in the graph. The actual royalty rate across total production is generally lower than the marginal rate as reflected by the effective rate in the graph. Second, cost recovery. All costs related to petroleum operations, including CapEx and OpEx are fully recoverable over the life of the field. But annually, cost recovery is capped at a certain percentage of gross revenue. This cap rate is negotiable and confidential. The remaining revenue after royalty and cost recovery is considered the profit share and is divided between the contractor and the government.

Finally, contractors are subject to taxes and levies as defined in the PSC. This includes crude oil export tax on revenue generated from oil exported outside of Vietnam and environmental charges reflecting payments linked to environmental protection. Corporate income tax is levied on taxable income with varying rates depending on a block's government-defined incentive status. All terms apply at a block level and are part of the agreement between the contractors and the government. In PSCs, what you sign is what you should expect all the way through the life of the contract. If the country were to introduce new laws that would impact the general fiscal terms positively, the contractors can apply for that benefit. If the host government wants to introduce new terms that have a negative economic impact, a stabilization clause is in place for the contractors to obtain relief.

Let's discuss how cash flows through a production sharing contract and how project revenue ultimately translates into cash flow for both the contractors and the host government. At the project level, a full life project will incur exploration and appraisal and development CapEx upfront. Once production begins, the project starts generating gross revenue and incur operating costs. The contractor incurs all exploration and appraisal CapEx, development CapEx as well as operating costs. These costs accumulate in a cost bank and are eligible for recovery through the PSC cost recovery mechanism. From gross revenue, the first call is royalty, which is paid to the government. Next comes cost recovery. A portion of the production referred to as cost oil or cost gas is allocated to the contractors to recover eligible capital and operating costs.

While there's usually an annual max on how much production revenue can be used for cost recovery in any given year, the point is that all costs related to petroleum operations are recoverable over the life of the project. After royalty has been paid and cost recovery allocated, the remaining production is classified as profit oil or profit gas. This profit share is then split between the contractors and the government based on the agreed profit sharing terms. From their share of profits, contractors may also be required to pay tax and other levies depending on the specific PSC structure. Stepping back from a cash flow perspective, contractor cash flow is driven by cost recovery plus profit share, net of taxes and costs.

Government takes consists of royalties and share of profits and taxes. This is the basic framework of how project cash flow is allocated between contractors and the host government. And more importantly, it highlights the sequencing. Contractors recover their costs first and then share the remaining revenue with the government. As a next step, I want to walk you through the cash flow over the first 12 years of the life of a fictional project. For this fictional project, we're assuming a royalty rate of 5% and cost recovery ceiling of 50% of the annual gross revenue. As a reminder, costs will be recovered fully over the life of the project and the ceiling applies only on the annual basis. Here, our contractor profit share and corporate tax rate are assumed to be 50%.

Additionally, for the sake of simplicity, this example uses a fixed flat price of $75, OpEx of $10 per BOE and a flat production of 15,000 barrels of oil equivalent per day. Now let's dig into the model. In the first year of the project, we incur exploration costs followed by appraisal and development costs in year two through four. These costs accumulate in the cost bank as we have no production and negative cash flow. In year five, production starts and we generate revenue for the first time. In this example, royalties are calculated as 5% of gross revenue. We also incur OpEx and some extra development costs, which add to the cost bank.

Now that we have production, we're eligible to recover cost by drawing against the cost bank up to the ceiling of 50% of gross revenue, as previously mentioned. Unrecovered costs remain in the cost bank. After cost recovery, next step is to calculate the profit, which will be shared between the contractor and the government. We subtract the cost recoveries and royalties from gross revenue. In this example, the profit is split 50-50 between the host country and the contractor. At this point, the contractor's revenue equals the contractor cost recovery plus the contractor's profit share. From this revenue, we subtract the operating costs and the corporate income tax to get to after-tax operating cash flow.

Then after-tax free cash flow is calculated simply by deducting capital expenditures from the operating cash flow. Contractors' entitlement production is comprised of cost oil and profit oil, which can be calculated here by dividing the contractor revenue by the price. From year 6 to 9, we continue to chip away at the cost bank, recovering our costs. Year 10 is the first year the cost recovery ceiling is higher than the remaining cost. So in year 10, the project becomes cost current and has recovered all accumulated costs. Once the project is cost current, the government takes a higher share of the revenue and the contractor's entitlement production and free cash flow decreases.

The drop in entitlement production in year 10 onwards is an artifact of the mechanism of the PSC, not reservoir performance. Additionally, in this example, all prices are modeled to be flat, whereas in reality, changes in prices can introduce variations in year-to-year reported entitlement production. As we discussed on the previous slide, entitlement production is comprised of cost oil and profit oil and can be calculated by dividing contractor revenue by price. Early in the project, entitlement production is largely driven by cost recovery as a significant share is derived from recovering the accumulated cost bank. As the project becomes cost current, the cost recovery component declines and profit share becomes a dominant driver.

The cost recovery and profit share components may vary over the life of the project, but the overall entitlement production remains more stable year-over-year. Starting in fourth quarter, we will start reporting the entitlement production from our Vietnam business unit. In Vietnam, production and cost banks accumulate at a block level. This contract structure can influence how quickly incremental capital such as tiebacks can translate into recoverable costs and free cash flow. This is where our hub-and-spoke strategy, as we discussed during webinar 2, will really drive value for our shareholders. Once we have our two hubs producing, Golden Camel in Block 15-1/05 and Golden Sea Lion in Block 15-2/17, we will be able to recover exploration and development costs for future tiebacks against revenue from existing hubs, accelerating cash flow and adding to our net production.

Let's look at an example of how our hub-and-spoke development will work and its benefits. The graph on the right represents cost recovery and profit share for a single project. Both Field A and Field B are in the same block. Sample Project A begins production in year 1 and becomes cost current in year 4 on a stand-alone basis. Project B, based on a stand-alone economics, doesn't become cost current until year 7; however, since they're both in the same block, any new exploration or development spending on project B or any other projects in the same block can be cost recovered against field A production. Therefore, once we run the economics at a block level, the combined A+B project becomes cost current also in year 4. Since the Vietnam's PSC work at a block level, future development costs are recovered faster from existing revenue.

This will be the case for any future activity post first oil from the Golden Camel and Golden Sea Lion hubs. This is what the Vietnam PSC is designed to enable to incentivize the contractor group to continue to invest and develop resources and recover these costs from prior investments. Before closing, I want to focus on how PSC mechanics translate into something equally important for investors, valuation resilience across commodity price cycles. The chart compares the net present values for two offshore fields, one under PSC structure and the other under a traditional concession regime across different oil price scenarios. The key takeaway is that PSCs dampen volatility. Since PSCs prioritize cost recovery up to a revenue threshold, they allow contractors to recover capital earlier and share downside risk with the host government, resulting in more stable cash flows and lower valuation fluctuation across price scenarios.

Overall, PSC provides a natural buffer in lower price environments, helping protect cash flow when prices are under pressure, while concession arrangements allow for more participation in the upside. From the government's perspective, as prices rise and profitability improves, government take increases through profitable sharing, but the contractor still participates meaningfully in higher absolute cash flows. As we mentioned in our first webinar, our exploration portfolio is being built to perform across commodity cycles and it's not just a collection of individual prospects. This portfolio balance creates durability in our ability to deliver transformational upside.

Our objective is not just to maximize returns or net present value in a single price deck, but to build a portfolio that generates strong returns, supports the balance sheet and remains attractive through commodity price cycles. A combination of PSCs and concession-based assets allow us to do exactly that. And now I will turn it over to Eric.

Thank you for participating in our webinar series. We hope that our webinars helped improve your understanding of Murphy's strategy and capabilities and Vietnam's growing role within our exploration and development portfolios. The data is clear. Shale oil production will likely peak within the decade as global oil demand continues to rise, creating a supply gap, which can only be filled with ongoing exploration. Today, Murphy is among a very short list of companies who have maintained the muscle to successfully explore and develop. As the industry shifted its focus to shale, Murphy continued to invest in exploration and maintained an innovative oilfinder culture. Our culture and demonstrated track record allow Murphy to attract top exploration and offshore development talent and build a pipeline of opportunities with significant potential.

Our recent exploration success rate of 60%, combined with our ability to develop resources 40% faster than the industry, gives us a competitive advantage that simply cannot be replicated overnight. In Vietnam, you can see Murphy's strategy in action. Our track record in Southeast Asia earned Murphy access to the country, and we now have line of sight to a material 30,000 to 50,000 barrel per day business there in the 2030s. We still have more exploration to do. And with our current 100% exploration success rate in the region, we're optimistic about further upside. Overall, Vietnam represents the next frontier of organic growth for Murphy, and I'm excited for our future there.

As we look ahead, our entire organization remains laser-focused on our strategy to explore for untapped resources around the globe, develop them efficiently and deliver strong execution and long-term shareholder value. Thank you for joining us throughout the series for your engagement, your questions and your partnership. We will now take your questions.

[Operator Instructions] Your first question comes from Carlos Escalante with Wolfe Research.

Thank you for walking us through the PSC mechanics as you see it. My first question is on Slide 5, and we can perhaps go there. You mentioned that -- and I think we are well aware that the basis of any conversation with the government is around risk reward and obviously, fiscal terms. You've outlined multiple times throughout the past that the government take on the project is on the low 70%, so presumably between 70%, 75%.

My question is, if I look at that slide, and I understand that it's illustrative, you're outlining a 250 case at $75 oil, which, again, I understand it's illustrative. But it sort of points to a better than what you've outlined before. And the real question here is you've said multiple times that you've been invited by the government. And so presumably, you would have a fairly competitive set of terms. So just wondering if maybe you can square that away for me. Maybe it's just an illustration as a whole, but it would really help if you can provide some color there.

Great question, Carlos. The terms that we've talked about, they vary somewhat significantly based on the production rate from the block. So what I have said historically is 65 to 75. And if I was guessing, I'd say around 70, which is what's really indicative on this slide. Two points to make. First, the 15-1/05 block, the PSC was signed before we entered the block. There was a super major operator on the block who worked on that before we even entered the block.

So we did not have an opportunity to shape those terms. They were indicative of what the terms were at the time that was created. And I think that PSC was signed in 2007, so quite a long time ago. And the other block we were, of course, involved in. We can't disclose the terms. What we're trying to show you here is that these are sort of if you went to look at the petroleum law in Vietnam now, you would come out with a model field that would have this type of government take. And we're not intending to provide a fine-tuned number on what the government take will be from our blocks, but indicative of what you would expect for an average participant in the country now.

Got it. Okay. That helps. And as my follow-up, if you guys don't mind, referencing your hub-and-spoke strategy and because you are ring-fenced at the block level, what would a hypothetical successful [ HSV-3 ] exploration will mean for your current LDV -- for both your current LDV development and for a potential sanctioned HSV platform? And I'm thinking in terms of cost recovery and how you develop the field.

Carlos, Franc Garcia here. So a successful HSV-3X, if you -- as you know from the map, it's on the 15-1 block. What that will mean is that it will put us in the realm of unitization. So what will happen then is we'll create a unit for the whole development. And then each block's fiscal term will determine how the entitlement barrels will work. So there could be a case if we have a successful 3X and we improve reservoir connectivity, and we're now unitizing the field that we could be recovering HSV costs on 15-1 with the production from the Golden Camel.

Your next question comes from Charles Meade with Johnson Rice.

I wanted to ask, I think we -- I guess, in the investment community, we've seen a lot of other companies publish their PSCs with escalating R factors and all those sorts of things. So I'm curious, is this driven by Vietnam that you can't disclose? Or is it instead a Murphy decision? And are we going to be able to see the PSC terms for Cote d'Ivoire if something develops there?

That's a great question, Charles. So we are not allowed under our agreement with Vietnam to publish the terms of our PSC. If we were able to, we would publish them. As Murphy, we're not withholding information that we would like to give you. We're giving you what we can. What we're trying to do in this webinar series is give you as much information as possible that we think is helpful in order for you to create a PSC that closely resembles what we actually have without actually disclosing the terms.

And what I think you'll find from us over time, if we see a company like an information provider or a specific analyst that we think is particularly good at modeling our PSCs, then we may say, "Hey, why don't you have a look at So and so's model as we move forward and we think people are doing a better job or a worse job of modeling our PSCs. We'll try to help as much as we can while complying with the agreement we have with the government of Vietnam.

Got it. And any implications for Cote d'Ivoire?

To be honest with you, I don't know the legality of disclosing the terms in Cote d'Ivoire. I'd have to look at that. The terms in Cote d'Ivoire are very good. We showed on our webinar today sort of the risk reward. And typically, PSC terms are more favorable for the contractor group when there's a less proven basin, which I think is true of Cote d'Ivoire. And the terms there are very good.

In fact, they're almost as good as the United States, which is one of the best fiscal regimes in the world. They're not quite as good, but they're good. I'll have to follow up with my team later and determine what we can say about Cote d'Ivoire. I suspect we cannot reveal the actual terms because we probably would have done that already if we were able to, but I just don't have that answer.

Right. But if and when it becomes relevant, you'll disclose what you can, if I understand you. Correct?

Absolutely. We will help you as much as we can.

Your next question comes from Betty Jiang with Barclays.

Thank you for doing this webinar series. My first question is on the production optimization and how you guys think about sizing the size of the production? Because your Slide 10 shows that as your production goes up, your marginal royalty rate and contractor -- government take also goes up. But on an NPV basis, we typically think bigger boat, higher revenue, higher NPV upfront. So how do you optimize that return for the company?

And could you also just clarify whether the production stack up, like whether, say, Project 1 plus Tieback 1, Tieback 2, does that all stack up to the total production that determines the royalty rate?

Betty, Franc here. So we -- yes, so as we mentioned in our remarks, some of the terms in the Vietnam PSC are based on production tiers, but we don't really think of the tiers. We really think of value at the block level, which is what you're alluding to. So what we do is we look at the combination of our hub and spoke strategy, and we come up with the best way to maximize block value. And we run two cases usually. One is constrained facility capacity and the other one is unconstrained. And then we figure out what does that mean in terms of CapEx investment and what does that mean in total returns.

So that's how we think about. It's about maximizing net present value for the block versus trying to stay within certain tiers in the production sharing contract. And to add to your clarification, yes, the production stacks up and it's all added up at the block level. Same thing with cost as well. All the costs are aggregated in one cost bank for the block level as well.

Add-on comment, Betty. When we prepare a plan of development for field, we work it with our partners and the host government. And what will happen in the initial development is we will come up with an optimal development. And we don't -- just to be clear, we don't intentionally try to stay in a certain production tier.

We try to optimize total value, and we get help from that with our partners and the government. They would not -- we would not, nor would they allow us to have a development plan that has some kind of overly constrained production rate to try to maximize entitlement. We're really trying to create value for everybody and doing it in a very transparent kind of open book way with the government.

Got it. That's very helpful. A follow-up on the unitization comment. So if I think about HSV, that straddles two block and the economics for HSV will be a blend of those two block. How does cost recovery work then? Basically, I'm trying to think like does HSV costs get -- can LDV revenue be used for cost recovery for HSV?

Yes. So cost recovery is at a block level. And the way to think about it is the costs that were incurred first are recovered first. It's sort of a first into the cost recovery pool first to be recovered. So if you go back to the very beginning, the very first exploration wells added cost for Block 15-1/05, and similarly, the first two wells we drilled on Block 15-2 are in the cost pool for 15-2.

If we have a field that is confirmed to straddle the block boundary and we develop a unitization plan, then there would be a participation share of how much of the HSV field or Golden Sea Lion is on 15-1 and how much is on 15-2. The cost related to the part that would be on 15-1 would be recovered from the revenue from Lac Da Vang after the other costs on the block have already been recovered.

There are no further questions at this time. This concludes today's conference call. You may now disconnect.

Hello. My name is Sarah, and I will be your conference operator today. [Operator Instructions]

I will now turn it over to Atif Riaz, Vice President of Investor Relations and Treasurer.

Thank you, operator. Good morning, and welcome to Murphy's 3-part Educational Webinar series. This series has been designed to highlight the company's exploration and development strategy with a specific focus on our growing Vietnam business.

Today's webinar will feature prepared remarks by members of Murphy's senior leadership team, followed by a live question-and-answer session. A copy of the presentation for today's webinar is posted on the Investor Relations section of Murphy's website.

As a reminder, our webinars may contain 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 webinar, 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 Hambly, our President and Chief Executive Officer.

Good morning, and welcome to the second session of our webinar series. Today, we will provide an in-depth overview of our business in Vietnam. I'm excited to discuss our plans there as we anticipate that Vietnam will play an increasingly important role in our portfolio.

Before we begin, here's a quick overview of where we are in our webinar series. Our first webinar last week covered Murphy's strategic approach to exploration and how it delivers real value when combined with our strong development expertise. Hopefully, you walked away from that webinar with a better understanding of our unique value proposition and distinct position within the industry. Looking ahead, in the final webinar on March 24, we will cover the history and fundamentals of production sharing contracts, review their structure and build an example PSC model together.

Today, we will start by exploring what makes Vietnam compelling from both an energy and economic standpoint, highlighting its rapid economic growth and rising long-term energy needs. Next, we will examine the Cuu Long Basin and its long-standing role at the heart of Vietnam's oil production. We will then review Murphy's assets in the Cuu Long Basin, discussing our blocks, discoveries to date and how these discoveries will contribute to a strong lasting business presence. Finally, we will present Murphy's strategy and future plans in Vietnam, demonstrating how our expertise, favorable geology, solid economics and cooperative partnerships position us to create enduring value in the country.

To kick off today's webinar, we want to start with a story of how Murphy entered Vietnam, and that story begins in Sarawak, Malaysia. Murphy originally acquired two blocks in Sarawak that had previously been held by a super major. Early on, we discovered and quickly developed the West Patricia oil field. The cash flow from West Patricia became the engine that funded further exploration, including our Kikeh discovery. From there, our team delivered a series of discoveries. We first found the gas field shown in red on this map. Later, our exploration team asked a simple question. Could the prior operator small gas discoveries, which have been drilled near the crest of the structures actually beat gas caps of underlying oil reservoirs. That hypothesis proved correct. We drilled, we found oil, and we went on to discover several oil fields shown in green here. This became a showcase of Murphy's technical creativity and disciplined execution, taking what was assessed as a marginal set of assets by a peer and unlocking meaningful additional value.

As we were making successful hydrocarbon discoveries in Malaysia, Petrovietnam, the national oil company of Vietnam, took notice. They recognized our success and ability to deliver on both exploration and development and invited us directly to explore in the Cuu Long Basin. That invitation is just one example of Murphy's strong international reputation, which has opened the doors for us across the globe. It's the reason Murphy entered Vietnam in 2012 and ultimately, the reason we're able to pursue the material opportunity set we'll be talking about today.

So the key takeaway here is that our position in Vietnam wasn't luck. It was earned. It was the result of strong execution, value delivery and the reputation built through our success in Malaysia. Later in the presentation today, you'll hear more about how our success in Malaysia is analogous to what we plan to achieve in Vietnam.

I'll now pass the conversation to Chris Olson.

Thanks, Eric. Before we delve into our business in Vietnam, I want to frame why Vietnam represents a compelling international growth opportunity for Murphy. Today, Vietnam is one of the fastest-growing economies globally with sustained GDP growth of 5% to 7% per year and a stated goal to become a high-income nation by 2045. That growth trajectory is translating directly into rising energy demand, while domestic supply, as you can see in the chart on the bottom right, has been steadily declining for more than a decade. Our strategy here is to help bridge the supply gap through production from the Cuu Long Basin, a basin that contains a proven petroleum system and delivers more than 80% of Vietnam's total oil output. The basin benefits from extensive established infrastructure and a low-cost operating environment, which supports attractive project economics. Taken together, Vietnam and specifically the Cuu Long Basin offers Murphy scale running room in advantaged blocks that remain underdeveloped relative to the basin's proven potential.

Now let's take a closer look at Vietnam's energy landscape and why it's structurally attractive for Murphy. First, Vietnam is a growing economy, and there's strong recognition by the government that foreign participation is critical to meeting Vietnam's long-term energy goals. Second, Vietnam's economy relies heavily on fossil fuels for power generation with more than half the country's electricity coming from fossil fuels. As we mentioned previously, and as you can see on the chart to the right, domestic oil production has been declining for more than a decade, while consumption has increased. Today, Vietnam has become increasingly reliant on oil imports, already importing over 200,000 barrels of oil per day. Despite this decline in production, as a country, Vietnam has meaningful remaining potential with approximately 6 billion barrels of crude reserves and around 38 trillion cubic feet of proven gas reserves. Unlocking these resources, however, requires new investment, and that's where Murphy's operating model fits exceptionally well with Vietnam. The takeaway here is pretty simple. Vietnam is a growing economy with rising energy needs, declining domestic production and an appetite for foreign energy investment to help fill the gap. Murphy offers Vietnam a productive partnership to explore for and develop new hydrocarbon resources to support their economic goals.

With the market fundamentals clearly pointing to a runway of opportunity, it's natural to question Vietnam's investment climate and whether Vietnam is a stable and reliable place to invest. Vietnam has implemented major business and investment reforms over the past several years, which have been highly effective in drawing global capital. Today, foreign investment accounts for more than half of the country's GDP, and the country is especially supportive of investments in the energy sector.

We are seeing and realizing the value of this support firsthand. Several key factors consistently draw investor interest. First, a stable political system with a governing structure that has been in place for more than 50 years; second, a strong economy with sustained economic growth; third, a skilled workforce and competitive labor costs; and finally, an expanding network of trade agreements and legal reforms that enhance transparency and market access. Vietnam's economic growth ranks among the top 10% globally and foreign direct investment has trended up over the last 20-plus years. Additionally, over the last several years, Vietnam has entered into trade agreements and strategic partnerships that improve Vietnam's global integration. Altogether, these factors build a strong foundation of fiscal stability and investment security. And for Murphy, these characteristics serve as the cornerstone for confident long-term investment.

Now let's talk about fiscal terms because this is an area where people often make assumptions and are influenced by perception and not reality. When investors hear that Vietnam's government take is around 70%, the immediate reaction is often, man, that sounds high. The fiscal regimes don't exist in a vacuum. They're fundamentally a risk-reward relationship that can balance and enhance Murphy's portfolio. Government take is designed to balance risk. Lower government take typically applies to higher-risk environments like deepwater, frontier and unproven basins. Higher government take typically indicates lower risk like proven and mature basins, shallow water or areas with extensive data and existing infrastructure. Vietnam fits squarely in the second category. The Cuu Long Basin is a mature, proven prolific oil-prone basin with decades of production history. So the government take here isn't a penalty, but rather a reflection of the fact that investors are operating in one of the lowest risk oily basins in Southeast Asia.

Looking at the chart to the right, Vietnam's terms are well within the range of global comparables for different fiscal regimes, including PSCs and tax royalty structures. In other words, Vietnam is neither unusually punitive nor unusually generous and is appropriately calibrated for the risk profile of the basin. What drives real value in Vietnam is the quality of the rock and the quality of the projects that we're developing. A proven basin with a high chance of success, stacked pay zones, fast cycle times and existing infrastructure creates economics that outperform lower government take basins with poor subsurface characteristics.

So rather than focusing solely on the top line government take number, the right question to ask is, what is the risk-adjusted return? And in Vietnam, that combination is attractive. We plan to dive deeper into this during the next webinar in our series.

As discussed during the first webinar, for Murphy, everything starts with the big picture and regional work informs our access strategies. When most people think about hydrocarbon occurrence and phase in Southeast Asia, they think about natural gas. The Cuu Long Basin, however, contains one of the most prolific oil-prone source rocks in Southeast Asia, having yielded approximately 5 billion barrels of oil equivalent reserves from 57 discovered fields. The basin is strongly liquids weighted with roughly 75% of recoverable volumes being oil and liquids, which is a key differentiator relative to the gas dominated basins in the region.

Thinking regionally, this was key as Murphy contemplated access over a decade ago. Geologically, Murphy's acreage is optimally positioned. Blocks 15-1/05 and 15-2/17 sit within the core of this oil-prone source basin where hydrocarbon source rocks are heated and transformed from organic material into oil. With that, their proximity to these mature source rocks facilitates hydrocarbon migration and the efficient filling of large structures. The basin is incredibly rich and nearly every porous and permeable layer from the pre-cretaceous basement through the Miocene sees oil accumulations or oil shows. With a runway of exploration opportunities that remain to be tested, this materially reduces comparative exploration risk in our exploration portfolio.

I will now turn it over to Frank to talk more in depth about our Vietnam business.

Thank you, Chris. We entered the Cuu Long Basin by acquiring working interest in the 15-1/05 and later entering the 15-2/17 block. At the time, there were two discoveries, Lac Da Nau or Brown Camel and Lac Da Vang or Golden Camel, which serve as springboards for future ideas and scale. Our first operated discovery was the Lac Da Trang or white Camel in 2019, which led to the development of the Hai Su Vang or Golden Sea Lion prospect. In 2023, we structured our activity around a hub-and-spoke model that maximizes capital efficiency and shorten cycle time, similar to what we achieved in our Sarawak business. What we mean by hub and spoke is that we have an anchor field that will serve as the hub in that it can support the investment to install processing and export infrastructure. Then future smaller discoveries can be tied back for lower capital.

First, we sanctioned the Golden Camel development with a three-year time line to first oil. Second, we approved the 2024 exploration campaign to drill the Golden Sea Lion hub class prospect and the Pink Camel tieback prospect. The thought at the time was for the Golden Sea Lion prospect to become the anchor for the 15-2/17 block, while the Pink Camel prospect will be a tieback to the Golden Camel hub, providing optionality to maximize available facility capacity. Combined, this program set the basis to build a material oil-weighted growth platform with disciplined capital deployment and clear line of sight to production and cash flow growth.

Fast forward to today, our exploration and appraisal record in our Cuu Long Basin blocks has a 100% success rate. The Golden Sea Lion has line of sight to be one of the largest discoveries in Southeast Asia and our Golden Camel development is on track for first oil by fourth quarter this year.

Over the next few slides, we'll give you a deeper look into the opportunity set in both our Cuu Long Basin blocks. As combined, this will result in a material business for Murphy in Vietnam in the 2030s. Starting with the 15-1/05 block. The Golden Camel is a hub class development of Eocene-aged sandstones with 100 million barrels of gross recoverable resource that is a phased development plan designed to efficiently bring volumes online. We expect peak production in the range of 10,000 to 15,000 barrels of oil per day equivalent net to Murphy.

On the map on the right, you can see the Golden Camel or Lac Da Vang field positioned alongside the Pink Camel, Brown Camel, White Camel and other key prospects within both the 15-1/05 and 15-2/17 blocks. In the future, Golden Camel will serve as a primary infrastructure hub to produce from these neighboring fields, lowering the economic threshold for these prospects and improve capital efficiencies.

The Golden Camel is also Murphy's first development in Vietnam, where we are seeing strong execution from our project team. We remain on track to hit our milestones with the launch of our floating storage and offloading facility in the first quarter, topsize installation in third quarter and first oil in the fourth quarter of this year. The ability to have a hub class development with multiple low-cost tiebacks is a clear advantage of the Cuu Long Basin that we identify and are proud now to be part of this ecosystem. The basin has a strong supply chain that is aligned with our focus on safety, environmental protection and fast tracking time to first oil.

The chart on the left shows gross unrisked resource potential across the broader area, highlighting how the Golden Camel integrates into a multi-asset, multiphase plan. When you look at the stacked reservoirs and the proximity of these fields, the strategic value of an anchor becomes clear. The infrastructure we put in place for the Golden Camel will ultimately enable lower cost, faster cycle tiebacks from surrounding discoveries that target different play types.

The important takeaway here is that the Golden Camel isn't the only project in this block. It's the foundation of Murphy's long-term Vietnam business. It proves the business model, confirms a strong supply chain in the basin, reduces future capital intensity of prospects and it sets up a scalable development pathway across the block.

For the last two years, we have received the best gift you can give an oil finder, a sample of clean oil. Our Golden Sea Lion discovery hits on a theme we highlighted in the first webinar. We find potential where others miss. Prospectivity on these blocks was identified for several decades, including a 10-year of operatorship by a super major. By leveraging learnings from the previous discovery in our position, we came up with a unique concept of a play that has not been largely tested in the Cuu Long Basin. We continue to be impressed with the quality of resource and materiality of the Golden Sea Lion discovery. Oligocene-aged sands with a projected gross recovery range of 170 million to 430 million barrels of oil equivalent with thick reservoir sections and large oil columns, they are hard to come by, especially in shallow water. True to our approach, we move fast to appraise with the goal of increasing the understanding of the field and start testing different development concepts.

Today, we have many options to develop the Golden Sea Lion. Next major milestones are sanctioning the project by year-end 2027 with the goal of first oil in 2031. To get there, we have started to evaluate several concepts. I would like to provide a bookend of potential development concepts. One is leveraging a design similar to our Golden Camel. It's a project that we're executing well, understand the cost and what it takes to deliver. And the other is an FPSO redeployment. Each will have trade-offs when it comes to schedule, CapEx and execution risk. What you can expect is for us to tap into our proven track record of offshore development to accelerate the Golden Sea Lion to first oil. Lastly, once the Golden Sea Lion is online, it will be our second hub and platform for future oil growth. And similar to our Golden Camel, we have the opportunity to unlock exploration upside once our infrastructure is in place.

At Murphy, we're excited to play a key role with our partners in Vietnam to help the country achieve its ambitions. Our Cuu Long Basin business is set up for success with our two hubs, Golden Camel and Golden Sea Lion. We have executed this formula once before, picked up blocks that were discovered by a super major, established a hub led by a discovered resource, created a lot of value for our shareholders and host nation. We are laser-focused on replicating this model again in Vietnam to build an oil-weighted business that can produce 30,000 to 50,000 barrels of oil equivalent per day, underpinned by successful exploration and our offshore development capabilities, positioning Murphy to be the preferred partner in the Cuu Long Basin.

And with that, I'll hand it over to Eric for closing slides.

In closing, Vietnam's growing economy offers a compelling investment opportunity. The need for energy is clear, the economic and political climates are favorable, and the country is welcoming foreign investment like ours to meet their energy demand. Murphy has already established a tangible foundation in country through our Lac Da Vang Golden Camel development and the Hai Su Vang Golden Sea Lion discovery. These projects provide a clear line of sight to building a material long-term business in Vietnam.

Vietnam gives us the opportunity to replicate the success we achieved in Malaysia with attractive fiscal terms, strong local partnerships and our proven offshore expertise, we are on the path to turn this basin into Murphy's next engine of long-term shareholder value creation.

As mentioned previously, our next webinar will focus on production sharing contracts or PSCs. We will start with an overview of PSCs, their purpose, their history and how they differ from other fiscal regimes such as the tax and royalty structure in the United States. Next, we will walk through the typical fiscal structure of a PSC, including how production and revenue flow between the contractor and the host government. And finally, probably the most exciting for this group will be a step-by-step walk-through of an illustrative PSC cash flow model. We hope this will help clarify how entitlement production is calculated, how cost recovery works and how profit oil is allocated across different phases of a project.

Thank you again for joining us today. We look forward to seeing you for our final session on March 24. We will now take your questions.

At this time I will open the call for the question-and-answer session. [Operator Instructions] Your first question comes from Carlos Escalante with Wolfe Research. Carlos, perhaps your line is on mute.

Okay. We will move to Leo Mariani with ROTH Capital Partners.

I wanted to focus on this chart on Page 13, which kind of shows the oil production potential for Golden Camel. And I was hoping just to try to get a little bit more color on that. I guess I see you have this kind of darker blue wedge of development. And I guess that really represents the first field sort of coming online, but correct me if I'm wrong.

I wanted to kind of get a sense of a rough time line in terms of how you get from initial production, which I guess will be in the fourth quarter to kind of peak production. When do we sort of expect that? And then you've got this overlay of discovered upside. And presumably, that's the fields around it. So, Pink Camel and White Camel eventually being tied in. Just wanted to get a better understanding what that chart represents here.

Leo, thanks for your question. What I'll do is do a little bit of framing and then I may have Frank come in with a little more detail.

But I think the way that you interpret it is how we intended to communicate it. The dark blue development is the Lac Da Vang field, which as we've communicated previously, is a phased development. The initial production will come from Lac Da Vang A platform. And in 2028, we'll install a Lac Da Vang B platform and drill half the wells from each of the platforms. So what will happen over the course of the development at Lac Da Vang is that we will continue to add wells in a phased manner out through 2029. And then when we finish drilling those wells, we expect that it will begin to decline.

What we're trying to show here on the plot is that the potential for the block is much more than just the Lac Da Vang Golden Camel field, but the discovered upside are those other fields that we have already drilled and identified hydrocarbons. In many cases, they may need some additional appraisal before we move them into a development funnel. But we have a pretty decent idea about the relative size of the resource. And from what we've found so far, they're really tieback scale opportunities, smaller than Lac Da Vang, but significantly large enough to be -- to continue to add to the resource from the block, which is what we're showing here.

And then the last wedge on top is in the lightest color is the exploration potential, and that is targeting the prospects that we highlight with sort of lightly blue shaded polygons in the Block 15-1/05. To be clear, on Slide 13, we're talking just about the Block 15-1/05. And then on the following slide, we talk about the Block 15-2 potential.

So my last comment I'll make, and I'll let Frank add any color, is that the success rate we've had so far in drilling in the Cuu Long is 100%. I don't imagine that we will get through all of our exploration program here at 100%, but it is a pretty strong track record, and it gives us some confidence that there's a very good chance we're going to keep finding oil in these prospects and allow us to continue to maximize the facilities we're developing for Lac Da Vang in a very capital-efficient way.

So Frank, if you want to add any color.

Yes. Thanks, Eric. Yes, Leo, I think one thing that we highlighted in our prepared remarks is our hub-and-spoke model and the benefits of that. And what we've seen from where we run our internal economics is the minimum economic field size to make these tiebacks work is roughly 8 million to 10 million barrels. So it's a very low threshold. And we think the prospects here, the prospectivity around Lac Da Vang is above that. Each prospect ranging between 20 million to 30 million barrels that we will test appraisal test. So that's what gives us now that we have the infrastructure in place for the Golden Camel, we now can start exploring and opening up testing concept similar to what we're seeing in the Golden Sea Lion in order to maximize facility utilization of the investment that we made with the Golden Camel field.

Just a last comment for me. We're showing here a production profile that is not intended to be overly quantitative. It's really trying to be sort of relative scale of what we found versus what may be found in a sort of cartoon way. I wouldn't try to put this exact production profile in a model. I just -- it gives you a sense for a relative scale of what may be developed across the block.

That was super helpful, very thorough there. I want to jump over to Hai Su Vang at this point. I think you guys are doing two more appraisal wells here this year. Can you talk a little bit about the timing of those? Are they -- have they -- one of those spud yet? Are those more second half wells?

And then I guess, maybe just talk about more what you hope to accomplish. You have the range of 170 to 430 MMBOE, which you already have. I think you've already indicated you're kind of at the higher end of the range at this point. And maybe just talk about what the goals on those two wells would be. Presumably that can expand that range above that. So maybe just provide some more color on that would be great.

Thanks, Leo. We are in the middle of our appraisal campaign. As you noted, we announced the results from the 2x well, which gave us a significant view of the resource that puts it towards the higher end of the initial communicated range. We still have a lot to learn about the field. So the 3x and 4x wells that we're working on now will help us assess the resource more comprehensively. The 3x well is drilling in the Northeast extension of the field in 15-1/05 Block, and the 4x well will be drilled in the Southwest part of the field.

So when we're done, we'll have 4 penetrations in the reservoirs, and it will cover the bulk of the structure. And that information is important for us as we cover the bulk of the structure, we'll be able to update in a kind of comprehensive way what the resource range is for the reservoirs that we encounter.

And so the 3x and 4x campaign is underway. I anticipate that we'll have results from those wells and an updated resource range somewhere around the middle of this year, maybe by the time we come up with all the new assessment of resource range, it might be in the August time frame. But that's what we have -- we expect to do going forward.

Okay. That was super helpful, Eric. And supposedly, if these wells are very successful, then this 430 number should move up over time if those wells are really solid, right?

I would not necessarily characterize that the resource range moves above. I think what we should do is get through our program and fully assess the field and what do we learn from every penetration in the reservoir. The aerial extent of what we've identified the oil down to so far is the size of Manhattan, and we have two small holes in the ground. And there's a lot of information to be learned about the field. I feel good about what we've communicated historically here is that our midpoint is probably towards the higher end of our initial range. It's possible that we could see resource that goes significantly above the 430 initial high point, which is what we communicated with our press release in January.

I would hesitate to speculate on a number at this point. I think what we need to do is finish our appraisal campaign and have a really comprehensive updated view of the resource range. And so you won't see us in the next month or two speculating. We want to get through our program and then come up with a new range that we think is probably tighter than this, and we'll be happy to kind of move forward on the development plan with that basis.

Your next question comes from Arun Jayaram with JPMorgan.

My first question is on the LDV field. Eric, you've highlighted 100 million barrels equivalent of gross resource potential. I was wondering maybe you could help us understand what is the gross CapEx number for that development kind of today? And from a reserve booking standpoint, what is Murphy booked in terms of its reserve report from a proven reserve basis?

Thanks, Arun. I'll hit on the reserve booking, and then I'll have Frank talk about the CapEx.

We made an initial proved reserve booking net to Murphy of about 13 million barrels. And we did that after we sanctioned the project in 2023. So it's been on the books for a little while now. And what will happen over time with proved bookings in these type of offshore fields, you start out, you get a little production performance and then over time, you add to the proved reserves. So the initial booking is a pretty conservative number. And I wouldn't take 13 million barrels compared to 100 million barrel total potential and say that reflects what we think our net ultimate potential is. It's really a fairly conservative initial booking.

And then on the project spending, I'll let Frank give some details around that.

Yes. Yes, Arun. So on project spending, total project CapEx out there since we sanctioned is around $390 million net CapEx to us. And then this year, we're projected to spend around $100 million. And then through 2027 to 2029, the average will go down to about $50 million, which will be mostly spent on the second wellhead platform and the other half of the wells. to get drilling to be done with drilling all the way until 2029.

So, Arun, we're 40% working interest. So if you want a gross number, you could take the number that Frank said and net that up at 40%. So about $950 million. So about $10 a barrel.

Okay. Just to clarify a couple of numbers. The 13 million barrels of reserve booking, is that -- that's on a net basis?

It is.

Okay. Great. And then the $50 million of CapEx that Frank talked about, is that per annum or total between '27 and '29.

Per annum, on average.

Per annum. Okay. Got it. Got it. That's helpful. Just maybe a follow-up, Eric. We know that one of your partners in Vietnam is marketing, I believe, a 25% interest in the block. Do you have a ROFR on your position in Vietnam? And how would you and the Board evaluate potentially increasing your interest in what looks to be a really exciting growth opportunity for the company?

We do have a ROFR. And if we believe that our partner that is potentially transacting a sale has negotiated terms that we think are competitive for us, then we will exercise our ROFR most likely because we do see the potential here. It's significant.

I will highlight that we don't know for sure if a transaction will happen. They have an active data room. They have been a little bit unclear about exactly what they may sell. We have heard that they are maybe selling only their interest in 15-1/05 and not 15-2/17, but I think they're marketing both and they're open to offers. So we'll see what happens.

Obviously, we have a track record of not overpaying for things. So it will be interesting to see if they do reach a deal with a potential purchaser what the valuation will be and if it looks attractive to us to move in. But we do like the opportunity here. I would love to have more of it at the right price. We think the potential on the blocks is significant, which is what we're trying to highlight in our presentation today.

Your next question comes from Charles Meade with Johnson Rice.

I'd like to ask a question on Slide 8. And it's really if you could help paint a little bit more the picture for us for Vietnam as a host government. I think the term coming this Communist Party is a little -- it's off putting, but it seems like it maybe is more of a label than a kind of a substantive description. So you've laid out a good case here where the country is opening up to -- and making deals with Western countries, Western business interest. But can you give us a sense of what the history specific to the offshore has been? Has there ever been an expropriation or kind of a post facto change of PSC terms or anything that maybe was a historical concern, which you think is no longer a concern now?

That's a really good question. The environment in investing -- foreign investment in Vietnam is extremely stable. There is no history of any PSC terms changing or a block being expropriated. The oil business in Vietnam initially was established without foreign participation with the exception of the Soviet Union post the war. And they developed their own capability and a very healthy mature service sector. The investment in oil business there has just been tremendous and extremely stable for 50 years. And so we're really happy to invest there.

I guess some people, the coming this party term could be off putting, but that's what they are, and that's what they call themselves. They are a very pro foreign investment communist government. It's a very stable government. It's effectively a unit party for 50 years. We're happy to be doing business there. We're very happy with the ability to invest with confidence and have no concerns. Have there ever been a period where we've been concerned that the government instability or the risk of something being taken from us. They're welcoming. They're extremely encouraging for us to invest. They're supportive. Last year, I met with the senior leader of the Communist Party, Mr. To Lam, and he said all the things I just told to you. He said that they're supportive and they want us to invest, and they're there to help our project move along in a timely manner and hope that we continue to discover more Camel colors.

Okay. Great. And then my second question on Slide 11. When I look at your -- I'm looking at the different horizons you've discovered oil in the HSV, the rightmost one there, it suggests to me that your first two wells, you've only tested through the, I guess, the middle Oligocene and you haven't tested yet the lower Oligocene or Eocene. And so I'm curious, are the 3x and 4x designed to test those deeper horizons? And also, it looks like maybe you go down to the Oligocene, but you're not going all the way to the pre-cenozoic like you have in the Brown Camel. So why not go that deep? Maybe just kind of -- I know there's a couple of questions in there, but just are you appraising those lower Oligocene and Eocene in the 3x and 4x, it looks like you are. And then why not go deeper? And maybe that's -- maybe there's a larger discussion there about a deeper setting here versus the Brown Camel find?

Yes, nicely spotted there. The 3X well that we're currently on is specifically designed to test the four reservoirs that you see there, including the deeper potential than the oil discoveries we've announced in two reservoirs so far. So it is specifically designed to test for deeper potential. One of those reservoirs is the reservoir that is being developed and will soon produce at Lac Da Vang field. The basement here, the pre -- I can't say the word very well, cenozoic, is not viewed by us at this time as being particularly prospective in the HSV location.

And Chris, maybe if you want to add any color around why.

Yes. So as we look at these different dots indicating productive reservoirs in the basin, obviously, you're increasing with depth. At the location, what we're drilling at Hai Su Vang, the Golden Sea Lion, Basement is very deep and would take a very long time to drill to. And the image quality is not very good on the block. So there's a lot of uncertainty with the prospectivity of the traditionally productive basement interval in Vietnam and the Cuu Long Basin.

Yes. So what we've been finding so far, if we encounter reservoir sands that are of high quality, they've been filled with oil. And so we're trying to identify all the potential of the reservoir sands that have the potential to be commercially developed.

Your next question comes from Paul Cheng with Scotiabank.

Can you give us a comparison from a CapEx standpoint on Golden Sea Lion versus the Golden Camel? I mean Golden Camel a number of years ago, you start the last several years, inflation has been high. So everything else equal, that may lead to a higher unit cost, but then you have much better economy of scale. So how -- when you put everything together, how should we look at it? I know it's still a little bit early, but if you can give us some point and also that other than, say, inflation and the economy of scale, will the design or the structure itself will also lead to a lower unit cost development or higher unit cost development? That's the first question.

Yes, Paul, thanks for that. As we talked about earlier today, the development cost of Lac Da Vang Golden Camel is around $9 to $10 a barrel. For Hai Su Vang, we highlighted that we have not yet selected a development concept. But with the different ranges of potential development concepts there, I would anticipate the development CapEx to be in the $5 to $10 a barrel range. In general, I think there are things with Hai Su Vang that suggest it could be more capital efficient than Lac Da Vang. The reservoir production rates that we're expecting from -- that we have seen, I should say, from our drill stem tests and the first two wells are very high and suggest you may need less wells for the same resource in Hai Su Vang compared to Lac Da Vang. So that would suggest potentially less spending on wells.

I will say though, it is a very large structure, and it will need multiple drilling centers. And so that's something we have to figure out is the exact extent of the reservoir to be developed, how many drill centers do we need in order to reach all the targets to drill the development wells. It's a bit early to say. But I would say that it would not be unreasonable to expect unit development cost to be slightly better than Lac Da Vang, and we'll update that when we know probably about a year from now.

That's great. And can you remind us that how long is the -- when the exploration period will expire?

The exploration period has still got a long way to go, and we're not concerned about that being an issue for us. We have lots of years left, and we can find that date. I don't recall it. But it's not in my mind because it's not a big concern.

Okay. So...

My [indiscernible] tells us it's five years from now. Five years from now.

Okay. So we have plenty of time to really -- if you want to delineate the deeper zones that to see what our potential.

Yes.

Your next question comes from Carlos Escalante with Wolfe Research.

This is Aayush Gupta on behalf of Carlos Escalante. He apologizes for not being on. So we'd like to ask about porosity. You have two successful flow tests on a basin where reservoir characterization as pointed by some research paper seems to point out Oligocene sands in the range of 5% to 20% with a mean towards the lower end. So why would you not disclose perhaps a range on that?

Let me start with an answer and maybe Chris can add more color if necessary.

We are hesitant to disclose one parameter about something that is -- that's really one parameter over a very large field. What I would point you to is we've announced results from our drill stem test, and we've flow tested the 1x well, 10,000 barrels a day. and two different flow tests, summed together 12,000 barrels a day for the 2x well, which gives us high confidence in a highly productive, highly permeable reservoir of tremendous quality. Probably those flow rates are better than the basin average from different reservoirs. It's probably on the order of 3x to 5x higher production rate than has been commercially developed in the basin. So we're -- we think that's a very concrete result.

In a reservoir, the scale we're talking about, which have multiple reservoirs in these reservoirs, porosity is something that varies across the reservoir. So we have so far two holes in the ground where we've encountered significant pay within the pay section, the porosity varies within just the well we're in. So to come up with an average number where we have small holes in an area the size of Manhattan is premature. We would rather get through our comprehensive appraisal program and come up with a much better model of what the average properties are.

But having said that, I think we have high confidence that we have a highly productive prolific reservoir here and focusing on just one parameter is not -- I would say it's not critical. What is important ultimately is what is the oil in place and how much of the oil in place will be recovered. And porosity is one of about seven parameters that are related to determining how much oil will come out of the ground.

[Operator Instructions] Your next question is a follow-up from Leo Mariani with ROTH Capital Partners.

Just wanted to follow up a little bit on exploration. So we talked a lot about sort of appraisal at Hai Su Vang and development of Lac Da Vang. But can you maybe just talk a little bit more color about what kind of an exploration program can look like? I think on your previous call, you guys talked about drilling more exploration wells between '27 and '29. You just mentioned the five-year window a bit ago. But presumably, you're just going to be drilling kind of in and around these hubs that you're developing. I think I did hear you say a little bit ago that prospect size at Lac Da Vang is kind of 20 million to 30 million barrels.

And maybe you can just kind of characterize what you're looking for? Is it more kind of smaller kind of satellite fields and everything gets tied back eventually? And is that the case for both hub developments? Are there any other sort of larger prospects left? Just hoping you could give us kind of an overview of what you guys are seeing from an exploration perspective.

Leo, that's a great question and it gives me an opportunity to give you some pretty good color here. We have one exploration well planned in Block 15-1/05 this year that is the Lac Da Vang North, so White Camel North. And that's a well we'll drill this year. What I expect is in the 2027 to 2029 time period, we are likely to come back here and have quite an active exploration program to test the remaining undrilled prospectivity on the block and set ourselves up for an optimal tieback development program. And these fields, I think Lac Da Vang preliminary results we said is probably in the 30 million to 60 million barrel range. The other fields, we have some work to do to kind of assess just how big they are.

What is important and what Frank tried to point out was we need somewhere less than 10 million barrels to have a tieback work, and we're probably going to find things that are 20 million to 40 million barrels would be kind of a guess of the size of the future tiebacks there.

So, what it does for us, it sets us up to fully test the block, just like we did in our Sarawak Malaysia business and then optimally plan a development where we efficiently develop all the total resource in the block over time. And it's likely that's done with common infrastructure. The FSO and pipeline infrastructure almost certainly will be used in common. It's possible that we may need more processing equipment or expand the capacity of the Lac Da Vang development to accommodate future higher processing capacity. We may find a field that's large enough that it justifies its own processing platform, and we would just have common FSO and pipeline infrastructure.

I think you'll see us focus sooner on testing the prospectivity in 15-1/05 and then probably pivot to the 15-2, where, as you can see from our slides, there's a lot of remaining prospectivity to test. But the timing is probably more important than 15-1/05 because of the nature of an ability to move into tieback mode quickly with first oil in Hai Su Vang, obviously coming probably in the early 2030s or maybe 2030. So you'll probably see us be more active in 15.1 and then pivot later to explore more in 15.2.

There are no further questions at this time. This concludes today's conference call. Thank you for joining. You may now disconnect.

Good morning. My name is Sarah, and I will be your conference operator today.

[Operator Instructions]

I will now turn it over to Atif Riaz, Vice President of Investor Relations and Treasurer.

Thank you, operator. Good morning, and welcome to Murphy's 3-part Educational Webinar series. This series has been designed to highlight the company's exploration and development strategy with a specific focus on our growing Vietnam business. Today's webinar will feature prepared remarks by members of Murphy's senior leadership team, followed by a live question-and-answer session. A copy of the presentation for today's webinar is posted on the Investor Relations section of Murphy's website.

As a reminder, our webinars may contain 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 webinar, 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 Hambly, our President and Chief Executive Officer.

Good morning, and thank you for joining us. Today, we are kicking off a 3-part conversation about the unique exploration and development capabilities driving Murphy's long-term value creation with a focus on our Vietnam business. You will hear from 2 of Murphy's key leaders, Chris Olson, our Senior Vice President of Exploration and Subsurface; and Frank Garcia, our Senior Vice President of Development and Engineering.

Our first webinar today is Strategic Exploration and Development, and it is designed to provide a deeper understanding of how our offshore capabilities create long-term value in a market that has become heavily focused on short-cycle shale-dominated plays. Webinar 2 on March 10 will be a deep dive on Murphy's Vietnam opportunity, including Vietnam's government, economy, geology of the Cuu Long Basin, our track record in the region and why we see Vietnam as a long-term value driver for Murphy. And then webinar 3 on March 24 moves into the fundamentals of production sharing contracts or PSCs and how to frame and model our Vietnam PSCs.

With that overall road map in mind, let's take a look at key discussion topics for today. First, we will provide an overview of Murphy's unique history, how more than a century of exploration heritage has shaped the way we operate today. That history, combined with our belief that exploration remains a global strategic necessity, underpins our ongoing focus on exploration. We will then talk about the macro themes highlighting why exploration is essential to meeting long-term energy demand. From there, we will transition into Murphy's strategic approach to exploration, the discipline, workflows and integrated decisions that help us high-grade opportunities and maintain a robust prospect maturation funnel. And finally, we will walk through how this strategy delivers real value when combined with strong development expertise and skill set.

Exploration alone is not enough. Our ability to develop efficiently is what converts geology into cash flow, and that's a key component of our competitive advantage. Murphy has a long history in oil and gas with our first major oil discovery dating back to the Delhi field in Louisiana in 1944. As you can see from this time line, we have leaned into innovative exploration and development throughout our history. One milestone that really defined Murphy as an international offshore operator was the Kikeh project in Malaysia. Kikeh began with a major deepwater discovery in 2002 and reached first oil just 5 years later in 2007, setting the record for the fastest deepwater development in the industry at the time. After Kikeh, we discovered and brought online the Sarawak oil and gas fields in Malaysia in record time as well.

Our success in Malaysia is what ultimately opened the door for us in Vietnam, and we see several analogs between our Sarawak development and what our Vietnam development is shaping up to be. We will talk more about this in webinar too. More recently, in 2022, we demonstrated our offshore expertise by bringing the King's Quay asset online in just 3 years from sanction with a payback period of less than 1 year. These achievements are just some of many proof points of Murphy's capability to take on technically challenging offshore projects and move from discovery to execution with speed, safety and discipline. Murphy today has a diverse but intentional portfolio with production in North America and soon in Vietnam and exploration prospects in the Gulf of America, Vietnam, Côte d'Ivoire and Morocco.

Our onshore and offshore assets are strategically complementary as they provide operational flexibility, financial resilience and exposure to exploration-driven upside across multiple regions. Our business is balanced across 3 value streams: conventional offshore, which provides stable, long-lived cash flow; North America unconventional, which gives us short-cycle flexibility with decades of inventory; and international exploration, which is where we unlock the large-scale, high-value opportunities that really differentiate us from our peers. Our strategy enables us to dedicate a material part of our capital and personnel resources to exploration, which we believe is a necessity for any oil and gas company with an eye towards long-term success.

I want to touch on why we believe exploration is so important in today's world. On the top right, you can see the trajectory of global oil production decline if the industry were to stop investing. Global supply would fall by roughly 5.5 million barrels per day every year from 2025 through 2035. This is the equivalent of losing the entire production base provided by Brazil and Norway combined every single year. The world cannot maintain the supply needed for long-term demand without continued exploration and development. The bottom chart highlights that even if we continue to invest in existing projects, it still leaves a significant energy demand gap in the future. This underscores Murphy's thesis on the importance of exploration. It's not just about growth for Murphy. It's about meeting a critical structural need in the global energy ecosystem.

Core to the issues facing the industry today is that the size of discoveries has been shrinking for the last 60 years. In the 1960s, the industry discovered close to 90 billion barrels of oil per year. Today, that number has fallen to single digits. As the demand grows, the supply is shrinking. To add to this, the time it takes to develop projects has increased. Since 2010, it has taken nearly 20 years on average to move a conventional project from grassroots prospect identification to exploration, discovery and ultimately first production. So while we're in an oversupplied market today, we're facing a structural long-term shift, declining base production on one side and fewer discoveries that are taking longer to come online on the other. This is where lean, financially strong and operationally skilled companies like Murphy are best positioned to play a role in the E&P space. And frankly, there aren't many of us out there.

If we think about who can fill this gap in the market, there are very few companies who have consistently invested in exploration and maintain the relevant skills and resources required to successfully explore offshore. When you narrow the universe of 50 or so U.S. exploration and production companies down to those with meaningful offshore exposure, a strong balance sheet and the ability to move quickly into a new region, only 2 companies stand out. Of these 2, Murphy is the only one with an exploration pipeline that could potentially double our offshore reserves.

Just 10 years ago, the universe of U.S. E&P companies and those focused on exploration would have been much larger. Today, Murphy stands out among the handful of companies still exploring for and finding oil. We pride ourselves on being oil finders and have remained committed to exploration as many in the industry shifted to pure shale plays. Our advantage comes from our oil finder culture, which permeates throughout the organization, the development skill set established over many decades as well as a disciplined financial strategy and strong balance sheet that support our exploration and development programs.

At Murphy, we have a history of creating value by investing strategically through cycles. This has allowed us to develop some of our biggest projects such as Kikeh and King's Quay when oil prices and service costs were low and bring them online when oil prices were high. We can't time the market, but operating our own assets and maintaining a steady commitment to exploration and development has allowed us to optimize value while continually building a refreshed pipeline of opportunities. Maintaining our exploration and development muscle has given us a significant advantage in cycle time compared to our peers. On average, Murphy is able to deliver first oil about 40% faster than the industry. As the need for new barrels grows, we will be able to deliver projects faster and create outsized value for our shareholders.

Chris and then Frank will now share more about the key ingredients that fuel our successful exploration and development programs.

With that, I will now turn it over to Chris.

Thanks, Eric. Today at Murphy, we maintain our unique exploration culture and capabilities as oil finders. When you look at the map to the right, you can see Murphy's current focused exploration footprint. This international business, however, is not new to us. If you're not familiar with Murphy's history, Murphy was exposed to historically broad global exploration footprint over the last quarter century with positions onshore and offshore, shallow water and deepwater and locations across North America, South America, West Africa, North Africa and Southeast Asia. This business is absolutely at the core of what we do.

Today, exploration at Murphy is purposely designed to support our existing cash flow engine in the Gulf of America and expose ourselves to organic growth for long-term resilience in a short-cycle dominated world. Four core exploration pillars form the foundation of this exposure and the strategy. These pillars include our differentiated exploration culture, our rigorous portfolio management and our data-led regional evaluations and our unique offshore operating capabilities. With this, we'll drive into each of these pillars on the coming slides.

We believe our differentiated exploration culture sets Murphy apart. I realize that this is kind of soft and hard to describe, but it's something that we are very proud of. We have built a productive environment that attracts, develops and retains top exploration talent by empowering multidisciplinary teams with deep and complementary subject matter expertise. Just as importantly, we are intentionally developing a runway of exploration talent and future leaders, ensuring that Murphy is positioned for exploration success well into the next decade. For us, success isn't defined by a single well. It's measured by overall program value creation. This mindset encourages creativity, challenges assumptions and promotes productive technical tension where ideas are rigorously tested and matured before capital is risked.

Exploration is a hard business that can take patience to yield the huge result. Our team realizes that there will be failures, but we are built to accept these calculated risks, learn and continually improve. This is a sign of a healthy exploration organization that is enabled by Murphy's business model having multiple free cash flow generating engines. Finally, we are supported by an experienced drilling organization that allows us to operate globally without being constrained by geography or water depth. This unique combination of creativity, disciplined risk-taking and execution capability is driving results.

I want to talk about how we build a balanced and disciplined exploration portfolio, which is essential for sustaining long-term growth and managing risk across cycles. Murphy's strategy ensures that we have the right mix of lower risk, mature and proven basin opportunities and higher risk, higher reward frontier prospects with transformational growth potential. The exploration portfolio is being built holistically to perform across commodity cycles and not just as a collection of individual prospects.

Portfolio balance creates durability in our exploration organization. Low-risk, mature and small proven basin opportunities support near-term cash flow and production volumes through higher-margin infrastructure-led exploration. These opportunities give us dependable and repeatable outcomes, allowing us to simultaneously pursue large, longer-dated growth options. In terms of portfolio maturation, we don't just assemble opportunities. We mature them systematically. Investment discipline is supported by a fit-for-purpose maturation process that ensures consistency, introduces productive technical tension, test the technical work, calibrates risk and develops opportunity through choice. This helps us sequence our drilling schedule so that we are exposing ourselves to the right prospects at the right time.

Opportunities, however, must earn their way forward, and we preserve optionality at every stage, allowing us to advance, pivot, pause or exit based on value and risk and not just execution readiness. This discipline drives successful exploration outcomes. By deliberately balancing mature proven and frontier basins across regions like the Gulf of America, Vietnam, Côte d'Ivoire and Morocco, we avoid technical and geographic risk concentration, and we are developing a durable portfolio of actionable opportunities that deliver repeatable results while simultaneously exposing Murphy to transformational upside.

Our exploration process starts with the big picture. We begin our evaluations at a global scale, understanding the intricacies of basin formation through plate-tectonics and basin analysis. This process provides crucial regional geologic context that allows us to identify, research and critically understand the uncertainty associated with the presence or absence of each of the elements of a petroleum system. These elements include the likelihood of source rock presence, reservoir presence and the prediction of reservoir quality, seal rock deposition, trap formation, hydrocarbon maturation and hydrocarbon migration.

We put the earth back together through time and rely on global, regional and local analogs to reduce uncertainty. Regional work is the backbone of what we do, directly informing us where we choose to explore. It screens for geologic complexity, defines the extent of each basin's exploration playground and establishes critical limiting geological and operational boundaries. By building this context upfront, we have substantially improved our predrill prediction accuracy. Importantly, establishing good regional context allows us to avoid opportunity shopping for one-off individual well opportunities. This is what allows us to see value where others don't. It identifies massive potential in the middle of a mature basin offshore of Vietnam, and it allows us to see the upside offshore Morocco, where others have failed to realize success to date. Fundamentally, our regional approach drives our new access strategies by putting exploration ahead of execution, ultimately driving more informed investment decisions.

Murphy consistently allocates 10% to 15% of capital to exploration, ensuring that we are developing and maintaining a strong and sustainable portfolio. With this, we remain focused on increased exposure to emerging and frontier basins where the fiscal terms are attractive and the resource potential can be transformational. We are pre-investing in the right data, and we run a fit-for-purpose assurance process that challenges assumption, removes bias and identifies clear opportunity off-ramps and necessary pivot points. This ensures our portfolio is consistently defined and strategically aligned with our overall execution plan.

Our people make this all possible, though. We have a skilled and creative exploration team already in place that understands how exploration impacts the bottom line, not just technically but commercially. And this is especially important at Murphy. With this, exploration at Murphy is delivering.

Since 2024, our exploration program has achieved what we believe will be a 60% commercial success rate and all noncommercial projects from '24 to '26 have found hydrocarbons. This is evidence that we're doing the right things and exposing Murphy to the right opportunities. Importantly, as we previously discussed, Murphy maintains offshore execution capabilities that uniquely differentiate us from our peers.

And with that, I will now turn it over to Frank Garcia, Senior Vice President, Global Development and Engineering, to discuss how these capabilities support exploration success.

Thank you, Chris. Over the coming slides, I'm excited to highlight our top quartile offshore capabilities that enable Chris' exploration and subsurface team to pursue resources where others cannot. We have deep experience across both shallow and deepwater, allowing us to operate and maintain control over execution, timing and capital, reducing uncertainty from discovery through development. Our footprint is both domestic and international, supported by a strong reputation and long-standing relationships that enable access to opportunities globally.

Most importantly, this capability is embedded across the organization and is something we are very proud of. From technical teams to operations and back-office support, we built this muscle over decades, focused on enabling top quartile time to first oil. This integration of exploration and offshore execution is a key driver of Murphy's repeatable success.

One of Murphy's key competitive advantages is our ability to fast track first oil after a discovery is made. This is not luck, but by design. Our skilled teams enabled by our flat and tightly aligned organization allow us to make quick decisions. Also, once we determine we have a commercial discovery, we progress field appraisal and development processes in parallel. This contrasts with other companies' approach to fully delineate fields before starting development activities. Finally, for our development concepts, we do not preferentially engineer our solutions. We lean on our experience and industry partners to deliver fit-for-purpose solutions to maximize value creation. It is this approach that makes us a strategic alternative to super majors in the global E&P space and frankly, a great place to work.

Host nations and national oil companies recognize Murphy's development capabilities, and this recognition is what allows us to opportunities like our Vietnam Cuu Long Basin position. On the graph on the right, you can see that the industry average for years from exploration to start-up have increased over the last 25 years, but Murphy has been well below the average on 2 of our key projects, which I will talk about on upcoming slides.

Our offshore development competitive advantage will be relevant if we didn't have the resources to leverage it. Our strong balance sheet is another differentiator for us where Murphy maintains top-tier low leverage, allowing us the flexibility to advance high-return offshore projects without being constrained by market cycles. A strong balance sheet and liquidity means we don't have to delay projects, feel obligated to farm down interest in any of our discoveries or adjust pacing for financing reasons. We can execute when it makes the most sense economically, allowing us to create the most value for our shareholders from discovery to first oil.

The financial stability is a key enabler of our offshore execution track record, and it positions us to move decisively on Vietnam as discoveries mature toward development. The Kikeh and King's Quay developments are 2 prime examples of Murphy's offshore execution. For the Kikeh project in Malaysia, the project took just 5 years from discovery to first oil, an exceptionally fast time line for a deepwater development and a true field of first for the region. Ultimately, the project generated over $6 billion in pretax value for Murphy. We carry those same capabilities into the Gulf of America with King's Quay, where we deliver first oil in only 3 years from sanction, which is the top 10% of industry cycle times. Because of this strong execution, we achieved project payout in 1 year.

Faster execution pulls cash flow forward, reduces capital at risk and improves full cycle economics. That speed paired with disciplined project management and a strong balance sheet is what allows us to translate great geology into great returns. And importantly, the same execution capability is what positions us so well for Vietnam. The faster we can move discoveries at Hai Su Vang through appraisal into development, the sooner we unlock value.

I want to walk through the history of our Kikeh project in more detail because there are a lot of parallels to what we are preparing to do in Vietnam. Kikeh is the fourth largest discovery in Southeast Asia in the last 25 years. Our entry into Malaysia was led by a discovered resource and significant exploration upside. Murphy acquired these blocks after they were released by a super major. This is a common theme in many of our development successes and an example of recognizing potential where others do not. Once Kikeh was declared commercial, the project was sanctioned during historic low prices and was funded by the divestment of noncore Canadian assets. It was the first deepwater field developed in Malaysia and require new technology, new partnerships and an integrated team able to move quickly and decisively, all of which we uniquely achieved as a resourceful and efficient independent E&P player.

True to our philosophy, we fast-track development activities and deliver first oil 5 years after discovery, allowing the project to flow in a period where oil was significantly above the assumed sanctioned price deck. With this success, Murphy was able to extract value to us, we transform our offshore business with our Gulf of America acquisitions and open the door to our current Vietnam business. And our Hai Su Vang or Golden Sea Lion discovery is a perfect example of the opportunities we can capture by being a strategic preferred partner.

Eric spoke about our thesis on oil supply and where we believe it's headed given the trends we're seeing. So I want to frame our Golden Sea Lion project in terms of onshore inventory since declining shale inventory is one of the key macro themes in focus today. The Golden Sea Lion discovery is equivalent to more than 500 Tier 1 locations in the Eagle Ford Shale, which highlights the scale and materiality of this fine. These are locations that are neither for sale or even exist in South Texas for somebody to capture. This is the true value of greenfield exploration success.

The resource quality is exceptional. We're seeing $1 to $2 per barrel finding cost and an estimated full cycle F&D cost of around $10 per BOE with breakeven below $40. Those metrics position Vietnam firmly as a Tier 1 oil project with strong returns and long-life value. What makes this even more compelling is the development environment, shallow water, premium Brent pricing and runway to capture exploration upside via future tiebacks. This combination supports efficient execution and a clear line of sight to future cash flow.

In short, Vietnam gives us a high-impact, low-cost oil-weighted growth engine, exactly the kind of organic value that complements our offshore capabilities and elevates Murphy's long-term profile. We will discuss our Vietnam opportunity in greater detail in the next webinar.

But for now, I will turn it over to Eric for the closing slides.

Thanks, Frank. Over the past 2.5 decades, we have strategically reshaped our offshore portfolio, evolving from our legacy position in the Gulf of America to successful exploration in Malaysia and returning to the Gulf of America through asset acquisitions from log exploration and the formation of the MP GOM joint venture with assets from Petrobras. During this time, we also built a complementary onshore business, providing balance and runway to enable our exploration strategy. Looking ahead, there are several levers for growth in our base assets, but we are presenting a scenario with flat base production in this chart to highlight the significance of our Vietnam assets.

As you can see, Vietnam will become a material business for Murphy in the 2030s, bringing to life our strategy of creating long-term shareholder value through organic growth. As we think about our Vietnam growth and what it means for our company, I wanted to share with you a similar story from our past. This chart shows how exploration success can impact our valuation in the market and the value this brings to our shareholders. After the Kikeh discovery in Malaysia, we saw an increasing uplift in our share price versus peers, which accelerated sharply after first oil. Our shareholders who supported us from discovery to first oil saw outsized returns, both through a long-standing dividend and a strong share price growth. We believe we are on track to replicate that success with our offshore exploration and development strategy in Vietnam.

As we have discussed today, Murphy offers a distinct value proposition compared with other E&P companies. Our offshore track record, reputation and specialized exploration personnel distinguish us from peers of comparable size. On the other hand, we maintain a lean team and dedicated focus on exploration, allowing us to advance projects unencumbered by the red tape often present in larger organizations. In addition, our unique expertise and financial capability enable us to pursue resource opportunities that may be too big for independent companies, yet remain below the threshold targeted by major industry players. This is exactly how our strategy wins.

Malaysia serves as a prime example, where we delivered significant value to shareholders by successfully exploring and then efficiently developing oil and gas fields in offshore blocks previously abandoned by super majors. Vietnam is a similar story. Murphy fills a critical gap for national oil companies by providing the ability to develop resources that might otherwise remain untapped, an increasingly important role on the global energy stage.

In closing, our thesis is that within the next decade, the world will face an oil supply shortage while global energy demand continues to grow. With the decline of shale, exploration is becoming more important and companies with the capability, discipline and the financial strength to explore and develop efficiently will be the ones who deliver outsized value. We're proud that Murphy stayed invested in offshore exploration when others stepped away to focus on pure shale plays. Our commitment preserve the talent, expertise and overall offshore capability that differentiate us today. As we look ahead, we are now bringing that strength and capability to Vietnam. With the right resources, the right people and the right momentum, Vietnam represents the next chapter of long-term sustainable growth for Murphy.

Thank you, and we hope this session was helpful. We hope you will join us for a deep dive into Vietnam in our next webinar on March 10.

[Operator Instructions]

Your first question comes from Leo Mariani with ROTH Capital.

I wanted to follow up a little bit on Côte d'Ivoire here. Just wanted to get kind of a rough sort of time line for when you expect to decision the Bubale well. And then additionally, if whatever reason this well is not successful, would that potentially hasten an exit from Côte d'Ivoire? Or are there other future projects that maybe you guys are maturing?

Leo, thanks for your question. Thanks for participating in our webinar today. Briefly on Bubale timing, we anticipate an ability to release a result of that well in about 45 days or so. We will -- we are currently drilling the well and making good progress. And I think the time line around 45 days probably makes some sense. The short answer on the results of recent wells plus Bubale is that we will use the data from all of the wells to reassess the prospectivity that exists on the blocks. There are a number of prospects on the blocks that are unrelated to the plays that we just tested.

There are also prospects that are of the same age or in the same type of region, the prospects that we drilled. And we believe that there may be some information that informs future prospectivity. We will likely have an operational pause after Bubale, where we assess over the course of a year or maybe 1.5 years, whether there are prospects that we are excited to go drill and kind of regroup and plan. So we don't have a current conclusion about what it may mean. There's a lot of information to assess, and there are quite a few remaining prospects on the blocks that we may drill in the future.

Your next question comes from Carlos Escalante with Wolfe Research.

If I can turn to Slide 21, I'd like to unpack really what's going on after 2025 or what you're describing that 2025 is. I think on your slide deck is #20, but on ours is 21. It looks like the exploration upside option, it looks like for Vietnam, that could be double your current exploration success, if I'm interpreting the chart correctly on the lighter blue shade. Is that upside a function of what you think the underlying resource could be in a best case scenario today? Or is that more a function of what an optimal development pace and case might be?

That's a really good question. And we are going to touch on that in a lot more detail at the next webinar on March 10. But I'll kind of briefly frame it now and we'll again in more detail in about a week. The results from our discovered fields in Vietnam, so Lac Da Vang Golden Camel and Hai Su Vang Golden Sea Lion put us in that Vietnam exploration success category. Obviously, with Hai Su Vang, we're in the middle of an appraisal program. We have uncertainty about the size of the resource. We are on this slide using what we think is a conservative view of the potential of that field. And obviously, we have not yet planned a development scenario. So the rate is an estimate.

But the currently discovered resource of Lac Da Vang and Hai Su Vang suggest a development that's at least 30,000 barrels a day net to us. A larger Hai Su Vang or more optimistic view of the potential there could push you closer to the 50,000 barrels a day or have more confidence in both of them pushing you to a higher rate. The upside, exploration upside, we believe that there is significant remaining prospectivity on the 2 blocks where we're operating in the Cuu Long and there may be about as much resource to be discovered as has been discovered. Obviously, it's exploration, and we don't always have success.

We have been fortunate so far in our Cuu Long business to have 100% success exploring, and there are quite a few prospects left to drill. I think what we'll see is a likely setup of a northern hub in Block 15-105 and a southern hub 15-217, anchored by the development of Lac Da Vang and Hai Su Van. And then additional fields, both the several that we've already discovered in the 15-105 block and other likely future discoveries could push us up. So what you see in this plot is a sort of cartoon view. It's not intended to be a quantitative exact outcome, but we have confidence in a 30,000 to 50,000 barrel a day business. The higher end realized by larger Hai Su Vang and then plateauing at a high rate for a long time would likely be driven by additional exploration success where existing discoveries like the Pink, Brown and White Camels get tied into the Golden Camel development and then also additional exploration success being tied in kind of in a phased way over the period of time in the early 20 to mid-2030s.

That makes sense. Am I able to make a follow-up? Or are we holding to one question?

You can have a follow-up, no problem. Whatever you want, Carlos?

I appreciate it. Well, you're talking about it next week, so I kind of feel like I burn my one question. So taking a step back, big picture, it sounds like this is more representative than anything than intended to be a representation of Murphy 2028, 2035 time line. So -- with that in mind and where you sit today with Vietnam, I know you used to give a very soft guide back in the day that elicited or looked like it would take you to 210, 215 BOE per day. In light of where we are today, can you give us a quick refresher of where that stands? And I don't know if even serves to talk about an upside scenario to that, given the pipeline of exploration you have and being how binary it is. But if you feel comfortable enough offering that, that would be great as well.

Yes, it's a great question, and we get that one quite a bit. What I have done over the last year or so is pivot my explanation of the future of Murphy from a very granular specific range of production rates. And what I've tried to do is communicate the ability of our assets to deliver and our assets provide us optionality. There are things we can do between now and 2032 that could affect the overall production rate of the company because we may do something different than a plan that was developed several years ago. But what I will tell you is our assets have the ability to deliver low single-digit growth. And with the significant increased volume in Vietnam, they have an ability to put us into the same production range that we had previously guided that [indiscernible] is in reach is likely.

I have tried to pivot away from a very specific description of when we hit that exact number and tried to say that our assets allow us material organic growth and flexibility. If we have low oil prices for a while, we may choose to do something in our onshore business or our offshore business that may affect near-term rates, may affect 2-, 3-year rates, but the overall ability of the assets to deliver exactly as we previously guided is there. And I think you'll see that be delivered over the course of the next 10 years or so.

Your next question comes from Charles Meade with Johnson Rice.

Eric, I feel like one of the themes you're trying to develop here is that you, Murphy, have less competition in developing some of these offshore projects than you used to. And I wondered if you could kind of give maybe some detail, if that's the right narrative, give some detail on how the you tell me the right word, how you were invited into this Vietnam block in [indiscernible] for what happened in Côte d'Ivoire. And just tell us who you think your competition is when host governments are looking to bring someone into develop?

Yes. Thanks very much, Charles. I'll first touch on our entrance into Vietnam, and it's also something we'll give additional detail on at our next webinar. But briefly on Vietnam, we had developed, as you know, since you followed us for a long time, a significant business in Malaysia. And the success that we had in our Sarawak business in Malaysia stood out to some of the regional NOCs, including PetroVietnam. And they invited us to enter the Cuu Long Basin Block 15-105 because they saw the success we had both in developing oil and gas in very similar type of shallow water environment. and they weren't seeing that. That Block 15-105 was previously operated by a super major who exited the government ended up with the larger ownership, and they wanted to bring in a capable operator that they thought could move things along and be effective.

So we were invited into a block that previously had not been something that an external western party could enter. It was sort of viewed as the forbidden basin that you could not get into. And we were very happy to welcome into the basin because we had been looking at it, identified it as one of the few oily basins left to explore in, in Southeast Asia. So we were excited to enter. We were entering the block when there was a couple of discoveries on the block, including the first well in Lac Da Vang, and we entered an appraised successfully Lac Da Vang, which led to the development we're executing now. Since then, we've had additional exploration success, of course, which we've just talked about.

So it's very nice when you are sought out as an operating partner by an NOC because you've demonstrated a track record of delivery. The Côte d'Ivoire experience is somewhat similar. It's a block that we had been looking at for quite a long time, going back to about the time of 2014, we had kept an eye on Côte d'Ivoire and identified the potential there. And we were able to move to enter when many companies had stopped exploring and had low level of activity. And we expressed quite a bit of interest to the government in the 2021, 2022 time frame, and they had a largely unleased position Eni had significant acreage holding in Côte d'Ivoire with a differentiated exploration strategy and many of the blocks that were available in the country, and we approached them.

And I think they like what we have to offer, our ability to explore in deepwater and also if we have success to be able to develop efficiently is something that is desirable for countries when they're looking to partner with someone to bring somebody in. There are many discovered resources in West Africa that were discovered by super majors that are sitting undeveloped. And that's a frustrating experience for a host government. They do not want that to happen. And when they look at a company like us and our demonstrated track record of swift execution of exploration and development campaigns, it's a desirable attribute. And so it does provide a competitive advantage.

And then my last comment on that is that we do not need to find a 1 billion barrel field to be successful. We are very happy to find significant discoveries that are smaller, and that differentiates us in 2 ways from super majors. One is that super majors need to find very large resource for reserve replacement. They would be disappointed in sub-billion barrel scale. And also, if we find a material discovery as we have in Hai Su Vang or may in the future in Côte d'Ivoire or elsewhere, we have an ability to create outsized value for our shareholders because the significance of that discovery and the value creation from it is large compared to our current enterprise value. And that's a major differentiator and allows us to be competitive. Successful exploration is driven by a quality team with differentiated technical capabilities and ideas. It's not driven by massive scale as we've demonstrated.

Got it. And then my follow-up, I'd like to ask a question about Morocco, which is one of your more recent entries. I did some -- once you guys announced that position, I went to try to figure out some of the history there. And it looks like there have been some natural gas discoveries. It looks like you guys -- somebody or a European entity retained part of a block, but you guys picked up what the remainder of it was. But I wonder if you could talk -- that looked to me -- maybe you can tell us the story, was that the same sort of invited in? Or was that where you were in some kind of competitive negotiation to get that concession? And talk about what kind of prospectivity I'm really thinking oil versus gas you see there.

Yes. Thanks for that. What we see in Morocco is that our team with some fairly unique capability, we're able to do some analysis of the prospectivity there. We identified an opportunity set to explore where others have missed it. In fact, we had previously missed it. And when we did a comprehensive regional study, we identified some prospectivity on the block that we're excited about. The block contains a large undrilled way structure that other people have probably looked at and said that won't work. We have done some work to assess that it may and entered the block when we went to approach the Moroccan government, they were happy to welcome us in.

And what we will likely do in Morocco over the next few years is reprocess seismic and determine whether or not our preliminary view holds up to more scrutiny with reprocess and improved imaging and then decide do we want to drill a well or not. This is a frontier play. Those frontier plays tend to have a higher risk component, but the upside with success is that it could be quite large. The history of exploration in Morocco is not very strong. There have been a number of larger and smaller companies that have explored and found hydrocarbons in the offshore. There's limited amount of production onshore in Morocco. The country is in desperate need for more energy. They import a lot of natural gas into the country from Spain. So an oil or gas discovery would likely be quite valuable here. We typically tend to explore for oil, and we have an oil story around why we'd be exploring in this block.

Got it. Anything on the Atlantic margin is going to at least generate some interest.

Thanks for your appreciation of the webinar.

Your next question comes from Tim Rezvan with KeyBanc Capital Markets.

Just as a lead off, I think this is an awesome idea to sort of seminar through March. So on behalf of probably all of us on the sell side, thank you for setting this up. My question, Charles stole my Morocco question. So the one I had here, I recognize that the exploration side of the business is part of the DNA, and you've shown the track record for decades. But opportunities like Vietnam come along kind of once every generation. You are still sort of a mid-cap company with a strong balance sheet, but finite liquidity.

So how do you balance the need to kind of continue sort of scratching the exploration itch when you're sitting on something so large and transformational? Because you can make the case that maybe some other activities should sort of stop at a time when you don't have a lot of free cash flow because of the needs. I mean it's a high-class problem to develop a prospect like this. But how do you kind of balance those different items as you think about the business?

I appreciate that question. And let me try to frame it this way. We believe that the development that we will conduct in Vietnam fits pretty well inside our capital program that we've been guiding a $1.1 billion to $1.3 billion annual capital program should be sufficient to continue to invest in an onshore stable production profile driven by our Eagle Ford Shale and our Tupper Montney business and allow us to continue to develop in Vietnam, completing the Lac Da Hong or Golden Camel development in 2029 and then ramping up spending to develop Hai Su Vang at about the same time with likely a phased development of Hai Su Vang or Golden Sea Lion in the early part of the 2030s. We are going to target first oil in the 2030 to 2031 time frame.

Right now, based on what we know, those are probably equal likely first oil dates. We probably have a 2-year ramp-up type of project where all of the Hai Su Vang development is not online day 1, but we have a stage development because of the size of the field and the size of the structure, we'll have multiple drilling locations, which likely implies, although we haven't planned it yet, likely implies a stage development over a couple of year period. That allows us flexibility a bit on the capital timing. Again, I think that we can develop that pretty handily within our guided full company $1.1 billion to $1.3 billion annual capital program.

There are likely times in the next few years where we will pivot slightly more investment into exploration and appraisal in our Vietnam business. We love the ability of our onshore business to be a bit flexible. We think that we can do all of those things within the current program and maintain stability of our onshore operations. But we do have and are happy to have the flexibility to pivot some of our investment. We also have an ability to pivot our investment in the deepwater Gulf. We can ramp it up or ramp it down. And that's a great advantage of having a multi-basin strategy where we're not in one thing, one play, one basin. And I think it is somewhat unique for a company, as you point out, that we're a smaller company.

And again, I think that what we're able to do there allows us to create a lot of value for shareholders. We have been fortunate and work very hard to have a strong balance sheet and increase our liquidity to be in a position to do exactly what we're planning to do in Vietnam right now. If we're fortunate enough to make a significant discovery in Côte d'Ivoire, we would probably be facing a capital bill that's large there. We have 90% working interest and a deepwater field of scale would be a significant capital allocation concern for us, and we're prepared to handle that through a combination or options around bringing in a partner to help us develop, taking on a bit of debt.

We would consider selling down or selling out of other assets in order to fund that. And what we would do is assess whether or not that new thing was the best thing to invest in for shareholder value creation and the role of our other assets in our portfolio, which is what we have done over the last 25 years cycling through, which we highlight on Slide 21. I hope that gives you a little bit of confidence in how Vietnam can be developed without significant change in our capital program, but also the awareness that we're willing to pivot if needed to fund larger scale developments.

[Operator Instructions]

Your next question is a follow-up from Leo Mariani with ROTH Capital.

Sorry, somehow my line went dead earlier. I got cut off. I did want to ask you folks just a follow-up here on Morocco. So I think you explained your process for continuing to evaluate a big 4-way closure through seismic reprocessing. But if that were to be successful, I know there's no near-term drilling obligation, but do you have a rough estimate of when that well might actually could spud? Are we talking a year from now, 2 years, 3 years? Just trying to get a rough sense of when you guys would actually be able to attack that.

Leo, it's a good question. I think we're a little bit too early to make that call right now. I will frame it in this way. It takes about a year to plan and then begin executing a frontier exploration campaign in a place like Morocco. And so we will not surprise you with a plan. We will likely be -- when we decide to drill or not drill there, we will likely be guiding the timing of that well in advance of the campaign. I just hesitate to say when we do it now because I don't know if we will drill a well or not. It's something that we will study and evaluate. It's definitely not this year, and it's likely not a '27 thing. I can't tell you if it's a '28, '29 or '30. I just don't know. And when we know, we'll let you know, and it will take about a year to make it happen.

Okay. So would that sort of just an inference here basically mean it would take you guys maybe a year or a little bit more to reprocess and interpret all the seismic on your end. Is that kind of a way to think about that?

That's fair. I would think a couple of years of studying it.

Okay. I know you're going to have another, I guess, webinar on Vietnam, but you kind of mentioned this a few times on the call already. But are there other exploration prospects in Vietnam that you are currently maturing? I know you've got these 2 significant developments that you're working on, but it sounds like there's more to do exploration-wise in Vietnam. Is that right?

There is definitely more to do in our 2 Cuu Long blocks in Vietnam. I imagine we will have an active exploration campaign there in '27 through 2029 period. We will likely find out what the entire block prospectivity is so that we can plan a phased development of both blocks to fully develop all of the economic resource of the blocks before they expire in the 2040s or '50s, whenever they are.

Your next question is a follow-up from Charles Meade with Johnson Rice.

Yes. Eric, forgive me if you addressed this, and I missed it. I think at least -- this is about [ PON ] at Côte d'Ivoire. Where are you guys in the process of making a call on whether that will be a development?

Great question, Charles. We had an obligation when we entered the block that contains the PON discovery to submit a field development plan. We prepared and submitted a field development plan. We did that last year and the government has received that. In parallel with preparing and that field development plan, we also negotiated with the government, the Ivorian government around a gas sales structure that might make it a project that was economic for us to pursue. As a reminder, PON is an oil field with a fairly thin oil column and a large gas cap. So it will produce significant gas resources. Roughly 2/3 of the total resource on a BOE basis would be gas and the rest would be oil and liquids.

And so the gas price and the structure around the gas sales agreement is important for that commerciality of that field. We failed to reach an agreement with the Ivorian government on a structure for the gas sales that would make that a project that we wanted to pursue. And we got then -- at the end of those negotiations, we got close to the beginning of executing our 3-well exploration program. And I think the Ivorian government wanted to see if we find additional gas resource that could be added to the PON gas that could make that project move forward.

It is interesting to note that between the Bubale prospect, which we're drilling now and the landing point at the shore, along the way on that path is the PON discovery. So if Bubale encounters an oil field with associated gas or happens to be a gas field of significant resource, it may add resource that would help justify the significant cost of gas pipeline from PON to the beach. And so that's something that we'll be evaluating in the future along with our partners in Côte d'Ivoire.

That's a really -- that's great detail, Eric, because there's -- it helps me understand how those pieces fit together, which is not obvious before. Last question for me, and I know we're supposed to be more focused on Vietnam. But this Bubale project that I'm going to dilatant this, but it looks like how far you are offshore and the size of your block there, is that like a basin floor turbidite fan that you're going after? Is that kind of the -- which has kind of been one of the ideal sorts of targets in that part of West Africa? Or can you just talk about the geological setting of your target horizon there?

Well, Charles, you got it exactly right. And I think we need to hire you as a geologist.

I'd hope you drill more dry holes, Eric.

Your next question is a follow-up from Carlos Escalante with Wolfe Research.

It's actually Doug on Carlos' line. Eric, I hope you don't mind me jumping on. I wanted to follow up on Charles' question, if you don't mind. Our understanding is Côte d'Ivoire is a bunch of independent play types that you're targeting. Obviously, you've had a couple of unsuccessful tests so far. Can you just tell us what the failure mechanisms have been and what it would take for you to walk away from the -- from a broader exploration program?

Yes, it's a great question. So the first 2 wells that we drilled, the Civette and the Caracal wells, we're testing different plays. Civette tested an interval that is shallower and equivalent to Eni's [indiscernible] discovery. We encountered oil in multiple reservoirs. We just did not find enough oil to have a commercial deepwater development. And so we are encouraged that the technical work leading up to an assessment of when we see something on seismic, does it look like it could bear hydrocarbons is playing out.

Finding hydrocarbons is hard. Finding commercial levels of hydrocarbon is even harder. And I think we're on track. In the Caracal prospect, it was targeting an Albian carbonate, which was equivalent to Eni's Baleine field that's currently producing. And we encountered a well-developed Albian carbonate. We just did not find enough hydrocarbons to be commercial. We have a little more work to do to identify exactly why those outcomes happen. Of course, we just got the results from those wells, and we'll incorporate it into the future prospectivity on the blocks.

There are significant remaining prospects that we will consider drilling. We don't have an answer in terms of -- today, we don't have an answer in terms of the likelihood of going back and drilling. We're going to study them. It's a piece of data. I think it's worth noting that while Eni has had tremendous success, they've been active in the basin for 1.5 decades, and they themselves drilled 7 dry holes. So exploration is a process. We're at the beginning stages of the process in Côte d'Ivoire. I'm encouraged that we're -- our geologic assessment from our team has held up pretty well. I'm disappointed in not having commercial discoveries as always, but I'm not surprised because each individual prospect has a chance of finding hydrocarbons that's likely somewhere in the 25% to 35% chance of success.

Eric, a quick follow-up. Is there any prospect of data sharing? Or has there been any data sharing with those that have had some success in the basin?

I would characterize data sharing as informal.

There are no further questions at this time. This concludes today's conference call. You may now disconnect.

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 a resource that is significantly above our initial midpoint of 170 million barrels of oil equivalents.

Although we're continuing the appraisal campaign with 2 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 Eagle Ford 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 Côte 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 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 Eagle Ford 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 2 appraisal wells in Vietnam's Hai Su Vang, Golden Sea Lion field, and 2 exploration wells in Côte d'Ivoire. In addition, as I mentioned in my stockholder update, we have expanded our exploration portfolio with an entry into offshore Morocco and acquisition of 7 new blocks in the Gulf of America. Bid results are pending for another 7 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 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. If 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.

[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 day range. So we're seeing what we think is very good reservoir quality, high productivity from our tests so far. So a really compelling result there so far for us at Hai Su Vang 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 makes 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 Lac Da Vang or Golden Camel development project. We had 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 Côte d'Ivoire, we have 2 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 Hai Su Vang, 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, has very robust economics. We're a high owner and it is expected to be a high rate well. So it will have a significant impact in our second half of the year production rate and it 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 3 to 4 months of our rig program in the Gulf of America. In our Eagle Ford 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 '26.

If you think broader, if you go into 2027 and say we have very low oil price in '27 and -- 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% -- 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 a longer picture view of our flexibility around capital deployment.

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.

Good morning, ladies and gentlemen, and welcome to Murphy Oil Corporation Third Quarter 2025 Earnings Conference Call and Webcast. [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, Lucy. Good morning, and welcome to our third 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 third 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 this morning. Consistent with our approach last quarter, we released our quarterly stockholder update last night alongside our earnings release.

This morning, I will share a few high-level insights and perspectives on our business before we move into Q&A. I'd like to start by thanking our employees for delivering strong operational performance in the third quarter, exceeding the high end of our production guidance for the second quarter in a row.

We achieved total production of 200,000 barrels of oil equivalents per day and oil production of 94,000 barrels per day, underscoring the strength and potential of our assets. It's always good to have a quarter where we deliver strong operational performance, both on the production and cost fronts, and we did exactly that in the third quarter.

Operating costs in the quarter averaged $9.39 per BOE, 20% less than in the prior quarter.

In the third quarter, capital expenditures totaled $164 million, which was below our guidance. While a large part of that lower CapEx was due to timing, it also reflects our ongoing efforts to drive capital efficiencies across our business.

On the international development and exploration front, we made significant progress in the third quarter. Our Lac Da Vang (Golden Camel) field development is progressing on track. And in fact, we started drilling our first development well earlier this week.

This is a major milestone marking our first development in Vietnam. I commend the team for continuing to execute this project safely and ahead of schedule in collaboration with our multiple local and international partners.

Our Hai Su Vang 2X Appraisal Well was spud in line with our plan and Civette, the first of our 3-well exploration program in Cote d'Ivoire is also on track to be spud before year-end. This quarter, our exploration teams are working very hard at exploring and appraising prospects across 3 continents, testing gross resource potential of over 1 billion barrels of oil equivalent.

These projects showcase Murphy's international expertise, reputation and partnerships, key differentiators that position us as a partner of choice for global exploration and development.

We look forward to sharing the results from our exploration and appraisal program with you in the coming months. As we assess our operational plans for 2026, we are closely monitoring the commodity markets.

We remain confident that our strong balance sheet and flexible multi-basin portfolio will allow us to manage near-term volatility while staying on track to achieve our long-term goals.

Looking ahead, exploration continues to play a significant part in the Murphy story and we're encouraged to see a renewed focus in the industry on the need for exploration and conventional resources to meet global energy demand.

With a robust portfolio of assets and decades of expertise, we are well positioned to capitalize on the opportunities ahead.

That's a very brief summary of our quarter and key catalysts for our business and we will now open the lines up for questions.

[Operator Instructions] With that, our first question comes from the line of Arun Jayaram with JPMorgan.

Eric, I was wondering if you could start a little bit around your exploration program in West Africa. Maybe some details on the Civette well, which you mentioned should spud by year-end.

And it looks like you've re-sequenced the program to include a different prospect for your third exploration approach. I was wondering if you could just give us some more color around that program.

Sure, Arun. We're really excited about our Cote d'Ivoire exploration program, which will start drilling before the end of the year, likely spud Civette in December and that should put us in a position to have some results to discuss at our January fourth quarter earnings call.

The following 2 wells in the program likely not have results to report until later in the first quarter or possibly into the second quarter of 2026. The Civette prospect is very similar in terms of the geology to the Calao discovery from the Murene-1X well Eni announced in the second quarter of 2024.

It's the same type of geology, just a slightly shallower interval testing highly prospective to us, Santonian-Turonian interval which we're really excited about. We think as we released in our slide decks in the past, the potential is significant.

And the reason that we are really excited about it is it has the potential to be quite large with a mean of over 400 million barrels, upside of 1 billion barrel range and we're able to test the wells. Our program of wells are going to be kind of in the $50 million to $60 million gross range.

So really excited about it. It's definitely in the right neighborhood. There's been a lot of recent success from Eni in the area and it's similar looking geology and we're pretty excited about it. [Indiscernible].

So as we've kind of continued to work through our reprocess seismic data set and kind of mature our assessment of the prospectivity, we decided to pivot from drilling Kobus to Bubale. And the reason we did that is we think that it offers a lower cost to test and lower risk or a higher chance of a discovery and also a very large resource range.

So we're pretty excited about that. The Kobus discovery is definitely still something that's out there and it might be the subject of follow-on exploration. Obviously, with some success, it would encourage us even more.

It is a different play type than Kobus, one that we think has a higher chance of being successful and that's why we made the switch. So there's nothing wrong with Kobus, just that we think that Bubale is a slightly better and we're prioritizing sort of our top 3 exploration tests in the blocks. Those are the ones that we think are the most compelling near term.

Makes total sense. And just maybe a follow-up. Obviously, you're drilling one of the more important appraisal wells at a very long time in terms of Murphy. Can you give us some of your key objectives?

And I know you've shared with us the location of the appraisal well in Vietnam, but maybe give us some thoughts on what you're looking to test at the HSV field.

Sure. Yes, it's a good question. The main purpose of the HSV-2X well is to determine what the lateral continuity of the reservoir is. So away from the discovery location, what is the makeup and content of the sand in the major discovered reservoirs to potentially test for a thick in the pay section and really critically determine if we can, where the oil water contact is.

So we believe the location that we're testing has the potential to prove a thickened section in the primary reservoir of the discovery and also prove the known oil column deeper. And that's the main objective of the appraisal well, which the whole point is to determine what is the -- tighten the range of resources and figure out how large is the field and help us start to plan field development.

We need to know where the oil is so we know where to put the development wells. And this is the first of what may be more than one appraisal well to determine how large the field is and how to optimally develop it.

But this one has a significant impact in that the major discovered reservoir that we flow tested that we announced earlier this year, we're hoping to prove a deeper oil column with that and potentially expanded thicker section.

Great, Eric. We'll enjoy well watching because you have a lot of interesting things that you're testing over the next 3 to 6 months. Appreciate it.

And the next question comes from the line of Neil Mehta with Goldman Sachs.

We're obviously working through a choppier macro right now and there's a lot of reasons for long-term optimism, but of course, there's some reasons for near-term caution.

So just talk about your down cycle playbook and how you ultimately use a period of potential commodity weakness to make the business better a couple of years out.

Great question. Obviously, we're paying very close attention to what's going on with commodity markets, watching both oil and gas. We're still working to put together a plan for our 2026 budget, which we'll discuss like normal in our fourth quarter call in January.

We're factoring in things like what do we think will happen with oil price in the first part of the year versus potentially the later part of '26 heading into '27. We're trying to develop a plan, not just for the year, but a multiyear plan that supports our strategy that balances near-term production and free cash flow with investing for longer-term resource additions, primarily for our offshore business.

We do have significant flexibility in our capital program. We could run quite a bit smaller onshore program for sure. In our offshore business, there are a few things that I think we're likely to do in almost all oil price scenarios.

There are things that we have a lot of flexibility to have an altered program. I think the things that are likely to be a little more sticky for us and that we probably choose to do, our Vietnam appraisal program that we're doing now and our Cote d'Ivoire 3-well program, I think you could see us doing those in most cases.

You would have to probably have a very, very low oil price where we decide to alter those plans. The other one is our Lac Da Vang (Golden Camel) field development. It's something that we likely see through to conclusion of the first phase in most oil price scenarios.

As we talked about last quarter, I'll kind of reiterate, we're very comfortable with our sort of base plan in line with our communicated multiyear range of CapEx. If oil price is $60 or so the longer that we think we'll see a sustained oil price that might be lower like, say, $55 or lower for a long time, we might start to get more aggressive in altering and lowering our capital plan.

And again, we have quite a bit of flexibility. Obviously, the sooner we start making changes, the more we could affect next year CapEx. But we feel like we're well positioned.

We also feel like we have a very strong balance sheet. So we're able to kind of -- if we wanted to, we could lean into a little bit of invest through the cycle. But like I said earlier, we're going to be pretty cautious around protecting a strong balance sheet, investing with kind of a balance of short term, medium term, long term.

And I think we've acted in the past with quite a bit of discipline and you can expect to see that from us going forward.

Yes, very clear, Eric. And then that brings up the follow-up, which is as we think about the '26 CapEx, the midpoint of your guide this year is $1.21 billion, of which offshore is 36% of the balance is outside of it.

And so just how do you think about the buckets of CapEx as you go into '26, recognizing we'll get more color early next year, but what are some of the moving pieces as we anchor 6 versus 5?

Very good question. Again, we're still working the details. I'll give you kind of directionally that is kind of provisional. I think with our active program exploring in Cote d'Ivoire, you might see a little more spending from us in exploration than this year or past years just by a little bit.

In terms of onshore spending, we'll probably have a slightly lower capital program in Tupper and Eagle Ford than we had in 2025. In offshore, we have a really compelling set of investments to pursue with strong returns and very low breakevens.

One of which we've highlighted is the Chinook 8 well, which is a development well in our currently producing Chinook field that we expect to bring online in the second half of the year. And we think it will have a gross oil production rate somewhere in the 15,000 barrel a day range.

So those are very compelling investments that we're likely to do. The rest of the details around exactly what the rest of our offshore program and do we fine-tune our Eagle Ford program with potentially lower commodity price, that's something that we're going to be looking at and paying attention to and kind of thinking about as we head into next year.

I would say, overall, it would be reasonable to expect us to have a capital program next year of a similar scale as we've communicated in the past, which is a $1.1 billion to $1.3 billion range.

And the next question comes from the line of Carlos Escalante with Wolfe Research.

First of all, congratulations, quite the turnaround on sequential quarters. So congrats on that. If I may, I'd like to ask my first question on your operational improvements thus far this year.

So maybe you can perhaps frame and quantify how the improvements in both your Eagle Ford and Montney, how that success has translated in terms of corporate breakeven. And I know and I realize it's a small piece of your portfolio, but just wonder how that is manifesting in your underlying breakeven.

Great question. Just high level, I'm very impressed with and very happy with our team's ability with a fairly limited onshore program to be able to continue to make improvements in our capital efficiency, both Eagle Ford and Montney, particularly, where in the second quarter and third quarter wells, we saw some of our strongest performance ever.

Initial rates, 90-day cum oils, 90-day cum gas for Tupper, all been amongst some of the best wells we brought online. That's been through a combination of various things.

In many places, we're drilling longer laterals, which we're able to improve our drilling targeting, our completion styles, we adjust kind of the completion design for each specific area to try to optimize what's going on there.

Our flowback strategies have been really enhanced. And it's just driving a really strong outperformance. I think we've highlighted that in some cases, we're seeing production rates in terms of the first few month production that are 50% to 100% above what historical performance is. So really strong.

In our Tupper asset, we -- in 2025, we've used a completion design that had significantly higher proppant loading and we think that's working for us and will likely feature that going forward. What I'm also really proud about is that we were able to pump better fracs with CapEx neutral or, in fact, some CapEx savings across our program.

So we're doing things that are not just spending more money to get more performance. We're actually getting better performance with equal or lower investment, which is really good for generating cash flow and to your point, what our breakevens are.

In the stockholder update, we highlight just how low some of the breakevens are for the Catarina program we delivered. Obviously, when you can have breakevens that are $35 or less and sometimes even in the $20s, that's awfully strong.

So really happy with how all that's going and it's led to significant performance -- outperformance and I think it's durable in the sense that the remaining inventory we have to drill, we're going to keep doing the same sort of stuff and we should continue to see that kind of outperformance as we progress the rest of our onshore program.

In offshore, I'm really happy with the turnaround. We had a tough year, 1.5 years with wells offline in the Gulf requiring workovers. We progressed through that. I think we're in a good spot.

We did have a production beat for the quarter even when you adjust for no storm downtime in the Gulf, we still exceeded even beyond what the storm downtime provision was with really impressive work by our team to have very low downtime in our operated major facilities, really top world-class performance in terms of our operating performance there.

That's very, very helpful color, Eric. And then for my follow-up, if I may follow up on Arun's question on West Africa. It looks like most of the historical exploration effort in the region has been done along the Upper Cretaceous with some success, but it was really Eni's Baleine and Calao discoveries, at least in our view, that have enlightened this new wave of excitement in the emerging deeper Albian Santonian intervals.

Would you guys concur with that in terms of is your seismic effort consistent with exploring that deeper potential as well as the Santonian-Turonian interval that you mentioned, Eric?

Yes, it's a very good question, Carlos. So what has happened in this Greater Tano Basin area is after the success of Jubilee going back a decade, pretty much everybody drilled the same look-alike prospects as Jubilee until Eni did something different.

And I would say it's a fair characterization that we see potential in the largely untested slightly deeper intervals. And that's what we're pursuing in most of our prospects here that we're testing.

And the next question comes from the line of Paul Cheng with Scotiabank.

Two questions. One, I want to go back into the 2X appraisal well that you're going to drill in Vietnam. If it is successful, Eric, can you tell us that is that going to be sufficient for you to set the development plan or that you think you actually would be better off because it's a large discovery?

So you're better off that to drill an additional appraisal well that to really get a confirm and whether that you will go with a -- given the size that do you think that a early production system will work better and then that you will have a full development?

Or that you will just go ahead with a full development? And trying to see that, I mean, what's the next step in 2026 after this -- after the completion of this well is going to look like? This is the first question.

The second question is on the impairment charge. You're saying that just because of a unfavorable disproportion expense allocation so that you write down the value in there, is that have any implication for your other well or other fields in the area?

Okay. Paul, on your first question, we're drilling the Hai Su Vang-2X well. And I mentioned earlier on the call kind of the purpose of what we're trying to accomplish.

So the potential for future appraisal beyond this is somewhat dependent on what we find in the 2X well. If we find a deeper oil column than proven in the discovery well, we're likely to have other appraisal wells to kind of determine where -- how much oil there is.

If we drill just below the currently low proven oil in the Hai Su Vang-1X discovery well and find water level, then we may be less likely to pursue another appraisal well. So it somewhat depends on what we find.

What we will do, what we typically do is sort of learn as we go and on a kind of point-forward basis, determine what do we need to know about the field to move forward to have confidence that we have it described appropriately with an ability to commit the capital to go develop it.

So I think it's likely that we will have an additional appraisal well beyond the 2X, but it will be somewhat dependent on the results that we have and what we still have unknown about the field as we go forward.

If we find only oil in the 2X well, it could imply that there is a deeper oil water contact than we test in the 2X and we'll likely go find it or try to find it with additional appraisal wells.

One of the thing, our appraisal program is pretty efficient here. These wells are not too expensive to drill to find out. So we're able to do that quite efficiently. Just briefly on the impairment [indiscernible]...

Impairment. Can you tell us what is you guys leaning to us into the development concept at this point?

Sure. Yes, Paul. So -- and I didn't fully answer part of your question, I guess. We will try to do what we can to appraise the field kind of in the coming months and understand what we think the size of the reservoir is and how to optimally develop it.

We will try to move forward to planning a field development plan and working with our partners and the government on that. And I would say we don't know yet because we don't know what we haven't yet determined, but we'd probably be looking at targeting final investment decision in 2027 and looking in a kind of a standard mode to producing Hai Su Vang in, say, around 2030, possibly earlier with an early production system.

We're looking at all opportunities we can to efficiently develop the field. A conventional development of the field would be similar to our (Golden Camel) Lac Da Vang would be an FSO and a series of platforms, a main processing platform and wellhead platforms.

There's also a possibility of redeploying an existing FPSO and doing some wellhead platform or subsea tieback type of opportunities. Those are all things that we're thinking about, looking out and we'll be trying to move as aggressively as we can to see first production with potentially early production system, but that's not something that's been particularly common in Vietnam.

So that would be something we'd be sort of newly bringing to bear there. Before I move on to the impairment, did I address your question, Paul?

Yes. Very good.

Okay. On the impairment, we periodically review the projects in our portfolio and kind of reevaluate our plans of investment. In the Dalmatian field, we had planned to do 2 wells.

And as we continue to study those and think about them, we saw that the operating expenses that those wells would be burdened with from the host facility that we do not operate started to look like they were really high costs.

And that high cost made it look like they may not be the best investments to make. So with the current cost estimates, those investments in new wells would definitely clear our cost of capital, but they start to become less attractive investments compared to other things we would choose to invest in.

So we decided in our 5-year plan in front of us to not invest in those 2 wells that were in our prior plan. When we remove that assumed revenue and reserves from our plan, it led to an impairment.

The producing wells are doing fine. The impact of producing wells is really nothing. We just -- when you take the revenue and the reserves away from that plan, the future cash flow didn't compare favorably to the undepreciated book value, which led to an impairment.

So there's no significant read-through to the currently producing assets or any other fields in the area. It's just we're choosing in our 5-year plan to invest in better investments.

Right. I think that's my question because you're saying that is related to a unoperated facility that the allocation of cost is higher. Do you have other assets that will have a potential impact or potential risk to that that will change your development outlook?

That's a good question, Paul. So we are fortunate to be in a position where we operate the host facilities for most of our production and the host facilities other than the one that Dalmatian uses that we do not operate have very low operating expenses.

So the main nonoperated ones would be St. Malo and Lucius, which are very strong performing assets with very low operating expenses. The rest of our Gulf of America portfolio, effectively, we operate almost all of it and we're happy with our expenses there.

It's really just this one Petronas facility that's late in life and experiencing escalating costs and the operator hasn't been too willing to do much to make the cost structure go lower, which is really the only sore point from escalating third-party operated cost issue.

And the next question comes from the line of Charles Meade with Johnson Rice.

I wanted to ask a question about your U.S. onshore guide for 4Q. And this might be down in the weeds a bit, but -- and specific to the Eagle Ford. And so that asset has really outperformed in 2Q and again in 3Q.

And I understand you're not bringing any new wells on in 4Q. But even just for the PDP decline for that, your guide calls for that dropped by roughly 30% quarter-over-quarter. And I think you mentioned earlier in your prepared remarks that those recent wells that you brought online, I think I wrote down, you said those have been 50% to even 100% above type curve.

And so I'm curious, is this -- that decline you're projecting for 4Q, is that the case where just internally, people don't want to underwrite the idea that these wells are going to continue to outperform the type curve?

Or alternatively, is this something where you've already seen here in October, maybe early November, that those wells that had been 50%, 100% over the type curve have reverted to the type curve? Where do we fall on that spectrum there?

That's a good question. What I'll do is I'll give you my thoughts and then if it's insufficiently answered, I'll have Chris jump in and help me out here.

What we have seen in Eagle Ford is really strong early production performance from our second quarter and third quarter wells. In the third quarter, more than half of our Eagle Ford production was from wells that we brought online in 2025 in the second and third quarter.

So you're seeing more than half of our production come from essentially brand-new wells, which, as we know, shale wells, once they come off peak, they do have early kind of in the first quarter or so, a steep decline and they sort of shallow out over time.

So what we are including in our guidance is an assumption that we will see significant decline in line with our kind of typical shale well performance that we see in Eagle Ford. Having said that, the early decline performance from our Eagle Ford wells is either in line or shallower than our historical decline performance from prior years.

Even though our initial rates are higher, the decline rates early on so far have been in line or in some cases, shallower. So there's no big issue [indiscernible]. We are just modeling what we think will be a reasonable decline from what are really high initial rates.

I'm really happy with the team performance. If you look at our Eagle Ford asset, roughly our fourth quarter guide is something like 5,000 barrels a day above our fourth quarter of '24. So that performance is continuing to be strong heading into the fourth quarter. It's just that the wells are -- the last of our new wells came online in July and we expect them to decline.

Hey Charles, just to add to that, when you're thinking about Q3 production, this is -- Eric mentioned, it's the highest new well production that we've had since 2019.

So it is a little -- it is a big -- because we've outperformed so well, that's why you have more steep decline with the new wells versus the base. But looking forward, we've got such a bright outlook on the Eagle Ford wells and just continue to improve our long runway of Tier 1 inventory that just keeps getting better and better with lower breakevens.

Right, right. That's helpful. So success can bring its own different issues. Eric, I want to go back to Vietnam, but ask about your Lac Da Vang development.

And appropriately, there's a lot of attention on the HSV. But can you remind us what the -- I know that there was already discovery that you guys came into, but can you give us -- remind us of the kind of the history of this field?

And what I'm really curious about is if there -- when you're drilling your development wells there, is everything already very well characterized and there's no chance of a surprise? Or are there things that you're attuned to possible surprises or upside with this development drilling that's going to deliver more near-term volumes?

That's a great question. The Lac Da Vang (Golden Camel) field is one that has been significantly appraised up to the point prior to our investment decision. The initial phase development is targeting what is sort of the most appraised part of the reservoir.

The second phase is sort of targeting, which will be wells online in probably '28, '29 -- sorry, drilling in '28 and online in '29. That part of the development has about half fairly well appraised and half kind of reaching out into the less appraised parts of the field.

So near term, we're really comfortable that we're going to be developing something that we understand pretty well. Having said that, I think that there's always a little bit of uncertainty in terms of new field, how you expect wells to perform.

So far, we continue as we learn more about the field to think it looks better and better versus worse and worse. And we'll certainly learn a lot from the initial development wells that we drill and we'll be trying to optimize our development as we move forward.

But yes, it's -- I would characterize it as quite reasonably appraised, especially for what we're going to bring online for first oil.

And the next question comes from the line of Leo Mariani with ROTH Capital.

Wanted to ask a little bit about operating expenses. So very, very low here in 3Q, kind of certainly below the guidance range you guys had given. And now you guys are sort of kind of maybe guiding back up a little bit on OpEx in 4Q.

So can you just provide some color there? Was it just like a total absence of workover spend in 3Q or something? Why did the number come out just a lot lower than it sort of has been? And is that sort of repeatable?

Yes. Great question. We did have some offshore workover spend in the third quarter. We talked about our onlines of kind of wrapping up our program.

So we did have workover spend offshore, but it was of a little bit lesser amount than in prior quarters. The lack of large-scale offshore workovers helped improve our costs.

We had significantly higher production across our onshore business and we lowered costs. In our Eagle Ford business, particularly, we're really focused on reducing the dollars being spent.

That's mostly driven by field labor, maintenance costs, rental equipment, water handling, some work from our supply chain team to kind of renegotiate contracts and a real serious focus on optimizing the work that we do in the field through our remote operations center working with the guys out there in the field.

Really happy with that. Those reductions in costs, which we kind of highlight in our stockholder update, those Eagle Ford reductions are durable and that really helped. What also really helped for the quarter was our record Tupper Montney production, has extremely low operating expenses.

So when you blend in the sub-$4 operating expenses from Tupper, it really helps you have a total company fairly low operating expense.

In the fourth quarter, we're guiding a $10 to $12 per barrel OpEx across the whole company. And the reason it's going up is that not because costs in terms of dollars are going up, but we are modeling a little bit less production.

So the cost per barrel will likely creep up into that kind of range, which really is sort of a typical range for us on the long haul.

Okay. Very thorough answer. Appreciate that. And then just kind of on the sort of operational side. Obviously, gas prices have been quite low in Alberta in terms of AECO. Are you guys factoring in any kind of shut-ins that may have occurred in the guide for 4Q?

Certainly, your Tupper volumes are down a decent amount. I know we haven't had really drilled a well in a while and you're getting some declines. But just what's the story with any kind of Montney shut-ins? How are you thinking about that? Is there some price level where it's kind of saved some of the gas? Or is it more just kind of keep the plant full?

Yes. What we're modeling in our fourth quarter production for our Tupper Montney is just typical decline from our base and new wells. And also, we're estimating a higher royalty paid in the fourth quarter compared to prior couple of quarters, driven by what we expect to be higher gas prices, pretty significantly higher.

I won't get the numbers exactly right, but rough math I think AECO in the second quarter was like $0.64 an Mcf, and we're expecting a fourth quarter to be a little over $2, like $2.05, something like that. That may not be the exact numbers, but they're awfully close.

Okay. That's helpful. And then just real quick on the buyback. In this type of oil market, call it, $60 hasn't been obviously great for anybody. Are you guys basically kind of saying that probably don't expect much of the way the buyback if this kind of price sort of holds as you really kind of prioritize capital spend and the dividend?

I think it's fair to say with the free cash flow we have available with current commodity prices, we're less likely to be particularly active in share repurchase.

Having said that, if we think there's a big dislocation in terms of our valuation and what our stock trades at, then we're not opposed to leaning into it as we've done in the past.

Tom, if you want to add any color to that or that.

I think you covered it. It's something that we think of on an annual basis. We did in the first quarter start off with $100 million of share repurchases. But as Eric said, we're kind of keeping an eye on the price and oil price and likely not going to go too heavy on that in the remainder of the year.

And the next question comes from the line of Geoff Jay with Daniel Energy Partners.

I guess I was just going to follow up on Neil and Charles' questions from earlier. But when you talk about how there could be a smaller onshore program next year, is that potentially in response to a lower kind of macro or lower oil price environment? Or is it kind of a confirmation that you think that the outperformance that you've seen onshore is repeatable?

Good question. In our base plan, it's mostly the latter that, for example, our Tupper Montney, we kept that plant full for 5 months. The activity level we think it takes to refill and keep full from Tupper is less than this year because we are already coming in at a higher production level.

In Eagle Ford, we've been guiding for many years that we anticipate using the asset to produce it in a 30,000 to 35,000 barrel a day range. And this year, we should be significantly higher than that, like around 37,000 for the year.

And we think that the repeatability of our strong well performance of our new investments will be there. And so we think it will take a little bit less capital to deliver the same or higher kind of performance from our onshore assets. That's what's really driving it.

My other comment earlier in the response to the call was if we see significantly low commodity prices, we do have flexibility and even pulling the capital spend in those assets down below what our kind of base plan might look like, which would have production impacts, obviously.

And we currently have no further questions at this time. I would like to turn it back to Eric Hambly for closing remarks.

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

Thank you, presenters. And ladies and gentlemen, this now concludes today's presentation. Thank you all for joining. You may now disconnect.