Murphy Oil Corporation (MUR) Earnings Call Transcript & Summary

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.