Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation first quarter 2025 earnings conference call and webcast. This call is being recorded on Thursday, May 8, 2025. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, operator. And good morning, everyone, and thank you for joining us on our first quarter earnings call today. With me are Eric Hambly, President and Chief Executive Officer; Tom Mireles, Executive Vice President and Chief Financial Officer; and Chris Lorino, Senior Vice President, Operations. Please refer to the informational slides we have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, 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, see Murphy's 2024 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Eric Hambly. Eric?

Thank you, Kelly. Good morning, everyone, and thank you for joining us on our call today. Looking back on the first quarter, I'd like to thank our employees for staying with it as we continue executing our plans. I believe we've turned a corner with our operations, and I'm pleased with our recent success. Murphy remains focused on our operational excellence, multi-basin portfolio expansion, and capital returns to shareholders. Murphy drilled our longest laterals in company history in the Eagle Ford Shale and Tupper Montney, as we advance our onshore program in the first quarter. Keeping our teams safe while we execute our operations is extremely important. And I'm excited that early in the second quarter, we achieved 1,000,000 work hours with no lost time injuries on the platform construction for our Lok Da Vong or Golden Camel field development project. We also announced today further success in building our Vietnam business and expanding Murphy's multi-basin portfolio. During the first quarter, we drilled our second oil discovery in Vietnam at the Loch Da Hong 1X or Pink Camel exploration well, where we encountered 106 net feet of oil pay from one reservoir. The company also acquired the Pioneer floating production storage and offloading vessel in the Gulf of Mexico for a $104 million net purchase price. Murphy upholds our commitment of returning cash to our valuable shareholders, and in the first quarter, shareholder returns totaled $147 million through $100 million of share repurchases and $47 million of dividends. Murphy has an exciting year ahead and we'll execute our plans through the lens of our strategic priorities. Murphy has successfully achieved the core objectives of our capital allocation framework since we first announced it nearly three years ago. Looking ahead, we will continue to focus on rewarding shareholders for their support,…

Thank you, Eric, and good morning, everyone. Murphy has made tremendous strides in strengthening our balance sheet over the past four years, which allows us to maintain our capital program and our competitive durable dividend while investing through the cycle. Further, our financial strategy incorporates a diverse marketing plan that enables us to capture natural gas price dislocations while also realizing premium pricing from our oil-weighted portfolio. I'm pleased that we have strong liquidity to support our investments with $1.5 billion as of March 31, as well as no near-term debt maturities. Our disciplined capital spending enables Murphy to prioritize adjusted free cash flow for share repurchases, potential dividend increases, and balance sheet purposes. Overall, Murphy maintains flexibility as we advance our strategic priorities. In the first quarter, Murphy acquired the Pioneer floating production storage and offloading vessel for a $104 million net purchase price as well as executed a new five-year operating agreement. This transaction creates tremendous value for Murphy and reduces our annual net operating expenses by approximately $50 million, thereby achieving a two-year payback. Additional benefits will be unlocked through further development and exploration in the area. We look forward to drilling and bringing online our Chinook development well in 2026 in addition to any potential third-party tieback opportunities around the FPSO. With that, I will now turn the call over to Chris Lorino, Senior Vice President, Operations.

Thank you, Tom, and good morning, everyone. Our Eagle Ford Shale asset produced 25,000 barrels of oil equivalent per day in the first quarter with 83% liquids and one gross nonoperated well came online in Karnes. As a result of our recently enhanced development plan further improve capital efficiency, Murphy drilled the longest Eagle Ford Shale lateral in company history at 13,976 feet in our Catarina acreage, representing an 8% increase from the previous record. We're also testing two tight turn radius wells to capture additional volumes in the completions process and are excited to see the results later this year. For the second quarter, 18 operated Karnes wells are now producing, and we anticipate three operated Catarina and three operated Tilden wells to come online later in the quarter, as well as 11 gross non-op Karnes wells. Murphy produced 340 million cubic feet per day from the Tupper Montney in the first quarter and brought online five wells as planned. The remaining five wells of our 2025 program came online early in the second quarter, which wraps up our well delivery schedule in the area for the year. With our enhanced development plan, Murphy recently drilled our two longest lateral Tupper Montney wells in company history at more than 13,600 feet each, with the longest representing a nearly 4% increase from the previous record. Murphy is always striving to improve our operations, and we tried a new completion style with enhanced proppant loading in the Tupper Montney. We are pleased with the early results as we've seen more than a 30% increase in initial production rates compared to our historical performance. I'd also like to highlight that with our new wells now online, we have reached our Tupper West plant capacity and are currently producing nearly 500 million cubic…

Murphy maintains a focused and meaningful exploration strategy with a near-field infrastructure-led program in the Gulf of Mexico and high-impact growth opportunities targeted internationally. We've made purposeful investments in the data behind our portfolio, allowing us to mature our understanding of the basins and support future leasehold expansion. Our current international priorities, in particular, offer a unique combination of development and exploration opportunities in offshore Vietnam and Cote D'Ivoire, and we are excited to advance these projects in the coming years. Murphy plans to drill two operated exploration wells in the Gulf of Mexico in the second half of this year for an estimated net cost of $18 million per well. We are targeting lower-risk opportunities near existing infrastructure and highlight that the Cello Number One and Banjo Number One prospects are located near the Murphy-operated Delta House floating production system. We're excited to announce that in the first quarter, we drilled an oil discovery at the Lok Da Hong 1X Pink Camel exploration well in Vietnam. The well was drilled to a total depth of 13,616 feet in 151 feet of water and encountered 106 feet of net oil pay from one reservoir. Based on these results, we estimate a preliminary mean to upward gross resource potential of 30 to 60 million barrels of oil equivalent. Murphy also conducted a flow test and achieved a maximum flow rate of 2,500 barrels of oil per day. Additional testing showed high-quality oil with an API gravity of 38 degrees. We are continuing to review the results of this discovery and highlight that it enhances the value of Murphy's growing Vietnam business when coupled with our nearby Loch Da Vong Golden Camel development and recent Hai Suvang Golden Sea Lion discovery. Earlier this year, we announced a significant oil discovery at the…

Thank you. Ladies and gentlemen, we will now conduct a question and answer session. If you have a question, please press the star key followed by one on your touch-tone phone. You will hear a one-tone prompt acknowledging your request. Your questions will be pulled in the order they are received. And if you would like to decline from the polling process, please press the pound key.

Our first question comes from the line of Arun Jayaram from JPMorgan. Your line is open. Yeah. Good morning, Eric and team. Eric, it appears that you're sticking with your capital allocation for 2025. But my question is for you and Tom. How do you think about your game plan in a lower oil price environment, call it, if things settled out, call it, in a mid-fifties kind of environment, how do you think about your program, which has generally been citing, call it, $1.1 to $1.3 billion of CapEx as you move some of these development projects through the queue?

Yeah. Thanks, Arun. Obviously, a very logical question considering where we are today. At this time, as you can see from our release, we think it's appropriate to maintain our 2025 capital plan. We've made significant progress in delevering our balance sheet, and in general, we want to position ourselves to continue investing in high-returning exploration and development projects through near-term volatility and be positioned to capture upside to commodity prices in the future. We think it's important that we balance the trade-offs between investing in our assets, returning value to our shareholders, and protecting our solid, really industry-leading balance sheet. We will continue to monitor the situation carefully, monitor the oil price environment, and as we've demonstrated in the past, we'll continue to act with financial discipline. So while we're not recommending or proposing a change in our 2025 capital plan now, we're aware and we're watching. We have identified opportunities to significantly reduce spending in 2025 and will be more likely to implement those changes if it looks like oil prices will be below $55 a barrel for the remainder of the year. At $55 a barrel for the end of the year, we see an average price of around $60 a barrel, which is very comfortable for us with our dividend and our capital plan. But if we see lower prices and we think they're going to be longer, then we would be more likely to move on some of the things we've identified. Some of the opportunities we've already identified to reduce spending in 2025 include not drilling Eagle Ford Shale wells in the third and fourth quarter, which are designed to come online in early 2026. We could delay those. We could not complete our four-well KBOB Duvernay pad that we're nearly done drilling. We…

That's super helpful. Thanks for going through your thought process. It makes a lot of sense to us. Maybe a follow-up. I wanted to get your thoughts, Eric, on how the recent discovery in Vietnam impacts the LDV development plan. I know you're setting the platform in 2026. And then you're scheduled to do the B platform in, call it, the 2028 time frame. How does this discovery impact the development plan of the 30 to 60 million barrels?

And, just a few miles away from the Lok Da Vong development. And the way that this will likely unfold, of course, we still have work to do with field development planning, but the way this will likely unfold is we'll probably set a wellhead platform at our recent discovery, Loch De Hong, and have wells drilled there and have production be processed from the Loch Dehong A platform, which we will bring online in 2026. So it's going to be a very capital-efficient project with an ability to probably get online faster rather than slower. We're going to be moving rapidly to develop and get approved from partners and government a field development plan to do that work. I'd like to give you exact timing of when that would happen because we have a long way to go with the approval process. But I would imagine before the end of the decade that we'd have that online.

Great. Thanks a lot, Eric.

Our next question comes from the line of Greta from Goldman Sachs. Your line is open.

Good morning, and thank you for taking my questions. Was just wondering if you could speak a bit about how the Khaleesi number two and Marmalard number three workovers currently underway are trending, what operational steps are remaining, and if there's incremental color you could provide on their timing?

Yeah. I may have Chris Lorino dive in there and give you some details on that. You don't mind?

Yes. I'll talk about the Khaleesi two first. We just got on the Khaleesi two and the Marmolard three workovers. You know, we mentioned the kind of winter storms that pushed back Samurai three. So we're kind of toward the beginning stages, but things are moving along like we had hoped. And, as far as our OpEx goes for our workovers, you know, we did have some OpEx slide in from Q1 to Q2. But even with Marmalade III slipping into Q3, we're looking at getting back to our normal OpEx run rate around $10 to $12 per BOE for the back half of the year. We feel comfortable about the Khaleesi-two being done in the second quarter. Yeah. And the Marmalard three well-being done in the third quarter. And making good progress.

Great. Thank you. And then for my second question, I was wondering if you could comment on your OCT exposure to current prices for the remainder of the year and into 2026. About how many months out do you procure your steel for your onshore operations, and what sort of impact to all costs are you currently embedding in your Outlook?

I may get some high-level comments in the maybe Tom can provide additional detail since he runs our supply chain organization and has done a fabulous job. I would characterize in general with all the pluses and minuses in our supply chain we feel that our onshore wells are effectively have flat total costs for the year compared to the prior year. We do see some pluses and some minuses. Rig rates in 2025 for Eagle Ford are lower than 2024. We do see a little bit of pressure on tubular goods maybe in the second half of 2025, but it's fairly limited. I think we're thinking of a three to 5% type of impact on potential exposure. In Canada onshore, our program, of course, is nearly done. But we saw effectively flat cost year over year, so we don't see an issue there. On offshore, we're seeing a reduction in drillship cost. We'll see a reduction in diesel cost, which is material. Probably seeing slight pressure on OCTG. In general, I think our team has done a great job of securing the equipment that we need, and most of the things that we need are already in-country and not subjected to tariff pressures this year. I don't know, Tom, if you want to add any more commentary on that.

Eric, I think you covered it. It's, you know, 2025, we're in really good shape, in particular with our onshore plans. And even in 2026, offshore, we have a lot of long leads that we'd already locked in place. You know, in 2025, I would say, 70% of our spend is in the US. The remainder is outside of the US, which, you know, isn't really subject to tariffs. And then 2026, it might be similar or even a little bit more spending outside the US.

Great. Thank you.

Our next question comes from the line of Davin McDermott from Morgan Stanley.

Hey. Good morning. Thanks for taking my questions. I wanted to ask about the production profile for this year. We'll look at, you know, 1Q, I think it was a mix of non-op operated activity in Canada, impacting results. The full-year guide implies a step up in the back half oil production relative to the first half. So I was hoping you could talk through some of the key drivers of that, the 2Q step up and then the incremental growth in the back half. And just the confidence in achieving kind of the implied full-year oil guidance range?

Yeah. That's a great question, Devin. So one of the things that I'm really happy with is, the bulk of our onshore program is online right now. Our, you know, our Karnes wells, which are highly productive, are all flowing today, they're performing really well. Our Tupper Montney 10 well program are all online and frankly, exceeding our expectations. So I'm really feeling very confident that we've turned a corner operationally here, and the production rates that we're already seeing in this quarter give me quite a bit of confidence in our ability to deliver our guide for the second quarter. If you move through the rest of the year, we'll bring on the remainder of our onshore wells, so that'd be more operated, nonoperated Eagle Ford wells in the third quarter. And also our KBOB Duvernay four-well pad. And so you see production in the third quarter increase a bit from the first. And then the fourth quarter, probably start to see a little bit of a decline from the high of the year, which would be in the third quarter.

Got it. Okay. It's really helpful. And you provided a lot of great detail response to one of the earlier questions on just capital allocation and thoughts about where you could trim capital in a lower oil price environment. In a world where oil softens but natural gas prices stay strong, or improve further, you have a tremendous amount of gas resource in Canada. But what milestones or what benchmarks we need to see in order for that to become more competitive for further growth? Understanding there's capacity constraints on the processing plant right now, but are there environments where that would actually compete for capital more and not be an area where you trim when you look out over the next few years?

Yeah. I think what you mentioned was really important. We do have a plant capacity issue that, we are currently have a plant full at Tupper West, which is where the bulk of our Tupper production comes from. So the ability to add more there in the really short run is limited. Although and I've mentioned this in maybe past calls. I think that we could see a commodity price signal there that would cause us to have more investment in wells. So we maintain the plant full for a larger part of the year. Our typical plan over the last year has been to build a plant, and the plants stay full for a while. And then after a lot of, many months of no new wells, we declined from the peaks. So we could potentially have another pad of wells, another five wells, or, you know, three wells that could allow us to maintain our plant at a higher level. That's something we could do on a fairly short cycle. That's something that we think about, we model, we evaluate. We'll be watching that as we think Canadian gas prices may improve materially in the second half of 2025 with LNG Canada finally taking some volumes to the West. And so it's something we'll watch and monitor. The capital efficiency of our Tupper wells is tremendous. We're getting wells this year that are producing early days at 17 to 25 million cubic feet per day. These wells cost us about $5 million, $5.05 and a half million dollars. And so it's pretty easy to spend that, you know, highly capital efficient to bring on gas if we saw a high enough gas price. The concern I have and that we've been fairly careful about is historically, with a high price signal, every single player in Western Canada has pretty significant capital efficiency, and they spend money to bring on new wells, and gas price is negatively affected. It's something that we're going to be watching carefully. We have a great opportunity to, if we think there's a durable higher price, then short cycle invest into that. But we're going to be watching the larger macro issues pretty carefully before we make that decision.

Makes a lot of sense. Thank you.

Our next question comes from the line of Paul Cheng from Scotiabank. Your line is open.

Hey, guys. Good morning. Eric, and may I don't know whether this is a fair question. Looking at the in the first quarter, your free cash flow negative, and you spend $100 million in buyback. Just curious that, I mean, how we contemplate or that the board is thinking about the buyback. Is it we need such a quick idea, especially given that we are seeing to buy back stock and buy borrowing money, which you draw down on your credit facility. And, obviously, that, with the uncertainty, it could also come with opportunity. So should we try to have a stronger balance so in the event that you have opportunities that come up that, you can strike, I mean, given Murphy actually have a very good track record in terms of acquisition. That's the first question then.

Paul, that's a great question. The draw on our revolving credit facility was primarily driven by our $100 million share repurchase and the capital weighting of our first quarter capital weighting of our program, including the purchase of the FPSO. I think we did a really good deal with that FPSO. You know, it's an oil price independent about two-year payout, and it really helps us unlock an opportunity there. So pleased with that. When we purchased $100 million of our stock in the first quarter and we had pretty significant oil prices in the first quarter and a view at the time that were going to remain to be fairly significant. So we felt where our shares trading at the time represented a significant disconnect in intrinsic value. And it made sense to do that. Obviously, commodity prices have softened since. And it's something that we're watching carefully. We do, in general, want to be very disciplined around protecting our balance sheet. So we're not likely to spend at a point where we would take on significant debt. We're going to be very careful about that. But we will also potentially be opportunistic if we see a very large disconnect between our share price and what we think it's worth. So, don't want to get in front of a board decision around what we might do about further share repurchase. Obviously, there'd be limited adjusted free cash flow, which is, remember, after our dividend, with oil prices in the low fifties. So taking on debt to buy back our stock is something that we would consider, but it's probably not likely.

Okay. Second question, the BW Pioneer, it at least looked to us that it's a great deal. I mean, two-year payback. But a lot of pushback that we heard from time is that, hey. Normally, that no one will sign a deal that, to from a seller standpoint that to do a two-year buyback. So is there any kind of colors additional need that you can provide? What incentivize the seller to sell? At this price?

Yeah. So the seller was looking for two things. Certainty in what to expect from potential ability to make money there, and also to raise cash for other issues in the rest of their business. It's the only FPSO operating for them in the Gulf of Mexico. And at some point, they decided it wasn't something they wanted to keep on owning. And we were happy to do a deal there that we think was a good deal. And we are we did award a contract to the seller to continue to operate. They've been a very good operator for us on the assets. So we are paying them to operate on our behalf. And they're making a little money doing that and they're happy with that, the certainty that that cash flow provides for them. And they were able to address other corporate needs for cash. And I think it was a win-win deal for both parties, and we're pretty pleased with it.

Alright. We do. Thank you.

Thank you. Bye.

Our next question comes from the line of Charles Meade from Johnson Rice. Your line is open.

Yes. Good morning, Eric. Tom, Chris, and the whole Murphy team there. I wanted to go back to what's happening in the Gulf of Mexico. If I'm understanding things correctly, it's your activity, including your planned activity with these workovers, that's really the big variable about how the 2025 production will play out. So can you talk a little bit more about what those two workovers are? And at Khaleesi and Marmolard? And I'm thinking along lines of are these relatively simple zone changes moving up the hole, or are they more complex things where you're trying to remediate sand or water production or something like that?

Okay. Yeah. Let me tell you what we're doing there, and then I'll go back and talk about the production impact for the year. The Khaleesi 2 Well is investigating what we believe is a failed safety valve. That's fairly simple to fix. We pull tubing out of the well and rerun tubing with a new safety valve in the well. So something that is routine, it's frustrating and disappointing that we have to do that. Obviously, that's not something we expect, especially from a relatively new well. But it's a pretty quick fix. The Marmalard three is to do a sidetrack and completion of an existing well. That's a slightly more involved activity. And that's why it'll take a little more time and we wrap it up in the third quarter. The production impacts for the year, we highlighted some of the downtime we had in the Gulf from non-operated assets, and also from offshore Canada, that's driving obviously a first-quarter impact. The other issue, which maybe is a little more nuanced, is the rigs that we had doing work at Mormont 4 and Samurai 3 that are now online, we were a little slower in conducting the work that we had been doing on those. Because we had winter storm activity that made periods of time where we couldn't be productive with the use of the rig. So we had nonproductive time, which delayed them coming online. Now the Marmalard and the Khaleesi Well activities are using the same two rigs. So the rig got to the Khaleesi 2 and Marmalard three later than we originally expected for the year. And but it's hard to go back and then we just have to execute those, and they're going well now. Make the rigs show up earlier. It happened already. I hope that helps.

No. That does help. And that's the kind of thing that wouldn't necessarily be obvious if you just looked at the presentation. So I appreciate that. I want to ask a question on, my sec follow-up on Vietnam. And so, this most recent discovery look. I think it's obviously going to be a good piece of business in shallow water nearby an existing development. But I wanted to ask you, it looks like it came in a little smaller than your predrill, and I wondered if you could tell, if there's any what the relationship, if any, is, but between what you found in this zone and what you found in your, the two zones you found in your earlier Vietnam discovery. And if anything you saw in this most recent one is going to, you know, affect or inform how you design your appraisal well on that, earlier larger discovery.

That's a great question, Charles. We did have a post-drill result that we believe is a bit lower than the predrill. We expected that we predrill, we expected that we would encounter oil in multiple pay sands. We ended up encountering what's a nice discovery in one pay sand. That pay sand is the same age reservoir as our Hai Subong or golden sea lion discovery. What is significant about the relationship between the two is that the Lok Da Hong, the most recent discovery, pink camel, was drilled at a depth that is now deeper than Hai Soubong discovery in the same pace. They are structurally separated from each other. But encountering oil deep in the overall system and demonstrating that that Lok Da Hong recent discovery was able to flow at commercial rates is very encouraging for us. So distribution of sand, depth of oil, productivity of the well, reservoir quality, all those things are encouraging for further appraisal at Hai Sibong.

Got it. Thank you.

Thank you.

Our next question comes from the line of Carlos Escalante from Wolfe Research. Your line is open.

Hey. Good morning. Good morning, Eric and team. Look. I guess I'd like to ask about Vietnam as well, you know, resonating one of my colleagues' prior comments. The results are certainly encouraging. And I think that it continues to de-risk a development at scale. But just along those same lines of what you said, Eric, the reservoir quality if you compare and contrast both HSV versus LDH, I think on your opening remarks, you mentioned that the flow rates for this latest well came at 2,500. At max flow rate capacity. Whereas, if I compare it to your HSV comments where you mentioned that the 10,000 barrels of oil per day were facility constrained, not sure if we're reading too much into this, but was hoping that you guys can perhaps elaborate a little bit on what you're seeing in terms of an apples-to-apples comparison of the flow rates and, you know, also qualify for how long did these wells flow at such rates because that matters as much as the size of the flow rate.

Carlos, I appreciate that. When we do these flow tests, the wells will flow for days. We conduct flow tests at a variety of production rates, and we do pressure buildup testing to learn as much as we can about the reservoirs. Typically, toward the end of one of these tests, we do flow the wells at a maximum rate just to get a sense of the total deliverability that's possible. So over the wells flow per day, but the highest production periods are hours long. They're not minutes long. They're hours long, and they're not days long. So we're pretty comfortable that they tell us quite a bit about the ability of the reservoirs to produce. I'll note that the pay thickness of the recent discovery Lok Da Hong pink camel is about one-third of the thickness in the main pay sand that we tested flow tested at the Hai Soubong discovery. So because we found a thinner pay, we would expect it to produce at a lower rate. So if you adjust for pay thickness, they're similar. The Lok Da Hong may be slightly less productive per foot than the Hai Sibong, but we're really happy with it. It's clearly commercial. You know, typical production rates in this basin are 1,000 to 1,500 barrels per day per well. We're really pleased, obviously, with the strong flow rate from Hai Sibong and the really quite compelling flow rate from the Lok Da Hong.

Okay. So just to clarify, both were both flow rates are at facility constraint levels. Correct?

No. The result that we announced earlier in the year was at a facility-constrained level. 10,000 barrels a day. Lok Da Hong produced what the well could deliver. It was less of a production rate primarily because it's three times thinner. So you would expect the thickness driving partly the production rate potential.

Gotcha. Alright. Makes sense. And then for my second question, on Cote D'Ivoire, we can talk about that for a minute. What are you looking for on those three exploration successes and knowing that there's been some, you know, adjacent success in the recent times, with other companies. Are you looking for there, and then how do you benchmark that and plan for 2026 and 2027 in the event of a successful campaign up there?

Carlos, we provide on our slides quite a bit of detail around expected resource ranges for the three prospects that we expect to test. We provide details on those. The Civet the mean is 440 million barrels with the potential up to a billion. The Cobas is expected to be fairly similar with a higher and a bit higher, but maybe over 1.2 billion. The Caracall prospect, which is a Belane look-alike, is probably 50 million barrels up to 360 million barrels. So these are really sizable opportunities for us. We still have to award a rig there to do the work and finalize our well cost. But we're talking about wells that are around $50 to $60 million a piece and to test these types of volumes with the kind of low cost is really compelling for us. The fiscal terms, while I can't give you all the details, they are very strong. The fiscal regime in Cote D'Ivoire has metrics, financial metrics that are not very different from the United States, which is the best fiscal regime in the world. So we're really happy with the potential here to find significant resources tested with low well cost and with success be very profitable for us. The Civet prospect, which is likely to be our first well, which we'll drill later this year, is geologically very similar to ENI's Moraine one x or Kalau discovery that was announced in March of 2024. And the Karakol prospect is very similar to the Balane producing field, which obviously gives us quite a bit of confidence that we have some nice-looking prospects here. The Covis prospect is more frontier, testing two different play types in one well, and we're really excited that the potential there is material. The other thing I'll point out is with success here, there's significant running room on other prospects on these blocks. So potentially, this could be really exciting for us if we have success in any of these prospects.

Thank you, Eric.

Thank you.

Our next question comes from the line of Tim Rezvan from KeyBanc Capital Markets. Your line is open.

Good morning, folks, and thank you for taking my questions. I just wanted to kind of close the loop on repurchases. Obviously, a pretty heavy first quarter. Just to clarify, is it safe to say you are still in the market, but you're obviously, you know, keeping an eye on negative free cash flow for the year. Just trying to understand, I know you won't talk amounts and timing, but is it safe to say that you're still going to remain active to some extent going forward?

Tim, the way I would characterize it is we will not preclude being opportunistic. But we are very attentive to paying careful, you know, attention to our balance sheet. We like our industry-leading balance sheet. We're going to protect our industry-leading balance sheet. We think we have a good dividend policy. Happy with the share repurchase we've done in the past. We won't preclude doing it, but we're probably not leaning into it too heavily.

Okay. That's a perfect answer. Thank you. And then just, again, one more on Vietnam. As the platform construction continues, I know it's easy for me here, you know, in the US to say this, but why wouldn't you kind of incorporate, you know, this exploratory success from LDH given it's three miles away? Are you sort of set in stone with the process you have in place? And you know, why wouldn't you kind of pull that value forward if it's just a three-mile tieback to that facility? I guess the bigger question is sort of how we should think about gross flow rates at that facility from start-up in 4Q 2026. Just trying to kind of get a little more context on that. Thank you.

Yeah. Great question, Tim. Yeah. Great. So the recent discovery, Lok Da Hong or pink camel, like I said earlier, we expect that that'll probably be developed with a wellhead platform tied into the production facility at Lok Da Vong A, which is the first platform that'll come online. We will need another platform to be able to drill wells that we can produce. So we don't expect we'll be able to drill wells from Lok Da Hong A platform to develop the Lok Da Hong discovery. So a fairly simple wellhead platform where which we can see that the basis of the location of the drilling wells is likely the development concept there. Now we can incorporate that in the production platform and the FSO that are already part of the Lok Da Vong development, which should allow us to speed up the development. If it was a standalone with its own processing platform, and own, oil storage, then it would be a slower development. So in a sense, what we're saying is we believe the forward plan will be an accelerated version of a development. And that's why I think it's possible that we could be producing there before the end of this decade. Total capacity of the facility is probably 30,000 barrels a day gross.

Okay. I appreciate that. Thank you.

Thank you.

Our next question comes from the line of Leo Mariani from Roth. Your line is open.

Hi, guys. Wanted to follow-up a little bit on activity levels. So appreciate all the commentary around, you know, looking to cut activity if oil is below $55 a barrel sustainably. You talked about a potential rather substantial cut of 20% to 40%, you know, next year. But just wanted to kind of investigate, you know, potentially a middle ground scenario. I mean, you know, what if oil is closer to 60? Do you guys kind of hold firm on sort of that capital spending range, the one one to one three? Or is there kind of somewhere in the middle where maybe there's some more modest cuts as we look forward here?

Leo, that's a great question. We really feel comfortable with the kind of capital level that we've been guiding, the $1.1 to $1.3 billion. At oil prices that are anywhere from the high fifties to low sixties a barrel WTI. So that's a good question. So I think that if we thought we would have sustained, you know, 2026 oil prices, that would be 60 to $58, something like that, we would probably have a more significant capital program closer to what we've been guiding long term. With that type of oil price, we're able to easily manage our dividend and the capital program at that level. We would likely not have material free cash flow beyond that for debt reduction, but we'd be happy with that. And I think considering that quite a bit of our capital investment is middle or longer cycle, and if you think that oil prices toward the later half in the decade are going up because of exhaustion of top-tier shale, then we think it would make sense to kind of invest through the cycle, especially with oil kind of in the low Sixty, High Fifties Range.

Okay. That's Helpful. And I Guess Just On Offshore Canada, obviously, you guys had a bit of a hiccup there. In the first quarter where you lost some volumes. So it seems like it's kind of been an ongoing problem for a while where volumes are not have been what you guys wanted them to be. Can you maybe just give a little bit more kind of color and sort of a little bit more detailed update on kind of what you see happening there? And also just on LOE, you guys talked about LOE coming down in the second of the year. Do you expect it to still be elevated kind of in the second quarter?

Great questions. So in Canada offshore, what happened has really nothing to do with the assets themselves, the Hibernia, Terra Nova. The issue was an oil shuttle tanker had a collision with the port. And became unavailable and the operators there had to come up with alternative methods, alternative tankers, to deliver the oil from the facility to the tanker. So really, it had nothing to do with the operators or the assets themselves. It was a short-lived issue. It did impact us, unfortunately. Impacted everybody producing offshore Canada. We're happy with the performance of the assets other than that. And it's an unfortunate incident that affected us a bit. But it's not something that is expected to be ongoing. It's very unusual, and it was fairly short-lived. If you look at operating expenses, for the second quarter because of the ongoing workover activity, I think that you'll see operating expenses continue to be elevated above sort of our long-run level. I think you'll see something in the $14 range for the second quarter and I think you'll see that drop into the 10 to $11 range for the last two quarters of the year.

Thank you.

Thank you.

Ladies and gentlemen, if there are any additional questions at this time, please press star followed by the number one. As a reminder, if you are using a speakerphone, please leave the handset before pressing the keys. Our next question comes from the line of Josh Silverstein from UBS. Your line is open.

Yes. Thanks. Good morning, everybody. Yeah. Everybody's trying to talk about some kind of added flexibility to their programs. I'm curious how you kind of think about your Eagle Ford program. It's clearly kind of weighted to two quarters from a turn on line stamp. As you go forward, is this the most efficient way to operate this asset? Or do you think there could be a little bit more of a balanced approach across the year?

Josh, thanks for that. The way that we're been managing our Eagle Ford business, if you go back say, 2021 through 2023, we were running a program that was very heavily weighted to the first half. In 2024, we shifted our program to have steady drilling operations throughout the whole year. And we're repeating that in 2025. It turns out just based on the amount of activity of drilling in the fourth quarter and the later half of the third quarter we have planned, that we won't get to completing those wells that we drilled late 2025 until early 2026. So the cadence of online is still a little bit more weighted to the first three quarters. But our rig activity is constant through the year. So at the capital level we're investing, we really can't do more to smooth it out than that.

Got it. Understood. And then as you guys are starting to, you know, contract out the offshore rigs, for exploration and development programs kind of later on this year and into next year, what's the current availability look like? And how are the discussions on pricing relative to maybe what you saw three and six months ago?

So for our Cote D'Ivoire plans, we are close to awarding a rig contract there. I'd rather not describe exactly what the rig rates are because we haven't awarded the contract. But we're comfortable that you'll be happy, I think, with the rate there. It won't be particularly high. The rig availability is significant. I think we had over 10 rigs participate in our tender process. So quite a bit of rig activity is possible in Africa. And when we get to the point of being able to award a contract, we'll probably be able to say more there. In Vietnam, the appraisal program that we have coming up, we have a rig contract that is nearly ready to be signed. And the rig rate is quite low. It's significantly lower than the rig rate we had during the exploration program. So, again, when we have those contracts awarded, I'd rather be able to talk about later, but we're seeing some softening in rig rates both in jackup and in drillships. So I'm pretty happy with that development as it relates to our ability to efficiently execute our exploration programs.

Got it. Appreciate the color.

Thanks, Josh.

Our next question comes from the line of Brian Valley from Capital One Security. Your line is open.

Hey. Good morning, everybody. I thought that I had jumped out of the queue or at least I tried to. Leo kind of beat me to the punch with his LOE cadence question. So thank you for those comments.

Happy to hear from you, Brian. Thanks.

Alright. Yep. Thanks.

There are no further questions from our phone lines. I would now like to turn the call back over to Eric Hambly for any closing remarks.

Thank you for listening to our call today. If you have any additional questions, please follow up with our outstanding IR team. Have a good day, everyone.

Thank you, sir. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we may ask that you disconnect your lines.