Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2026 Earnings Conference Call and Webcast. Operator provided 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 has 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 two 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 provided instructions. Your first question comes from the line of Arun Jayaram with JPMorgan.

Eric, totally understand how you're not yet at total depth at 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 total depth. 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. 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 slightly 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 three-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 two primary opportunities. The first would be an FSO paired with a series of platforms that would be processing platforms and/or wellhead platforms. 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, 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 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 exploration 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, 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. 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 two-thirds 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 at a lower price, which is more in line with the 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 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 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. We also 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 ago. And so we see some opportunity that's attractive, and we get into the country relatively cheaply and can assess it. 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. 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 and our share price may come down with it. So it may make sense to wait. 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 Margaret 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. Those lag by about a month. Usually with WTI, our benchmarks, we see those average prices as we market our crude. But the differentials are set with a bit of a lag. So through April, going forward, we'll start benefiting from those more constructive differentials 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 higher chances of success, but not very large opportunities that allow us to put additional future volumes over facilities that we own and operate today. The other part of the blocks we picked up are a little more emerging part of the basin. We are going to assess and evaluate the optionality we have there and think about an exploration program in '27 and '28 that balances near-field opportunities versus a little more emerging part of the Gulf.

Your next question comes from the line of 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. 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: people, seismic data and 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 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. 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 abandoned. The only thing is that we'll try to 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 our balance sheet. Obviously, with our debt towers now, it's more difficult for us to reduce long-term debt rapidly, 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 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 the line of 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. I'll let Chris 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. We also 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. We've really got it down to a science in each location and continue to see surprises to the upside. 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. 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 two, and that work is ongoing. 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 elevated premium and 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. 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 two 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 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 perhaps beyond the high end of that range. We'll see.

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. 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 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, Cote d'Ivoire, 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 next 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 de-risk 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 missed the few minutes of your call, I don't know hard time getting on, but 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 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, two 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. 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, we were leasing the FPSO that is used to produce the field. We identified that the terms were not 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. 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 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, 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 noncontrolling interest 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 preference 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 preemptive 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.