Okay, we're going to keep things moving. Our next presenter is Murphy Oil. Delighted to have Murphy's new CEO, Eric Hambly, to participate in our fireside chat with us today. Even though he's the new CEO of Murphy, he's been at the company for quite a bit of time, around 20 years, and he's really grown up throughout the organization, leading the operations since 2020. He joined, like I said, Murphy in 2006 and has been leading the company forward since January. The excitement here is just a few days after he became CEO, he had the pleasure of announcing a world-class discovery in Vietnam. A great and amazing start to your tenure, Eric. Before diving into our fireside chat, I was wondering if you could just start off with some introductory comments around the company, Eric. I appreciate that, Arun. Thanks for having us to your conference. I think I heard today that we are at your 10th, 10 out of 10 conference. Yes. Murphy, big supporter, and we appreciate your support of us over the years. I think we have an exciting future ahead of us at Murphy. I think we're a very different company than many of the companies that are kind of our scale. We have an onshore and an offshore business. We've maintained the capability of doing international exploration and development, and we have a large inventory of remaining shale locations. I think that as we head toward the end of this decade, it sets us up to be really differentiated compared to companies that are really many more close to our scale. We'll talk probably more in this Q&A, but I think we have an exciting exploration and appraisal program in front of us. We're on the cusp of building what looks to be a material business in Vietnam with a development project, Golden Camel, the Hai Su Vong, Golden Sea Lion, recent discovery, and another Pink Camel discovery that we just made. I think we're setting up for a really successful future for Murphy in Vietnam as we head toward the end of this decade. I think over time that'll increasingly make us look a lot different than other companies and a compelling story in terms of investing in. Eric, before diving into the fundamental story here, I mentioned how you just started as the CEO just a few months ago, which has given you perhaps a fresh license to look at the organization, your leadership team, and strategy. I am wondering, any kind of perspective and any thoughts on tweaks to the organization or strategy? Yeah, that's a great question. Fortunately, I had the opportunity to work over the last few years to help shape the Murphy strategic priorities, key objectives, and focus areas. That's something that Tom Mireles, our CFO, who's here, and Roger, our prior CEO, worked on quite a bit with our board. As I start my tenure as CEO, I look and see that the things that we would like to be doing better or do differently, I was able to help shape the implementation of that over the last few years. I think we're starting to see some success from that. For example, I think that our exploration organization, we worked over the last two years to significantly improve the capability of our team, our process around acquiring and analyzing data before making decisions about which wells to drill from an exploration perspective. I think you can see over the last year or so, the results that we've demonstrated are showing that the success of that work has come to bear. The other thing, I had a little bit of a discussion at dinner last night around some companies, some of our peers that are really focused on cost reduction efforts. I'll just point out that in 2020, Murphy had a major cost reduction effort that we significantly streamlined our organization and our cost structure. In 2019, we had annual G&A of $243 million. The last few years, we're running about $110-$107 million. What companies may now be doing to cut costs out of their structure, we really did in 2020. It's an effort that I worked on with our senior HR leader, Maria, and kind of led an implementation of that in my prior role. A lot of the things that you might look to say a new CEO may do, we have already kind of done, and I was able to help shape it. I feel really good about our organization, our capability, and really, really happy of the recent success in improving our exploration organization. Okay. Let's dive into the 2025 program. Your budget is earmarked to spend about $1.2 billion of capital with 85% of the budget earmarked for development. Can you talk about how you're thinking about kind of the macro picture and where Murphy stands in terms of kind of executing its original program? Yeah, we're very happy with the capital program that we laid out for this year and our longer-term guide of a typical year being between $1.1 billion and $1.3 billion capital program. We're happy with that, with oil basically in the 60s. We easily cover our dividend and our capital program with oil prices in the 60s. We highlighted in our first quarter earnings call recently that if we saw oil prices that were lower for a sustained period of time, like maybe say $55 a barrel, WTI, that we thought would be a long duration, that we might make adjustments to our capital program. The reason to do that would be to basically protect our balance sheet, which we think is currently industry-leading, really solid balance sheet. We want to keep that to be able to be opportunistic to fund successful exploration, to potentially go after M&A opportunities that other people may not be able to do. We'll be a bit careful. With the prices we're seeing now and what we think looks like next year, we should pretty much stick with that type of capital plan. When the capital plan we put together, that $1.1-$1.3 billion kind of in a typical year, we allocate about 10%-15% of that for exploration. The rest of the business is a combination of sustaining basically a steady performance of production level from our onshore business. Eagle Ford, we're managing in a 30,000-35,000 barrel a day net to us range. Our Tupper Montney business, we're periodically refilling to our plant capacity. The rest of the investment, other than exploration, which I highlighted, is development activity for the Gulf of America primarily. We have a steady plan of activity through the end of this decade to continue to develop our assets in the Gulf of America, which should provide single-digit, low single-digit growth in our business. When you add our Vietnam new production coming online in 2026 to that, we started little step-ups over time between now and the end of the decade. Great. I want to dig deeper a little bit on the portfolio. Let's start with the Gulf. Can you provide kind of an update on your plans and with the drill bit in 2025? Sure. Let me go back to the beginning of 2025. In the first quarter, we brought online the Mormont number four new development well. In the first early part of the second quarter, we completed a workover on the Samurai three well. Those are already online. In the second quarter, we are progressing workovers at the Khaleesi two and Marmalard three, which should have first production in the second quarter and the third quarter, respectively. That should be the end of our offshore workover program, which, as you are familiar with, has been a bit of a sore point for us over the last few, well, the last 18 months or so. Rounding out the rest of 2025 in the Gulf of America, we have two exploration wells planned that will drill in the third quarter. They are called Cello and Banjo. They're near our Delta House operated facility. With success, we'll have the ability to fairly quickly tie them in and bring them online. They're not expected to be really large resource opportunities, but they're highly accretive and quick to bring online. In the Gulf, we round out the year drilling a new well in Samurai, which will come online and be completed in the early part of 2026. On top of all of that, in the Gulf, we have some long lead acquisition of equipment, long lead equipment in 2025 to support operated and non-operated wells in 2026 and 2027. That's kind of how we're spending our money and what we're developing in the offshore space. Okay. Maybe a quick update on the St. Malo water flood project with Chevron. Where do you stand with that? When can you start to see some production from that project? The St. Malo water project was substantially completed last year and water injection began. What we expect to see over time is the water injection will provide pressure support in the reservoir, which will help sustain a production level that's sort of steady. The water flood contribution over time will be larger and larger. At this point right now, we're not yet clearly able to distinguish what is sort of base performance from water flood performance. We do expect throughout 2025 to start to see a contribution from the water flood project, and increasingly in future years, more and more of the total production will be from that. What's interesting about sort of typical deep water fields, if there is a typical one, decline rate of without activity is typically somewhere around 18%. We're basically not seeing decline at the St. Malo field. The water project, while early, it's probably starting to show some performance. Okay. It sounds like the workover program is largely in the rearview mirror. How do you think about kind of normalized workover? Obviously, the last, call it 12 to 15 months, you've had a little bit higher of equipment workovers, but it sounds like you'll be moving to more of a normalized level of workover spend. I sure hope so. If we look at a typical year, we do not expect to have any offshore workover activity. If you look back over the period of time from 2023 back to say 2018, we might have had one offshore workover in our deep water Gulf of America business. It is normal for us to expect to have a year without any workover activity. We have, as I just mentioned, had quite a year plus of quite a few high-rate wells that needed to be worked over. What is interesting about them is the wells all had issues with different pieces of equipment. There is not a commonality. There is not the same type of equipment or the same failure mechanism for the wells. We feel like once we get past the work that we are aware of, that it'll be normal to expect no repeat and kind of get back to lower operating expenses. Yeah. One of the things that I think you did have to do is replace some subsea safety valves on a number of wells. Where are you in terms of that process? Yeah. So the Dalmation well, we had a safety valve repair in 2024. That well has been back online and producing. The Khaleesi two that we're working on in the second quarter is also a safety valve repair. What's interesting is there are two wells of completely different vintages and totally different types of safety valves. Safety valve failures are not very common in the Gulf. We were quite surprised to have them. The Dalmation well produced, I think, for eight years or so before having any type of issue, whereas the Khaleesi two well was about two and a half years old. Again, totally different types of safety valves, fundamentally different designs. Fairly unusual to have something like that happen. I think, like I said, I think we've turned the corner and we're getting back to kind of normal run rate. Our total company operating expenses, when we do not have significant offshore workovers, they are kind of typically in the $10-$12 per BOE range. I think you should see us get to that kind of level in the latter half of the year. Okay. One maybe final question on the Gulf of America. Love to get an update on Chinook and maybe you could set the stage because I think that could be a really interesting well for you for next year, I believe. Sure. The Chinook field, the Cascadia and Chinook fields produced to an FPSO, which we purchased early this year for a little over $100 million. That sets us up to have a lot better creative economics of a development project there. We've been aware of a development opportunity to replace a well which was previously producing from one of the Chinook reservoirs for quite some time, but we were not moving it forward because we had a fairly high day rate under a lease agreement for that FPSO. Now that we've purchased the FPSO, we have a lot of flexibility in what we want to do. What's interesting about Chinook is we have quite high ownership. We're over 86% working interest. The well that we have in mind, which we'll likely include in our 2026 budget and will likely come online in the last half of 2026, has the potential to be pretty high rate on a net basis. It might be up to 15,000 barrels a day. It is a pretty compelling opportunity for us with really strong economics. It is a developed field, so we do not have a lot of subsea infrastructure we have to install. Thankfully, Doug was talking about how much cost pressure they are putting on us, and we will not have a significant amount of that for this project. The timeline to bring it online would be a pretty quick drill complete tied in. Is that fair to characterize this more as a development slash well versus? It is. It's a development well. It's targeting a reservoir that's been developed and is producing, but we need to have another well to have another take point in the reservoir to optimally produce. There was a well that was producing in that pre-2019, which had demonstrated rates that were in that range. There is quite low subsurface risk in terms of the outcome. I got to think, and maybe I'm getting down too much into detail, but is an EUR for that type of well, 20-30 million barrel kind of? That's a fair assessment, yes. Okay. Great. Great. You plan to drill that in the second half of 2026? We'll start drilling it sometime probably in the second quarter of 2026, but it'll take a while to drill. It's a fairly deep well, and it'll probably come online in the, I don't know if it's the third or fourth quarter, probably the fourth quarter of 2026. Yep. We've had some ebbs and flows in terms of offshore service costs. Doug, who presented how to use, has obviously been pushing margins, but it's been a little bit of slackness in the deepwater rig market. Talk to us a little bit about the strategy and maybe where you're seeing in terms of pricing and your contracting strategy. Yeah, great question. We're seeing a bit of a mixed bag in terms of offshore costs. We recently extended a rig contract for a drill ship we've been using now for a number of years out through what is our planned activity through the middle of 2027. The rig rate has some adjustments through time, but basically the day rates are about 15% lower than what we were seeing in the market last year. We're seeing a softening of drill ships through that period of time. Other significant costs, the day rate of a drill ship is about 40% of the cost of a deep water well, a big piece of our business. Other things, other services are basically stable costs. We have kind of a rolling series of contracts that our procurement team works to renew through various means that most of the services have been pretty stable. Of course, diesel is a significant part of our cost, which moves around with oil price. Two areas where we're seeing cost increases that are one modest and one more significant is the more modest increase we're seeing in tubular goods. So offshore wells, just the casing, the steel tubing, et cetera, in our program, we're seeing probably around 5% type of cost increases this year compared to last year. And then for major subsea projects, trees, umbilicals, risers, the things that we get from people like Technip, FMC, we're seeing compared to our last major greenfield project, which we brought online in 2022, we're seeing 30-50% cost increase. So it's a lot of pressure there. It's one reason why I'm really excited to have some success in a shallow water Vietnam because I don't need any subsea trees or umbilicals or risers of that kind of nature from what's really a hot market with a lot of demand across the industry and consolidation in that space. Great segue, Eric. I was going to ask you about Vietnam. The company reached FID on the Lac Da Vang development a little bit of time ago. It's about a 100 million barrel gross field. Can you provide an update on this project, which is targeting a first oil in the fourth quarter of next year? Sure. We're really happy with our execution of the project there. When you do a new greenfield project in a country that you haven't been active in before, it's always interesting to get a sense for the capability of the construction yard and the people we work with and the talent. I've been very, very happy with how it's going so far. Major milestones for the project are building the Lac Da Vang A platform and building an FSO. It's a floating storage and offloading vessel, which is basically a big storage tank with a turret. Along with that, we'll install some sort of infield pipelines. Execution of the project is going very well. We're very happy with it. We're definitely on track for first oil in the fourth quarter of 2026. Sort of key milestones to be paying attention to there. The jacket for the platform will be installed in 2025, probably in the third or maybe early fourth quarter. We will begin drilling development wells from that location. The top sides for the platform will be built in, will be installed in 2026 along with the FSO in 2026. We will bring the field online. Okay. How should we think about kind of the CapEx outlay for this project? Because it is kind of a phased development with a couple of platforms. That's right. The overall development will spend between 2024 and 2029, we'll spend net to Murphy about $380 million. $110 million is what we allocated for our budget for 2025. Next year's spending is probably on the order of $90 million. We'll have first oil after spending maybe two-thirds of the total capital program roughly. In 2028, we'll likely install a second, simpler wellhead platform where we'll drill the other half of the wells for the development. It is sort of a spread out capital program from over many periods. Production likely peaks in the 10,000-15,000 barrel a day net to Murphy in the 2027, 2028 timeframe. As we continue to add wells through 2029, we should see relatively stable production. Then start to see when we finish drilling wells, we'll start to see decline probably at the end of the decade. Okay. Let's talk about the Hai Su Vong discovery. Again, just announced just a few days after you became CEO. Obviously, you're involved with that whole process. Talk to us a little bit about what you think you've found thus far with the discovery well. Yeah. What we've announced so far about the discovery well was that it was drilled at the crest of the structure. The main pay that we discovered is a large four-way structure. We drilled close to the crest. We flow tested the well at 10,000 barrels a day, which is an extremely high rate for a well in shallow water, 150 feet of water. What we found in the well is consistent with our pre-drill range of expectations for the field, which was 170 million barrels equivalent to 430 million barrels equivalent. We do not know now because of where the well was drilled, we do not know how much of the structure is filled with oil. The discovery well encountered only oil and no water. We do not know when oil-water contact is. The structure is quite large. The appraisal well that we have planned to start drilling in the third quarter will be drilled off the crest of the structure. The main objectives are to test for the continuity of the reservoir over a large distance and also hopefully help us get a better view for how much of the structure is oil-filled. That could help us firm up our range of resources for the field. It has a potential to be pretty large. I do not like to get too ahead of ourself. I would like to see the result of the well before we say more about it. It is pretty exciting. The discovery that we already are aware of from just what we have identified in the well is a commercial development. That is a standalone scale development that we will be able to develop. We're excited, hopefully, to potentially prove up a larger resource with some appraisal success. Okay. Great. You did announce a discovery at Pink Camel last quarter, maybe not the same size as Hai Su Vong, but still a great outcome for the company. Talk to us about that discovery and plans to develop that. Yeah. That's a nice discovery for us. We expect that that field is somewhere in the 30-60 million barrels oil equivalent. I'll mention that these fields for us in our Cuu Long blocks, they're very oily. They're 90% plus oil. So we give you BOE numbers, but they are quite oily. We will likely develop the Pink Camel or Lac Da Vang field as a wellhead platform tied back to the infrastructure of the Golden Camel development that we're doing now. The Pink Camel field is three miles away from our infrastructure LDVA. So very close tie back. We needed to find something on the order of 8-10 million barrels to have a commercial development. And we found what we think is 30-60. So it should be quite successful there. One thing to note, the PSCs that we have in Vietnam, they have ring fencing at a block level. Once we establish revenue from Golden Camel or LDV field, we'll start to recover costs from all of our investment in the block, including exploration. Pretty attractive opportunity for us there. Good segue. How do you think about the attractiveness of this PSV versus elsewhere that you look at globally? The terms of the PSC in Vietnam have an overall government take over the life of a typical field that is pretty consistent with the Malaysia business that we built over many years. That might be a 65%-75% take. The oil companies get a lot of their return early, and then later on, the government gets more. It is pretty typical of PSCs. Indonesia PSCs typically have a little higher government take, so it is more competitive. If you contrast that with our business in the rest of the world, obviously the government take in the Gulf of America is like the best system fiscally in the world. In Côte d'Ivoire, where we have five blocks, the government take is not much different than the U.S., it is a little higher. Really compelling there if we have some exploration success or a development project there that the government take is set up to be something that we can do quite well financially. Let's talk a little bit about West Africa, Côte d'Ivoire. Eni is at the conference, but your acreage position is bookended by two significant discoveries by Eni, Baleine and Marine. Maybe just talk about your plans and opportunity set in Côte d'Ivoire through the drill bit. Great. We're going to start drilling a three-well program in Côte d'Ivoire in the fourth quarter. That program, the first well in the program will be Savette, which is 10 kilometers away from the Marine 1 X discovery well on the field that they call Kalau, which they announced, Eni announced in March of 2024. Geologically, the Savette prospect is very similar to the Kalau discovery. It's testing the same age reservoir, just slightly shallower interval. We're really excited about it. It looks very similar geologically to what is a very close success. The Kalau discovery goes a long way toward demonstrating a working hydrocarbon system, petroleum system. It is possible that the Kalau discovery extends onto our block. We don't know that yet, but it looks like it from assessing the seismic data. We're really excited about the prospect. The size of that Savette prospect is over 400 million barrel mean with up to a billion barrel upside. Something of significant scale for us. We still have some work to do to award the contract for the rig and also finalize the estimate of the cost of the wells. Sort of ballpark, we're talking about $50 million-$60 million gross well cost, which is pretty compelling to spend that type of money and test something of a scale that could be 400 million barrels plus with good fiscal terms. The other prospects that we have planned, likely the next prospect will be one called Caracal, which is geologically similar to the producing Baleine field that Eni discovered in 2021. We do not think Caracal is as large as Baleine, which is sort of a billion barrel recoverable scale, but it does look very similar. It's fairly close by. It has the same age reservoir and the same sort of geologic features. We think we're bookended by what are compelling analogs for what we'll drill, and we're really excited about it. The third prospect that we'll drill is likely to be more of a frontier, testing less demonstrated successful plays, some plays that work in the larger Tano Basin, including in Ghana, but a little more frontier and therefore a little higher risk. Again, large opportunities with low well cost. We're really excited about that. We'll have some pretty exciting results to talk about. If you kind of step back and look at the testing we're going to do with appraising in Vietnam and the three-well program in Côte d'Ivoire, the sum mean unrisked resource of those opportunities is five times the size of our current offshore approved reserves. With success in any of them, it has a pretty material impact to our company. Yeah. Market will definitely be well watching regarding Murphy. I'm pretty sure our share price will go down if we announce a discovery because of concerns about additional CapEx. Got it. Got it. Let's talk about maybe the technical team because what type of knowledge base do you have internally in terms of your explorationists with West Africa? The exploration team we have assembled has a diverse set of experience of quite a few basins around the world. We typically have most of our senior technical hiring is from people that work at Super Major or other types of companies and come to work for us because they like to work for small companies that still explore, and there aren't that many of them left. We have a team that's very experienced. We do supplement that with some earlier career people, but we have people on our team that have a lot of experience in the Gulf of America and West Africa. We are really well positioned for executing a nice program there. Maybe final question on West Africa is Anadarko's legacy Pond discovery. I believe it's your intention to submit a field development plan to the government by year-end, subject to kind of a gas sales agreement. Where do we stand with that process? Yeah. The Pond field is very well appraised by Anadarko before they relinquished the block. It is a relatively small field. It's an oil field with a thin oil column and a large gas cap. Negotiating the terms of a gas sales agreement is one of the critical things in determining whether or not that's an economically viable project. We have a work obligation for the PSC to submit a plan of development for the field by the end of this year, which we're well on track to do. We're in parallel with that, negotiating with various Ivorian government parties around a gas sales agreement. We may or may not come to terms with them that'll lead to a commercial project. It's kind of a coin toss at this point, whether it's something that happens or it doesn't happen. In the country, Côte d'Ivoire is importing diesel and using it to generate electricity. The legacy supply of natural gas that they're using to generate power at their thermal power plants, the legacy supply is in screaming decline. The additional gas volumes coming from Baleine, the way we understand it, are not enough to meet the demand. The country really has aspirations and needs some more natural gas, but they have to be willing to pay what it takes to make a fairly marginal project happen. We're trying, but we don't know if it'll happen or not. It's sort of a 50-50 at this point. All right. Sorry to ask you this question, Eric, but we're the last conference before 2Q earning season is here, five days away. How are you feeling about 2Q? How the rest of the year is kind of setting up for you? I'm very happy with our operations as we progress through the second quarter. We will, as typical in our early August earnings call, give a full update on our 2Q performance and also kind of an updated view of what the full year looks like. I'm pretty happy with how we're executing both offshore and onshore. Great. Why don't we cut it off there? Thanks, Eric. Thanks so much. Appreciate it.