Good day, everyone, and welcome to the EOG first quarter 2024 earnings conference call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call over to the Investor Relations Vice President of EOG Resources, Mr. Pearce Hammond. Please go ahead, sir. Good morning, and thank you for joining us for the EOG Resources first quarter 2024 earnings conference call. An updated investor presentation has been posted to the investor relations section of our website, and we will reference certain slides during today's discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG's SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP measures, definitions, and reconciliation schedules for these non-GAAP measures and related discussion can be found on the investor relations section of EOG's website. In addition, some of the reserve estimates on this conference call may include estimated potential reserves, as well as estimated resource potential, not necessarily calculated in accordance with the SEC's reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO, Billy Helms, President, Jeff Leitzell, Chief Operating Officer, Ann Janssen, Chief Financial Officer, Keith Trasko, Senior Vice President, Exploration and Production, and Lance Terveen, Senior Vice President, Marketing. Here's Ezra. Thanks, Pearce. Good morning, everyone, and thank you for joining us. EOG is off to a great start in 2024, both delivering value directly to our shareholders and investing in future value creation. Primary drivers of that value are EOG's commitment to capital discipline, operational excellence, and leading sustainability efforts, all underpinned by our unique culture. Strong first quarter execution from every operating team across our multi-basin portfolio has positioned the company to deliver exceptional returns. Production and total per unit cash operating costs beat targets, driving strong financial performance during the quarter. We earned $1.6 billion of adjusted net income and generated $1.2 billion of free cash flow. We paid out more than 100% of that free cash flow through our peer-leading regular dividend and $750 million of share repurchases. EOG's operational execution continues to translate into strong returns and cash flow generation. Our robust cash return to shareholders continues to demonstrate our confidence in the outlook and value of our business. Quarter after quarter, we have delivered outstanding operational performance in our core assets, while also driving forward progress in our emerging plays. We've built one of the deepest, highest return, and most diverse multi-basin portfolios of inventory in the industry. The most recent addition to our portfolio is the Utica Combo play, a textbook example of our differentiated approach. Capturing highly productive rock through our organic exploration and leasing efforts is the primary way of expanding our premium inventory with a low cost of entry to drive healthy full-cycle returns. Adding reserves at lower finance development costs drive down DD&A and lowers the overall cost basis of the company. The result is continuous improvement to EOG's company-wide capital efficiency. Our track record of successful exploration, strong operational execution, and applied technology has positioned the company to create shareholder value through industry cycles. The oil macro environment remains dynamic but is overall constructive, and we anticipate that certain drivers will limit oil prices to a relatively narrow band this year. In the first quarter, global demand performed as expected and is on trend to increase throughout the year, led by a strong U.S. economy. While U.S. production surprised to the upside in 2023, several developments have altered the U.S. supply outlook this year. Rig counts have remained flat over the past 8-9 months, and oil drilled but uncompleted, or DUC, inventory has been drawn down. Current activity levels, combined with M&A in the public and private sectors, should lead to more moderated U.S. growth this year. Globally, spare capacity has kept inventory levels around the five-year average to start the year, and we forecast these barrels returning to the market throughout the second half of the year and aligned with growing demand. Overall, the result is a strong operating environment for a low cost and returns-focused producer such as EOG. And while we expect the natural gas market to remain soft through the end of this quarter, much like last year, we expect it to strengthen through the second half of the year and are managing our Dorado program to align with demand. Longer term, we expect an additional 10-12 Bcf a day of demand for LNG feed gas and another 10-12 Bcf per day of demand from several areas, including overall electrification, exports to Mexico, coal power plant retirements, and other industrial demand growth. The outlook for North American natural gas by the end of this decade is bullish, both for the industry and in particular for our Dorado dry gas play, which has advantaged access to the Gulf Coast and pipeline infrastructure. We look forward to participating in the emerging LNG demand through our diverse sales agreements to grow from 140,000 MMBtu per day today to... ... to 900,000 MMBtu per day over the next three years. Through EOG's differentiated approach to organic exploration, the utilization of technology to improve operational efficiencies, vertical integration of certain parts of the supply chain, and our diverse marketing strategy, EOG remains focused on being among the highest return, lowest cost, and lowest emissions producers, offering sustainable value creation through the cycles. Ann is up next to provide an update on our forecast and 3-year scenario. Here's Ann. Thanks, Ezra. Given the recent strength in commodity prices, we have updated our 2024 forecast to reflect $80 oil and $2.50 natural gas for the remainder of the year, and now expect to generate $5.6 billion of free cash flow for the full year. Considering both share repurchases executed during the first quarter and our annualized regular dividend, we have already committed to return about $2.9 billion this year, which represents more than 50% of that free cash flow. So we are well on our way to return a minimum of 70%. And while cash return exceeded free cash flow during the first quarter, we continue to view our return commitment on an annual basis. During the first quarter, we repurchased 6.4 million shares for $750 million, averaging about $118 per share. Since we began using our buyback authorization at the start of last year, we have bought back more than 15 million shares, or nearly 3% of shares outstanding, for an average price of about $115 per share. To date, that totals about $1.7 billion worth of shares. We will continue to monitor the market for opportunities to step in and repurchase shares throughout the year. Last quarter, we provided a three-year scenario to illustrate EOG's expanded capacity to generate free cash flow and earn a strong double-digit return on capital employed to create future shareholder value. This quarter, we provided an additional price scenario to illustrate our expanded free cash flow potential over the next three years by assuming similar commodity prices as the past three years. From 2021 through 2023, oil averaged $80 and natural gas averaged $4.25. Over that three-year time frame, we generated $18 billion of free cash flow. Applying those same commodity prices to our forecast for the next three years, we would expect to generate $21 billion of free cash flow. That's 17% more cumulative free cash flow than the prior three years at the same price deck. Robust cash return to shareholders, supported by substantial free cash flow, stems from EOG's strong operational execution. By focusing on well performance, sustainable cost reductions, and maximizing full cycle returns through organic exploration and disciplined growth, EOG has driven a step change in our financial performance and capacity to create significant value for our shareholders. Now, here's Jeff to review operating results. Thanks, Ann. I'd like to first thank all the employees for a great start to the year with safe and efficient operational execution. Our first quarter volumes in total per unit cash operating costs beat targets while capital was in line. For the year, our capital forecast remains $6.2 billion and delivers 3% oil volume growth and 6% total production growth. We continue to expect that capital this year will be slightly more weighted in the first half, driven by the timing of our investments in the two infrastructure projects that we provided details on last quarter. These projects include the Janus Gas Processing Plant in the Delaware Basin and the Verde Pipeline that will serve our South Dorado, South Texas Dorado play, both highlighted on slide 10 of our investor presentation. By the end of the second quarter, we expect to be on pace to have spent about 56% of our $6.2 billion capital plan. While our oil production and capital plan for the full year remains unchanged, we are actively managing activity in our Dorado asset, which is reflected in our second quarter natural gas production guidance published yesterday. As discussed last quarter, we moderated activity in Dorado this year in response to a weaker natural gas market and are now leveraging additional flexibility to delay well completions and manage volumes through the summer. However, we will continue to pursue a balanced development approach with this asset, which includes operating a full rig program throughout the year. This will help maintain operational momentum, capture corresponding efficiencies, and continue to advance and improve the play while we continue to monitor the natural gas market. We remain constructive on the long-term gas outlook for the U.S., supported by LNG, power generation demand, and the growing petrochemical complex on the Gulf Coast. We are especially pleased with Dorado's place in the market as one of the lowest cost suppliers of natural gas in the U.S., with an advantaged location and emissions profile. With regards to service cost market, bids for standard spot services have been trending lower, which is consistent with our expectations of seeing some deflation this year. For high-spec rigs and frac fleets, we are still observing stable pricing. However, their availability is improving, especially in markets with less activity. As a reminder, we have secured 50%-60% of our service costs in 2024, primarily with our high-spec, high-demand services to ensure consistent performance throughout our program. By securing these resources, we're able to focus on sustainable efficiency improvements to progress each one of our plays at a measured pace. EOG's operating performance and capital efficiency continues to improve as our cross-functional teams work to drive efficiency gains throughout our multi-basin portfolio. A significant driver of efficiencies this year is longer laterals, which we expect will increase by 10% on average company-wide. The charge is being led in our foundational plays, the Delaware Basin and the Eagle Ford. Our operating teams in both plays have achieved consistent execution and success, drilling and completing longer laterals, leading to increased efficiencies, lower per-foot well costs, and improved well economics. In the Delaware Basin, we drilled four three-mile laterals in 2023, and have plans to drill more than 50 in 2024. In the Eagle Ford, our 2024 plan includes increasing the average lateral length by about 20% to continue to unlock new potential across our 535,000 net acre footprint. Moving to the Powder River Basin, our technical teams continue to make good strides with our balanced development approach between the Mowry and the Niobrara formations. In the Niobrara, we have recently transitioned into package development by applying the learnings we captured while drilling the deeper Mowry formation first. In our first three Niobrara development packages this year, we've been able to increase our drilling footage per day by 25% compared to 2023 averages, while maintaining over 95% in-zone targeting. This can be attributed to our refined geologic models and a better understanding of the stratigraphic variation across the play. With these continued efficiency gains across our diverse portfolio plays, along with stable service costs, our expectations for full-year well cost decrease is a low single-digit percentage. After a strong first quarter, EOG is well positioned to execute on its full-year plan. Our technical teams continue to drive innovation with a focus on improved recovery, lowering costs, and being a leader in sustainability. Now, here's Keith to provide more color on the Utica. Thanks, Jeff. We're very happy with the results of our first three packages of development wells in the Utica Combo play. We now have over six months of production data from the first two, the Timberwolf and Xavier, which continue to outperform our expectations. Daily production rates per well have averaged more than 1,000 bbl of oil, 600 bbl of NGLs, and 4 million cu f t of gas over the first six months. On average, these seven wells have produced more than 200,000 bbl of oil per well since being brought online in the second half of 2023. We recently brought on our third package, the White Rhino. This is our first development package in the southern portion of our acreage. The four White Rhino wells, drilled at 1,000-foot spacing, have been meeting our expectations during their first few weeks of production. Initial production also indicates a slightly higher liquids mix than our Timberwolf and Xavier wells, drilled in the north and central parts of the play. While our northern and central acreage benefits from a thicker Utica, the southern area has better geomechanical properties. The southern area also benefits from significant economic uplifts associated with the mineral rights we secured across 135,000 net acres. The White Rhino wells add to our growing collection of data points, which includes 18 legacy wells, four delineation wells, and now three development packages, which adds another 11 wells. While we expect to see performance vary across our 435,000 net acre position, well results over the past two years in multiple areas confirm high liquids premium productivity through the 140-mile north-south trend of the Utica's volatile oil window. On a per-foot basis, the cumulative production in the Utica Combo play compares favorably with some of the best areas of the Permian Basin with respect to both oil and total equivalents. Our large, contiguous acreage position in the Utica lends itself to developing a long-life, repeatable, low-cost play, competitive with the premier unconventional plays across North America. Our operating team continues to leverage consistent activity to increase efficiencies and drive down well costs. We recently drilled a 3.7-mile lateral on our Sable pad in the south, which is an EOG-wide record lateral length. This well is scheduled to come online later this year, and we're excited to continue driving similar efficiencies as we increase our activity across this asset. For 2024, we are on target to drill and complete 20 net wells in the Utica across our northern, central, and southern acreage, which supports a full rig program and enables significant well cost reductions. Now, here's Ezra to wrap up. Thanks, Keith. I would like to note the following important takeaways. First, our differentiated business model, focused on exploration and innovation, has built one of the deepest, highest return, and most diverse multi-basin portfolios of inventory in the industry. The Utica, our most recent exploration success, will be competitive with the premier unconventional plays across North America. Second, consistent execution in our core Delaware Basin and Eagle Ford assets delivers outstanding operational performance quarter after quarter, while investment in our emerging plays contributes to EOG's financial performance today and lays the groundwork for years of future high-return investment. Third, our robust cash return to shareholders continues to demonstrate our confidence in the outlook and value of our business. Finally, one of EOG's best champions of utilizing innovation to constantly improve the company is our friend and colleague, Billy Helms. Billy recently announced that he will retire at the end of this month. ... In Billy's 40-year career with EOG, he demonstrated a distinctive ability to encourage new ideas from our employees across multiple disciplines, innovative ideas that utilize in-field technology, information technology, and new processes to drill better wells for lower cost, more safely, and with lower emissions. He then helped shepherd the very best of those ideas through to execution across the company. Even though well-earned, the retirement of a friend and colleague is bittersweet. Best wishes to you, Billy. Thank you for your service to EOG. Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key, followed by the digit one on your touchtone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the pound two key. We will pause for just a moment to give everyone an opportunity to signal for questions. And our first question today comes from Steve Richardson with Evercore ISI. Hi, good morning. Thanks. Ezra, I was wondering if you could talk a little bit about the gas outlook, particularly as it regards Dorado. Appreciate that you're moderating activity in the near term, but maybe you could talk a little bit about, you know, if the forward curves, it sounds like you all are pretty bullish on demand, and the forward curve certainly reflects that, you know, $3.54 out on the curve. Maybe talk about what could happen in the play in terms of where that one rig program goes, and maybe also remind us as Verde gets into phase two, do you all need to drill to fill? Or how do I think about the flexibility up/down of that play, once the infrastructure is complete? Yeah, Steve, that's a great question. This is Ezra. You know, so you're right. Gas, you know, obviously, it's stating the obvious, but inventory levels are very high after two consecutive warm winters. But, you know, I will highlight in the last two years, we've also seen strong demand on the power side during the last two summers, and we expect that to obviously continue into this summer. So strong summer demand, coupled with reduced supply, not only from some operators curtailing, but just from the reduction in rig activity. You know, we see the potential that inventory levels could come off quite a bit in the second half of the year. Now, that said, overall, we're maintaining flexibility with investment into those gas plays, and dominantly, what we're talking about is Dorado. You know, I would say, Steve, we really would prefer to keep some rig activity running and really continue to capture the operational efficiencies. It's always difficult when you actually completely shutter a program. Unfortunately, you know, in some of our plays, that happened obviously during COVID in 2020. So we'd prefer to continue to capture our learnings and continue having a rig operate in the area. But we do have a lot of flexibility on the completion side. And so you could look to us to potentially build some DUCs, more so DUCs than necessarily hold back on turn-in lines, although, you know, we've done that before as well, but we prefer to be flexible on our completion schedule side. As far as, you know, commitments to filling the infrastructure, no, Steve, we don't have any of that. For us, you know, what's gonna really determine the pace of our investment there and when we bring the gas online, it's really a returns-based question. That's one reason that we did, in fact, put the infrastructure in ourselves, is it's really in line with our longer-term marketing strategy, which, of course, is, you know, duration, flexibility, diversity of markets, and most importantly, in a situation like this, control. And so we don't have any obligations necessarily to deal with. Great, thanks. And so, Ezra, would you hazard a guess—I appreciate that you've got this downside flexibility in a low price environment, but in a $3.50 or $4 price environment, could we see activity go to 2-3 rigs, or don't wanna get ahead of ourselves, but, and appreciate that there's probably efficiencies you wanna retain on the upside as well? Yeah, Steve, that—yeah, the last part you touched on is exactly the right way to think about it. It's the way that we think about it. We don't wanna outrun our pace of learning. Now, we are very constructive on the longer-term gas forecast for demand in North America. And we've talked about it before. We think Dorado is advantaged not only with the cost of supply, but really with the geography where it's located, so we can service all the upcoming demand along the Gulf Coast. But the thing about a gas play is, we're very committed to making sure that this is a low-cost asset. That's the most important thing, because while we're constructive, you know, on the mid-cycle gas price increasing throughout the rest of this decade, it's easy to see that gas historically has been very volatile, because no matter what, you need to layer in weather on top of whatever gas supply demand model you've created. And so the most important thing for us is, even in the early days of investing in this play, is making sure that we're investing at a pace to optimize the returns and optimize the cost of supply and keep our cost basis low, so that we can continue to have a positive cash flow through some of those skinny times. So I'd say we could look to increase the activity. I think we've talked in the past of being prepared to increase it with the upcoming LNG and just overall demand. But as far as assigning a hard level to it, Steve, you know, we'll have the infrastructure in place. We have not only the takeaway infrastructure, but in basin, you know, things like sand and water lines and things of that nature. So we could ramp it up, but you should look at us to ramp it up commensurate with our learning, which would be at a more measured pace. Thank you. Our next question comes from Arun Jayaram with JP Morgan Securities. Yeah, good morning. Ezra, you returned, you know, over 100% of your free cash flow this quarter, you know, above your 70% target for the year. I was wondering, you know, what the signals to the market, you know, historically, you haven't returned this level of cash flow. So outside of the fact that you thought your stock call below $120 was dislocated, any other implications, you think, to the market from this from the buyback activity in the quarter? Yes, Arun. This is Ezra, and I'd say, you know, last year we did return to the market through buybacks and specials and our regular dividend, about 86% of the cash flow. So, you know, having higher quarters is not out of line. The big difference, as you highlighted, is that it was all biased towards buybacks rather than specials. And that's really been the trend over the last few quarters, and I think that trend will probably continue. The reason I say that is, you know, our business has really strengthened substantially over the past few years, as we've highlighted before, not only in our core assets, like the Permian and Eagle Ford, but especially in these emerging plays, the Utica, the Dorado, we're just talking about, and even the Powder River Basin. Really, it's the entire energy sector. EOG, certainly, we think, remains undervalued relative to the broad market, and those are really the big things that provide us confidence to continue buying back our shares. In general, I'd say our cash flow allocation priorities remain unchanged. It is focused on the regular dividend, but we will continue to be opportunistic on share buybacks, and, you know, we'll use market volatility to our advantage. We've really been doing that now as we've been in the market repurchasing shares for the past five quarters. You know, I'd say we'll continue to evaluate the opportunities as they present themselves on how best to return cash to the shareholders. But the feedback that we've received is, the shareholders appreciate our approach, and as I said, you know, we've been biased to buybacks for the last couple of quarters, and for the time being, you can certainly see that probably proceeding going forward. Great. My follow-up, Ezra, based on the 2Q guide, you're spending around 56% of your full-year CapEx in the first half. I was wondering how the timing of some of the strategic infrastructure spend you highlighted last quarter, how that's influencing the first half CapEx, and just thoughts on confidence in hitting the $6.2 billion full-year CapEx guide for 2024. Yeah, Arun, this is Jeff. Thanks for the question. What I'd first say is, you know, our 2024 plan, it's playing out just as we had expected. So everything's in line as far as timing, and we still feel really confident with the total CapEx budget of $6.2 billion. You hit it on the head, and we talked about in our opening statements. You know, CapEx will slightly be higher there in that first half at that 56% of total budget, but that's really just due to some standard indirects and really those strategic infrastructure spends that we have talked about with the Delaware gas plant and the Verde pipeline there. The nice thing about it is both projects are scheduled to come online. The gas plant we've got planned for the first half of 2025, and the second phase of Verde Pipeline is gonna come on, hopefully, the back end of this year. We're really excited about it, to be able to get to realize that $0.50+ per Mcf GP&T savings that both those projects are gonna bring for the life of the asset. Thank you. Our next question comes from Neil Mehta with Goldman Sachs. Good morning, team, and thanks for the update here. Just love your perspective on the Eagle Ford and Bakken. As those fields enter into more maturity, some of your peers have talked on this earnings season about different things that they're doing to extend the life and deepen the inventory, and just would love your perspective on some of the things you're doing on the ground to drive as much value as we get into the next phase of these assets. Yeah, Neil, this is Jeff again. You know, with the Eagle Ford, you know, we've got a really good consistent program this year. We're gonna be completing about 150 net wells there. You know, as far as looking at the well performance, you know, everything's been in line and right with our expectations. You know, with any mature asset, you know, you're gonna see some productivity degradation. I mean, you know, we started out in the east, where we had a little bit more prolific, you know, geology, and then, you know, more recently, we've moved out to the west, where it's slightly lower quality pay. But the key takeaway is, you know, we've been able to continue to improve the economics in that play year-over-year. And we've really done that just through, as you talked about, increasing operational efficiencies, you know, focusing on, you know, drilling faster, completing faster with Super Zippers, longer laterals, and cost reductions, you know, that have continued to improve the capital efficiency of the play. And what I'd say is also one of the big movements that we've had is we're actually increasing the lateral length there in the Eagle Ford, about 20% this year. So, and you can see the activity might be down just a hair year-over-year, but we've completed the same amount of lateral length as we did in 2023 with those longer laterals. So that's just one of the ways we're really able to drive efficiency there, and, you know, you can see it in the returns. I mean, really, it's got some of the highest rate of returns over the last three years, and, and we've been drilling in the Eagle Ford for 15 years. ...Then, you know, looking over to the Bakken, you know, we are very mature in that resource. Right now, we kind of run a program of about 10 net wells there. Primarily, they're just Three Forks targets and Bakken targets. And really, we're just going in and offsetting and filling around some of our existing development. We're staying ahead of depletion, and then also we've had some areas with limited markets, but we've got some new available capacity, so we're able to bring some additional wells online there. So, obviously, with a really oily play, the well productivity looks great on there, and we're excited about those wells this year. Thanks. Thanks, team. And then, Billy, I just want to extend my congratulations to you on your retirement, and thanks for the insight over the years. My follow-up is just on the macro, on the oil macro, specifically. We've got an OPEC meeting coming up here in the next couple of weeks, and a lot of uncertainty on both the demand and supply side. So just how is this year from a commodity perspective, oil commodity perspective, trended relative to your expectations? And I know you have a big in-house operation looking at the macro. What's the crystal ball telling you, Ezra? Yes, Neil, well, I'd start with the fact that, you know, Q1, I think has really played out as most people expected. You know, there was a bit of a pullback in demand there, and that's one thing that had prompted, I think it prompted some of the spare capacity being brought offline. But ultimately, you know, that demand was about 102 million bbl a day. It looks to us and others out there, other models, it looks like demand should strengthen throughout the year. So we have not only seasonal demand picking up here, but also we're seeing underlying strength in the U.S. economy, also in the China, Chinese economy, just a little bit, namely on the manufacturing side. So ultimately, we see demand reaching a bit above 104 million a day in the back half of the year. And so that's on the demand side. You know, when you think about inventory levels, obviously, first quarters, with spare capacity offline, inventory levels have stayed just below that five-year average, but products really are a bit lower. And so that, you know, shapes up for a good, some good inventory draws potentially in the back half of the year. And then really on the supply side, as I spoke about in the opening comments, you know, we think U.S. supply should be pretty moderate. We're in agreement with other estimates of kind of that 300,000-400,000 bbl per day growth, year-over-year. And that's where we arrive at a model that would indicate we see much of the spare capacity reentering the market throughout the rest of this year. But we'll see how that really plays out, as you said, at the next upcoming OPEC meeting. Thank you. Our next question comes from Neal Dingman with Truist Securities. Morning, I want to start by congrats to Billy. Billy, thanks for all the help in the past. As my first question today is on your Utica play, specifically, looking at the map on slide 12, it appears you all continue to target more so the eastern side of the volatile window. I'm just wondering, could you talk about your thoughts, maybe on the prospectivity of the black oil window? And, you know, if there's just anything that you might see this year that might cause you to change activity in the play for the remainder of the year. Yeah, this is Keith. You're right. We have been delineating mainly north, south through the volatile oil trend. You know, it's a 140-mi area. The first thing we need to do, kind of on the west, is we need to acquire seismic data. We're in the process of doing that. We need to see the degree of structural complexity, kind of before we start developing. But geologically, you know, in general, we don't see significant changes in thickness or pay from east to west. On the west, you're going to have a little bit lower maturity, which would equate to less pressure. But in our other plays, you know, such as the Eagle Ford, less pressure reduces the well productivity, maybe a little bit, but it also reduces costs. So your economics are still really comparable to all the other portions of the play. And then, overall, you know, just on activity level, you asked, you know, we have ramped up to one full rig this year. We want to be able to grow at a pace where we can leverage our learnings, continue to get better, and also drive costs down. We need to keep getting infrastructure in place in the basin, like in-basin sand and water reuse. So we are sticking to our 2024 plan, laid out last quarter of 20 net wells, and it's a little too early to disclose anything for 2025. But overall, this play really competes with our, our best plays, for capital. The other great thing is with the multi-basin portfolio, we don't necessarily need to ramp it up, aggressively. We're just going to let returns, drive that. Very, very good details, Keith. And then, just a second quickly on... Look at the supplement slide 12. I like that slide you talked about, just your marketing opportunities. Specifically, I'm looking at, sort of around the oil side, the U.S. oil. Is there opportunities to, you know, increase around the export side if opportunities present, or maybe just talk about the, optionality or flexibility you might have around those markets? Yeah, Neil, good morning. This is Lance. Yeah, I think what we like best is just we are advantaged when you think about just from the supply that we have out of the Delaware Basin, the capacity, the firm capacity that we have that can come into the Gulf Coast. And then the facility that we're at down in Ingleside, it's just an outstanding facility. They recently just increased the dredging that's there, so we're actually been loading VLCCs there. So the capability that we have there and our tank position, we've actually been pushing more across the dock into the export markets in the most recent quarter. Thank you. Our next question comes from Scott Hanold with RBC Capital Markets. Yeah, thanks. You know, a little bit more on the Utica. I appreciate the fact that, you know, you guys do not want to outrun your learning curve, but, you know, given that, you know, you're demonstrating some pretty good competitive economics, you know, with places like the Permian, just big picture, like, what needs to happen, or what do you need to see for this to become a more meaningful part of your capital allocation and, you know, production going forward? Hey, Scott, this is Ezra. Yeah, I think we're very happy with where we're at. You know, it's a 400,000-acre position. As Keith highlighted, it's 140 mi north to south. And, you know, let's be honest, we've got two packages on right now. Now, the two packages are fantastic. They're exceeding what we initially had in our type curves, and they're, you know, more than confirming some of our early thoughts on the spacing test. So at this point, everything's going in the right direction. As Keith highlighted, to, you know, help delineate some of the other acreage that we have, the first step is to... Well, really, the first step was, you know, having some of the well log identification. So really, maybe the second step now is to go ahead and get that seismic and see what the level of complexity is. As Keith talked about in his opening comments, we have just brought on a package down in the south, which will prove up. You know, it's a bit of a different geologic environment down there. It's also an area where we own the minerals, which is very exciting. You guys know the economic uplift that that can have. So overall, I would say that, you know, everything's right on pace. We'd like to continue to get some in-basin, you know, just infrastructure and be able to start to leverage the size and scale that we have. Maybe one way to think about it, Scott, is in all these early, you know, resource plays. Think about where the Utica is, and, you know, maybe it's around where the Permian was in kinda 2012, 2013 timeframe. And so that's why, you know, when we all talk about not outrunning our ability to learn, you know, the costs that you're putting in the ground today, we think about it as full cycle economics, and they're gonna stay with you on the life of this asset. We're not at a point where we're in need of increasing the activity here. We've got a very deep, high return inventory across multiple basins, and that's really the big difference. I think our business model has changed as the company's matured, and we've built out that inventory where we don't need to lean in aggressively on any single one asset anymore. We've got the ability with this multi-basin portfolio, that we can invest in each of these at a pace that really allows them to improve year-over-year. Now, we definitely want to bring some of these capital efficiency learnings from the Eagle Ford, the Bakken, the Permian into the Utica, but we wanna do it at a place where we're not, you know, we don't have the misses on spacing or higher well costs or things that have, you know, plagued some of the early learnings in these other resource plays. So I wouldn't say we're looking for any, you know, major sign or any silver bullet that we're gonna turn on a 15-rig program or anything like that, Scott. It's really the, where our company is at, where we're at in the cycle, and it ultimately comes down to a returns-based decision, not at the asset level, but really at the company level, as to how to capitally allocate across the portfolio to maximize shareholder value. I appreciate all that context. Before I ask my next question, you know, I wanna extend my congrats to Billy as well. Obviously, we all appreciated your insights and expertise over the years. So my follow-up question is, could you all refresh us on Trinidad a little bit? I mean, you obviously have some growth coming there that was planned, but, you know, remind us the economics and how pricing is set in that region relative to, say, like, what we're seeing with Henry Hub pricing. Hey, Scott, this is Jeff. Yeah, just on the activity in Trinidad, you know, we're currently just running our one-rig program there, you know, and everything's going really smooth. Earlier this year, we completed two of our remaining wells there in the Modified U(a) block successfully and brought those online. You know, we're currently drilling and completing a couple exploratory wells in SECC block. Then after that, we'll move the rig, and we've got a couple recompletes to do in our Sercan area, and then one more exploration well to finish up the year in TSP area. Another note that I'll point to you, too, is we're also installing our Mento platform. Everything's been on time and looking good there, getting the facilities in place, and that's in our SMR block. What that will do is that will, you know, really set us up for the program next year, so... As far as the marketing side, I'll hand it over to Lance to give a little color. Yeah, Scott, we've always been real pleased there in Trinidad, especially when we think about our price realizations and obviously meeting that local demand, you know, into the country. So I think you can see, even with the price realizations that we had in the first quarter, they were very attractive. So we continue to see that kind of on a go-forward basis. Thank you. Our next question comes from Leo Mariani with Roth MKM. Yeah. Hi, I wanted to just follow up a little bit more on the exploration side. Obviously, you guys seem happy where you are in the Utica, but just wanted to kinda ask in terms of activity levels, is there other kind of ongoing exploration still this year in some of these U.S. oil stealth plays? And perhaps you can just talk about, you know, kinda levels or wells. I know you're not gonna reveal necessarily any of the specific areas. And then just on a related point, obviously, you guys have talked about this exploration being able to kinda drive down the DD&A rates, you know, for the company. Happened to notice that your DD&A rate did go up a fair bit here in the first quarter versus where it was in fourth quarter. Maybe you could just kind of, you know, wrap it all together and give us some color on that. ... Yeah, Leo, this is Ezra. I'll start with the exploration, and then hand the DD&A details over to Ann for an answer. On the exploration side, yeah, we do have some exploration dollars in the budget this year, as we highlighted on the first quarter call. We continue to explore for. Yeah, we continue to focus on oil plays, but at the core of it, what we continue to explore for are things that are gonna be additive to the quality of the corporate portfolio. And that's what you're seeing with the Utica, obviously, so that's a major success for us. We're not exploring for things that are simply just gonna add inventory. We really want them to be additive on a returns basis, additive on a, on a cost of reserves or a finding and development cost basis, and that's how it contributes into lowering the DD&A rate. This year, we are drilling a couple of what I would call, you know, initial wells or, you know, I hate to call them wildcat wells because these aren't, you know, frontier types of activities. These are in basins where there's data and there's been historic production and things like that. But let's call them the initial wells to test some exploration ideas. And then we've still got another, stealth play or two, that are, a bit more in, say, a, a delineation phase, where we've drilled the initial well. We've seen, we've been encouraged with the initial well results, and we're continuing to test and see if it's, you know, gonna clear those hurdle rates that I talked about. The big thing I'd say is, you know, these days, our exploration plays and these initial wells, and I think I've highlighted this before, you know, in the U.S., the way we operate through exploration, there's so much data that, you know, we're not really drilling these initial wells and, you know, to see if they'll actually produce oil and natural gas. It's not like we're testing, you know, whether or not the rock is productive and could we end up with a dry hole. These days, it's really about when we get the oil and gas to surface, is it what we expected? Is it gonna be economic in such a way that it really competes with the existing portfolio? Are we exploring? Have we found something that really commands investment and taking rigs off of another play? I'll hand it over to Ann. The DD&A you saw increase in the first quarter was just due to a one-time prior period adjustment, due to some natural gas production being used in our gathering systems. We did come in at guidance level, and you can expect that DD&A to moderate over the remaining three quarters for the year, expecting about $10.50 for the remainder of the year. Okay, appreciate that color. And then just wanted to follow up real quick. Obviously, you guys are pretty optimistic on natural gas, kind of laid out some pretty big demand increases over the balance of the decade. You spoke a little bit about, you know, 2024, second half, continuing to look better. Maybe if I just wanted to focus a little bit more, you know, near term, as you look at, you know, 2025 strips kind of just north of $3.50 or so, are you just, you know, increasingly bullish on 2025? You think that strip price is pretty reasonable, or do you think things can potentially, you know, be better than that? I think, you know, everyone's kind of on board that demand will be a lot better later this decade, but just want to maybe focus a little bit more on kind of the next year or so. Yeah, Leo, this is Ezra. I don't know if I'd call it bullish on 2025, but I would say that we're constructive. You know, as I said, we've seen a surprising upside on the amount of natural gas demand for power generation over the last couple of summers, and we continue to think that's gonna be true this summer. That a big part of that is coupled with coal retirements. We also think the pull on natural gas this summer, because pricing is soft, will also continue to be great as well. You combine that with the reduction in rig activities over the past eight months or so and the fact that operators now are also starting to curtail volumes. We think that's gonna bring down the supply side to a point where you could actually make some pretty good progress on those inventory levels in the back half of this year. That, with a little bit of feed gas starting to be taken on the LNG, that's, you know, it gives us a little bit of confidence headed into 25. But, you are right, there is quite a bit of an overhang right now that we need to see come off starting with this summer. Thank you. The next question from Paul Cheng, with Scotiabank. Thank you. Good morning. Ezra said, yes, I have to apologize. I want to go back into Utica. If I'm looking at from a well cost, or that, well productivity, what kind of improvement you need in order for you to move from the appraisal mode into the or the elimination mode into the manufacturing or production development mode? And also that, based on what you can see from your inventory backlog, what is, once that you feel comfortable about the delineation, what is the development program look like? Whether it's in the number of rig and crew or number of wells that you expect going to come from that, on a per year basis? That's the first question. Yeah, Paul, this is Keith. So I'll start on the well costs. You know, it's still early on in the play. The team continues to drive down the costs. We see a lot of room for further efficiencies. The consistent activity this year with one full rig has helped that a lot. We like that generally in the area. It's an easier operating environment compared to a lot of our other plays. That's consistent geology. It's a little bit shallower depths. Example of that is our 3.7-mi lateral we just drilled on the Sable. ...We also brought in a e-frac crew for higher pump rates and increased efficiencies. And overall, we see development costs, you know, someday getting to be a little bit lower than the Permian, even on a dollar per foot. But the great thing is that this play just has the opportunity to benefit from the learnings of all of our other plays and EOG best practices. On the well performance side, we're really happy with the wells as I and Ezra, you know, kinda already touched on. We see that these compete with the best players in America, very comparable to the Permian on a production per foot basis, both in oil and equivalents, really highlighting our differentiated organic exploration strategy. The development program, as far as rigs and crews and number of wells, you know, it goes back to growing at that pace where we can still learn and just the more two-basin portfolio. You know, we don't necessarily have to ramp this up aggressively, so. Mm-hmm. I see. Yeah, before I ask my second question, I also want to add my congratulations and best wishes to Billy. Thank you for the help over the past several years. The second question, I think, is for Ann. You this year that you have about $400 million on strategic infrastructure spending. I assume that it's not every year you would have that, but throughout the cycle, you're always going to have some strategic infrastructure spending, I suppose. So what will be a reasonable average for the cycle assumption for the strategic infrastructure spending, and also that add to overall spending level for the infrastructure overall, D&C for you guys? Yes, Paul, this is Ezra. Yeah, the $400 million in infrastructure, the strategic infrastructure that we've highlighted before, which, you know, we couldn't be more excited about because of some of the long-term margin expansion benefits that Jeff highlighted at the, in the opening remarks. You know, these are projects that. You know, historically, we look for opportunities like this, but they're very rare to present themselves, where we can take on infrastructure projects that generate such a compelling rate of return. You know, we've talked about the Verde Pipeline is expected to generate about a 20% rate of return uplift. And then on top of that, we get that GP & T Savings and Net back Uplift of $0.50-$0.60 per Mcf over the life of the asset. Similarly, on Janus, the gas processing plant in the Permian Basin, that one also has roughly an anticipated 20% rate of return. And then on that one, we have a GMP-- GP & T Savings and Net back Uplift of about $0.50/Mcf. If we could continue to find some of these projects with that strong of a return profile and that much value creation for the shareholders over the life of the assets, we would be interested in continuing to do them. But to be perfectly honest with you, typically, those margins get squeezed down to a point where we don't wanna do them. It's really more beneficial for a third party to come in and do them. But there are times in the cycle where, and it seems to happen every, you know, five, eight, 10 years or so, where there ends up being enough margin there, where we see the opportunity to go ahead and capture that value for our shareholders. Thank you. Our next question comes from Derrick Whitfield with Stifel. Good morning, all. I'd like to extend my congrats to Billy as well. Leaning in on the Utica, it sounds like the southern part of the trend could be advantaged on returns based on the elevated NRIs and potentially geology. Could you perhaps expand on the difference you're seeing in the geology between the north and the south? Yeah, this is Keith. So yeah, it's still early in the play. We're learning more every day about how the geology ties to production. It's, it's gonna obviously vary over the 435,000 net acres. But in general, the Utica, Utica is thicker in the north. The south is a little bit better pay, but it has better geomechanics and rock properties. That has to do with frack barriers and keeping the frack energy, more contained, near the wellbore. So we expect as we gather more data, different areas are gonna have different type curves. Geology is also gonna drive the spacing, too. But we're real happy with the well results in all of the areas. They're exceeding expectations, generating great returns, and we're happy so far with these White Rhinos that are down in the south. So they're still cleaning up. They've been on for a couple of weeks. We're seeing a little more, more liquid yield compared to the Timberwolf and and Xavier, and you're right, those, those do have the minerals, so they benefit from that, and we'll be able to update you when we have a little more production data. Great. Then bigger picture question on the PRB Niobrara. Assuming further D and C optimization efficiencies based on your progress to date, could this play compete with the Delaware and Eagle Ford over time in returns? Yeah, Derrick, this is Jeff. So yeah, we've made a lot of really good strides there in the PRB. You know, we started out really focusing in on that deeper Mowry, really to refine our geologic models kinda throughout the whole section. And we had good success with the Mowry with that. We went into package development last year, and we saw with package development a really good uptick in overall productivity there, about 10% in the Mowry. ...So once we accumulated enough data, we went ahead and we're moving up in section in the package development there in the Niobrara, and just really started drilling some wells this year, having really good success operationally, and we'll look to be bringing some of those on later in the year here. So in comparisons to, you know, the Powder and the Permian, I mean, there's not many basins that are going to be like the Permian as far as overall productivity and results. It's just a little bit different. But there are some advantages up there. It's got a really low F&D cost, and there's a lot of scale there. You know, obviously, we've got close to 400,000 acres, and we're really just focused in down on the South Powder portion of that. So we've got a lot of expansion that we can take our learnings and we can move it up to the North Powder, which we've had some delineation wells and across the acreage from that aspect. So we're excited about it. You know, it's, it's not moving as fast, you know, maybe as what the Permian Basin had, but, we're making really, really good strides. The returns look great on it, and the teams are continuing to make really good improvements from an operational aspect, and, and we are seeing premium returns on that play. Thank you. The next question from Nitin Kumar with Mizuho Securities. Hey, hey, guys, and congrats to Billy on the retirement. Thanks for all the help over the years. I want to start off, Ezra, some of your peers have talked about refrac and recomplete activity in the Eagle Ford. You obviously have a long history in the basin and obviously are, you know, on the leading edge of technology. I just want to ask, you know, what are your thoughts around refracs, and could they compete with some of these new plays like the Utica and others on economics? Yeah, this is Jeff. We obviously keep our finger on kind of, you know, what's happening with refracs and that technology out there. We've done tests in the past, you know, in multiple basins, and what we really find is just with our robust inventory across our multi-basinal portfolio, you know, the opportunity for refracs, we're much better to either go in and offset an existing completion that was maybe poor or lesser, or, you know, just go ahead and drill a new well in a new section from that aspect. And then the other thing that I'd point out is, you know, from refrac technology, I think there's still a long ways to go. I mean, there's pretty crude approaches to where you kind of do some Hail Mary fracs or have to install expensive additional casing strings, and you never quite get the productivity uplift that you're looking from an actual new well. So no, at right now, we see just a lot more potential in our existing inventory and the acreage that we have out there. We will keep an eye on the refrac technology and watch it advance and see if it has application, but we feel that going ahead and drilling a new well or an infill well is a much better investment. Great. Thanks for the answer. And I guess as a follow-up, you know, we've talked a lot about gas macro today, but you have a pretty strong marketing arm. Are you starting to see demand pull directly from the producer, from some of the AI or Mexican exports or any of these, you know, tailwinds to gas macro demand that we're, you're hearing about? Yeah, Niten, good morning. This is Lance. Yeah, I mean, I still... It's still pretty early on the AI front, but I'd say when you think about us, you're right. I mean, we do have a lot of capability and a lot of reach, you know, with the marketing arm. We are, you know, very pleased with the execution that we have. You know, we talked a lot. You heard even Ezra talk about, you know, the pillars that we have there with diversification and control, the flexibility. You know, all those things provide, you know, the reach that we need as we think about our price realizations and getting to the most attractive markets. Thank you. Our final question comes from David Deckelbaum with TD Cowen. Thanks for squeezing me in, guys. I just wanted to ask a follow-up just on the Utica, particularly as you fit into some of the analogs in other plays that you've been in, in the life cycle of that exploration and development program. How do you think about testing longer laterals in the Utica, specifically over time, which seems to be a play that's quite amenable to even lateral lengths beyond three milers, versus, you know, attempting to get down your footage costs? Sort of where are we in, you know, the theoretical innings there? Yeah, David, this is Jeff. You know, we're in the very early innings there, and what I'll say operationally is the Utica sets up, I mean, almost perfectly. It's the efficiency gains that we're able to see there, we're getting better with just about every well. And as Keith had talked about in his opening statements, you know, we drilled our longest lateral there to date at, you know, 3.7 mi. Our program right now consistently is 3 mi, and the team plans on continuing to push that out just because, you know, we can do one runs in the laterals and stay on bottom longer and not have to trip out of the hole, and we really have no problems operationally completing the well. I think the plan looking forward as far as from longer laterals is, yeah, we'll continue to push the limits there. We've got a lot of other drivers. You know, it's not just a cost per foot metric we're looking at, you know? There's other movement that we have that we're able to lower cost. But I would expect, you know, as we continue on with the operational successes we have, we will be drilling longer and longer there in the Utica. Appreciate that. Just my final question, just, you know, as you think about the incremental few hundred million spent this year on strategic infrastructure, you know, and some other projects, along the infrastructure side, how do you think about sort of the forward capital intensity of infrastructure as you continue developing in the 2025 and 2026 and beyond? Is that a number that should increase with intensity every year, just given, you know, some of the infrastructure calls that are out there currently, or is this sort of what you feel is like a steady run rate as a percentage basis? ... Yeah, David, this is Ezra. Yeah, those are those are fixed projects, the strategic infrastructure that we're talking about. And so the best, you know, kind of way to look at it maybe is to reference that three-year scenario that we have out there. Now, that is not guidance, but it is a scenario that potentially assumes, you know, a similar macro environment to what we've seen in the last few years, and what we could do going forward. And what you see there is maybe not as much capital intensity, but what you see there is an expansion of our cash flow and our free cash flow. And that, that's really the thing that we focus on, and that's the important thing to keep in mind when we talk about these strategic infrastructure projects. It's something I highlighted before, is that when you can invest... You know, we're not, we're not aggressively seeking out these strategic infrastructure, these infrastructure projects, but when you have the opportunity to invest in something that offers a very compelling rate of return upfront, and it gives you the margin expansion for the life of the asset, that's definitely an opportunity that we want to grab. It's one of the ways that we continue to lower the cost basis of the company, and it's one of the ways that in that three-year scenario, you see the free cash flow, margins expanding. Thank you. This concludes the question session. I would like to turn the call over to Ezra Yacob. Thank you. We appreciate everyone's time today. I'd like to hand the call over to Billy to wrap up. Thank you, Ezra, and thanks to all of you for your kind remarks, and I truly have enjoyed the chance to meet all of you and work with you in the past. Let me just add, I've been blessed to be part of this company and its unique culture for the past 43 years, working beside so many talented people and watching the company grow to become a leader in the industry. And while I certainly will miss the daily interactions, I take with me incredible memories, and I have great confidence in the leadership team and look forward to watching EOG's continued success. So thank you. Thank you. The conference has now concluded. Thank you for attending today's presentation.