Good day, everyone, and welcome to the EOG First Quarter 2024 Earnings Conference Call. As a reminder, this call is being recorded. 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 in 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.

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 have 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 finding and development costs drives 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. And 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 to 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 5-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 low-cost and returns-focused producers 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 to 12 Bcf a day of demand for LNG feed gas and another 10 to 12 Bcf per day of demand from several areas, including overall electrification, exports to Mexico, coal power plant retirements, and other industrial demand growth. So 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 900,000 MMBtu per day over the next 3 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.

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, 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 3-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 3 years by assuming similar commodity prices as the past 3 years. From 2021 through 2023, oil averaged $80 and natural gas averaged $4.25. Over that 3-year time frame, we generated $18 billion of free cash flow. Applying those same commodity prices to our forecast for the next 3 years, we would expect to generate $21 billion of free cash flow. That's 17% more cumulative free cash flow than the prior 3 years at the same price deck. Robust cash returned 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 and 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 2 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 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 supplies 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% to 60% of our service cost 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 cost, and improved well economics. In the Delaware Basin, we drilled 4 3-mile laterals in 2023 and have plans to drill more than 50 in 2024. In the Eagle Ford, our 24 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 mile reformation first. In our first 3 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.

Thanks, Jeff. We're very happy with the results of our first 3 packages of development wells in the Utica combo play. We now have over 6 months of production data from the first 2, the Timberwolf and Xavier, which continue to outperform our expectations. Daily production rates per well have averaged more than 1,000 barrels of oil, NGLs, and 4 million cubic feet of gas over the first 6 months. On average, these 7 wells have produced more than 200,000 barrels 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 4 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 mechanical properties. The southern area also benefits from significant economic uplift 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, 4 delineation wells, and now 3 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 2 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 stable pattern in the South, which is an EOG-wide record lateral length. This well is scheduled to come online later this year, and we are 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.

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 to utilize infield 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 learned, the retirement of a friend and colleague is bittersweet. Best wishes to you, Billy. Thank you for your service to EOG.

Our first question today comes from Steve Richardson with Evercore ISI.

Ezra, could you provide some insights on the gas outlook, particularly regarding Dorado? I understand you are moderating activity in the near term. Could you discuss the forward curve and your strong outlook on demand? What are your thoughts on the potential developments in the play concerning the one-rig program? Additionally, as Verde transitions into Phase II, will drilling be necessary to fill? How should I consider the flexibility of that play once the infrastructure is in place?

Yes, Steve, that's a great question. This is Ezra. So you're right, gas, obviously, it's stating the obvious, but inventory levels are very high after two consecutive warm winters. But 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 the reduced supply, not only from some operators curtailing but just from the reduction in rig activity we see, the potential 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. 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, 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 we've done that before as well, but we prefer to be flexible on our completion schedule side. As far as commitments to filling the infrastructure, no, Steve, we don't have any of that for us. What's going to really determine the pace of our investment there and when we bring the gas online is 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 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.

Ezra, I appreciate your flexibility in a low price environment, but in a $3.50 or $4 price environment, could we potentially see activity drop to 2 to 3 rigs? I don't want to get ahead of ourselves, but I understand there are efficiencies you want to maintain when prices rise as well.

Yes, Steve, the last part you mentioned is exactly how we view the situation. We are cautious about not exceeding our learning pace. We have a positive outlook on the long-term demand for gas in North America, as we have discussed previously. We believe Dorado has advantages, not just in supply costs but also in its geographic location, allowing us to cater to the increasing demand along the Gulf Coast. However, our commitment to maintaining this as a low-cost asset is crucial. This is the most important factor because, while we are optimistic about rising mid-cycle gas prices for the remainder of this decade, it is important to note that gas prices have historically been very volatile, influenced significantly by weather conditions in addition to supply and demand factors. The most important thing for us is to ensure that we are investing at a pace that optimizes returns and minimizes supply costs while keeping our cost basis low. This way, we can maintain positive cash flow during challenging times. We are prepared to increase our activity with the upcoming LNG and overall demand. We will have the necessary infrastructure, including takeaway infrastructure and in-basin resources like sand and water. We can ramp up, but it will be aligned with our learning, which will proceed at a measured pace.

And our next question comes from Arun Jayaram with JPMorgan Securities.

Ezra, you returned over 100% of your free cash flow this quarter, exceeding your 70% target for the year. I'm curious about what this signals to the market, considering you haven't historically returned this level of cash flow. Besides your belief that your stock was undervalued below $120, do you see any other implications for the market from the buyback activity this quarter?

Yes, Arun. This is Ezra. I'd say last year, we did return to the market through buybacks and specials and our regular dividend, about 86% of the cash flow. So 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 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, Utica, the Dorado, we're just talking about it, even the Powder River Basin. The entire energy sector, including EOG, remains undervalued compared to the overall market. These factors give us confidence to keep buying back our shares. Generally speaking, our priorities for cash flow allocation have not changed. We are focused on the regular dividend but will remain opportunistic with share buybacks, using market fluctuations to our advantage. We have been active in repurchasing shares for the past five quarters and will continue to assess opportunities for returning cash to shareholders as they arise.

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?

Yes, Arun, this is Jeff. Thank you for the question. I want to start by saying that our 2024 plan is progressing as we anticipated. Everything is on track in terms of timing, and we remain very confident in our total capital expenditure budget of $6.2 billion. You correctly mentioned that we will spend a bit more in the first half, with 56% of the total budget allocated then, but that's mainly due to some standard indirect costs and the strategic infrastructure investments we've discussed, including the Delaware gas plant and the Verde pipeline. 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 going to come on, hopefully, the back end of this year. we're really excited about it to be able to realize that $0.50-plus per Mcf GP&T savings that both those projects are going to bring for the life of the asset.

Our next question comes from Neil Mehta with Goldman Sachs.

I just love your perspective on the Eagle Ford and Bakken fields entered to more maturity. Some of your peers have talked on this earnings season about different things that they're doing to extend 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.

Yes, Neil, this is Jeff again. With the Eagle Ford, we've got a really good, consistent program this year. We're going to be completing about 150 net wells there. And as far as looking at the well performance, everything has been in line and right with our expectations. With any mature asset, you're going to see some productivity degradation. I mean, we started out in the East where we had a little bit more prolific geology. And then more recently, we've moved out to the West, where it's slightly lower quality pay, but the key takeaway is we've been able to continue to improve the economics in that play year-over-year. We've achieved this by increasing operational efficiencies and concentrating on faster drilling and completion with super zippers, longer laterals, and ongoing cost reductions that enhance the capital efficiency of the play. A significant change this year is that we're increasing the lateral length in the Eagle Ford by about 20%. While activity might be slightly down year-over-year, we've completed the same amount of lateral length in 2023 with those longer laterals. This illustrates how we're driving efficiency in the operation, and you can see it reflected in the returns. I mean, really, it's got some of the highest rate of returns over the last 3 years, and we've been drilling in the Eagle Ford for 15 years. And then looking over to the Bakken, 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 offset and infilling 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.

Billy, I want to congratulate you on your retirement and thank you for the insights you've provided over the years. My follow-up question is about the broader macroeconomic situation, specifically related to oil. With the upcoming OPEC meeting and significant uncertainty regarding both demand and supply, how has this year trended in relation to your expectations from a commodity perspective? I know your team has a strong focus on macro analysis. What insights can you share with us, Ezra?

Yes, Neil. Well, I'd start with the fact that Q1, I think, has really played out as most people expected. There is a bit of a pullback in demand there. And that's one thing that had prompted I think, had prompted some of the spare capacity being brought offline. But ultimately, that demand was about 102 million barrels 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 and also in China, the 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. When you think about inventory levels, obviously, the first quarter has seen spare capacity offline, inventory levels have stayed just below that 5-year average, but products really are a bit lower. And so that shapes up for 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, we think U.S. supply should be pretty moderate. We're in agreement with other estimates of kind of that 300,000 to 400,000 barrel per day growth year-over-year. And that's where we arrive in 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 depends, how that really plays out, as you said, at the next upcoming OPEC meeting.

Our next question comes from Neal Dingmann with Truist Securities.

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 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?

Yes, this is Keith. You're correct that we have primarily focused on the north-south trend within the valid oil area, which spans 140 miles. Our first priority on the western side is to gather seismic data, and we're currently in that process. Understanding the level of structural complexity is essential before we begin development. Generally speaking, we do not observe major variations in thickness or pay as we move from east to west. In the west, there may be slightly lower maturity, which translates to reduced pressure. In our other fields, like the Eagle Ford, lower pressure can decrease well productivity a bit, but it also leads to lower costs. Therefore, the economics remain quite similar across different sections of the play. And then overall, just on activity level, we have ramped up to 1 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 best places for capital. The other great thing is with the multi-basin portfolio, we don't necessarily need to ramp it up aggressively. We'll just kind of let returns drive that.

Great details, Keith. Just quickly on the supplement Slide 12, I appreciate the slide you mentioned regarding your marketing opportunity. Statistically, I am considering the U.S. oil sector. Are there potential opportunities to enhance exports if they arise? Also, could you discuss the flexibility or options you may have in those markets?

Yes, Neil, this is Lance. What we appreciate most is our advantageous position. Considering the supply we have from the Delaware Basin and the firm capacity that can flow into the Gulf Coast, along with our exceptional facility in the Eagle side, we see significant potential. They have recently enhanced the dredging in that area, allowing us to load more there. Our capability in that facility and our tank position have enabled us to push more product across the dock into export markets in the last quarter.

Our next question comes from Scott Hanold with RBC Capital Markets.

Yes, thanks. A little bit more on the Utica. I appreciate the fact that you guys do not want to outrun your learning curve. But given that, you're demonstrating some pretty good competitive economics with places like the Permian, just big picture, like what needs to happen and what do you need to see for this to become a more meaningful part of your capital allocation and production going forward?

Scott, this is Ezra. Yes, I think we're very happy with where we're at. It's over a 400,000-acre position. As Keith highlighted, it's 140 miles north to south. And let's be honest, we've got 2 packages on right now. Now the 2 packages are fantastic. They're exceeding what we initially had in our type curves, and they're more than confirming some of our early thoughts on the spacing test. So at this point, everything is going in the right direction. As Keith highlighted, to help clarify some of the other acreage we own, the initial step was identifying some of the well logs. Now, the next step is to proceed with the seismic analysis to determine the level of complexity. As Keith mentioned in his opening comments, we have recently added a package in the south, which will validate our findings in a somewhat different geologic environment. This is also an area where we own the minerals, which is very promising, considering the economic benefits that can arise from that. Overall, I believe that everything is progressing as planned. We aim to enhance our infrastructure in the basin and start leveraging our size and scale. One way to conceptualize this, Scott, is to consider where the Utica stands in relation to where the Permian was around 2012 or 2013. This is why we emphasize the importance of not exceeding our ability to learn; the costs we are investing today should be viewed through the lens of full-cycle economics, and they will remain relevant throughout 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 has 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. We definitely want to apply some of the capital efficiency lessons from the Eagle Ford, the Bakken, and the Permian to the Utica. However, we want to do so in a way that avoids the issues of spacing, higher well costs, and other challenges that have affected the early experiences in these other resource plays. Therefore, I wouldn't say we're in search of any major indicators or a quick solution that would lead us to initiate a 15-rig program. It's really about our company's current situation, our position in the cycle, and ultimately, it’s a returns-based decision that is made at the company level regarding capital allocation across our portfolio to enhance shareholder value.

And before I ask my next question, I want to extend my congrats to Bill as well. Obviously, we all appreciated your insights and expertise over the years. And 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 remind us the economics and how pricing is set in that region relative to, say, like, what we're seeing with Henry Hub pricing?

Scott, this is Jeff. Yes, just on the activity in Trinidad. We're currently just running our 1-rig program there and everything is going really smooth. Earlier this year, we completed 2 of our remaining wells there in the Modified U(a) Block successfully and brought those online. And we're currently drilling and completing a couple of exploratory wells in the SECC block. And then after that, we'll move the rig, and we've got a couple of recompletes to do in our Sercan area. And then one more exploration well to finish up the year in the TSP area. Another point to mention is that we are also installing our Mento platform. Everything is on schedule and looking positive. We are setting up the facilities in an SMR Block, which will position us well for the program next year. Now, I will pass it over to Lance to provide some insights on the marketing side.

Yes, Scott, we've always been real pleased there in Trinidad, especially when we think about our price realizations and obviously meeting that local demand into the country. So I think you can see even with the price realizations that we had in their first quarter, they were very attractive. So we continue to see that kind of on a go-forward basis.

Our next question comes from Leo Mariani with RothamKM.

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 kind of ask in terms of activity levels. Is there other ongoing exploration still this year in some of these U.S. oil stealth plays and perhaps you can just talk about kind of levels or wells? I know you're not going to 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 drive down the DD&A rates 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 the fourth quarter. So maybe you could just kind of wrap it all together and give us some color around that?

Yes, this is Ezra. I'll begin with the exploration part and then pass the details on DD&A to Ann. Regarding exploration, we have allocated funds for it this year, as mentioned in our first quarter call. We are still focused on oil plays, but our primary goal is to find opportunities that will enhance the quality of our corporate portfolio. The success we've had with the Utica is an example of this. We are not interested in merely increasing our inventory; instead, we want projects that will improve returns, as well as the cost of reserves and the costs associated with refining and development, which will help reduce the DD&A rate. This year, we are drilling some initial wells to explore certain ideas. While I hesitate to call them wildcat wells since they are not in uncharted territories, they are located in basins with existing data and historical production. We also have another player that is in more of a delineation phase, where we have already drilled the first well. The results from this initial well have been promising, and we are continuing to test whether it will meet the necessary criteria I mentioned. The big thing I'd say is these days are exploration plays in these initial wells I think I've highlighted this before. In the U.S., the way we operate through exploration, there's so much data that we're not really drilling these initial wells and to see if they'll actually produce oil and natural gas. It's not like we're testing 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 going to 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?

And I'll hand it over to Ann. The DD&A increase you saw 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't expect that DD&A to moderate over the remaining 3 quarters for the year, respecting about $10.50 for the remainder of the year.

I wanted to follow up quickly. Clearly, you all are quite optimistic about natural gas and have outlined significant demand increases for the rest of the decade. You mentioned that the second half of 2024 looks promising. Focusing on the near term, as you look at 2025, with prices hovering just above $3.50, do you feel more optimistic about that year? Is that strip price reasonable, or do you believe it might improve further? While there seems to be consensus that demand will strengthen later in the decade, I wanted to concentrate on the next year or so.

Yes, Leo, this is Ezra. I wouldn’t necessarily describe our outlook for '25 as bullish, but I do believe we have a positive view. We've observed a surprising increase in natural gas demand for power generation over the past couple of summers, and we anticipate that this trend will continue this summer. A significant factor in this is the retirement of coal plants. Furthermore, with softer pricing, we expect strong demand for natural gas this summer as well. When you factor in the reduction in drilling activities over the last eight months and the fact that operators are beginning to scale back production, we believe this will lower the supply to a level where we can achieve substantial progress on inventory levels in the latter half of this year. With a small amount of feed gas beginning to be utilized for LNG, we feel a bit more optimistic as we approach '25. However, it is important to acknowledge that there is a significant overhang currently that we expect to diminish starting this summer.

The next question from Paul Cheng with Scotiabank.

I need to take a moment to apologize, but I want to revisit the Utica situation. When evaluating a well's cost or productivity, what improvements are necessary for you to transition from the current situation to a more defined outline of manufacturing or production development? Additionally, considering your inventory backlog, which area do you feel most confident about for delineation? What does the development program entail in terms of the number of rigs, crews, and wells you anticipate annually? That's my first question.

Yes, Paul, this is Keith. I'll begin with the well cost. It's still early in the play, but the team is continuing to drive down costs. We believe there is significant potential for further efficiencies, and the consistent activity this year with one full rig has greatly contributed to that. Generally, we like the area because it offers an easier operating environment compared to many of our other plays. The geology is consistent, and the depths are relatively shallower. A good example is the 3.7-mile lateral we just drilled. We have also brought in an e-frac crew to achieve higher pump rates and improved efficiencies. Overall, we envision development costs eventually falling below those in the Permian, even at $1 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, we kind of 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, it goes back to growing at that pace where we can still learn and just the multi-basin portfolio. We don't necessarily have to ramp this up aggressively.

I see. 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. This year that you have about $400 million on strategic infrastructure spending. I assume that it's not every year, you will have that. But throughout the cycle, you're always going to have some strategic infrastructure spending, I suppose. So what will be a reason for that based on the cycle assumption for the strategic infrastructure spending and also that add to overall spending level for the infrastructure all along D&C for you guys?

Yes, Paul, this is Ezra. Yes, the $400 million of infrastructure, the strategic infrastructure that we've highlighted before, which we couldn't be more excited about because of some of the long-term margin expansion benefits that Jeff highlighted in the opening remarks. These are projects that, 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. 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, a netback uplift of $0.50 to $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 GP&T savings, a netback uplift of about $0.50 per 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 want to do them. It's generally more advantageous for a third party to handle these projects. However, there are certain cycles, typically every 5, 8, or 10 years, where the margins become favorable enough for us to pursue these opportunities and provide value for our shareholders.

Our next question comes from Derrick Whitfield with Stifel.

Leading on the Utica, it sounds like the southern part of the trend could be advantaged on returns based on the elevated NRIs and potential geology. Could you perhaps expand on the difference you're seeing in the geology between the north and the south?

Yes, this is Keith. So yes, it's still early in the play. We're learning more every day about how the geology ties to production. It's going to obviously vary over the 435,000 net acres. But in general, the 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 frac barriers and keeping the frac energy more contained near the wellbore. So we expect, as we gather more data, different areas are going to have different type curves. Geology is also going to 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.

Great. Then bigger picture question on the PRB Niobrara. Assuming further D&C optimization efficiencies based on your progress to date, could this play compete with the Delaware and Eagle Ford over time in returns?

Yes, Derrick, this Jeff. So yes, we've made a lot of really good strides there in the PRB. We started out really focusing in on that deeper Mowry really to refine our geologic models kind of 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 Mowry. So once we accumulate 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 comparison to 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. 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. It's not moving as fast 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 we are seeing premium returns on that play.

Our next question comes from Nitin Kumar with Mizuho Securities.

Congratulations to Bill on his retirement. Thank you for all your support over the years. I want to start by discussing Ezra; some of your peers have mentioned refrac and recomplete activities in the Eagle Ford. You have extensive experience in the basin and are familiar with the technology. I would like to know your thoughts on refracs and whether they could compete economically with some of the new players like the Utica and others.

Yes. This Jeff. We obviously keep our finger on kind of what's happening with refracs and that technology out there. We've done tests in the past in multiple basins. And what we really find is just with our robust inventory across our multi-basin portfolio. The opportunity for refracs, we're much better to either go in and offset an existing completion that was maybe poor or lesser or 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 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.

Great. And I guess as a follow-up, 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 kinds of tailwinds to gas macro demand that you're hearing about?

This is Lance. It’s still early in the AI space, but we do have significant capabilities and reach through our marketing efforts. We are satisfied with our execution. We discussed the fundamental elements we focus on, such as diversification and maintaining flexibility. These factors collectively enhance our reach as we consider our pricing strategies in the most promising markets.

And our final question comes from David Deckelbaum with TD Cowen.

I just wanted to ask a follow-up just on the Utica, particularly as you fit into some of the analogs and 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 3 milers versus attempting to get down your footage cost? Sort of where are we in the theoretical innings there?

Yes, David, this Jeff. 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, we drilled our longest lateral there to date at 3.7 miles. Our program right now consistently is 3 miles, and the team plans on continuing to push that out just because 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 wells. So I think the play I'm looking forward to is as far as from longer laterals is, yes, we'll continue to push the limits there. We've got a lot of other drivers. It's not just the cost per foot metric we're looking at. There's other movement that we have that we'll be able to lower costs. But I would expect as we continue on with the operational successes we have, we will be drilling longer and longer there in the Utica.

Appreciate that. And just my final question. Just as you think about the incremental few hundred million spent this year on strategic infrastructure, 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 '25 and '26 and beyond? Is that a number that should increase with intensity every year just given 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?

Yes, David, this is Ezra. Those are fixed projects, the strategic infrastructure that we're talking about. And so the best kind of way to look at it maybe is to reference that 3-year scenario that we have out there. Now that is not guidance, but it is a scenario that potentially assumes a similar macro environment to what we've seen in the last few years. And what you see there is maybe not as much capital intensity, but you see there is an expansion of our cash flow and our free cash flow. And that's really the thing that we focus on. It's important to keep in mind that while we are not actively pursuing these strategic infrastructure projects, we do want to take advantage of opportunities that present a strong rate of return from the start and provide margin expansion throughout the asset's life. This approach helps us reduce the company's cost basis and contributes to the expansion of free cash flow margins within that three-year scenario.

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 and 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.