Good day, everyone, and welcome to the EOG Resources first quarter 2023 earnings results 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir. Thank you, and good morning. Thanks for joining us. 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 in EOG's SEC filings. This conference call also contains certain non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures can be found on EOG's website. Some of the reserve estimates on this conference call may include estimated potential reserves and 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 and Chief Operating Officer; Ken Boedeker, EVP, Exploration and Production; Jeff Leitzell, EVP, Exploration and Production; Lance Terveen, Senior VP, Marketing; and David Streit, VP, Investor Relations. Here's Ezra. Thanks, Tim. Good morning, everyone. Strong first quarter execution from every operating team across our multi-basin portfolio has positioned the company to deliver exceptional results in 2023. Production, CapEx, cash operating costs, and DD&A all beat targets which underpinned our excellent financial performance during the first quarter. We earned $1.6 billion of adjusted net income and generated $1.1 billion of free cash flow. Free cash flow helped fund year-to-date cash return to shareholders of $1.4 billion through a combination of regular and special dividends and share repurchases executed during the first quarter. Combined with our full-year regular dividend, we have committed to return $2.8 billion to shareholders in 2023, or about 50% of our estimated 2023 free cash flow, assuming an $80 oil price. We are well on our way to achieve our target minimum return of 60% of annual free cash flow to shareholders. Our first quarter results demonstrate the value of EOG's multi-basin portfolio. We have decades of low cost, high return inventory that spans oil, combo, and dry natural gas basins throughout the country. Our portfolio includes the Delaware Basin, which remains the largest area of activity in the company and is delivering exceptional returns. After more than a decade of high return drilling, our Eagle Ford asset continues to deliver top-tier results while operating at a steady pace. Beyond these core foundational assets, we continue to invest in our emerging Powder River Basin, Ohio Utica Combo, and South Texas Dorado plays, which contribute to EOG's financial performance today while also laying the groundwork for years of future high return investment. Our portfolio provides flexibility to invest with discipline and develop each asset at a pace that allows it to get better. It provides optionality to actively manage our investments to minimize impacts from inflation. Diversity of our investment portfolio also translates to diverse sales market options, enabling us to pursue the highest netbacks. Our shift to premium drilling several years ago has helped decouple EOG's performance from short-term swings in the market. The result is an ability to deliver consistent operational and financial performance that our shareholders have come to expect and that drives long-term value through the cycle. Recession risk and the near-term demand outlook for oil continues to drive volatility of prices month to month. However, our outlook remains positive. Inventory levels currently near the five-year average are reducing as we progress through the year. Global demand continues to increase and is forecast to reach record levels by year-end. New supply has moderated from pre-pandemic levels of growth. Longer term, with the reduced investment in upstream projects the last several years, we remain constructive on future pricing. For North American gas, near-term prices reflect high inventory levels due to this year's warm winter and reduced LNG demand during repairs at Freeport. As such, we are currently evaluating options to delay some activity at Dorado. The medium and long-term outlook for natural gas, however, continues to strengthen. Currently, U.S. LNG demand is at record levels with an additional 7 BCF a day capacity under construction or through FID with expected startup between 2024-2027 that should position the U.S. as a leader in the global LNG market. Our confidence in the outlook for our business is demonstrated by our capital allocation decisions in the first quarter. Disciplined reinvestment in our high return inventory continues to lower our break-evens and expand the free cash flow potential of EOG. We strengthened our balance sheet by retiring debt, paid out nearly 100% of free cash flow in regular and special dividends. We utilized our repurchase authorization to buy back $310 million worth of stock late in the quarter during a significant market dislocation. I'm confident EOG has the assets, the technology, and the people to deliver both return on capital and return of capital for years to come. In a moment, Billy will discuss why we believe our foundational assets in the Delaware Basin and Eagle Ford will provide higher returns, margins, and free cash flow in the years ahead, and why we remain excited about the progress we are making in our emerging assets, Powder River Basin, Ohio Utica Combo, and South Texas Dorado. First, here's Tim to review our financial position. Thanks, Ezra. EOG generated outstanding financial performance in the first quarter. We produced $1.6 billion of adjusted net income, or $2.69% per share, and $1.1 billion of free cash flow. Timing differences associated with working capital accounted for an additional $661 million of cash inflow in the quarter. Our outstanding financial results were driven by strong operating performance. Compared with the prior year, first quarter production volumes increased 2% for oil and 7% overall. We mitigated most of the inflationary headwinds to limit the increase to per unit cash operating costs to just 3% or $10.59 per BOE, which was more than offset by a 12% decline in the DD&A rate. Capital expenditures in the quarter of $1.5 billion came in $100 million below target. Our long-standing free cash flow priorities and cash return framework remain consistent. Our priorities are sustainable regular dividend growth, a pristine balance sheet, additional cash return options, and low cost property bolt-ons. We are committed to return a minimum of 60% of the annual free cash flow to shareholders through our sustainable regular dividend, special dividends, and opportunistic share repurchases. We believe the consistent application of our free cash flow priorities and transparent cash return framework positions the company to create long-term shareholder value through the cycle. In March, we strengthened the balance sheet by paying off a $1.25 billion bond at maturity with cash on hand, leaving $3.8 billion of debt on the balance sheet. The next maturity is a $500 million bond due April 2025. Cash at the end of the quarter was $5 billion, yielding a net cash position of $1.2 billion, up $300 million from December 31. Yesterday, our board declared a second regular dividend of $0.825 per share, the same as last quarter, and a 10% increase from the prior year level. The $3.30 annual rate is a $1.9 billion annual commitment. On March 30, we also paid the $1 per share special dividend declared in February. EOG also repurchased $310 million of stock in the first quarter at an average price of $105 per share. For several days during the last two weeks of March, market volatility created a significant dislocation between the price of our stock and the value of the business. We were able to utilize our strong balance sheet to repurchase shares at highly accreted prices. You should expect us to step into the market again when there are significant dislocations. We are off to a very strong start in 2023 to deliver on our full year cash return commitment of a minimum of 60% of annual free cash flow. Altogether, the full year regular dividend, along with the first quarter special dividend and buybacks, represents $2.8 billion of cash return, which is about 50% of the $5.5 billion of free cash flow we forecast for 2023, assuming an $80 oil price. We will continue to monitor oil and gas prices going forward. We remain committed to delivering on our cash return commitment and look forward to updating you over the rest of the year. Here's Billy to discuss operations. Thanks, Tim. EOG's operating performance continues to improve with the first quarter generating outstanding results. Our first quarter volume, capital expenditures, and total per unit cash operating cost performance came in better than our forecasted targets. I'd like to thank our employees for their dedication and outstanding execution, giving us a great start to 2023. Our full year 2023 capital and production plans are unchanged. We forecast a $6 billion capital program to deliver 3% oil volume growth and 9% total production growth. We maintain the pace of activity from the fourth quarter of last year in the Delaware Basin and Eagle Ford, our core foundational plays, and continue to expand development in our emerging Powder River Basin, Ohio Utica Combo, and South Texas Dorado plays. Well productivity and cost performance are meeting or beating expectations across our portfolio as each play sustains sufficient activity to support continued innovation. As Ezra mentioned, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a big part of our overall strong first quarter results. Sustaining a consistent level of activity in these core plays is driving operational improvements and continues to be one of the primary hedges to offset areas of cost inflation. We are excited about the outlook for these assets in the years ahead. Even as these assets mature, we can apply technical learnings, operational innovation, and leverage prior infrastructure investments to continue to improve the operating margin and capital efficiencies of these world-class assets. In the Delaware Basin, we expect well performance will continue to improve this year, delivering productivity and returns well above the premium hurdle rate. Last year, our Delaware Wolfcamp wells delivered an average six-month cumulative production of about 34 barrels of oil equivalent per foot and are expected to improve this year. See slide 10 of our updated investor presentation for details. While well mix can impact the relative contribution of oil, NGLs, and natural gas, overall performance is improving in large part due to continued innovations like our new completion design. We have now tested 39 wells in the Wolfcamp that are yielding an average increase of 22% in the first-year production, with a 20% uplift in estimated ultimate recovery compared to the similar wells and targets using our previous completion design. With these encouraging results, we now expect to deploy this new design on about 70 wells this year. This new design is continuing to show promise as we expand the number of wells and test the design across different targets and basins. Operationally, maintaining a consistent level of activity in the Delaware Basin, combined with our culture of continuous improvement, is generating noticeable results. Drilling times continue to improve and are generating peer-leading performance aided by our drilling motor program and high-performing staff. The amount of footage drilled per motor run improved by 11% in the first quarter as compared to last year. Similar progress is being achieved with our completion operations with the expansion of our Super Zipper technique. These efforts, combined with the opportunity to co-develop multiple targets in this stack pay resource by using our existing surface footprint and infrastructure, are expected to drive significant efficiency gains and continue to improve our margins in the Delaware Basin for years to come. We first introduced the Super Zipper completion technique in the Eagle Ford in 2020. Since then, we have expanded its use throughout the play and have more than doubled completions efficiency as measured by completed lateral feet per day. As indicated on page 12 of our quarterly investor slides, the amount of lateral completed per day year-to-date has increased by another 18% compared to last year. In the first quarter, we also set a record in the Eagle Ford, drilling our longest well to date, reaching a measured depth of nearly 26,500 feet with a lateral length of over 15,500 feet. We expect to continue to see completion efficiency improvements as we extend laterals in the Eagle Ford to 3-plus miles where feasible. As a core operating area that has been under development for more than a decade, the Eagle Ford also benefits from our existing infrastructure from over 3,700 producing wells. Leveraging existing investments made in strategic water, oil, and gas infrastructure minimizes future CapEx needs and lowers operating cost. Ongoing improvements to completion operations and leveraging the benefit of existing infrastructure enable our Eagle Ford finding and development cost to continue to decline. Last year, the Eagle Ford's rate of return was the highest in the play's history. Longer term, we have over a decade of drilling inventory in the Eagle Ford, allowing us to maintain the current production base while generating high returns and lowering breakevens. As previously mentioned, we are maintaining activity in our core plays and progressing our newer emerging plays. This year's plan in Dorado contemplates 8 additional wells completed compared to 2022 in order to achieve a consistent level of activity to drive performance improvements. Our drilling operations are realizing a 29% improvement in the footage drilled per day since 2021. Completion operations will be conducted on a few wells in the second quarter. We are evaluating options to delay additional completions originally scheduled later this year due to the current natural gas price environment. To date, operational progress towards improvements and Dorado's well performance is meeting or exceeding our early expectations. Activity in the Utica combo play is just commencing, we are already witnessing the compounding effects of sharing technology across our multiple plays. For example, drilling performance for recent wells is improving on the order of 20%-30% compared to last year's results with the benefit of our proprietary drilling motor program and precision targeting. We expect similar levels of improvement from our completion program once we begin completing wells in the third quarter. For a little color on inflation and industry service cost. As we've anticipated in building this year's plan, the upward inflationary pressure that we witnessed last year appears to have plateaued, which still leaves us confident that our average well cost should increase no more than 10% compared to last year. Early indicators are showing signs of service cost moderation, which is more prevalent in some basins and less than others. We would expect that any softening of service and tubular costs will be slow to manifest into lower well cost and cash operating costs until much later in the year or more likely in 2024. As the year unfolds, we will continue to look for opportunities to leverage our scale and the flexibility of our multi-basin portfolio to manage costs across all operating areas. We also remain highly focused on sustainable cost reductions through innovation, operational performance, and execution improvements to mitigate inflation and further drive down our cost structure. Now I'll turn it back to Ezra. Thanks, Billy. In conclusion, I'd like to note the following important takeaways. First, strong execution from every operating team across our multi-basin portfolio has positioned the company to deliver exceptional results in 2023. Thanks goes to our employees for delivering a great first quarter with their outstanding execution. Second, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a significant part of our first quarter results. Third, our first quarter performance demonstrates the value of EOG's multi-basin portfolio. We have decades of low cost, high return inventory that spans oil, combo, and dry natural gas basins throughout the country. Fourth, our long-term outlook for both oil and gas remains positive, and our shift to premium drilling several years ago has helped decouple EOG's performance from short-term swings in the market. The result is an ability to deliver consistent operational and financial performance that our shareholders have come to expect and that drives long-term value through the cycle. Thanks for listening. We'll now go to Q&A. Thank you. The question-and-answer session will be conducted electronically. If you'd like to ask a question, please do so by pressing the star key followed by the digit 1 on your touch-tone telephone. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Questions are limited to 1 question and 1 follow-up question. We will take as many questions as time permits. Once again, please press star 1 on your touch-tone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing star 2 or the pound key. We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question is from the line of Paul Cheng with Scotiabank. Paul, your line is now open. Thank you. Good morning, everyone. 2 questions, please. I think the 1st one is probably for Billy. You talk about the Permian, the good well productivity. Just, can you give us a little bit more detail in terms of the test size you're doing over there and whether you're increasing it, especially if you start to do more co-development, and how many different landing zone or that you are targeting in your program? 2nd one that I'm just curious, I mean, I think in the last, say several months, a lot of investors have been asking why that go ahead with the expansion in Dorado. I think last quarter in the conference call, management has said, you're looking for the long term. Just curious that what may have triggered, your, maybe there's a slightly, change in your view about the pace on that development. Thank you. Yeah, Paul, this is Billy. Let me give you a little highlights maybe of the Permian program and what we're seeing there. I'll probably ask Jeff to give some more detailed color, so help explain some of the improvements we're seeing. Overall, we're very pleased with the progress our Permian plans are showing. In general, our results are playing out just as we anticipated. In our plans, we had planned all of our type curves are modeled and forecasted, the results are meeting or exceeding our forecasted results, including the co-development of different targets at the same time. I'd like to go ahead and turn it over now to Jeff, maybe talk a little bit about the new completion design, the results there we're seeing, some of the productivity improvements. Thanks, Billy. Paul, this is Jeff. We're extremely happy with our productivity out of the Delaware. Just to give you a little color, one of the big things that's really improving that is our new completions design, or I should say, kind of our improved completions design. As Billy stated today, you know, we've tested around 39 wells in the Wolfcamp, we're seeing an uplift of about 20% or so in the well productivity. That's in both the early and late life performance of that. I'll also note that the uplift, we're not just seeing that in one phase. We're seeing both in oil and gas, kind of across the board. With these outstanding results, what we've done is we've really expanded this program, and we're planning on completing about 70 additional wells in the Wolfcamp this year. That's gonna be about a 2.5 times increase from last year. We definitely went ahead and taken this into account in both our drilling plans and guidance for 2023. Looking forward with this design, we've had a lot of success in our deeper formations. Our team really plans to continue to kind of test in some of the shallower formations to evaluate its benefits. One thing that we have observed with this design is that there's varying performance uplift depending on the rock type and the depth of the target. The design does come with a little bit of a cost increase, so we just wanna be mindful about how quickly we're testing it and be strategic at the pace that we're going ahead and putting these in the ground. Also, I'd like to point out that, you know, the design isn't really new to EOG. It was actually first tested down in our Eagle Ford asset, and this is just an example of the technology transfer in the company of our multi-basinal operations. It's really helped us accelerate our learning throughout the company. Lastly, with the success that we've seen in the Delaware Basin, you know, we're actively testing it in all of our emerging plays throughout the company and really look forward to evaluating those results throughout the year. Paul, the other part of your question was on Dorado and really what triggered the change of pace that we're thinking about. You know, we put together a plan originally just to remind everybody that really it was not a huge acceleration in activity planned for. We're only adding eight wells. The plan never contemplated a huge amount of growth in Dorado to start with. However, we're always remain flexible on our program, that's the benefit of having a multi-basin portfolio is we can move activity around based on market conditions or other factors as they present themselves. Naturally, with gas prices remaining weak and moving into the year, it's only natural to think about options that we might be able to explore with Dorado activity. We are exploring the option to delay some completions that were scheduled for later in the year, and we'll give more color on that as that unfolds. Thank you, Mr. Cheng. The next question is from the line of Leo Mariani with ROTH Capital Partners. Leo, your line is now open. Yeah. Hi. I just wanted to follow up a little bit on the buyback, you know, versus the special dividend. Obviously there was no new special dividend, I guess, announced this quarter. Instead, you guys certainly lean on the buyback as you described in March. I just wanted to kinda confirm, you know, your thinking around this. I mean, it still sounds like the buyback is gonna be reserved only for kind of, you know, very opportunistic situations, you know, where there is this dislocation and, you know, generally speaking, it's probably more reasonable to expect, you know, the special going forward with the buyback kind of maybe every once in a while. Is that kinda how to think about it? Yes, Leo, this is Ezra Yacob. Good morning. I think you've summarized it pretty well. You know, our strategy hasn't really changed. We are committed to returning at least 60% of our free cash flow on an annual basis. Year to date, as Tim had mentioned, our cash return commitment is $2.8 billion. That's approximately 50% of our, you know, what would be our fiscal year free cash flow, at the assumed $80 oil price there. Just to recall, you know, that the cash return priorities for us, it really begins with the regular dividend as the first priority. The excess free cash flow, as you said, will either come back in the form of special dividends, which we've paid seven of the last eight quarters, we've distributed a special dividend or opportunistic buybacks. You know, what we saw in the first quarter when we executed a repurchase was we really saw a dislocation, dominantly associated with the banking crisis, and we were able to step in to repurchase approximately $300 million of the stock. As you pointed out, really in line with our strategy. Now, what I would say has changed over the last 18 months since putting the repurchase authorization in place, is really the strength of our company. You know, our primary value proposition, of course, is investing in high return projects, adding lower cost reserves to our company's profile, which, you know, thereby reduces our breakevens and expands our margins. As we continue to execute on this strategy and we continue to strengthen the company, the way we consider dislocations, certainly evolves as well. Okay. That's helpful. I just wanted to see, if there's any more of a robust update on the Utica. I think last time you guys kind of rolled that out, I think you had 4 wells on production, with a, you know, fair bit of history. Just trying to get a sense, are there more wells, you know, producing at this point in time in the Utica? Just any thoughts around, you know, some of the long-term performance of those, you know, prior wells that have been on, you know, for I guess over 1 year at this point? Yeah, Leo, this is Ken. We're making excellent progress on our Utica program this year. We currently have a drilling rig actively operating on our northern area and we're progressing nicely on our gathering and infrastructure projects. The 4 wells that you talked about that we drilled and completed in 2022 really do continue to deliver our expected performance, and we plan to drill and complete about 15 wells across both our north and southern areas this year. We'll have those production results more towards the end of the year. Another thing to note is we also continue to add acreage and look for additional low-cost opportunities to add to our position. Thank you, Leo. The next question is from the line of Scott Hanold with RBC. Scott, please go ahead. Yeah, thanks. Good morning. Congrats on the quarter. You know, Ezra, maybe if I could pivot back on the buyback conversation and if you could give us some color on, you know, what were the key triggers on the decision to do buybacks? Was it relative valuation of EOG to peers? Was it just the, you know, aggregate move? Is there other things like intrinsic value assessments that kind of generated that process to really kick it off there? Good morning, Scott. Yes, this is Ezra. Those are all accurate to the tune of how we kind of look at these opportunities. You know, as we've talked about in the past, it kind of begins with the macro, first of all, right? What's happening on both global and domestic supply and demand balances. As far as dislocations go, we do measure. We look at the intrinsic value of our business relative to different pricing scenarios, both short and long term. We do evaluate trading multiples, not just at EOG versus the peers, but actually for the entire peer group and see what's happening. So one comparison, you know, that could be made is, you know, the dramatic sell-off that the industry saw last summer, which was associated with a pretty dramatic pullback in oil prices. That was really fundamentally supported by a change we felt in the macro outlook. There was a significant announcement there for roughly 300 million barrels of petroleum reserves that would be hitting the market on the supply side from across the globe. What we saw in the first quarter was not really supported by a big change in the forecast on the fundamentals. Potentially really just triggered from the banking crisis, potentially an increased fear on the demand side from increased recession. We really feel like most of that has already been priced in to the market on the demand side. When we saw a pullback there and a dislocation with the market, really again associated in late March there with the banking crisis, we really didn't hesitate and were able to step into the market, and do that $300 million share repurchase, and we think we really created a significant amount of value there for the shareholders. That's great. Thanks for that. As my follow-up, you know, one of the things I think, you know, tends to get lost or is underappreciated is the premium pricing you all continue to get on your commodities across the board. Can you just give a sense of, you know, as you kind of look forward, do you find more opportunities ahead where you can continue to, you know, raise the bar on that as well? Hey, Scott. Good morning. This is Lance. Thanks for the question. Yeah, our realizations continue to be, you know, excellent. I mean, when we think about it's, it's really just the capability that we have when you think about the multi basins that we have, but just our transport position and then the capacity that we've taken out. You hear us talk a lot about control, and having control all the way to the water is exceptionally important. I would just say, as you think about our position and then the price realizations too, and then extracting additional premiums, I think our ability to just transact very quickly and with the supply, the scale that we have, I mean, we can definitely walk in with further opportunities. Thank you. The next question is from the line of Scott Gruber with Citigroup. Scott, please go ahead. Good morning. I want to circle back on the Wolfcamp development strategy. After looking at slide 10 here in the deck, you know, last year you layered in more Wolfcamp M wells. This year the percentage of Wolfcamp M will be sliding back down some. Is that impacted by where you'll develop and deploy the new completion design? Or is that a reflection of trying to be more selective with, you know, where you co-develop the Wolfcamp M? You know, just what's behind the shift in mix? Yeah, Scott, this is Jeff. Really, you know, our co-development strategy, you know, it's pretty straightforward. What we're trying to do is, we're just adding in high rate of return targets to our well packages. Really it's driven by the geology. Obviously the geology across, you know, our acreage, it changes, you know, very quickly. Kind of from development unit to development unit, you know, we've really got to strategically dissect what our, you know, strategy is gonna be there. From what we're seeing right now, and you can see that on slide 10 and 11 in our deck, you know, by adding in some of those deeper targets in the lower Wolfcamp, or I should say the lower upper Wolfcamp and then the middle, you know, we're achieving economics well over our premium hurdle rates. You know, we have some of the tightest co-development spacing out there in the basin. Ultimately, just this approach, I mean, it's improving our total recovery per acre. It's helping optimize that NPV of the resource, and it's just adding those barrels at finding costs below our current Delaware Basin levels. Got it. Yeah, just looking for some more color on the new completion design. You said it was, you know, initially developed and rolled out in the Eagle Ford. Did it become the dominant design in the Eagle Ford? You know, will it become the dominant design in the Permian? Yeah, how quickly can it be rolled out to some of your new plays? Yeah, Scott, great question. Yeah, the design as I talked about, it was first utilized in the Eagle Ford. It was back in right around 2016. We didn't see the same uplift that we see in the Permian. It wasn't quite as extensive, but that really has to do with the difference in rock type and their geological properties between the two plays. It did provide, you know, the application proved really beneficial as far as helping lower our well cost and reduce our completion time. Yes, it is something that we still do employ there in the Eagle Ford and as I said, in a lot of our emerging plays. As far as in the Delaware and our rollout, you know, our plan is to increase, as I said, the year-over-year number by 2.5 times what we did last year. I also did state there's just a slight cost increase, so we wanna be cognizant of how quickly we roll it out. Like anything in our program, you know, we just don't wanna outrun our learnings, and we wanna make sure that, you know, we continue to evolve this technique as we learn. Thank you. The next question is from the line of Derrick Whitfield with Stifel. Derrick, please go ahead. Good morning, all, and thanks for taking my questions. With my first question, I wanted to focus on CapEx cadence throughout 2023, with Q1 coming in better than expected and Q2 projected to be heavier than expected. Could you comment on the one to two drivers? Separately, if not part of the answer, could you speak to cadence on non-DNC investments throughout 2023? Yeah, Derrick, this is Billy Helms. Yeah, the second quarter CapEx has got it to be a little bit higher than the first quarter, and it's mainly due to some non-drilling and completion capital, the indirects or infrastructure and those kind of things that we put in our program, that it was originally scheduled to occur at the latter half of the first quarter. It turned out to be pushed into the second quarter. Thus, that's the reason the first quarter was under on CapEx, and the second quarter is a little bit higher. You know, that really sticks to our original plan. We had always planned for about 52% of our CapEx to be spent in the first half of the year. We're still on target for that and the 48% in the back half. That's kind of the way the program plays out. Great. With my follow-up, I'd like to focus on your operational efficiency gains in the Eagle Ford. Is your gain principally driven by increased Super Zipper activity? If so, are there practical limitations on the amount of completions you could pursue utilizing this approach? Yeah, Derrick, this is Ken. I'd like to start off by really crediting our team there in San Antonio for driving down that finding cost that you talked about. By focusing on improving the efficiency of every portion of the process, we've been able to drive down costs over the past several years, increasing our lateral lengths while improving targeting and focusing on bit and motor performance in conjunction with the advent of Super Zipper completion operations have really allowed us to improve efficiencies and, you know, really drill and complete more lateral footage in a day compared to a few years ago. That's really showing up in our lower cost basis. One thing to note is we do have over 10 years of high return drilling in this play that can sustain our current production levels and continue to expand our margins. Thank you. The next question is from the line of Doug Leggate with Bank of America Merrill Lynch. Doug? Good morning. This is John Abbott on for Doug Leggate. Our questions are really on Dorado. You know, we understand that you're going to potentially delay activity this year, but one of the goals that you set out this year was to try to just, again, get a greater economies of scale into play. When do you think you need to achieve that size and scale, noting that you have additional LNG capacity coming on exposure in 2026? Yeah, John, this is Billy Helms. For Dorado, you know, yes, we are increasing activity there mainly from the drilling side. Originally we had planned to also bring in additional completions. On the drilling side, I would add that we are seeing a tremendous improvement in the efficiency gains there. The team there has done just an excellent job of being able to improve our drilling times, lower our well cost, and just increase efficiencies overall. We're very pleased with the progress we've made. I think that that increased activity we're seeing on the drilling side is playing out what we're seeing on the drilling results and giving us insights into how we can continue to lower well costs going forward. On the completion side, we have some planned activity here in the second quarter. Beyond that, we're looking at ways we can with the flexibility we have in our program, to delay the completion of any wells that would beyond in the second half. Really just thinking about how we can leverage some of the learnings from our other programs and plays and combine that activity with the activity we have in Dorado by sharing equipment and people and those learnings across our portfolio. You know, we don't really feel the need to jump in and complete those wells, but we are evaluating options as they roll out and we'll see how those present themselves. As far as the activities for- I guess the- LNG demand, I guess, you know, the play, you know, the unique thing about this play, it doesn't take a lot of wells. The wells are very prolific, so we're well ahead of any timing that we would need to add LNG capacity in the future. We also have the flexibility of moving gas from other operating areas, multi-basin portfolio, to the Gulf Coast. Don't think of the Dorado as just simply applying itself to the LNG market. It's got the opportunity, but we can get gas from other plays to the Gulf Coast as well through our marketing arrangements. That's extremely helpful, which leads to the next question. You know, assuming there was not an issue with gas prices, how do you think about the optimal level of production for that play or activity long term? I mean, how big does it kinda get to? How do you think about that approach, that, I mean, efficiency program longer term? Yeah, John, this is Ken. If gas prices are not an issue. Yeah, John, this is Ken. I think the real thing in Dorado is it doesn't take a lot of wells to generate significant volumes out of that play. I don't know the exact right pace, but what we wanna do is we wanna develop this at the, at the right pace where we don't outrun our learnings. We're making significant progress as we really get those operational synergies together that Billy talked about. That pace of development is really gonna be dictated by not outrunning our learnings. Thank you. The next question is from the line of Neal Dingmann with Truist. Neal, please go ahead. Morning. Thanks for the time. My first question, just on the Powder River, I'm just wondering, hadn't heard too much on that lately. I'm just wondering, how do you still feel this competes versus your other premium plays? I know at one time you suggested you had almost 1,700 locations there. I'm just wondering your thoughts around this. Yeah, Neil, this is Jeff. No, we have outstanding results there in the Powder right now, and it's some of the lowest finding costs that we're seeing there in the whole portfolio. Yeah, we still have between kind of our full South Powder River Basin and then moving up to our north, about 1,600 net undrilled premium locations. Just looking at our program, everything's on pace this year. The wells are performing as we expected. Q1, we've completed about 15 gross wells, which two-thirds of those were Mowry. You know, we're seeing a lot of benefits also by getting some consistent activity up there in the Powder. We're running a consistent 2 to 3 rigs and 1 full frac spread with that, which is really allowing them to kind of push their efficiencies. Then we also have, you know, a lot of confidence in the play, you know, just with the overall performance and stuff as with the Mowry. Then from there, as we talked about, we wanna go ahead and gather the data, you know, in the upper overlying formations like the Niobrara, so we can develop that later in the future. Then also, you know, additional confidence in the play, I think would be really, should be said is the infrastructure acquisition that we had. We had noted that in our 10-Q, we acquired Evolution, and I'll go ahead and let maybe Lance say a couple things on that. No, thanks, Jeff. Just to add to that on our confidence when we think about the Powder River Basin, we did make a strategic investment there. That was about $135 million, we view that as a bolt-on acquisition, it's really a midstream footprint. There's a plant and gathering system that just overlays our southern acreage. The plant's a first-class asset. It was completed in 2019. When we think about this, it just really complements our existing gas gathering infrastructure build-out as we have connections in place. We really look at that as value because we can load that plant, fill the plant very quickly. There's also other benefits that we see long term as well as we think about just lowering cash operating costs, gathering, processing expense versus third parties. We'll have control and redundancy, but then also to the confidence we can expand that very quickly. Well. The last thing I just wanted- Will that plant help the diffs there as well? I'm just wondering with what you mentioned with that plant, would that boost the diffs there a little bit as well? When we think about that, we think about actually the gathering, processing, transportation expense. It's absolutely when we think about loading it with our equity gas into that facility and having to control, we're definitely gonna see better net backs. It's more as we think about just controlling the cost and lowering the cost basis of the company that's gonna absolutely make the Powder River Basin and the southern acreage there more competitive. Thank you. The next question is from the line of Bob Brackett with Bernstein. Bob? Good morning. Back to the Wolfcamp co-development. If you're hitting 2+ targets in the Wolfcamp versus, say, cherry-picking the best zone, all things being equal, you'd expect wells to get worse, yet you're seeing wells get better. Is that attributable completely to the design change? No, I'd say it's attributed to our co-development strategy. I mean, it's really been a process over time. If you look at back in 2016 in the Wolfcamp or I should say our strategy through the whole Permian, we had six unique targets. Kind of fast-forward here, you know, we're up to 18 unique targets. Obviously with that, the spacing has changed both in zone and from a vertical perspective. Our teams have methodically obviously tested this. You know, they've taken into account, you know, the actual spacing, how they interact, the depletion to it. We've come up obviously with the best co-development strategy really to maximize the overall production of those intervals and then obviously maximize the economics related to it. Great. I guess the follow-up would be, it sounds like the co-development strategy is driven by that desire to, you know, maximize the lack of communication between zones, or is it more driven by just logistics of having that kit sit in one spot for a longer time? It's really, it's about maximizing, you know, the overall resource there, as you said, you know. We do have the optimal amount of communication to we're actually able to, you know, optimize the recovery and then, like I said, really maximize those economics. Thank you. The next question is from the line of Arun Jayaram with JPMorgan. Arun, please go ahead. Yeah, good morning. I wanted to come back to the new completion design. You highlighted how you've tested this on 39 wells, and you plan to go to 70 wells. My question is, was the 20% uplift, you know, relative to wells in the same area or relative to the to your type curve? Maybe the follow-up is, are the 70 wells, you know, contemplated for this calendar year, and was that, was that, you know, part of your guidance? Did that include that, or would that reflect an upside risk to your oil guide? Yeah, Arun, this is Billy. The uplift we're seeing, a part of that was actually baked into our guidance. We didn't bake in the entire amount. When we put together our plan, we understood that there were gonna be some uplift. We did plan on 70 wells to be part of that calendar year program, and we baked in some of that into our production guidance knowing that we would see some uplift. I think the uplift is surprising us a little bit more to the upside, but I would say that's already really factored into our guidance that we've issued. As far as the, you know, what we're doing there, you know, we're finding that the target is critical, so the rock type is critical to why it works in some areas. We're cautiously moving through our program to make sure we test as we go to understand which targets lend themselves best to this design change and which ones don't. 'Cause it does cost a little bit more, and we wanna be very disciplined on how we apply that across the fields so we maximize, as Jeff was saying, the economics of the play. Okay. Just my follow-up is, any update on Beehive in Australia timing? Yeah, Arun, on Beehive, we're still excited to be able to drill that well, but it's gonna be probably in the first half of next year, before we're able to get that well drilled. Thank you. That's just really due to some timing on permits and those kind of things. The next question is from the line of Charles Meade with Johnson Rice. Charles, please go ahead. Good morning, Ezra, Billy Helms, and the whole EOG team there. I think just a couple of quick ones for me, touching on some of the common themes that you've already spoken on for a while. The Dorado, evaluating the slowdown, can you give some insight into your thinking? Is this about the natural gas price falling below your $2.50 double premium? Or is this about the contango you see in the curve and just the value of just waiting a few months? Or is it? I recognize those aren't exclusive and, but just some insight on what really keyed you guys to wanna examine that. Yeah, Charles, this is Billy. certainly, you know, it really is not triggered on a specific gas price, but just the overall softness we see in the current market conditions and the need, you know, to simply bring more gas on in this current condition. you know, as Ezra talked near term, we understand the near-term softness in the market, but longer term, medium and longer term, we're still very bullish on the long-term outlook for gas. You know, we do look at the different flexibility we have in the program and we're evaluating options to be able to successfully push those back in the year. We're just gonna continue to remain disciplined on our investment to make sure we're maximizing the value to the company over the long term. Okay, that's helpful. Then just one more quick one on this Wolfcamp completion design. I got the message, I think in your last response to the last question that this is not gonna be an across-the-board shift that you'd wanna make. Presumably, you've confirmed, I think you're talking about 16 targets it works in. Can you give us a sense, does it work in a quarter of the targets and maybe upside to half or three quarters? What's it look like to you guys right now? Yeah, this is Jeff again. Yeah, that is correct. You know, it's not necessarily a one-size-fits-all across. It really does have to do with the geology that we're, you know, applying it to. When looking particularly there in the Permian, we primarily just applied it down in the deeper Wolfcamp targets. That would basically be just kind of the up or down through the middle in a co-development standpoint. Now, we are testing on those shallower targets, but there are quite a few different rock types. You know, right now I say it's area by area. You know, from a percentage basis, you kinda hate to, you know, put an actual percentage on it. You know, right now we're still evaluating that, and it'll be a case-by-case basis. Thank you. The next question is from the line of Neil Mehta with Goldman Sachs. Neal? Good, good morning, team. My question was on the natural gas liquids market, where realizations obviously have been trending lower. I'm just curious on your perspective on what gets NGLs to firm up relative to WTI, and what are you seeing real time in the export markets? Thank you. Neal, good morning. This is Lance. I think what you're continuing to see absolutely the export, you know, positions that are getting built out. I think as you kinda have to think of those kind of, as we think about them, kind of more on ethane and more on propane. Continuing to see healthy propane exports. We continue to see the build-out that's accompanying with that. You're continuing to see the demand as you think about the Far East demand. That's gonna be the demand pool for those barrels. Continuing to see that there could be some firming up there, kind of maybe more longer term. Ethane obviously is gonna float a little bit more with gas prices, and that's kinda like what you're seeing today. Great. Then, just curious on your guys' perspective on the gas markets as well. You've talked a little bit about slowing down potentially in term from a drilling perspective, but how do you see the balances moving from here in a weather normal way over the course of the year? Yes, Neal, good morning. This is Ezra. As I stated kind of in the opening remarks, you know, we still remain constructive on kind of the longer-term gas story for the U.S. We think that the U.S., especially, Dorado being a big piece of it, has really captured a low cost to gas supply that can really compete on the global scale. With the amount of LNG that the U.S. is exporting right now, which is at record levels right now for the U.S., combined with the number of projects that have made it through a financial or a final investment decision, and then the additional projects that are still being kind of planned and discussed, the U.S. will be long-term positioned to be really a global leader in the LNG market. Gas is always difficult because it is highly volatile when it comes to things like the short-term pricing on weather. It's one reason you've heard this morning from both myself, Ken Boedeker, and Billy Helms that the most important thing we look at when we developed Dorado is to really invest in that at the right pace for the long term. We wanna make sure that we're not outrunning our learnings, that we appropriately invest to be able to keep our costs low and, at the end of the day, really keep our margins wide. We wanna put in the correct infrastructure to keep our low operating costs because the margins are always pretty skinny on gas. The low-cost producer for gas is gonna be able to be exposed to the global market here in the U.S. for the long term. Thank you. The next question is from the line of Josh Silverstein with UBS. Josh, please go ahead. Yeah. Thanks. Good morning, guys. Just sticking with gas first. You have a, I mean, usually wide gap on your differentials, even after reporting the first quarter results. Can you just talk about, you know, how you think that may shape over the course of the year, what you're looking for to come in towards the high end versus the low end there? Thanks. Yeah, Josh. Hey, good morning. This is Lance. I believe when we think about our guidance, we were just below the midpoint of the guidance on our realization from a gas standpoint. You've seen kind of our guidance for like the full year. We expect a lot of that's gonna be driven. Obviously, we have the diversification, you know, that we have with our Trinidad exposure. We have, you know, you can see on our supplemental slide 8, you can obviously see the large exposure that we have into the Gulf Coast. Obviously our JKM exposure as well. I think we're gonna hold with existing guidance that we have. Got it. Just as far as the shareholder return profile, I know you've been thinking about it from a percentage of free cash flow. But how would you think about it from managing a cash balance standpoint? You've been, you know, over $5 billion now for the past few quarters, including paying down the debt maturity in the first quarter. You know, is $5 billion, $6 billion the right level of cash for EOG? What level of cash would you not wanna get over? Because it feels like there are certain periods where you could return over, you know, 100% of free cash flow to shareholders if you really wanted to. Thanks. Yes, Josh, this is Ezra. You know, when we came out with that cash return guidance with a minimum of 60%, we really did just mean that it's a minimum. In fact, last year we returned excess of the 60% free cash flow to our shareholders. We started with that 60% because we feel confident on that, especially when we roll in, you know, kind of an almost a peer leading regular dividend that we'd be able to compete and deliver that through the cycles. When we think about a specific target for cash on hand, I wouldn't say that we have a real target. You know, we have spoken about some indicators and things that we strategically think about as far as holding a cash balance. The first, of course, is we like to have a bit of cash on balance just to run the business, to allow us to stay out of commercial paper. Historically, that's run about $2 billion, kind of depending on what point you are in the cycle. Then in addition to that, we do like to have cash on hand so that we can be strategic and counter-cyclically invest in opportunities as they arise, whether that's, you know, at times, investing in casing or line pipe, or last year, you know, we were able to step in and do an acquisition in one of our emerging plays there in the Utica, where we actually purchased approximately 130,000 mineral rights. Then lastly, of course, just the stock repurchase, which we exercised here in the first quarter. You know, we've talked about being able to utilize that opportunistically and really part of our strategy, the reason that you can actually step into a dislocated market and have the confidence to do a buyback is that you've got the strength of the balance sheet, which includes cash on hand. That's really what we're going for, and I think that provides another compelling reason to carry a potentially a higher cash balance than the company's historically done. Thank you. That concludes our Q&A session for today. I'll now turn the call back over to Mr. Yacob for any closing or additional remarks. I just wanna thank everyone for participating on the call this morning. I especially wanna thank our employees for the outstanding results they delivered in this first quarter. Thank you. That concludes the EOG Resources first quarter 2023 earnings results conference call. Thank you all for your participation. You may now disconnect your line.