Good day, everyone, and welcome to EOG Resources' Q2 2023 earnings results conference call. As a reminder, this call is being recorded. At this time, for opening remarks and introductions, I'd like to turn the call over to Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir. Thank you. Good morning, and 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 and 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, Treasurer and VP, Investor Relations and Finance. Here's Ezra. Thanks, Tim. Good morning, everyone. Our Q2 results reflect exceptional execution throughout our multi-basin portfolio. Production volumes, CapEx, cash operating costs, and DD&A all beat targets, driving another quarter of excellent financial performance. We earned $1.5 billion of adjusted net income and generated $1 billion of free cash flow. Year- to- date, we have generated free cash flow of $2.1 billion. That free cash flow and cash on the balance sheet funded year-to-date cash return to shareholders of $2.2 billion, including more than $600 million of share repurchases executed during the first half of the year. Taking into account our full-year regular dividend, we have committed to return $3.1 billion to shareholders in 2023, or about 67% of our estimated 2023 cash flow, assuming a $75 oil price, well ahead of our target minimum return of 60%. EOG's peer-leading regular dividend is currently the majority of the $3.1 billion of cash return committed to shareholders this year. Our sustainable growing regular dividend, which we have never cut nor suspended, remains the first priority to return cash. We also continue to leverage special dividends and buybacks to return additional cash depending on market conditions. Through the first two quarters of 2023, we've deployed more than $600 million to opportunistically repurchase shares during times of increased volatility. While our cash return strategy remains consistent, what has evolved since putting the $5 billion repurchase authorization in place over a year and a half ago, is the fundamental strength of our business. We continue to get better through relentless execution of and commitment to EOG's value proposition. We invest in high return projects across our multi-basin portfolio, adding lower cost reserves, which reduces our break-evens and expands our margins. We are now actively investing in five premium basins, more than any time in our history. Our foundational assets in the Delaware Basin and Eagle Ford continue to consistently deliver, and we are pleased by the outstanding progress across our emerging Southern 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 we invest and develop each asset at a pace that supports consistent execution and continued innovation. We continue to lower the cost basis of our company, utilizing technology and innovation that improves well performance and lowers well costs to sustainably reduce our finding and development costs. Efficiencies and infrastructure investments are lowering current and future unit operating costs and contribute to our emissions reduction efforts. Finally, we have further strengthened our pristine balance sheet this year while generating significant free cash flow and funding our transparent cash return strategy, which is designed to deliver consistent shareholder value through the cycle. Heading into the second half of 2023, our continued performance gains will be complemented by strong fundamentals. Oil demand has been resilient despite volatility in the first half of the year. Demand is showing signs of continued growth through the second half of the year. Strong inventory draws since the start of the year have pulled oil inventories below five-year averages. Refinery utilization remains high. Production growth in the U.S. is on pace to deliver similar rates as 2022, while exiting the year with significantly less activity as public companies continue to demonstrate discipline. It appears OPEC Plus are following through on announced production cuts. The culmination of these actions should further reduce inventory levels and place upward pressure on pricing through year-end. Regarding North American natural gas, while inventory levels remain above the five-year average, prices have firmed up recently, reflecting a reduction in natural gas drilling and an increase in demand from both power generation and LNG exports. These trends should support a more balanced supply and demand environment late this year and heading into 2024. We remain constructive on the longer-term gas story for the U.S., supported by recent LNG project approvals and the growing petrochemical complex on the Gulf Coast, and we are especially pleased with Dorado's place in the market as one of the lowest cost suppliers of natural gas in the U.S., with an advantaged location, EOG's value proposition is delivering results, and the strength of our business has never been better to deliver value for the shareholders through industry cycles and play a leading role in the long-term future of energy. Now, here's Tim to review our financial position. Thanks, Ezra. EOG delivered excellent operating and financial performance in all areas in Q2. Oil production increased 3% year-over-year, while total production increased 5%. Per- unit cash operating costs remained essentially flat from the prior year period, despite industry-wide inflation. Compared to Q1, however, per- unit cash operating costs declined by 5% and were lower in all four categories. We're beginning to see the benefits of lower cost improve our operating margin. The DD&A rate fell by 10% year-over-year, driven by the addition of reserves at lower finding costs compared to our production base. Capital expenditures came in at $1.5 billion, $130 million below our target and just slightly above the Q1 level. The difference was mostly due to the timing of non-well-related costs, such as infrastructure projects. Year-to-date, CapEx of $3 billion is 50% of the full year budget. The improving capital efficiency of our assets, consistent operational execution, along with the application of innovation and technology to lower costs, is making a big impact on the financial performance of the company. We earned adjusted net income of $2.49 per share in Q2 and generated free cash flow of $1 billion. Return on capital employed for the last 12 months is 29% at an average WTI oil price of $81 and Henry Hub natural gas price of about $5. Here's Billy to review operations. Thanks, Tim. I would like to first thank our employees for their commitment and dedication that led to another quarter of exceptional execution. EOG once again beat our forecasted targets and delivered a near perfect quarter. As a result, we have completed the first half of the year ahead on volumes and ahead on total per unit cash operating cost. Our volume performance in the first half of the year is due to several factors. The performance of new wells is outpacing our forecast, primarily in the Delaware Basin, part of which is due to our new completion design. We're also experiencing less downtime due to market interruptions than previously planned. Our investments in infrastructure, along with real-time data analytics, provided the control and flexibility needed to redirect sales volumes to different markets to maintain production. Unit cash operating costs for the first half of the year averaged 5% below the midpoints of our quarterly guidance due to a combination of several factors, including lower lease operating expenses, as well as reduced transportation cost. Lower workover and compression-related expense reduced LOE, while transportation costs benefited from the flexibility to sell into more favorable markets throughout the quarter. Credit goes to the cross-functional efforts of our production, marketing, and information systems teams, who remain focused on sustainable, low-cost operations quarter- after- quarter. We have line of sight to maintain these cost improvements throughout the year and as a result, have reduced our full year guidance for total unit cash operating costs. Operationally, EOG is firing on all cylinders. Our foundational Eagle Ford and Delaware Basin plays are delivering exceptional results, while our emerging plays benefit from learnings and technology transfer across our multi-basin portfolio. Our decentralized structure supports innovation in each operating area, which function much like independent technology incubators, and compounds the impact of that innovation by taking ideas born in one area and expanding them across multiple basins and across multiple functions. Across every operating area, our frontline engineers and geologists work the technology every day to lower cost and improve well performance. We look for strategic opportunities to vertically integrate certain services within the supply chain, where we find an opportunity to better align those services with our goals. That includes areas like downhole drilling motors, drilling mud, sand, and water. Developing such capabilities in-house significantly improves the cost structure of the company. This quarter, we're highlighting drilling performance improvements in the South Texas Dorado, South Powder River Basin Mowry, and the Ohio Utica Combo plays. Our emerging plays are moving up the learning curve faster due to the benefit of drilling advancements and the application of technology over the past decade. We continue to evolve our proprietary suite of applications powered by real-time, high-frequency data and analytics, to assist our frontline employees to collaborate and make decisions faster. The combined benefit of these efforts has already contributed to an increase of up to 25% in drilling feet per day for wells in our emerging plays this year. In our Ohio Utica play, we recently drilled a 15,700 foot lateral in 2.6 days and 100% in zone. Capital expenditures for the first half are also running light, due primarily to the infrastructure spend that has been deferred into the second half of the year. It is worth noting the economic impact of our investments in EOG-owned infrastructure. Our realized U.S. oil price in Q2 was $1.23 above the WTI, and U.S. natural gas was essentially flat to Henry Hub. CapEx for our drilling and completion program are right on track. The rate of change for inflation this year is consistent with what we had anticipated at the start of the year. We still see line of sight to limit year-over-year well cost inflation in 2023 to just 10%. While any additional softening of service costs this year has the potential to impact 2024, it's simply too early to predict. The market remains too dynamic, particularly given the constructive outlook for oil in the second half of the year. Furthermore, we remain focused on generating long-term, sustainable cost reductions, driven by utilizing the highest quality equipment and the highest performing teams, which are less exposed to the leading-edge price declines that we see in more marginal equipment. Our $6 billion capital program is forecasted to deliver 3% oil volume growth and 6% total liquids growth. In Dorado, our South Texas natural gas play, we delayed the timing of planned completions earlier this year, and about 5 wells have been pushed into early 2024. Thus, we reduced our full year gas volume guidance accordingly. We maintained our drilling pace in Dorado to build operational momentum and capture the corresponding efficiencies. As a result, we are seeing a 16% improvement in our drilling times for Dorado, as shown on slide 11 of our updated investor presentation. We are constructive on natural gas longer term and believe Dorado will be one of the lowest cost and lowest emission suppliers of natural gas in the US and will compete on a global scale. This year started out with many challenges, but also many opportunities to continue to improve the company. I'm very pleased with the progress our teams continue to deliver and remain optimistic about the second half of the year and how the company is positioned for the future. Now I'll turn the call over to Ken to discuss progress on lowering our emissions. Thanks, Billy. We're continuing to make outstanding progress on our emissions goals. As a preview to our 2022 sustainability report that will be published in September, we are excited to announce that we've reached three significant near-term goals well ahead of schedule. First, our 2022 GHG intensity rate of 13.3 metric tons of CO2e per Mboe is less than our 2025 goal of 13.5. Second, our 2022 methane emissions percentage is 0.04% of our natural gas produced and is significantly less than our 2025 goal of 0.06%. Third, we have achieved our zero, zero routine flaring goal in 2023, well ahead of our 2025 target and significantly ahead of the World Bank Initiative, which strives to attain zero routine flaring by 2030. We have also confirmed that our wellhead gas capture rate for 2022 was 99.9% of the gas produced. We continue to expand our in-house continuous methane monitoring technology, named iSense, and finished 2022 with 95% of our production in the Delaware Basin, covered by iSense monitoring. As a reminder, the power of iSense is incorporating continuous methane monitoring data with our production and facilities data and monitoring this data on a 24-hour basis in one of our four control centers. This enhances our ability to identify potential leaks and prioritize repairs that are needed in the field to minimize fugitive emissions. As with a number of EOG operations, it is anticipated that collection and integration of iSense data will lead to continuous improvement in facilities and production, design and operations. We're excited about the progress we've made in the last several years on our emissions performance and are very proud that we have such dedicated employees who are continually making our operations more efficient. Their innovative solutions and push to beat expectations have driven us to exceed our goals early. We are currently assessing new goals with our operations groups and anticipate publicizing those goals in the first half of 2024. Now, here's Ezra to wrap up. Thanks, Ken. Our Q2 results demonstrate, once again, that EOG's value proposition works. We invest in high return, low cost assets across a diverse multi-basin portfolio. We leverage technology and innovation to sustainably lower well costs and reduce emissions. These high return, low cost investments generate significant free cash flow to fund our transparent cash return strategy, backstopped by a pristine balance sheet to deliver consistent shareholder value through the cycle. Most importantly, our culture is at the core of our value proposition and is our ultimate competitive advantage. 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 one 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... Questioners are limited to one question and one follow-up question. We will take as many questions as time permits. Once again, please press star one on your touch tone telephone to ask a question. If you find that your question has been answered, you may remove yourself by pressing the star two key. We'll pause for just a moment to give everyone an opportunity to signal for questions. Our first question comes from Paul Cheng of Scotiabank. Paul, please go ahead. Thank you. Good morning. Ezra, can you hear me okay? Yes, sir, Paul, go ahead, please. Thank you. Two question, please. First, on the cash return on the free cash flow. Thank you that you are paying more than 100%, but just want to see how you determine that this is the right time to pay more than 100%, or how should we read that into the future? Given you're already in a net cash position, should we think that there's a little bit change in the management view and the payout is going to perhaps that closer to 100% until that maybe that market condition change? Also that whether we should read the second consecutive quarter of the buyback means that management now see the buyback as more of a ongoing part of the toolbox on your cash return. That's the first question. Second question, that, on the Dorado, the decision that to delay, the five well in this year, can you maybe then share with us. I think Billy had mentioned that, but can you share with us then what's the thinking behind the delay? I know that the street has been bugging you, that, you should delay, the Dorado, and you guys do it, in this quarter, but want to understand a little bit better in terms of the decision-making process behind. The, the full year guidance reduction, I think, is all related to that, right? Thank you. Sure, Paul. This is Ezra. I, I think I'll take that first question, and then, and then, Billy can address the, the second question regarding Dorado. Yeah, on the first one, it's a kind of a broad question on our cash return strategy. Hopefully, I hit on all the points that you were trying to get at. First, let's start with our guidance, which is, has always been the minimum of, of 60% of free cash flow. We've never guided to that 60% as being a, a specific target. It's always been a minimum of 60% of our free cash flow, and the reason we like that guide is, is honestly, it's pretty simple and dynamic. It's, it's easy to understand and communicate. The minimum of 60% is it can be supported over a range of price scenarios, especially when there's a pullback in prices. Really, we can underpin that with the growing, you know, sustainable regular dividend that we, we highlight and talk about so much. That, that's what can provide really a meaningful amount of cash return through the cycle. Again, I do want to emphasize, we consider that regular dividend to still be the true hallmark of a strong and improving, underlying business, and we like the message that it sends. We increase that regular dividend commensurate with the strength of the business, lowering the cost basis of the company, and also, in consideration with strengthening our balance sheet. More specifically, to kind of payouts that you've seen this year, we do recognize the value of opportunistic buybacks as part of that, that, cash return strategy as a way to, to create shareholder value. I would say that really the decision that, that you've seen, is consistent with our overall capital allocation strategy, where we buy back shares in an opportunistic manner, as a means to return cash above and beyond that minimum of 60%, in addition to our regular dividend. A t times, instead of paying a, a special dividend, we basically evaluate that buyback just like we do any of our other investment decisions, whether it's exploration or drilling high-return oil and gas wells or investing in infrastructure. It's how is that investment going to create long-term shareholder value? That's what we primarily focus on. The percent will fluctuate depending on a specific moment in time and what the circumstances are around our cash return strategy. What we have guided to and what you can bank on is, it's the minimum of 60%. We highlighted we paid 67% out last year, and we're very well positioned halfway through the year right now, where we've already committed or paid 67%, as I highlighted in the script. For the Dorado timing, I'll hand it over to Billy. Yes, good morning, Paul. On Dorado, we had indicated earlier in the year that we were evaluating the potential to delay some of our completions in Dorado. We are consistent with that strategy. We are elected to maintain our drilling operations there. We're seeing the benefits of that decision to play through the efficiencies we're gaining on the operational side. We've given some color on that in our new investor deck, illustrating the improvements in drilling times there in that place. We're very pleased with that progress. Don't forget, our investment strategy includes a gas price of investing for $2.50. That's our premium price deck when it relates to gas prices. We certainly were watching inventory levels on the gas side and, and just prudently decided to delay a little bit of the completions there, until we saw the, the fundamentals improve. We, we'll be just laying some of those completions as we go into the late this year, which pushes five wells into next year. That's simply the thinking on that. Our next question comes from Neal Dingmann of Truist. Neil, the line is yours. Morning, guys. Nice quarter. Ezra, my question's on well pro-productivity, specifically looking at that slide 10 of yours. Certainly appears that your Delaware's wells continue to notably improve. What I'm wondering, is this driven more by just continued DNC efficiencies, or is it more on formational targeting? I ask that, I just, you know, was looking at the bottom through left corner of those pies, and it looks like, over the years, not only the well's improving, but it looks like they're becoming more focused on that Wolfcamp oil. I'm just wondering what, what is driving that? It does look, it does look very positive. Thank you, Neil. This is Ezra. I'm actually gonna let, Jeff Leitzell, step in and address, your question. Hey, Neal, this is Jeff. O n our Permian productivity, we've been really happy with how the wells have performed in the Delaware, through the first half of the year. All of our primary targets, they're performing right now as forecasted or better, and I'd say this is primarily due to just our stack pay co-development strategy in combination with the new completion design we've talked about, which has continued to, you know, be really successful in our Wolfcamp targets. In regards to that new completion design, just kind of a quick update, we're still observing a 20% increase in both first-year production and EUR for both oil and BOEs in the Wolfcamp. For the full year of 2023, we're planning on bringing out about 70 total Wolfcamp wells with this new design, which is nearly twice the number we've completed in 2022. Also with it, you know, as we've talked about, we're continuing to test and expand the technique in other areas and targets in the Delaware Basin, along with all across our emerging plays in our multi-basinal portfolio. Yeah, very helpful. Then. Sorry about that. My second question is just on OFS cost. In the past, you all have been among the best, not only just what I would say, renegotiating contracts, but I know in the past, you've been able to stockpile pipe at the right time and all those sort of things. I'm just wondering, is maybe give us a little bit details of how you see the market now. Yes, Neal, this is Billy. Certainly we're seeing the service prices start to soften, these savings from lower service costs really probably won't manifest into lower well costs until later this year and certainly into 2024. These leading-edge prices are falling across various products and services for the industry, and certainly it varies depending on the product and the area. I'd add that there are several factors that kind of reflect kind of where our 23 capital program is. As a company, we, as you mentioned there, we focus on sustainable cost reductions through our operational efficiency gains. As a result, we do seek out the highest performing equipment and crews, super-spec rigs, electric frac fleets, et cetera, that's really less exposed to some of these headline inflation numbers that we're seeing on the more marginal end, equipments on the spot market. The second part of that is we really anticipate that service costs would moderate through the year when we put our plan together. Since, rig count really peaked back in November, and we built our plan in February, expecting well costs would increase no more than 10% relative to this last year. Things are really playing out exactly the way we planned. Another point there is we do try to secure about 50% of our well costs in the start of any given year, that really helps insulate us from inflationary impacts to our activity levels. And then lastly, you know, based on how we do manage our business, we're less exposed to the volatility and service cost in any given year. I would remind you, as you kind of alluded to there, our well costs really only increased about 7% last year compared to the over 20% inflation that we saw in the market. Yeah, it really helps us kinda manage our activity level with confidence as we go through the year. We'll certainly remain flexible as we look into next year to see how we can position ourselves for next year. Our next question comes from Arun Jayaram of JPMorgan. Arun, the line is yours. Yeah, good morning. I was wondering if you could help us think about the second half oil production profile for EOG. It looks like your updated guidance points to a slight sequential decline in 3Q. I just wanted to get some thoughts on, you know, if there's still kind of confidence on hitting the midpoint of the oil guidance range, 'cause that would imply a fourth quarter oil production number in the mid 480s to upper 480s. Help us think about the sequential movement in volumes in the second half of the year. Yeah, Arun, this is Billy. Yeah, I think the thing to keep in mind is we do operate in more than one basin and multiple plays, and we have varying sizes of well packages in each play. The timing of really, the quarter-to-quarter variance in production is really driven by the timing on a quarter-to-quarter basis of how these packages across different plays come online. Even within the quarter, how that varies, month- to- month within the quarter can vary, can drive the volume profile. I would remind you, and I just ask you to go back and look at the change from the Q1 to Q2. It's actually larger than what you're seeing in the forecast from the Q3 to the fourth quarter. We are maintaining ratable activity throughout the year, and just as a matter of simply timing on bringing on some of these larger packages. So far this year, we've either met or exceeded our volume on forecast, and have complete confidence in being able to meet the midpoint of our guidance. Great. Just to follow up, I wanted to get some thoughts on the Ohio Utica. One of the midstream providers, highlighted how they're building out, call it a backbone in the Utica. Looks like you may be the anchor E&P, for that investment. Love to get some thoughts on the Utica. We did see that you maybe pulled your till guidance down a little bit this year. Just an update would be helpful. Arun, hey, good morning, this is Lance. Yeah, I would say what we're most focused on right now is just getting all the midstream infrastructure in place. We do have 2 ongoing projects that are going on. We've got one in the north and then another one in the south as well. What we're really focused on is linking our production to the available processing capacity. Really what's happening is it's a consistent strategy that we've done in all our plays, where we're gonna have a balance of EOG-owned infrastructure, along with strong relationships with really good working third parties. We're gonna be need both in the Utica combo up there, right now, just focused on setting up 2024 and beyond with the infrastructure. Yeah, Arun, this is Ken. I just wanna give you a quick update on the, on the Utica. W e're making excellent progress on that, that program this year. We do plan to bring a four-well package online this month, and our frac crew will be starting up again in a few weeks. You know, the wells we drilled and completed in 2022 do continue to deliver at our expected performance, and we also continue to add acreage and look for additional low-cost opportunities to add to our position up there. Our next question comes from Doug Leggate of Bank of America. Doug, the line is yours. Thanks. Good morning, everyone. Ezra, it's a long time since we had to worry about the US growing too quickly, and all the whole market share battle issues that we all lived through over the last four or five years with OPEC. In your opening remarks, you did talk about Saudi's decision to support the price to extend their cuts. I'm wondering, when you sit in the boardroom and you look at what is an artificially high oil price, because Saudi is cutting production, arguably to support price, how do you think about what that means for your business? The appropriate level of spending, the, you know, the, the right allocation of, one could call it windfall cash flow because it's not a, you know, it's an artificially supported price by definition. I'm just curious how you think about what that means for your business. Your cash flow is basically being subsidized again by Saudi. Good morning, Doug. Thanks for the question. This is Ezra. Yeah, it's a dynamic environment, right? We had a large SPR release last year that increased the inventory levels kind of entering this year. As those have started to come down, now they're gonna start. All indications are that they're gonna start coming down significantly faster because OPEC Plus, as I said, looks like they are gonna support, you know, their cuts to kind of bring those inventory levels down. Your point is, it's a very interesting one, and it's one we discuss regularly, obviously, and we do different scenarios around. In general, what I'd say is, you know, on this year, what we look at is, you know, whether it's crude, products, gasoline, distillates, either globally or domestically, you know, inventory levels are basically in the lower half of a five-year range. That's a choppy five years, like we said, because of 2020, with COVID, and then, of course, with 2020 with half of the year being exceptionally low and then half of the year being somewhat, you know, artificially higher with the SPR. Outside of last month, you know, the last month we've seen kind of gasoline and distillate demand being just a bit weaker domestically, but otherwise, products demand has really been in line all year with our expectations. Crude demand has continued to increase, continued to grow. Not only with the, the high inventory levels that we entered the year with, but really, supply, I think, has surprised everybody a little bit to the upside. It's not necessarily, as you pointed out, U.S. growth, or new barrels, but it's really historically displaced barrels that are back online. You know, dominantly, what I'm talking about is Venezuela and Iran, and maybe a little bit of, you know, I think everyone's been a little bit surprised, at least we have, on the resiliency of, of the Russian barrels to hit the market. We don't forecast those as having a significant longer-term effect. One thing that, that we think about when we talk about the spare capacity that's now offline with OPEC Plus is, some of that spare capacity is really offsetting the previous spare capacity I just highlighted from Venezuela and Iran. It is a little bit different from prior years. Ultimately, what we see is the increasing oil demand overall. E xiting this year, you know, most estimates have it, at least at 102 to exit the year, which would put us at a significantly high point. Now, to your ultimate question on how we actually look at that internally, you know, our planning begins with everything we just talked about, kind of an evaluation of the macro environment with respect to supply and demand fundamentals, including spare capacity that's offline just by choice, and spare capacity that's offline for, you know, true geopolitical reasons. Then more than that, Doug, it, it really does come down to evaluating across all of our premium assets, both individually and collectively, we evaluate the correct investment level for each of those, the activity levels, to make sure that each asset will deliver improved metrics year-over-year. Ultimately, that'll be driving optimized returns and free cash flow generation at the corporate level, and that's what will continue to set up EOG to create shareholder value in the near and long term. Honestly, the growth ends up being a real output of our ability to invest and continue to lower the cost basis of the company and provide, you know, both near-term and future free cash flow generation. It's an interesting dilemma, Ezra. Thank you for your perspectives on that. A quick follow-up, hopefully, it's a quick one. I wanted to touch on I think this was asked earlier, but I wanted to elaborate just a little bit. The, the comments about inflation limiting to 10% this year, but it's too early to talk about 2024. You know, you're the pretty much the second to last company to have your earnings call this, this quarter, and pretty much everybody else has been pointing to, yeah, we're going to see some deflation in 2024. Are you just being conservative, or do you genuinely believe that there's still upside risk to capital in 2024 from inflation, I mean? No, Doug, I don't think we are anticipating that you'll see inflation into next year. I think what the comment was, you know, we started out the year. Let me just clarify something. You know, we saw inflation last year coming in the business. Rig counts kind of peaked in November of last year. We anticipated we would see a deflation in the market going into this year, so we built our plan based on the fact that our well cost in 2023 would increase no more than 10% relative to 2022. That's where the 10% comment comes from. As we go into 2024, I think we recognize and clearly we're seeing deflation in our business. I'd say it's too early to predict what that level of deflation is gonna do to our well cost next year. There's still a lot of market dynamics that we see in the business as Ezra just went through, so it's early to predict what the impact that's gonna have on next year's capital program, as well as kind of how we choose to develop our plays across the different plays that we have to invest in. That's the comment about too early for next year. It's just too early with the market dynamics we have for next year. Our next question comes from Leo Mariani of Roth Capital Partners. Leo, please go ahead. Yeah, good morning. Just wanted to kind of touch base on, on some of the emerging plays, really thinking about kind of Utica and PRB, and also some of the undisclosed, you know, exploratory plays, you know, out there as well. Just trying to get a sense, you know, if, if generally speaking, you've seen any increased competition, you know, in these plays during the, the course of, of 2023. I mean, it still seems like EOG is being a bit of a lone wolf, in pursuing, some of these plays where, you know, others, you know, maybe aren't, you know, doing as much, but maybe there's more kind of going on behind the scenes that you guys can help out with here. Yes, Leo, this is Ezra. Yeah, we continue to see very limited competition domestically on any exploration. I think, and, and you can kind of see that too, just in the, in the public comments that are made. Most operators, companies, whether private or public, have really kind of picked a basin and are honing in on more of a, you know, a drill down kind of specialist manufacturing mode. We continue to explore, and as Ken said, we're still looking to put on low cost, high quality bolt-on opportunities in some of those plays. With respect to, you know, the Utica and PRB, in specific, you know, it's a little bit early this year on Utica. We're pleased with what we're seeing on the operations side. As Ken said, we'll get a completion spread in there and get some results here coming up. On the PRB, we've had a very strong year. Everything's really fallen into line there. Again, the PRB and Dorado are really benefiting from more of a continuous operations program this year, as we focus on, you know, Austin Chalk and a little bit of co-development in the Eagle Ford and Dorado. We center most of our focus in the PRB, in the Southern PRB, is basically on the Mowry this year. Shifting to international for just a minute on the exploration side. As you guys know, we both explore onshore and offshore in shallow water internationally. I would say onshore, you know, there's still limited competition on the exploration side for un-conventionals in what we see. Of course, it's still a high bar that we have for international opportunities to. They really do need to compete with our domestic portfolio. W e're not just exploring internationally to try and say that we've got something internationally. It really needs to compete and deliver value for the shareholders. Then in the shallow water, probably a bit of the same, maybe a little bit more exploration out there. Dominantly, I think what you're hearing about in offshore international exploration is a bit more in the deep. E ven ultra-deep water than really in the shallow water that we're focused on. Okay, appreciate that. Just wanted to turn to CapEx, you know, for a minute here. You talked about it just a little bit in your, in your prepared comments, but you guys are kind of at 50%, you know, of the budget, you know, in the 1H, kind of right on where, what you expected here. L ooking at guidance, 3Q CapEx is up, you know, fair bit, you know, versus 2Q. Do we expect to see kind of a commensurate drop, you know, in 4Q capital to kind of get you back to that kind of midpoint on the full year? Just trying to get a sense of kind of CapEx cadence in the second half. Yeah, Leo, this is Billy. On the CapEx, I'd say, you know, our drilling and completion activity has been very ratable throughout the year, and we're pretty much on track with what our plan had laid out. The reason Q3 is up is simply due to the timing of our non-drilling and completion capital, and it moved from Q2 into the second half of the year. Everything else, all of our drilling and completion CapEx is really on pace with what we laid out. We've spent about half the CapEx for the year, and we've completed about half the wells that were planned for the year. I'd say everything is pretty much on track. Q4 will be a, a reflection of how that, non-DNC, non-drilling and completion CapEx gets spent in the third. Our next question comes from Scott Gruber of Citigroup. Scott, the line is yours. Thanks, good morning. I'll just go ahead and ask two questions up front here, since they're related. You guys know to continue the efficiency gains in the emerging plays. What are you seeing in terms of efficiency gains, you know, more broadly across the portfolio? O bviously, the gains are always greatest in, in the new plays, but I'm curious if you're still seeing, you know, solid gains more broadly across the portfolio. If you are, you know, without adding rigs and frac crews next year, just curious, you know, how much the, the overall well count could potentially grow next year, just on the back of those efficiency gains? I s that a kind of low single-digit type figure, potentially a mid single-digit figure? Yeah, Scott, this is Billy. We're still seeing continued improvements, although, as you noted, the at a lesser pace in our more active foundational plays, like the Delaware Basin and the Eagle Ford, simply because we've been active there for a long period of time. As you noted, the emerging plays benefit from that transfer of technology more rapidly, I guess, than some of the existing plays. Really, I'd just like to tie that back in a little bit. We still experiment quite a bit with applying technology across all of our assets, and especially is true of our foundational plays. The efforts we've gone to put in our data systems and track data across our plays gives us a lot of insights in how to how things are performing. That goes back to our bringing in-house our our drilling tools, our drilling motors, those kind of things. We still see improvements. In some of our supplemental deck in the back, you can see some of the increase in drilling times, say, in our Permian program, and how that's improved over time, and we continue to drive that down. T hat's an effort there, and then the same for the Eagle Ford. I think those are some of the slides in the back of our deck. We're still seeing improvements in both the drilling times and the completed lateral feet per day. We're very encouraged with that because that enables the technology transfer, enables quickly to go to the emerging plays and continue to reduce our cost. How that translates into next year, again, I'd say we're still a bit early to see how things are going to play out, on the macro side, you know, what the market looks like. I t's early to see, but I'm encouraged with the efficiency gains that we're seeing that we'll continue to find sustainable ways to improve our business and lower our cost basis going forward. Our next question comes from Derek Whitfield of Stifel. Derek, please go ahead. Good morning, all. For my first question, I wanted to focus on long lateral development, which has been a theme throughout Q2 and is a development you're highlighting in the Eagle Ford with an over 15,000 foot lateral this quarter. As it relates to the Eagle Ford and perhaps more broadly for your portfolio, are there considerations beyond lease geometry and legacy development that would limit your ability to pursue more 15,000 foot laterals? Yeah, Derek, this is Ken. Really, you know, longer laterals are a way we're increasing our capital efficiency in the Eagle Ford. If you look at it, we've drilled over 85 wells with laterals over 2.5 miles long across the Eagle Ford, and we've utilized these longer laterals over the last 5+ years where appropriate. You think about it, the faulting across the Eagle Ford does make these longer laterals challenging, but our data-driven approach and multidisciplinary teams enable us to steer the laterals within some narrow target windows and apply an optimal completion design to maximize that capital efficiency. These longer laterals have, have really contributed to us lowering our cost basis in the Eagle Ford and, and are an example of how we're focused on increasing our efficiencies, even in that play, where we've been developing it for over 10 years. Yeah, Derek, this is Billy. I'd just might add, you know, the lessons we're learning from our longer laterals we're pushing in the Eagle Ford, we're applying across all of our portfolio. W e're seeing those opportunities across every asset that we have. Our next question comes from Neil Mehta of Goldman Sachs. Neil, please go ahead. Yeah, thanks very, thanks very much. The first question is just around Dorado. Maybe you could talk about how that's tracking versus your target. How do you think about the timing of, of recompleting those Dorado wells? Yeah, Neal, this is Ken. As far as the, as the way that's tracking, the 5 wells that we've deferred, we would see that we'd be completing those early in next year. You know, it's still early in the play, and, and the wells in our core area are really performing as we've anticipated. Timing dynamic. Then, would love your perspective, stepping back to talk about the M&A markets. We've seen a pickup in consolidation throughout U.S. shale. How do you think of EOG's role in future consolidation? Is the best strategy, given the exploration program that we've been talking about here, is to continue organically or to grow the business? Do you think there are gonna be opportunities a la Yates to, to bolt on? Yes, Neal, this is Ezra. I think, you know, we've been 30 years strong as an organic exploration company, you know, 20 years separated there. I think that's. The thing about that is, the way we look at these deals is that it's similar to how I described every investment decision, is it's a, it's a returns-based decision. How is that investment going to create long-term shareholder value? We don't think of M&A versus exploration, but as a first mover, looking, trying to capture the sweet spots of new plays, obviously, you can get a lower cost of entry, and that offers a higher return. The exploration, I think, organic exploration, you know, stands on itself. As with regards specifically to M&As, you know, we're aware of opportunities. We evaluate many, many opportunities. The challenge with it always comes back to: Is that opportunity really gonna be additive to the corporate portfolio? Is it really gonna be something that is better than what we're already drilling? Is it something that's gonna add to the returns and add to the 10 billion barrels of equivalents that we've already captured as premium resources? We continue just to, just to, you know, evaluate opportunities, but kind of come up short with that evaluation. Our next question comes from Roger Read of Wells Fargo. Roger, please go ahead. Yeah, good morning. I'd like to, to come back to two things that have been discussed a little bit. One, Ezra, just, you talked about, you know, the, the low carbon advantage or the emissions advantage of Dorado. I was wondering if you could go in a little more depth on specifically what you see there. My other question would just be on, the inflation side. With oil at 80, 85 right now, aren't we, sitting in a situation where inflation pressures might be reversing rather than behind us? If that's not a right way to look at it, I'd be curious, you know, what you are seeing that says deflation is, is the right track here. Yeah, Roger, this is Ken. I'll go ahead and answer the, the first part of that with Dorado. You know, we're really confident that our, our gas production at Dorado generates significant returns and, and that that development will be both operationally efficient and have a small emissions footprint because of the dry nature of the gas and really the proximity of that gas to the Gulf Coast markets. Yeah, Roger, this is Billy. On the inflation question, I think you're spot on. I think that's why we're saying, you know, certainly we see deflation in the market today, but it's too early to think about 2024 because of the dynamic markets that we're seeing play out. We're gonna be patient and watch the market and see how it develops before we make any comments about where cost would go in 2024. I think as a company, we're certainly well positioned to take advantage of any opportunities that are presented. Our strategy about contracting and seeking out the highest performing crews are things that drive really our focus on sustainable cost improvements through the long term, and that's really what drives our advantage over trying to capture the, the premium barrel, premium price for all of our products. We have no further questions on the phone line. I'll hand back to Mr. Yacob. We appreciate everyone's time today on the phone call. Thank you to our shareholders for their support. I just want to give a special thanks to our employees for delivering another exceptional quarter. Thank you, everybody. Thank you for joining. This concludes today's call. You may now disconnect your line.