Operator: Good day, everyone, and welcome to the EOG Resources' Third Quarter 2024 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 the Investor Relations Vice President of EOG Resources, Mr. Pearce Hammond. Please go ahead, sir.

Pearce Hammond: Good morning and thank you for joining us for the EOG Resources’ third quarter 2024 earnings conference call. An updated investor presentation has been posted to the Investor Relations' section of our website and we will reference certain slides during today’s discussion. A replay of this call will be available on our website beginning later today. As a reminder, this conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG’s SEC filings. This conference call may also contain certain historical and forward-looking non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures and related discussion can be found on the Investor Relations' section of EOG’s website. In addition, some of the reserve estimates on this conference call may include estimated potential reserves, as well as estimated resource potential not necessarily calculated in accordance with the SEC’s reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO; Jeff Leitzell, Chief Operating Officer; Ann Janssen, Chief Financial Officer; Keith Trasko, Senior Vice President, Exploration & Production; and Lance Terveen, Senior Vice President, Marketing & Midstream. Here’s Ezra.

Ezra Yacob: Thanks, Pearce. Good morning everyone and thank you for joining us. Since the end of 2020, EOG has generated more than $22 billion of free cash flow and more than $25 billion in adjusted net income. We've increased our regular dividend rate 160% and including both regular and special dividends paid or committed to pay more than $13 billion directly to shareholders and $3.2 billion indirectly through share repurchases, all while reducing debt 35%. EOG has a history of delivering consistently strong financial and operational results, and the third quarter is simply more of the same. Led by our employees' commitment to operational excellence and capital discipline, we outperformed on oil, natural gas and NGL volumes for the quarter as well as beating expectations on per unit cash operating costs. We generated $1.6 billion of adjusted net income and $1.5 billion of free cash flow and returned $1.3 billion of that free cash flow back to our shareholders through a mix of our regular dividend and opportunistic share repurchases. In addition to announcing third quarter results yesterday, we demonstrated confidence in our ability to generate strong free cash flow in the future as well as our continued commitment to return a significant portion of cash to our shareholders by increasing the regular dividend 7% and boosting our share repurchase authorization by $5 billion. Cash return to shareholders begins with our focus on the regular dividend, which has never been reduced or suspended in the 27 years since we've been paying one, and it reflects our confidence in the increasing capital efficiency of our business going forward. And we continue to improve our capital efficiency by leveraging technology and innovation across both our foundational and emerging assets. That is one of the key advantages of operating in multiple basins. We are able to drive improvements to operational performance through technology transfer between those basins. We are drilling further and faster than at any time in our history, completing wells with fewer people and less equipment due to efficient operations, and we continue to capture additional value through our marketing strategy. EOG's performance is sustainable, because it's driven by our culture, empowering each employee to be a business person first, focusing on returns and seeking ways to improve the business every day. Our culture is our competitive advantage and combined with focus on sustainable value creation through the cycles, gives us confidence in our ongoing performance as we finish 2024 and position ourselves for 2025. In a moment, Jeff will provide some early commentary on our 2025 capital program, but our investment strategy always begins with capital discipline, balancing short and long-term free cash flow generation, return on capital employed and return of capital to shareholders. We also consider the macro environment in which we are operating. And currently, the overall macro environment remains dynamic. Oil inventory levels are below the five-year average with both supply and demand showing moderate growth year-over-year. We expect to finish 2024 with strong demand, slowing into a seasonally lower first quarter and then increasing throughout the rest of 2025. Domestically, while efficiency gains continue across the industry, we anticipate another year of slower US liquids growth grounded in the lower number of active drilling rigs and drilled but uncompleted wells. Regarding North American natural gas, inventory levels have moved closer to the five-year average throughout the year due to a combination of producer discipline and increased demand driven primarily by power generation. We remain optimistic on the long-term outlook for gas demand beginning in and increasing throughout 2025 from additional LNG projects coming online and ongoing increases in power generation. Finally, last month, we released our annual sustainability report for 2023, highlighting our leading environmental performance and commitment to safe operations. We achieved a GHG intensity rate below our 2025 target for the second year in a row and achieved a methane emissions percentage at/or below our 2025 target for the third consecutive year. Our in-house methane monitoring solution has progressed beyond the pilot phase and is integrated into our standard operating procedures. And our carbon capture and storage pilot project is operational, and we stand ready to deploy our learnings to future operations. Our consistent sustainability performance is a result of our empowered and collaborative workforce and our continued investment in innovation and technology to achieve not only leading environmental performance, but also strong and consistent safety performance throughout our operations. This year's report highlights our innovative culture that drives EOG's mission to be among the highest return, lowest cost and lowest emissions producers playing a significant role in the long-term future of energy. Now here's Ann with details on our financial performance.

Ann Janssen: Thanks, Ezra. EOG continues to create long-term shareholder value. During the third quarter, we earned $1.6 billion of adjusted net income and generated $1.5 billion of free cash flow on $1.5 billion capital expenditures. Third quarter capital expenditures were in line with forecast, and we still expect our full year capital expenditures to be about $6.2 billion. Cash on the balance sheet at quarter end is temporarily higher due to the postponement of certain tax payments until the first quarter of next year from disaster relief granted for severe weather events in Texas, including Hurricane Barrel. Our ongoing marketing strategy to diversify and expand our access to premium markets also delivered exceptional results during the third quarter with peer-leading US price realizations of $76.95 per barrel of oil and $1.84 per Mcf for natural gas. Finally, we paid a $0.91 per share dividend and repurchased $758 million of shares during the quarter. Year-to-date, we have generated $4.1 billion of billion of free cash flow which helped fund $3.8 billion of cash returned to shareholders. Of that $3.8 billion, $1.6 billion was paid in regular dividends and was complemented by $2.2 billion in share repurchases through the third quarter. Taking into account our full year regular dividend, we have committed to return $4.3 billion to shareholders in 2024 and we are on track to exceed not only our minimum cash return commitment of 70% of annual free cash flow, but also last year's cash return of 85%. The EOG's commitment to high-return investments is delivering high returns to our shareholders. Yesterday, we were pleased to announce a 7% increase to what is already a top-tier regular dividend, not only for our industry but the broader market. This increase reflects our confidence in the fundamental strength of our business which continues to get better through consistent execution of EOG's value proposition. Efficiencies and technology applied throughout our multi-basin portfolio continue to sustainably improve EOG's capital efficiency. A growing sustainable regular dividend remains the foundation of our cash return commitment and we believe is the best indicator of the company's confidence in its future performance. In addition to the dividend increase, the Board approved a $5 billion increase in our share repurchase authorization to supplement the $1.8 billion remaining on the authorization as of quarter end. The total $6.8 billion buyback capacity retains our flexibility to deliver on our cash return commitment to shareholders. Over the last several quarters, we have favored buybacks to complement our regular dividend and we will continue to monitor the market for opportunities to step in and repurchase shares for the remainder of the year. EOG's balance sheet underpins the financial strength of the company and remains a strategic priority. To optimize EOG's capital structure going forward, we intend to position our balance sheet such that our total debt-to-EBITDA ratio equals less than one times at $45 WTI. We believe this is an efficient and prudent long-term capital structure for a cyclical industry that will support our commitment to deliver shareholder value. As a result, we anticipate refinancing upcoming debt maturities, increasing our debt balance to $5 billion to $6 billion range in the next 12 to 18 months and maintaining our cash balance at levels similar to what we have carried for the last two years. By managing our debt levels toward this more efficient capital structure, we are increasing our capacity to return cash to shareholders. Now here's Jeff to review operating results.

Jeff Leitzell: Thanks, Ann. We delivered another outstanding quarter, thanks to our employees and their consistent execution across our multi-basin portfolio. Their focus on continued improvement through innovation, technology advancements and operational control is why our third quarter volumes and per unit cash operating costs beat expectations. Oil volumes beat our forecast, primarily due to better-than-expected productivity from new wells, driven by continuous improvement to our completion designs. Year-over-year, we have increased our maximum pumping rate capacity by approximately 15% per frac fleet on average. The benefit is twofold: Faster pump times and better well performance. Higher pumping rates provides our team with the flexibility to tailor each high-intensity completion design around the unique geological characteristics of every target. This, in turn, has helped to maximize the stimulated rock volume in the reservoir, resulting in improved well performance. Efficiency improvements due to faster pump times, combined with stronger well performance have more than offset the additional cost for these increased pumping rates. As a result of third quarter volume performance beats, we are once again raising full year guidance. Our oil production midpoint has increased by 800 barrels per barrels per day, natural gas liquids by 2,800 day and natural gas by 24 million standard cubic feet per day. We also beat per unit cash operating cost targets during the third quarter. The primary drivers were lower lease operating expense due to less workover expense and fuel savings. We now expect our full year per unit cash operating cost to be lower than forecasted and have reduced guidance accordingly. Our capital expenditures in the third quarter were in line with our forecast with only minor differences primarily due to timing of operations. In addition, well cost deflation driven primarily by efficiencies is playing out as we had forecasted at the start of the year, resulting in a 3% to 5% year-over-year decrease in well cost. As a result, our expectations for full year CapEx remain unchanged at $6.2 billion at the midpoint. The efficiency gains we continue to realize this year demonstrate the value of our multi-basin portfolio and decentralized structure. Ideas born in one operating area are replicated across multiple basins through technology transfer. Two examples of innovation, expanding through our portfolio and driving efficiencies this year are extended laterals and our in-house motor program. Average lateral lengths for our domestic drilling program continued to increase. In the Delaware Basin, we now expect to drill more than 70 3-mile laterals this year compared to our original forecast of 50. We've also set a new lateral length record in the Eagle Ford not only for EOG, but for all of Texas. Our Aspen A 1H well was drilled in our western acreage and has a lateral length of over 22,000 feet. As we highlighted last quarter, longer laterals allow for more time focused on drilling downhole and less time moving equipment on surface, decreasing overall downtime in days to drill. In addition, longer laterals help unlock new potential from acreage that might not otherwise meet our economic thresholds. EOG's in-house motor program also continues to pay dividends. In the Delaware Basin, we are testing the limits of our drilling motors in the shallower Leonard Shale and Bone Spring formations. While drilling the production hole section, we attempt to drill as much of the vertical curve and lateral portions of the wellbore with one motor run. Historically, this operation requires a minimum of three motor runs and two trips, which is a pause in drilling to pull a motor out of the wellbore and replace it with a new one. As a result, we have eliminated over one full trip per well in the shallower Delaware Basin targets. Given that each trip can cost $150,000 or more, the cost savings and efficiency gains from using better designed higher-quality motors continues to add significant value to our drilling program. This is just one of several examples of the value the EOG Motor program has created. Looking company-wide since the start of 2023, we have increased our drilled footage per motor run by over 20% versus third-party rental options. As we continue to test, learn, and redesign our drilling motors, we see substantial upside to our future drilling performance as we expand motor innovation throughout our multi-basin portfolio. In Ohio, we've made significant progress this year transitioning the 225,000 net acres of the volatile oil window in the Utica play from delineation into development. We now have five packages online and producing for more than 100 days, three of which have been producing well over 180 days. Both oil and liquids performance continues to meet or exceed expectations demonstrating the premium quality of this play. We are also capturing sustainable operational efficiencies through multi-well pad development and continuous operations. On the drilling side, the Utica provides an ideal operational environment to make significant gains quickly. We have decreased drilling days to drill three-mile laterals 29% year-over-year and have already achieved a record of drilling more than two miles in a single day. We also have made significant gains on the completion side, achieving a nearly 13% increase in completed lateral feet per day compared to last year. Over the next few years, activity in the Utica will continue to be primarily focused in the volatile oil window, where we anticipate our well costs will average less than $650 per effective treated lateral foot with finding cost and development costs in the range of $6 to $8 per barrel of oil equivalent. For 2025, we anticipate a 50% increase in Utica activity as we continue to leverage consistent operations to achieve additional economies of scale. Our large contiguous acreage position lends itself to developing a long-life, repeatable, low-cost play competitive with the premier unconventional plays across North America. Previewing 2025 company-wide, with the outstanding performance we have delivered this year, we do not see a need to significantly adjust activity next year. We do, however, expect very minor shifts in activity between basins with a continued increase in activity in the Utica and another year of actively managing our Dorado investment with a one-rig program. This will allow us to continue to capture some economies of scale across our emerging assets and advance our technological understanding of these plays while delivering the operational and financial performance that our shareholders appreciate. Now, here's Ezra to wrap up.

Ezra Yacob: Thanks Jeff. EOG recently celebrated our 25th anniversary as an independently traded public company. And while many things have changed across our industry, EOG's fundamental strategy and commitment to creating share value for our shareholders has remained consistent. First, our commitment to capital discipline begins with reinvestment at a pace to support continuous improvement across our assets delivering returns through the cycle, generating free cash flow, and maintaining a pristine balance sheet to support a sustainable growing regular dividend. Second, our strong operational execution begins with being a first mover in exploration to maintain a low-cost, high-quality multi-basin inventory. We leverage in-house technical expertise proprietary information technology and self-sourced materials help drive well performance and cost control, and we focus on a balanced approach to product, geographic, and pricing diversification to drive margin expansion. Third, we are committed to safe operations, leading environmental performance and stakeholder engagement. Our sustainability report highlights progress on our emissions reduction pathway, as well as overall environmental stewardship. And finally, our culture is our competitive advantage. A decentralized non-bureaucratic organization places value creation in the field at the asset level and in the hands of each of our employees. We take pride in our collaborative, multidisciplinary teams that drive innovation, utilizing our technology and real-time data collection to drive decision-making. Thanks for listening. Now we will go to Q&A.

Operator: Thank you. [Operator Instructions] And our first question today will come from Steve Richardson with Evercore ISI. Please go ahead.

Steve Richardson: Hi, good morning. I was wondering, if we could start as the optimization of the balance sheet. This is a new wrinkle from the company. And I wonder, if you could just talk about this incremental gross debt that you're looking at adding the time frame? Should we think about that $2 billion coming concurrent when you would look to refi the existing maturities? And then also the knock-on of that is -- how do you look at redeploying that cash, assuming into the buyback? And does this mean that you'll be taking shareholder returns above, sustainably above that minimum commitment for the next couple of quarters. Maybe just talk about time frame around that, please?

Ezra Yacob: Yes, Steve. Good morning. Thanks for the question. The decision is aimed at really just making our capital structure more efficient. We're moving to a level of debt that's more appropriate for a company of our size and strength, still being respectful that we're in a cyclical industry. Ultimately, the move is designed to allow us to move more equity into the debt side. We've always talked about we've been pretty consistent, but the goal of our company has never been to get to a zero absolute debt. And so really, the timing right now looks pretty good as we have a couple of bonds coming into maturity in the next 12 18 months, the market is looking a little more favorable than it has in the last few quarters. And so as we step into this -- as we talked about, as Ann mentioned, our debt target will be to keep total debt to EBITDA at less than one times, leverage ratio at a $45 WTI, which if you calculate that out is approximately a $5 billion to $6 billion range. And so you're right, that will free up some additional cash. And really, what I would look for is, yes, in the near-term, that does imply that we'll definitely be in a position to exceed the 70% commitment and quite frankly, be closer to 100% and at times, more than 100% of return of free cash flow to the shareholders. But I want to put a more specific time target on it other than the next 12-month time frame, the next 12 to 15 months is we look to be opportunistic in the market, not only with share repurchases, but also the timing of reaching out on these bonds.

Steve Richardson: That's great. Really strong choice capital allocation. Thanks. If I could maybe just a follow-up on natural gas. You have arguably the lowest cost dry gas asset in the market and with the Verde Pipeline finishing, you've got some real opportunities here. I appreciate the comments on a 1-rig program for 2025, but you mentioned off the top as how optimistic the natural gas demand outlook looks. So how should we think about the contango of the gas curve and what signal you're looking for to apply more capital there, arguably that you are at the low end of the cost curve in North America?

Ezra Yacob: Yes, Steve, that's another great question on Dorado. We've highlighted last quarter that cash operating costs are right around that $1 already for the asset. And so we do consider it to be one of the lowest cost natural gas projects in all of the US and very well positioned. Verde is online, which we're very excited about. But the North American gas inventory, as you said, is it's currently about 5% above the five-year average still. And we'll see what happens with winter. But either way, whether it's warm or cold, the industry does appear to have not only some curtailed volumes, but there is also some gas DUCs that will likely come online pretty quickly. And so what we see -- and this is somewhat in line with where we've been for the last two years is that 2025 is really going to be an inflection point for North American gas demand with LNG beginning to come online and then coming online really 2025, 2026 2027. And when we think about that, it's -- as we calculated about 10 to 12 Bcf a day of LNG that's under construction and should come online in that time frame. And then above and beyond that, we actually see another almost 10 to 12 Bcf a day in demand growth between now and the end of the decade, that's really associated with power demand, a little bit of industrial, some Mexico exports, but really, it's power demand driven not only by new power demand from AI and electrification, but also coal power retirements. And so our goal with Dorado is to continue to invest at a pace where we can capture some of the economies of scale, as Jeff talked about, which in the last two years has really been a 1-rig program. And as the market starts to open up for us, we'd like to increase that. The next kind of critical point in these unconventional plays is to get to a continuous completion spread. But we're very excited about where we can go and the asset that we've captured there.

Operator: And our next question today will come from Arun Jayaram with JPMorgan Securities LLC. Please go ahead.

Arun Jayaram: Yes, good morning. Ezra, I was wondering if we could talk about puts and takes in terms of 2025 capital. Jeff mentioned, that you expect to run relatively flattish activity but with the movements between some basins. So I was wondering if you could kind of characterize how capital would move. You're going to be a little bit more active at Dorado, we think, in the Utica I think your strategic infrastructure spend is going to go down on a year-over-year basis, and there's obviously some of the efficiency gains that Jeff was highlighting.

Jeff Leitzell: Yes, Arun, this is Jeff. Yes. Thanks for the question. So yes, as you talked about, and we talked about in our opening comments, the plan right now, which is still early, is to maintain relatively flat activity next year and those minor shifts, I mean, they're going to be fairly small. I mean a few wells here and there and pretty immaterial across the portfolio, which will lead to the modest increase in activity we talked about in the Utica. So what I'd first say is just about our current program and the activity levels we're at, we're extremely happy with the progress we've made. And the improvements we've seen across the whole portfolio by really focusing on that. And where we're at now is really we want to focus on the emerging plays and really getting them to that critical activity level to maximize our efficiencies, which the first step in that is getting it to one full drilling rig. And then really, the next hurdle is going to be getting those plays to one full frac fleet. So in the Utica, as we've touched on, we should be there next year. We're looking at about a 50% increase in activity. We'll be up to two full rigs and one full frac fleet by year-end. So we'll reach those critical points. And then Dorado, which you talk about we really anticipate maintaining just the one full rig that we've been running. We've been seeing outstanding performance and efficiencies from that consistent operations. But we'll continue to manage the investments in our completion activity just as we watch the natural gas market and move through the winter. So I think by doing all this, this really allows us to continue progress each one of those emerging plays, but we'll still be able to deliver another year of strong results from the portfolio. And then just real quick on infrastructure. You did hit on it. Over the last few years, we've had a little bit of additional infrastructure spend that was strategic with the Janus gas plant and the Verde pipeline. This year, it was around $400 million. And looking forward to 2025, really, we just -- we're going to be finishing up that Janus plant and a few little things from a facilities aspect on the Verde pipeline. So we expect strategic spend there next year to be somewhere around $100 million. And then as those continue to roll off and we look in the future, we'll start moving back towards that 15% to kind of 20% indirect level.

Arun Jayaram: Got it. That's helpful. Maybe just a follow-up to Steve's question on the optimization of the balance sheet. You mentioned Azure that this could maybe drive higher cash returns to investors. How much does the potential to do A&D or bolt-ons, countercyclical A&D? How did that progress in terms of your thinking terms of going to $5 billion $6 billion of gross debt?

Ezra Yacob: Yes, Arun, this is Ezra. Yes, I mean, I think you're right. While we're going to be making our capital structure more efficient, we'll be very well positioned still to have what we consider industry's leading balance sheet, quite frankly. And that does going to preserve -- it's going to preserve the financial strength of the business for us. That will give us the ability to still maintain the ability to continue to invest in countercyclic, low-cost property bolt-ons, other things that we've done in the past along those same lines. And what I would say is the ability to return more than 100% of annual free cash flow the near term and deliver more cash to shareholders over time, it's really just an effect of, again, shifting some of the equity into the debt side. Where we're starting at today is such a position of strength with a cash positive position that even leveraging up on this debt side, it still puts us in a great position to be able to continue to execute on a lot of our priorities. Like I said, including low-cost property bolt-ons to be able to be in a position to opportunistically step into larger share repurchases if the opportunity presents itself. And so we really see this as a very shareholder-friendly maneuver that we're doing. And like I said, the timing of it is really just what we kind of see in the market and the fact that we do have some of the bonds maturing.

Operator: And our next question today will come from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold: Thanks. And I'm going to hit on the balance sheet optimization. And as you just sort of answered part of my question there with regards to like the why now. It's definitely unique to the sector. And just kind of curious, was this a decision you've been contemplating for some time. Kind of what was the catalyst to move on it now? And also with respect to that, how much value creation from shifting to a lower cost capital structure like moving from equity to debt, some of that value. How much of a value improvement do you expect to see from that?

Ezra Yacob: Yes, Scott, this is Ezra again. So, on the strategic portion, and then maybe I'll hand over to Ann to get in a little bit more of the mechanics. But yes, I think this is really in line with where the management and Board has been thinking for a long time. As I started off the Q&A session with Steve, I mentioned that I think we've been pretty consistent talking about the goal of the company has never been to go to an absolute zero debt level. But really, we like to be positioned to create long-term shareholder value and having different measures -- different abilities to do that. One thing that we love about having that pristine balance sheet that I should have just mentioned when speaking with Arun is also the peer leading regular dividend that we have. And this gives us confidence in being able to continue to grow that and maintain that dividend. As I said in my opening remarks, it's been 27 years that we've been paying that dividend without ever needing to suspend it or cut it. And that's something we're very proud about. So, we really look at the entire priority of our cash flows when we were thinking about this. And the trigger again, that's caused it right now is just where we're at in the macro environment. And not from the commodity side, but really from the financial side. If you recall, Scott, the last bond that we retired was about a $1.2 billion bond back in Q1 of 2023. And that was right decision at the time for us, but one of the reasons is not only were interest rates climbing at that time, but as we all recall, there was a -- what turned out to be a rather somewhat small banking crisis at the time, felt like it could maybe possibly balloon into something larger. So, we refinanced that -- or I'm sorry, we paid that off with cash on hand. And essentially, since then, interest rates have always been climbing up until the recent last couple of quarters where things have kind of plateaued, and we're starting to see them bend over a little bit. So, those are really the things that have kind of given us the confidence to kind of go ahead and make this decision now. As far as moving the equity onto the debt side and the impact for us, I'll hand that off to Ann.

Ann Janssen: Yes. The way we look at it is the optimal capital structure is one where the balance sheet has more debt than what we have today. So, basically, we're looking at putting on a level of debt that is more appropriate for our company of our size and strength in this point in the cyclical industry. So, if you want to look at those parameters as we mentioned, first, we wanted to be less than 1 times total debt to EBITDA leverage ratio at approximate bottom cycle prices around $45. And if you compute that out, that gives us a yield of total debt level of about $5 billion to $6 billion. Conversely, if you look at the cash side of the business, as we look at the appropriate level of cash, we think that's currently about the level we've held for the last two years. We need about a minimum of $2 billion in cash to run the business on a daily basis. And then that additional cash allows us to backstop the regular dividend as well as support additional cash return and take advantage of those countercyclical opportunities. So, again, echoing Azar's comments, our main objective is just to create long-term value for our shareholders. And we think setting up the balance sheet the way we are, will better position us to have an appropriate level of cash to run the business, continue to make those investments as they present themselves and backs up our regular dividend through the cycle.

Scott Hanold: Understood. Thanks. My follow-up is a little bit on the election. The outcomes certainly have created a lot of volatility in the markets. And as you look at what this means to the energy industry and specifically for EOG. What are some of your initial kind of takeaways and the potential tailwinds at play?

Ezra Yacob: Yes, Scott. We still got obviously, the presidential and the Senate is getting close to -- you can kind of see who's going to control those two portions of our Congress and then we'll see where the house finishes up after that. I think for us, what we really prepare for is kind of this next couple of months. Whenever there's a change of administration, this is the time period when we really start to focus in, maybe take some steps to prepare just in case things can slow down. So we're feeling very good very good with where we're at right now. As far as going forward on the industry, I think the industry has come a long way as far as our relationship with not only at the federal level, but really at the local level, working alongside policymakers, regulators and such. And I think the industry is in a spot to continue the performance that we've had over the last few years. When I know I can speak a little more directly for EOG but in the areas that we operate, even the new areas like in Ohio with our Utica play, we've really developed an outstanding relationship. I think many across industry policymakers, really just stakeholders, in general, see that there is a long -- that oil and natural gas are going to play a long -- are going to play a part of the long-term energy solution. And that working with the industry is really the best way kind of achieve the goals of low cost, reliable and lower emissions type of energy sources.

Operator: And our next question today will come from Leo Mariani with ROTH. Please go ahead.

Leo Mariani: Hey, guys. Wanted to just touch base a little bit here on the Utica again. So just curious, you guys talked about $6 to $8 a BOE. I think that was exclusive to the volatile oil window. Do you think there's room to kind of continue to get costs down over time? I know you guys have talked about a long-term goal of BOE finding cost, but I think that may have included some of the gassier windows as well. So where are you at in the cost cycle in the Utica? And do you think there's still significant room to take that down?

Keith Trasko: Yes, Leo, this is Keith. The finding cost range, yes, you're right. It is specific to the volatile oil window and the 225,000 net acres we have there. The range represents the expectations for the next two to three years of development. That's the same for the well cost range. If you back out science on some of our early wells, we've hit the upper end of this range multiple times, and we'll continue to drive it down with the economies of scale. Versus the $5 finding costs we previously disclosed, that reflects the entire 445,000 acre field. That includes the up-dip oil window and the down-dip condensate window. It also incorporates full field development. So we still see line of sight to that, but what we're doing here is giving more guidance in the near-term. Overall, we've made great progress in the play, the well productivity and well cost continue to demonstrate the premium quality and it really highlights our organic exploration strategy.

Leo Mariani: Okay. Appreciate that. I wanted to see if there was any update on the PRB. I feel like it's been a little time since we've kind of heard on that. How are you kind of viewing that play in terms of how it stacks up against others? And I think you're doing a little bit less on the well side this year than you did last year. You talked about adding a little bit of activity in the Utica for 2025. Just kind of any update in terms of how the PRB is performing and how you're kind of thinking about future activity levels there?

Jeff Leitzell: Yeah, Leo, this is Jeff. So yes, the powder is progressing nicely. As we've talked about for the past handful of years, we've really been focused on the Mowry formation, which is the deeper formation and really kind of lining out our geologic model and what our development plans are there, and we had really good success with it. So shifted over since we've gotten all that overlying geologic data in the Niobrara to where we're really doing a split program this year of about 25 wells split between the more and the Niobrara. And what I would say is we've applied the new geologic models and we're continuing to refine our completion techniques up there. And through the first part of the year, we brought on some of those diabera wells. And I mean, results are very early right now, but they're very encouraging. We are seeing an uptick of greater than probably about 10% increase in productivity versus 2023 in the Niobrara. So moving forward right now, I think we're in a very comfortable spot. We still have little to learn there in the Niobrara and kind of just our development patterns and when to offset in depletion and space. And so I think we're probably going to be pretty consistent with our program as we move into 2025 as we continue to refine those models.

Operator: And our next question today will come from Kalei Akamine with Bank of America. Please go ahead.

Kalei Akamine: Hey, good morning, guys. Thanks for getting me on. My first question is on the gas guide. So we've seen it go up every single quarter this year, and we think that, that's the Permian. I appreciate that the Janus plant is coming online. But I'm wondering if that gas outperformance pulls forward any of your additional midstream development time lines?

Jeff Leitzell: Yeah, Kalei, this is Jeff and no, our plans are pretty secure as far as that goes. And really, there shouldn't be any advancement. I mean all of any of the kind of midstream or I should say, strategic infrastructure projects that we've talked about. I mean, they're on time and they're on pace to come online when we expected. With the Janus gas plant, as we've talked about, the plan is to complete that next year. So as we talked about, we'll have a little bit of strategic infrastructure dollars associated with that, about $100 million. But other than that, no, there will be really no acceleration in any of those projects.

Kalei Akamine: Got it. For my follow-up, I'd like to go back to Dorado. I appreciate that it's got very low cash costs. I think in the past, we've talked about $1, and that falling by $0.50 to $0.60 because of Verde. And sort of given its position on the coast, I imagine that it's going to be quite a resilient play. My question is, are you going to optimize production around that cash cost figure? Or do you think that there is a return threshold to consider that would cause you to maybe curtail production or maybe decelerate?

Ezra Yacob: Yeah, Kalei, this is Ezra. Dorado, the way we look at Dorado, quite frankly, is similar to the way that we invest in any of our basins, and it starts with the returns profile. Are we investing at the right pace to optimize the returns and the ultimate NPV of that asset. And quite frankly, what we found in Dorado, especially with its location there close to the demand center coupled with some of the strategic decisions we've been able to make on the marketing side is that this dry gas play from an economics perspective really competes with many of our oil plays. And so that's really what governs how quickly that we invest into that play. On the lower level, as we've talked about with any of these unconventional resources or these emerging assets, we like to try and get to these critical points of where you capture the economies of scale. So, the first is consistent rigs. The second point would be a consistent completion spread where you're not mobilizing in and out of basin, a lot of crews and things like that. It gives you the ability to really know the crew that you're working with and the equipment and you can really start to leverage the learnings. On the upper end of it, you can definitely outrun your pace of investment there and your ability to learn on each well and make each well a little bit better, whether it's finding cost or well performance. And then layered on top of that, obviously, is the macro environment. Now we've done a great job with Dorado by strategically allowing that gas to reach multiple markets. It's got multiple outlets and it's well-positioned along the Gulf Coast like we said. And so that does bring to it an inherent opportunity to continue to deliver that gas. And we think that it will be a significant portion of the future supply that should grow into the North American growing gas demand.

Operator: And our next question today will come from Neal Dingmann with Truist. Please go ahead.

Neal Dingmann: Thanks for the time guys. I'm hoping I can ask another one on the Utica specifically. I'd love to hear your latest thoughts on how you're thinking about the prospectivity more on the west side of the play, either in that black oil or volatile oil in the play? And then just one other question on this play. What's the latest on just the decline? I know it's still early, but I'm just wondering are these wells declining more like typical oil wells or like a Marcellus gas well?

Keith Trasko: Yes. This is this is Keith. On the prospectivity overall, we are still focused mainly on the volatile oil window and trying to dial down spacing there. We will eventually jump up to the west side or to the -- also to the condensate window at some point. We're still in the data-gathering phase there. On the decline side, I'd say we're not seeing anything out of the ordinary. It's a combo play, and we see the declines like a typical tight shale well similar to the Eagle Ford.

Neal Dingmann: Got it. Okay. Okay. And then maybe just a second one, a follow-up just on overall inventory. I'm just wondering, I understand no longer put out the well count in your slides like you previously had in the appendix. I'm just wondering -- I was hoping you could give a sense or maybe a ballpark of how many years you're thinking about of running room specifically in the Del, Eagle Ford, and Bakken at the current rig paces.

Ezra Yacob: Yes, Neal, this is Ezra. What we do disclose is our resource potential in -- as far as resource and we've continued to show that we've got about 10 billion barrels of equivalents the premium resource multi-basin portfolio. The ones that you're highlighting are -- it's an interesting collection because you've got a mix of kind of -- those are foundational plays, but they're all at different kind of legacy aspects. So, in the Bakken, we run basically a one-rig program, and we're at a point where we feel that we can continue to do that and generate similar returns for a number of years to come. In the Eagle Ford, many things have changed in the Eagle Ford, and I think everyone has seen that we've slowed down our pace of investment kind of just for lack of a better data point, say, pre-COVID until post-COVID, where these days, we put the sales maybe 120 wells to sales every year or something like that. And again, the slowing down of that investment, it's less about the inventory that we have remaining, and it's more about what I was speaking with Kalei about as far as investing in each of these plays at the right pace. Slowing down there in the Eagle Ford, we've actually increased the returns and expanded the margin profile, and that's really the thing that we focus on. And then in the last one that I would mention is the Delaware Basin, of course, to be honest with the Delaware Basin, I think it's difficult. Industry has done a lot of drilling there over the past decade. But with the technology advancements, I think industry continues to unlock especially on the Delaware Basin side, unlock additional targets every year. And so to be quite honest, it's a little bit difficult to quantify just how much inventory would be left in such a robust resource as the Delaware Basin. You're talking about literally a miles worth of oil and gas saturated reservoirs in that basin. And so we feel very good about the premium resource that we have in place. We've got a very high-quality, very deep bench of assets across multiple basins. And really at the pace that we're operating in the last couple of years and where the macro environment looks right now, inventory is lack of inventory is not really something that we really ever makes our radar. What we continue to look for is improving the quality of that inventory through our organic exploration efforts which is one of the things that's driven the success there in Utica.

Operator: And our next question today will come from Charles Meade with Johnson Rice. Please go ahead.

Charles Meade: Yes. Good morning. Congrats to you and your whole team there. I wanted to go back to your prepared comments, you spoke a bit about the commodity macro. And you gave a thought on the U.S. supply picture. But I wonder if you could kind of share with us your point of view on what the range of possible outcomes is for 2025? And not that we're looking for specific prediction, but more of just trying to get an understanding of your thinking that's informing your approach to 2025?

Ezra Yacob: Yes, Charles, let me give you a little more background on that. As you guys know, we kind of build our models. We start internally with the things that we know best, which are operationally in the field. And so the biggest thing that is driving our kind of U.S. numbers. And just for historical 2023, I think the U.S. was about 1.5 million barrels liquids growth. Last year, or I'm sorry, this year, it's looking more like it's going to be right around half of that, maybe about 700,000. And so in 2025, we see a little bit less than that, even moderated growth off of that number for the U.S. And it really begins with where the rig counts are at and where the oily drilled, but uncompleted well levels are at. Both of those are relatively low. And on the rig count side, it hasn't really moved. The rig count really hasn't moved in just about a year now. And so that's really the biggest thing that's informing our expectation for slightly less growth year-over-year in the U.S.

Charles Meade: Got it. Got it. And then could you give us a quick rundown of how or how we're went to meet our 2025 program?

Ezra Yacob: I'm sorry, Charles, you broke up there. I didn't catch that. How or when -- what was it?

Charles Meade: Beehive, the Australia well.

Ezra Yacob: Yes, sir. Yes, Jeff?

Jeff Leitzell: Yes. Charles, this is Jeff. Yes. So we have secured the permit there, and we're really excited to be testing prospect. The plan is to test it next year. So obviously, it's an oil prospect. It's a large untested structure there. It's really close to markets, and it's there on the Northwest Shelf of Australia. So the thing that I'd really point out is it's a prospect that's very similar in water depth and operations, the environment, I should say is Trinidad. So we'll really be able to leverage all that shallow water expertise that we have there. So at this time right now, we've got a team in place there in Australia, and we're excited to go ahead and test that prospect sometime next year.

Operator: And our next question today will come from Scott Gruber with Citigroup. Please go ahead.

Scott Gruber: Yes, good morning. You guys have mentioned keeping activity largely consistent for 2025. Your oil volumes will be up about 2% year-on-year at the exit this year. Is that a number, we should be expecting kind of a similar figure for 2025? And then obviously, there's some concerns on the macro side. Just curious, just under what conditions would you look to dial back activity to ensure more of a flattish trend on your oil production?

Ezra Yacob: Yeah, Scott, this is Ezra. Like you said, it's -- I don't think we're at this point ready to talk about a percentage there on 2025, but you can go ahead and count on what we've talked about today with similar activity levels. I mean, the way to really think about our capital allocation is it's not a -- it doesn't begin with that growth number. It really is an output of our investment strategy. And as you highlighted, we're not really growing that much right now. I mean I think in the last 12 months, we've grown about 10,000 barrels of oil per day, which for a 490,000 barrel of oil per day company is really pretty soft. It's certainly something that we could grow more aggressively if we want to focus on it. But quite frankly, what we focus on is we invest balance returns, NPV, free cash flow generation in both the short and long-term and how we can best return that cash to shareholders. That's really the focus of our disciplined investment strategy. And when we get it correct in each of our plays, you invest at the right pace as we've talked about today, that's when you really start to realize the operational efficiencies, the cost reductions and the performance improvement that Jeff really highlighted in his opening comments, so that's what you should expect for us. When we think about the success this year of managing the investment in that way and how we manage our portfolio, the exceptional results that we're seeing across our wells, I think in just the Delaware Basin and Eagle Ford alone are foundational plays. The wells that came on production in first half of 2024 actually paid back their capital investment in aggregate by July 1st. And those results are the types that are flowing straight through to the shareholders because in the first nine months of the year, we've been able to return 92% of that free cash flow to our shareholders. So that's really the way that we approach it. As far as what scenario would we do something dramatically different, we do have the flexibility to either increase or slow down our activity level. We have put out at the beginning of this year, that three-year scenario, which provides a little bit of -- I don't want to call it guidance, but it gives you some scenarios between a $65 to $85 range and the type of financial performance that we could expect if we invested it at similar levels to what we're talking about today. And you can see even at a $65 case, it's a very compelling investment scenario where we've got a low reinvestment rate, 6%, I think, is the cash flow and free cash flow growth per share, which doesn't include any share repurchases. You're talking about a 20% to 30% double-digit ROCE and free cash flow generation, not only to support our regular dividend, but excess free cash flow to support either additional special dividends or opportunistic share repurchases as well.

Scott Gruber: I appreciate all that color. I had a follow-up on your carbon capture initiative. With the pilot project up and running, can you speak to your interest in doing additional projects and would these be confined to internal projects? Or would you consider third-party projects?

Ezra Yacob: Yes, Scott, that's a good question. Right now, we view our carbon capture and storage projects as something internal to help our operations and focus on that. We've had good success with our pilot project, as I talked about just briefly in the opening. And it's really just turning into more of a standard piece of our business. And we are starting to look for other opportunities across our portfolio where we might be able to deploy that technology. But as far as looking at gathering third party or something like that, we've looked at it and evaluated it. But like most things, the real value for much of the technology that we develop is usually better kept inside.

Operator: And our next question today will come from Kevin MacCurdy with Pickering Energy Partners. Please go ahead.

Kevin MacCurdy: Hi, good morning. I think the market is appreciating the reconsideration of your capital structure. My question is on how dynamic do you plan to be on managing that capital structure? As EBITDA grows with higher production and better margins over time, it seems like you should have a more of a safety net on the downside leverage target. Would you keep – would you plan to keep returning a higher percentage of your free cash flow in the future, even if that moves you to a net debt position?

Ann Janssen: Hi, Kevin, it's Ann. We're in a good place now. We have such a strong balance sheet that the level of debt we want to carry and the amount of cash we want to carry has some flexibility built into it. So that's the good side of it. So as we're looking at how to return that free cash flow, we're going to stay in line with what our fundamentals are and how we want to return our free cash flow. We have the cash priorities schedule on how we look at just cash on the balance sheet and how we want to return that to shareholders. And as far as the debt level we want to carry, we're comfortable going to a higher debt level, if that's what makes sense for the business at the time. But again, we have a lot of flexibility in managing those components, and we will move forward based on what the business needs are at the time.

Kevin MacCurdy: Yes. I mean it seems like you highlighted the near-term shareholder return benefit, but this structure could set you up for potentially even higher percentage of returns in the future. I guess my follow-up here is, you mentioned low cost property bolt-ons as part of your balance sheet plans. Do you have any color on where you see the most opportunities for that? And what is the dollar threshold between a low-cost bolt-on and significant M&A, which you've kind of avoided in the past?

Ezra Yacob: Yes, Kevin, this is Ezra. That's a good question. It's not really defined, I think as far as a low-cost property bolt-on or significant merger and acquisition. I mean, I think on the one end, everybody knows what a significant M&A would be. It would be something corporate of magnitude like that. Really, the way we think about it is on the value driver. And so maybe that's the best way to answer it is low PDP with high upside on drilled acreage is what we really look for. And that high upside on undrilled acreage typically comes on emerging assets, to be perfectly honest, because if you're buying quality of acreage in a play that's known and it's going to be additive to the quality of our inventory, odds are you're going to be paying a big premium for that, and that's going to erode your long-term margins, not your wellhead rates of return, but your full cycle margins. So that's really what we look on. And I think that also kind of speaks to where you're at with where are the opportunities for that. Typically, we find those opportunities more often than not in some of the emerging assets, just because, again, we tend -- we think we have the ability to potentially identify and unlock value that maybe gets bypassed by others. And when you think about building out our inventory that way and continuing to improve the quality our inventory, that goes a long way to what you were just implying as far as the long-term return benefit with this capital structure. As you've seen, quite frankly, in the last couple of years is our emerging plays as we've gained more confidence in those, and those have come to fruition, we've increased the percentage of cash return from just below 70% -- down around 60% to making our commitment 70% to last year and this year basically at or exceeding 85% of the free cash flow. So as the strength of business overall improves from the operational performance, that's what ultimately flows through to the financial performance.

Operator: This will conclude our question-and-answer session. I would like to turn the conference back over to Mr. Ezra Yacob for any closing remarks.

Ezra Yacob: We appreciate everyone's time today. I just want to say thank you to our shareholders for your support and special thanks to our employees for delivering another exceptional quarter.

Operator: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.