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.

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.

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.

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 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%. 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.

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 provide 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 day, natural gas liquids by 2,800 per 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 continue 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 by 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.

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 to 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.

Thank you. Our first question today will come from Steve Richardson with Evercore ISI. Please go ahead.

Hi, good morning. I would like to start with the optimization of the balance sheet. This is a new approach from the company, and I’m curious if you could discuss the additional gross debt you’re considering and the timeline for that. Should we expect the $2 billion to coincide with the refinancing of existing maturities? Additionally, how do you plan to redeploy that cash, potentially into a buyback? Does this indicate that you will be increasing shareholder returns sustainably beyond the minimum commitment in the upcoming quarters? Please provide some insight into the timeline for this.

Yes, Steve. Good morning. Thanks for the question. The decision is focused on making our capital structure more efficient. We're adjusting our debt to a level that's more suitable for a company of our size and strength, while still being mindful of our position in a cyclical industry. The aim is to shift more equity into the debt side. We've been clear that our objective has never been to eliminate debt completely. The current timing seems advantageous as we have bonds maturing in the next 12 to 18 months and the market appears more favorable than it has in recent quarters. As we discussed, our target is to keep total debt to EBITDA at less than one times, with a leverage ratio reflecting approximately $5 billion to $6 billion at a $45 WTI. This will free up additional cash. In the near-term, we anticipate being in a position to exceed the 70% commitment, potentially approaching 100%, and sometimes exceeding 100% in returning free cash flow to shareholders. However, I cannot specify an exact time frame beyond the next 12 to 15 months as we look for opportunities in the market, including share repurchases and managing the timing of these bonds.

That's great. Really strong choice in 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 one-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?

Yes, that's a great question about Dorado. Last quarter, we noted that cash operating costs are around $1 for this asset. We believe it to be one of the lowest cost natural gas projects in the US and very well positioned. We're excited that Verde is operational. Currently, North American gas inventory is about 5% above the five-year average, and we'll see how winter affects this. Regardless of whether it's warm or cold, the industry has some curtailed volumes, and there are gas DUCs that should come online soon. We anticipate that 2025 will be a significant turning point for North American gas demand, with LNG starting to come online in 2025, 2026, and 2027. We estimate about 10 to 12 Bcf a day of LNG under construction to be operational during that timeframe. Additionally, we forecast another 10 to 12 Bcf a day in demand growth by the end of the decade, primarily driven by power demand due to new requirements from AI and electrification alongside coal retirements. Our objective with Dorado is to invest at a pace that allows us to realize some economies of scale, as mentioned by Jeff, which has been a one-rig operation for the last two years. As the market opens up, we aim to increase our activity. A critical next step in these unconventional plays will be achieving a continuous completion spread. We are very optimistic about the potential of the asset we have.

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

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.

Yes, Arun, this is Jeff. Thank you for the question. As we discussed, the current plan is to maintain relatively flat activity next year, with only minor adjustments expected. These adjustments will be minimal, involving only a few wells, and will not significantly impact the overall portfolio. This approach will support the modest increase in activity we anticipate in the Utica. Regarding our current program and activity levels, we are very pleased with the progress we've achieved and the improvements across our entire portfolio. Our focus is on the emerging plays and reaching the critical activity level to enhance our efficiencies. The first step is to utilize one full drilling rig, and the next goal is to have one complete frac fleet for those plays. In the Utica, we expect to reach this milestone next year, targeting a 50% increase in activity, resulting in two full rigs and one complete frac fleet by the end of the year. For Dorado, we plan to maintain our current operation with one full rig, which has been delivering excellent performance and efficiency. We will keep an eye on our completion investments as we navigate the natural gas market through winter. This strategic approach enables us to progress on each of the emerging plays while still delivering another year of strong results from the portfolio. On the infrastructure front, we have moderately increased our spending over the past few years, particularly with the Janus gas plant and the Verde pipeline, totaling around $400 million this year. Looking ahead to 2025, we will complete the Janus plant and make minor adjustments on the Verde pipeline, expecting next year's strategic spend to be around $100 million. As these projects wind down, we aim to return to an indirect spending level of approximately 15% to 20%.

Got it. That's helpful. Maybe just a follow-up to Steve's question on the optimization of the balance sheet. You mentioned, Ezra, 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 in terms of going to $5 billion $6 billion of gross debt?

Yes, Arun, this is Ezra. I think you're right. While we are making our capital structure more efficient, we will still be well positioned to maintain what we believe is an industry-leading balance sheet. This will help preserve the financial strength of the business, allowing us to continue investing in countercyclical, low-cost property acquisitions, similar to what we've done in the past. I would emphasize that our ability to return more than 100% of our annual free cash flow in the near term and provide more cash to shareholders over time is a result of shifting some equity into debt. We are starting from a strong position with a cash-positive status, so even increasing our debt, we remain in a great position to execute on many of our priorities, including being opportunistic in larger share repurchases when the opportunity arises. We view this as a very shareholder-friendly action, and the timing reflects our perspective on the market and the upcoming bond maturities.

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

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?

Yes, Scott, this is Ezra again. Regarding the strategic aspect, I will let Ann provide more details on the mechanics. I believe this aligns with the long-standing thoughts of our management and Board. As I mentioned in the Q&A session with Steve, our objective has never been to eliminate all debt. Instead, we aim to position ourselves to create long-term shareholder value through various means. One advantage of maintaining a strong balance sheet, which I noted while speaking with Arun, is our industry-leading regular dividend. This gives us confidence in our ability to grow and sustain that dividend. As I stated in my opening remarks, we have paid that dividend for 27 years without ever needing to suspend or cut it, which is something we take great pride in. Therefore, we evaluate our cash flow priorities when considering these matters. The current macroeconomic environment, rather than commodity factors, has triggered this decision. As you may remember, Scott, the last bond we retired was a $1.2 billion bond in Q1 of 2023. It was the right choice at that time, especially with rising interest rates and a brief banking crisis that seemed it could escalate. We paid that off using cash on hand, and since then, interest rates have generally been on the rise until the last couple of quarters, where we are starting to see them stabilize a bit. These factors have given us the confidence to move forward with this decision. Now, I will turn it over to Ann to discuss the effects of moving equity onto the debt side.

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 Ezra'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 back up our regular dividend through the cycle.

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 takeaways and the potential tailwinds at play?

Yes, Scott. As we approach the presidential and Senate elections, it will become clearer who will control those parts of Congress, and we will also see how the House will finalize. For us, we are primarily focused on the next few months. Whenever there's a change in administration, this is the period when we start preparing in case things slow down. We feel very positive about our current standing. Looking ahead in the industry, we have made significant progress in our relationships at both the federal and local levels, collaborating with policymakers and regulators. The industry is positioned to maintain the performance we've achieved over the past few years. Specifically for EOG, in the regions we operate, including new areas like our Utica play in Ohio, we have built strong relationships. Many in the industry and among policymakers recognize that oil and natural gas will continue to be vital in the long-term energy landscape, and that collaborating with our sector is essential for achieving low-cost, reliable energy with reduced emissions.

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

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?

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 a 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.

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?

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 Mowry 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 Niobrara 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 a 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.

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

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 timelines?

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.

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?

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 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.

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

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?

Yes. This is Keith. Regarding the overall prospectivity, we continue to focus primarily on the volatile oil area and are working on optimizing spacing there. We plan to transition to the west side or to the condensate area eventually. We are still in the process of collecting data on that. As for the decline, I can say we are not experiencing anything unusual. It’s a combination play, and the declines are consistent with what we typically see in a tight shale well, similar to the Eagle Ford.

Got it. Okay. I have a follow-up regarding overall inventory. I noticed that you no longer include the well count in your slides as you did before in the appendix. I'm curious if you could provide an estimate of how many years of running room you envision for the Delaware, Eagle Ford, and Bakken at the current rig paces.

Yes, Neal, this is Ezra. We disclose our resource potential, and currently, we have about 10 billion barrels of equivalents in our premium resource multi-basin portfolio. The areas you're mentioning are interesting because they include foundational plays with varying legacy aspects. In the Bakken, we operate a one-rig program and feel confident that we can maintain this and achieve similar returns for several more years. In the Eagle Ford, we've made changes and have slowed our investment pace since pre-COVID, currently bringing around 120 wells to sales each year. This slowdown isn't due to our remaining inventory, but rather about investing in each play at the right pace. By slowing down in the Eagle Ford, we've actually improved returns and expanded our margin profile, which is our main focus. Regarding the Delaware Basin, it is challenging due to the significant drilling over the past decade. However, with ongoing technology advancements, new targets are being unlocked every year. Thus, it's hard to quantify how much inventory remains in the Delaware Basin. We feel optimistic about our premium resources and have a high-quality, diverse asset base across multiple basins. Given our operational pace in recent years and the current macro environment, lack of inventory isn't a concern for us. Our goal is to enhance the quality of that inventory through organic exploration efforts, which has contributed to our success in Utica.

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

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?

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.

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?

Yes, sir. Yes, Jeff?

Yes, Charles, this is Jeff. Yes. So we have secured the permit there, and we're really excited to be testing the 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.

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

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?

Yeah, Scott, this is Ezra. As you mentioned, we're not quite ready to discuss a specific percentage for 2025, but you can expect us to maintain similar activity levels as we've talked about today. Our capital allocation approach doesn't start with a growth figure; it's a result of our investment strategy. As you noted, we're currently not experiencing significant growth. Over the past year, we've added about 10,000 barrels of oil per day, which is modest for a company producing 490,000 barrels per day. We could choose to accelerate that growth, but our priority is on balanced returns, net present value, and free cash flow generation, both in the short and long term, as well as returning cash to our shareholders. This is central to our disciplined investment strategy. When we invest at the appropriate pace in our plays, as we've discussed, we begin to see operational efficiencies, cost reductions, and performance improvements, which Jeff mentioned in his opening remarks. This year, we successfully managed our investments and portfolio, yielding strong results, especially in the Delaware Basin and Eagle Ford, which are our foundational plays. The wells that began production in the first half of 2024 recouped their capital investment by July 1st. These outcomes directly benefit our shareholders; in the first nine months of the year, we returned 92% of our free cash flow to them. This illustrates our approach. Regarding what would prompt us to change our strategy significantly, we have the flexibility to adjust our activity levels. Earlier this year, we shared a three-year scenario that outlines different conditions, not exactly guidance, but it offers some possibilities within a $65 to $85 range showing potential financial performance based on our current investment levels. Even in a $65 scenario, the investment outlook remains strong, with a low reinvestment rate of 6% for cash flow and free cash flow growth per share, excluding share buybacks. We anticipate a 20% to 30% double-digit return on capital employed and free cash flow generation, which not only supports our regular dividend but also enables us to provide additional special dividends or undertake opportunistic share repurchases.

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?

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.

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

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?

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 the 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.

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?

Yes, Kevin, this is Ezra. That's a good question. It's not really defined, I think, in terms of a low-cost property addition or a significant merger and acquisition. There’s a clear understanding of what a significant M&A would be, something that is quite substantial. The better way to approach this is through value drivers. We specifically look for areas with low production development potential but high upside on drilled acreage. Typically, that high upside on undrilled acreage can be found in emerging assets. If you’re investing in high-quality acreage in a known play that will enhance our inventory’s quality, you are likely to pay a considerable premium, which could negatively impact your long-term margins rather than just the wellhead rates of return. That's the focus we have. Generally, the opportunities we see are more frequent in emerging assets, as we believe we can recognize and unlock value that might be overlooked by others. Enhancing our inventory in this manner and steadily improving its quality contributes significantly to the long-term return advantages with this capital arrangement. Over the last couple of years, as we've gained confidence in our emerging plays and they have proven successful, we've boosted the percentage of cash return from just under 70% to making our commitment 70% last year and this year reaching or exceeding 85% of free cash flow. As the overall strength of the business improves from operational performance, it ultimately impacts financial performance positively.

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.

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.

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