Good day, everyone, and welcome to the EOG Resources Second 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.

Thank you, Danielle, and good morning. Thank you for joining us for the EOG Resources Second 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 and Production; and Lance Terveen, Senior Vice President, Marketing. Here's Ezra.

Thanks, Pearce. Good morning, everyone, and thank you for joining us. We delivered exceptional second quarter results, reflecting outstanding execution by our employees across our multi-basin portfolio. We earned $1.8 billion in adjusted net income and generated $1.4 billion in free cash flow. Every metric, including production volumes, capital expenditures, and per unit operating costs, surpassed our targets, leading to another quarter of excellent financial performance. Our impressive results year-to-date enable EOG to update our full year forecast for liquids production, cash operating costs, and free cash flow. As illustrated in our investor presentation, we raised our target for full year 2024 total liquids production by 11,800 barrels per day. The increase in production, along with a modest uptick in forecasted operational efficiencies, lowers per unit cash operating costs by $0.15, resulting in an increase of $100 million to our forecasted free cash flow, bringing it to $5.7 billion for the full year at the same strip prices of $80 oil and $2.50 natural gas. Demonstrating the advantages of EOG's unique culture and decentralized structure, our second quarter outperformance was not driven by any single operation or play. Our decentralized operating teams leverage technology and innovation across our asset portfolio to enhance unit costs, well costs, and well productivity. We made advancements in both drilling and completions, with contributions from every asset, including our foundational Delaware Basin and Eagle Ford plays, as well as our emerging Wyoming Powder River Basin, South Texas Toronto, and Ohio Utica shale plays. The strength and depth of our multi-basin portfolio of premium assets serve as a significant advantage, and our emphasis on premium drilling ensures that each asset competes against our premium price deck while assessing direct well investments against a $40 oil and $2.50 natural gas price for the asset's lifespan. This capital discipline grants EOG the flexibility to invest wisely across all our assets, supporting an operational pace tailored to each asset's optimal performance. We can adapt to changing market conditions, such as the broader macro environment and basin-specific economic factors. Consequently, our success does not depend on any single basin, product, or marketing channel. Capital discipline is central to EOG's value proposition, highlighted by our ability to generate free cash flow for eight consecutive years, which facilitates our consistent performance that shareholders expect and fosters long-term shareholder value through various cycles. EOG's remarkable and steady operational and financial performance positions us to fulfill our cash return commitments in 2024. Our strategy remains focused on our regular dividend, which has never been suspended or reduced in 26 years, along with special dividends and opportunistic share repurchases. Our disciplined and balanced investments in foundational plays, emerging assets, and strategic infrastructure, supported by a strong balance sheet, are paving the way for increased near and long-term free cash flow. The overall macro environment remains favorable. Global oil demand is steadily rising after a seasonally slow first quarter and aligns with our expectations. As predicted, domestic oil supply growth has slowed since last year due to industry consolidation and decreased drilling and completion activities driven by capital discipline. Activity levels, as shown in the rig count, indicate continued lower oil production growth until at least mid-2025. We anticipate Lower 48 U.S. supply will end 2024 at approximately the same level as year-end 2023, with only modest increases to total U.S. oil supply from offshore production. Regarding North American natural gas, during the second quarter, inventory levels approached the five-year average, and we expect this trend to persist partly due to supply curtailments and rising year-over-year demand. We are optimistic about the long-term outlook for gas demand beginning in 2025, driven by additional LNG capacity coming online and ongoing increases in demand from electricity generation. We will continue to prudently manage our Dorado activity as the current environment underscores the importance of being a low-cost natural gas supplier with access to multiple diverse markets. This quarter, we further expanded our marketing outlets, securing additional interstate pipeline capacity to deliver natural gas to demand centers in the Southeastern U.S. In a moment, Lance will provide details on this exciting opportunity, along with updates on our ongoing infrastructure projects. EOG's performance this quarter can be summarized as exceptional operational execution leading to exceptional financial performance, resulting in higher volumes and lower per unit operating costs for the same capital expenditures, producing increased free cash flow for the year. Ann will now provide an update on financials and cash returns to shareholders. Here's Ann.

Thanks, Ezra. EOG continues to create long-term shareholder value. During the second quarter, we earned $1.8 billion of adjusted net income and generated $1.4 billion of free cash flow on $1.7 billion of capital expenditures. Second quarter capital expenditures finished lower than expected due to the timing of certain indirect and international projects, along with contributions from efficiency gains above what we forecasted at the start of the year. Jeff will discuss these operating efficiencies in a moment. We also paid a $0.91 per share dividend and repurchased $690 million of shares during the quarter. In the first half of 2024, we generated $2.6 billion in free cash flow, helping fund cash returns to shareholders of $2.5 billion. We have paid over $1 billion in regular dividends and repurchased more than $1.4 billion in stock through the second quarter while maintaining a pristine balance sheet. Taking into account our top-tier full year regular dividend, we have already committed to return $3.5 billion to shareholders in 2024. 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. A growing sustainable regular dividend remains the foundation of our cash return commitment and is the best indicator of the company's confidence in its future performance. Special dividends and share repurchases are employed opportunistically to supplement our top-tier regular dividend. Since putting the $5 billion share repurchase authorization in place over two years ago, the fundamental strength of our business has improved as demonstrated most recently by our exceptional second quarter and year-to-date performance. We continue to get better through consistent execution of EOG's value proposition. As a result, over the last several quarters, we have favored buybacks, and we will continue to monitor the market for opportunities to step in and repurchase shares throughout the year. Since the authorization has been put in place, we have repurchased nearly 21 million shares, which is more than 3% of shares outstanding at an average price of about $118 per share, totaling about $2.4 billion worth of shares repurchased. Now here's Jeff to review our operating results.

Thanks, Ann. I'd like to first thank our employees for their outstanding execution this quarter. Your dedication to and focus on operational excellence extends our momentum from the first quarter and puts EOG in a great position to finish the year strong and deliver exceptional value to our shareholders. In the second quarter, we beat targets across the board, including production volumes, per unit operating costs and CapEx. Oil volumes came in above target due to a couple of drivers. Production in our foundational Delaware Basin and Eagle Ford plays is outpacing our forecast due to better well performance on a collection of packages. Also, our base production performance continues to improve due to the application of proprietary EOG technology. Over the last several years, we have developed in-house artificial lift optimizers for several functions, including gas lift, plunger lift and rod pump operations. These state-of-the-art optimizers use algorithms to automate the set points of artificial lift and cost factors that allow for real-time adjustments to maximize production and reduce interruptions from third-party downtime. These cross-functional efforts by our production, marketing and information systems teams continue to improve and pay dividends. The final driver of our second quarter volume beat was timing. We were able to bring online a package of wells a full month earlier than anticipated. As a result of volume performance beats to date and updates to our full year forecast for Delaware Basin and Eagle Ford production, we are increasing our annual volume guidance by 1,800 barrels of oil per day and 10,000 barrels per day of natural gas liquids. The volume uplift helps lower our per unit cash operating cost guidance for the full year, as well as generates additional free flow. Total well costs are trending in line with our expectations and resulting in a low single-digit year-over-year decrease. Driven by both moderate market deflation and drilling efficiency gains, we are seeing these cost improvements across our entire multi-basin portfolio. Regarding service costs, depletion is playing out as we had forecasted at the start of the year. Spot prices for certain services have trended lower, while high-spec rigs and frac equipment remain relatively stable. We have secured 50% to 60% of our service costs with contracts in 2024, primarily for high-spec high-demand services to ensure consistent performance throughout our program. By securing these resources, we're able to focus on sustainable efficiency improvements to progress each one of our plays at a measured pace. In our foundational Delaware Basin and Eagle Ford plays, operational efficiencies are driven primarily by longer laterals, improving drilled feet per day. Longer laterals allow for more time being spent drilling downhole and less time moving equipment on the surface. In addition, the more we extend laterals, the more benefit we derive from our in-house drilling motor program. EOG motors drill faster and are more reliable, which becomes more impactful on our drilling performance as lateral length increases. In the Eagle Ford, we are on target to extend laterals by 20% on average, and the year-to-date results have been a 7% increase in drilled feet per day. In the Delaware Basin, more than 50 wells or nearly 15% of our 2024 drilling program will use 3-mile laterals compared to four 3-mile laterals from last year. Year-to-date, the efficiency impact from our 3-mile program in the Delaware Basin is a 10% increase in drilled feet per day. In the Utica Shale, we continue to collect data from our new packages and evaluate production history from existing wells as we test spacing patterns and completion designs across our 140-mile acreage position. Two new well packages, the Northern shadow wells and Southern White Rhino wells, as seen on Slide 12 of our investor presentation, have delivered strong initial results and continue to demonstrate the premium quality of this play. In addition to strong well results, since last quarter, we have added another 10,000 net acres to our Utica Shale position, bringing our total to 445,000, while we continue to make delineation progress. Our focus in the near future for Utica development will be on the 225,000 net acres in the volatile oil window, where we have a more comprehensive geologic data set. Our large contiguous acreage position in the Utica lends itself to developing a long-life, repeatable, low-cost play competitive with the premier unconventional plays across North America. For 2024, we are on target to complete 20 net wells in the Utica across our northern, central and southern acreage, which supports a full rig program and enables significant well cost reductions. In Dorado, we continue to leverage the operational flexibility provided by our multi-basin portfolio to moderate and manage activity through the summer. Earlier this year, we decided to defer completions while retaining a full rig program to maintain operational momentum. As a result, the drilling team has achieved a 13% increase in drilled feet per day year-to-date. Maintaining a steady drilling program allows us to capture corresponding efficiencies in advance and improve the play, while we continue to monitor the natural gas market. Gas prices are improving into the second half of the year, and we remain flexible to respond to the market. As the year unfolds, we will continue to maintain capital discipline and leverage the flexibility of our multi-basin portfolio to ensure consistent execution across all operating areas. We also remain highly focused on sustainable cost reductions through innovation, operational performance and efficiency improvements to further drive down our cost structure and expand EOG's capacity to generate free cash flow. Here's Lance for a marketing update.

Thanks, Jeff. I'll be updating on our strategic infrastructure investments in the Delaware Basin and Dorado, as well as the exciting progress we have made expanding access to premium natural gas markets. First, in the Delaware Basin, our Janus Gas Processing Plant is on schedule to start up in the first half of 2025. This 300 million cubic feet per day plant will be instrumental in lowering our cash operating costs and improving netbacks. The Janus plant will have connectivity to the new Matterhorn Express Pipeline, estimated to be in service in the fourth quarter of this year. EOG has firm capacity on Matterhorn, which will allow us to move additional residue gas out of Waha to the Katy Houston Market Center. Most importantly, we expect our Waha gas exposure on a total company production basis to be only 5% in 2025. Furthermore, our new Matterhorn capacity already has term sales in place, along with additional downstream connectivity. Next, in our emerging South Texas Dorado natural gas play, Phase 1 of the 36-inch Verde Pipeline is in service with safe, consistent operations, and we are on schedule to bring online Phase 2 in the second half of 2024. We are excited that Phase 2 of the Verde Pipeline's terminus is the Agua Dulce market hub. While our current cash costs in Dorado are approximately $1 per Mcf, we expect the combination of Verde Phase 2 and the premium markets accessed at Agua Dulce will further expand our margins, positioning Dorado as one of the most competitive, lowest cost and highest return natural gas plays in North America. At Agua Dulce, we have executed agreements for three interconnects directly from our Verde pipeline, including White Water's new ADCC pipeline, supplying Cheniere's Corpus Christi LNG terminal, Enbridge's Valley Crossing pipeline with access to industrial, LNG and Mexico markets, and Williams Transco pipeline expansion, the Texas to Louisiana Energy Pathway Project, or TLEPP, reaching the entire Gulf Coast corridor, which is illustrated on slide 10 in our investor presentation. TLEPP received FERC approval at the end of June and is currently under construction, expected to be in service in the first quarter of 2025. EOG is contracted for the entire 364,400 Btu per day of firm capacity. Through TLEP, we expand our access to a valuable liquid market center that serves robust southeastern power generation and additional future demand. Our capacity on TLEP is in path for supply from multiple EOG assets, including Dorado from our Verde pipeline and the Permian Basin from our capacity on the Matterhorn pipeline. Securing capacity on TLEP is consistent with our broader marketing strategy to diversify our end market options. We continue to expand our access to multiple premium markets, serving customers from LNG to industrials to utilities and more while optimizing our valuable transportation position. Now here's Ezra to wrap up.

Thanks, Lance. I'd like to note the following important takeaways. EOG has delivered another outstanding quarter. Strong employee-driven operational performance produced strong financial performance. Our multi-basin asset teams continue to drive innovation and increase capital efficiency, not only on new wells, but by applying technology to our base production. We are delivering more volumes and lower per unit costs for the same CapEx, resulting in higher free cash flow for the year. Capital allocation across our foundational plays, emerging assets and strategic infrastructure is delivering strong near-term free cash flow while also laying a path to future free cash flow generation. EOG continues to expand an already diverse marketing strategy. Following our announcement of a new Brent-linked gas sales agreement earlier this year, this quarter, we have announced additional natural gas pipeline connections further reducing our exposure to in-basin differentials and exposing us to multiple demand centers. And lastly, EOG continues to deliver on its cash return commitment. While our regular dividend is the foundation of our cash return strategy, we are well positioned to continue delivering additional cash return through share repurchases and special dividends, supported by the strength of our balance sheet and low-cost operations. Including our annual regular dividend and share repurchases in the first half of the year, we have already committed to $3.5 billion in cash return and are well positioned to exceed our minimum cash return commitment. Thanks for listening. We'll now go to Q&A.

Good morning. I wanted to start in the Utica Shale. I was wondering if you could give us a sense of some of the key learnings thus far, including your initial test in the South and perhaps discuss maybe the glide path towards shifting into development mode. What are some of the key risks from here that you need to get comfortable with before shifting into development?

Yes, Arun. This is Ezra. Let me start with the last part of your question there, and then I'll hand it off to Keith Trasko for a few more of the details on the Utica play. What I'd say in the Utica overall is that we're very happy with the results that we've seen to date. The Southern wells, the White Rhinos that we've talked about are right in line with expectations, and Northern wells are consistently delivering strong results and very repeatable. So ramping up the Utica is going to be like any other play that we have in our portfolio. We want to invest in it at the right pace so that we can continue to learn and embed those learnings into the next well, and Keith will mention some of those learnings here in a minute. Ultimately, as we continue to delineate and invest more capital out there, it's going to be at a level of reinvestment that really reflects the maturity of that asset. And when we do that across our multi-basin portfolio, that's when we really start to drive down the cost of all plays and expand the margins at the corporate level.

Yes. This is Keith. On the well results so far, the recent ones, we're very pleased overall, I feel like we're making great delineation progress. Some of the key learnings so far, White Rhino, that is our prospect down south, the performance we're seeing to date is meeting expectations but has a little bit lower BOE IP30. That was something we were expecting because of a little bit of thinner reservoir down there, but it really benefits from the strategic mineral ownership which enhances the returns by lowering the royalties down there. That has a really big financial impact. The Shadow package that we just recently brought on is an offset to the Timberwolves. We're seeing consistently strong results at tighter spacing there. We did a 700-foot spacing test there versus 1,000. Spacing overall, I'd say, thus far, so good. We're excited about the consistency so far. We're going to keep incorporating data as future development decisions go there. But we're still early in the play. We need a little bit longer production history. We look at a lot of different things as far as the two- and three-stream production, the pressure, we're taking a lot of real-time measurements, choke schedules, those sorts of things. And we expect this basin will probably change across the play based on geology. It's just a really large acreage position. But I'd say, with our learnings, we're constantly bringing those into our decisions. We really pride ourselves on not getting into manufacturing mode and instead kind of developing the acreage package by package, integrating the latest data and learnings trying to maximize returns and the value capture.

Okay. My follow-up is – maybe, Jeff, if you could elaborate on some of the technology on the artificial lift side that you've been incorporating. What are some of the potential financial implications? Does this have a positive impact on your decline rates, sustaining capital requirements, but give us a sense of the big picture in terms of the artificial lift technology?

Yes. Thanks, Arun. Well, as we talked about, we've been developing this technology over the last few years. And it's one of the big reasons. Obviously, we had the increase to guidance this quarter, and it really had to do with better base production kind of across the full portfolio. And it has to do with these artificial lift technologies that we're implementing. For instance, we have a program that optimizes our gas lift, which will basically monitor and through algorithms iterate how much gas we are injecting downhole to maximize production on the full bank of wells that it's supplying gas to. If we ever have any kind of downstream interruptions, it can divert gas and move it to the higher producing wells to make sure we're maximizing the production potential through that downtime event and then it can switch back to optimal normal operations. We’ve done that exact same thing with plunger lift optimization and then also on rod pump to run exactly how fast the rod pump is working and to optimize the lift of the oil on all of our wells out there. So yes, it has been absolutely a big mover, and we've implemented it pretty much around our multi-basin portfolio. And I think you're seeing the benefits of it right now in the base production. We expect to obviously be moving forward to have less downtime and be able to maintain a better base production as we move into the future.

The next question comes from Neil Mehta from Goldman Sachs. Please go ahead.

Yeah. Thank you, Ezra and team. Ezra, I always value your perspective on the oil macro, particularly around the Lower 48. What's your view of how exit to exit is tracking? It does seem from this earnings season, whether it's you or the super majors, the execution from a production standpoint has been very good and how do you think this plays out in '25? Especially given the fact that OPEC has that spare capacity and indicating the return of supply into the market? So macro thoughts on the shale trajectory would be terrific.

Thank you, Neil, for the question and the chance to discuss the macroeconomic landscape. At a broader level, we are seeing global demand rise year-over-year, aligning with our expectations, but it's significantly lower compared to the increase from 2022 to 2023. Even in China, which raises many questions, the demand aligns with our expectations this year. Regarding U.S. supply, as we've mentioned in prior earnings calls, we anticipate an annual increase of between 300,000 and 400,000 barrels per day for crude, and possibly closer to 500,000 barrels per day for total liquids. Specifically, in the Lower 48, as I noted in my opening remarks, we expect activity to remain relatively flat from December to December. The DUC counts have stabilized over the last few months, and despite reports of improved operational efficiency, the rig count and completion spreads have also remained flat. This indicates that we continue to see the effects of consolidation in the industry along with overall discipline leading to moderate growth in the U.S. We believe this trend will persist into 2025 and for several years thereafter. With the current rig counts steady for the past eight to nine months, we anticipate moderate, or potentially even lesser, year-over-year growth compared to this year. Lastly, I want to highlight the issue of decline. The U.S. has experienced significant growth in oil production over the last decade, transitioning many barrels from conventional to unconventional resources that typically exhibit steeper declines. After years of growth, the U.S. now faces a considerable decline that must be addressed before we can achieve further growth through new production. These are the key metrics we are focusing on, and ultimately, it all begins in the field at the asset level, where we examine activity and capital efficiency in the plays.

Thank you, Ezra. That provides valuable insight. Regarding the macroeconomic situation and its connection to your business, there has been significant volatility in natural gas prices. We started the year with strong prices, but they have weakened considerably. This morning, we announced a six-month delay for Golden Pass. As you consider your plans for 2025, would it be accurate to say that you intend to focus more on oil rather than gas? Additionally, how will this influence your capital allocation in gas-heavy regions?

It's another good question. Currently, inventory levels are clearly above the five-year average, and natural gas prices are below the five-year average. It's important to note that inventory levels can change quickly due to weather, particularly winter weather. However, we expect the inventory surplus to persist into 2025. We believe that we will reduce inventory levels to the five-year average throughout 2025, assuming a typical winter. This expectation is driven not only by an increase in demand from LNG and higher electricity needs but also by the off-line demand we experienced in LNG this summer, which was unhelpful. Despite that, we are still witnessing an increase in year-over-year domestic demand, with electricity demand growing by about 4.5% year-over-year, which is encouraging for the long term. Regarding 2025, we aren't ready to discuss specifics yet, but we are actively managing our Dorado program, as we have done in past years. We remain optimistic about pricing in that area. We prioritize managing Dorado on the investment side as Jeff mentioned the advantages of maintaining a steady rig program, which has increased drilled feet per day by 13% year-over-year, and nearly 30% over the last two years. Once we start producing gas, we have a low cash operating cost of $1 per Mcf, which provides us with confidence and flexibility for our future investments in Dorado.

The next question comes from Steve Richardson from Evercore ISI. Please go ahead.

Thank you. Good morning. We saw impressive results this quarter, especially compared to the broader industry, which I believe is largely due to the uniqueness of your marketing organization. Ezra, could you elaborate on the structure of the organization? You seem willing to invest capital in both the field and, as mentioned, in longer-haul pipes. Considering your goal is to achieve the highest realization for your products and reach optimal sales points, how do you organize and incentivize that team based on returns? Additionally, how do you approach capital deployment in that area and assess the performance of the business, as well as its contribution to EOG?

Steve, this is Ezra. I appreciate the remarks there and the question. Our marketing team is something we're extremely proud of and what we think is a real competitive advantage, especially in a multi-basin portfolio company such as ours. So just maybe a few remarks by me, and then I'll hand it off to Lance to give some more details on it. Our overall marketing strategy, the first thing we always think about is really the netback pricing. Taking on additional transportation is not a negative thing if it's getting you into premium markets, either for oil or gas. We like to have flexibility as we've talked about. Diversification, with access to multiple markets. We love to have control, where we get firm capacity from the wellhead to sales points. And then the duration. We've had times in the past where we've committed to long-term commitments, and we realize that's not what we want to do. We want to minimize those long-term kind of high cost commitments and really invest good partners that understand that we're trying to align our commitments with how we think about our growth of the individual assets. We’re consistently challenging the marketing team to think about being a low-cost operator. And that's also how we invest in some of these strategic infrastructure projects—what will they do for us over the long term with margin expansion.

Yes. Right. And Steve, this is Lance. I think where I might add a little bit of additional color too, when you think about how we're differentiated. It goes back to the culture, too. I think like our marketing teams are integrated in with our division operations. I mean our division operations and our marketing team, that's all integrated with our fundamentals. So when we look at—we can look at the global markets, as we think about LNG or exporting our products. But then also when you get to in-basin fundamentals, we have a strong grasp of that and what we see. And so that way we can set up and have multiple markets, and we can get to new markets like we announced with TLEPP that gets to a new premium market for the company to just further strengthen our netbacks long term. I'd say all what Ezra put together with his comments and just the integration that we have internally too, I think is a real differentiator.

Thank you for the additional information. I would like to quickly follow up on service costs. I appreciate your comments about being 50% to 60% contracted for 2024. I am interested in what you are observing on the leading edge across the supply chain and your thoughts on what the second half of the year might look like, particularly regarding the parts of the bill of materials that are not contracted at this time?

Yes, Steve. This is Jeff. Thanks for the question. When we look at service costs, what we do is we really break them down into a couple of categories. So we have like our standard services, and then we have what we refer to as our high-spec services, which is the majority of what we utilize as a company. On the standard kind of rig and frac pricing out there, what we saw as it started to weaken in the second half of last year. And it really varied basin to basin based on activity levels. The Permian, I would say, definitely had the most resilient pricing for service costs since they have over half of the rig activity. So in general, I would say, since the middle of last year, standard rig and frac prices are down probably 15% to 20%. When you look at some of the support services over that same period, I'd say coiled tubing and wireline costs are probably down 15% and then workover rigs have reduced about 10%. An additional thing to point out is that through the first half of the year, we've really seen those reductions have kind of slowed as has Ezra talked about, with the rig count and the frac fleet count stabilizing. The big point out there, I'd say, is with the high-spec services we utilize, we currently see relatively stable pricing and we probably will mostly through the rest of the year. But we have started to see a few areas of moderation and a little bit of spot availability, primarily around the gas plays and outside the Permian. As you talked about, we're just locking up to 50% to 60% of our services. The way we do that, our contracting strategy is very strategic to where we stagger out our contracts. So we aren't rolling contracts off all at once. So we're constantly renegotiating new contracts and also renegotiating the spot market to make sure we're taking the best advantage of pricing that’s out there.

The next question comes from Leo Mariani from ROTH Capital. Please go ahead.

I just wanted to follow up a little bit on your comments around how you're going to be kind of prudently managing your Dorado activity. I just wanted to get a sense, are you pretty much committed to kind of the 1 rig this year? It sounds like you want to get the wells drilled, but is there a potential to maybe defer some of those turn in lines or maybe choke back some of those volumes until later this year, just based on the weak current pricing? Obviously, I know you got the second phase of your Verde pipeline coming on, which is going to improve netbacks. But I was just hoping to get a little more color on how you're kind of prudently managing that activity and how you're thinking about it?

Yeah, Leo. This is Jeff. As Ezra talked about earlier, there's really no change moving forward from what we had talked about last quarter. We're obviously managing the investment timing and it's primarily on the completion side where we just pushed a handful of wells into the second half of the year because we had some flexibility there. As he said, we’ll just be able to monitor those prices through the summer and fall to see what happens as we move into the back end of the year. With that, though, we are going to go ahead and maintain that 1-rig program really with no changes through the rest of the year. The team has done an exceptional job building on their existing operational efficiencies. As Ezra stated, they've already seen a 13% improvement in their overall footage per day. If you look at the program, it's only a 20 to 25 well program right now. We really want to build on that and continue to push the great technical and operational progress that we've made so far. So we'll continue to do that through the year and stay on course with our current plan and just continue to make the best economic decision for the play as we move forward.

I appreciate that. Regarding the Utica, you mentioned that the wells are performing according to expectations, but you're also experimenting with spacing and completion design. I'm unsure about the internal expectations, but are you observing an improvement in well performance? Are the last two pads yielding better estimated ultimate recoveries per foot compared to earlier in 2023? I'm trying to understand the trends for these wells and whether they are improving in line with your internal expectations.

Yeah, this is Keith. I'd say they've met our internal expectations. We're expecting performance to vary over the 445,000 net acre position with the 140-mile span of it. We've been focused on our activity on the 225,000 net acres that we have in the volatile oil window? We see changes in geology along there. We'll have different spacing in different areas, with different type curves in different areas, but we are constructive on the play overall everywhere we've tested, and we think the variation we're seeing is within the norm.

The next question comes from Scott Hanold from RBC Capital Markets. Please go ahead.

Yes, thank you. Good morning, Ezra, and the entire EOG team. I would like to revisit the Utica and the ShadowPad. The IP30 you presented appears to be very appealing compared to broader well performance. However, I am interested in any additional details or insights you can provide about the evolution of the spot rates from that pad. Also, do you have an estimate of when you'll be able to determine if the spacing policy has been successful?

This is Keith. As far as how the rates are evolving question and talk a little bit about, like the product mix. So our IP30s are heavily oil-weighted, heavily liquids-weighted. We do see that in a lot of combo plays. So expect that early on, and we've seen that across all the well packages we have in the north and south. So we still estimate a 60% to 70% liquids mix for the UR product. I'll tie back to a well that has a little more production history, which is the Timberwolf. So Timberwolf and also the Xavier package, that IP30 was around 55% oil cut. Those have been on for a little over six months now, and we see closer to a 50% oil cut right now. You see it moderate, but it's not a large drop overall. As far as how long to determine if the spacing is a success? It's going to vary in different places, but we just want to see more production data on the, I'd say, at least six months, nine months or so. And compare that to the data set that we have on some of our older packages, Timberwolf, Xavier, et cetera, and just see how they hang in there, see how the pressures look, et cetera.

The next question comes from Charles Meade from Johnson Rice. Please go ahead.

Good morning, Ezra, and the entire EOG team. I want to revisit the Utica and the ShadowPad. The IP30 you presented appears quite appealing compared to wells in the broader sector. Could you provide additional details on how the spot rates are progressing from that pad? Also, do you have an estimate of when you might determine if the spacing policy has been successful?

Hi, Charles, good morning. Thanks for the question. This is Lance. We could probably spend 30 minutes on that question, but I think Ezra is going to kick me over here if I spend too much time. But I'd say I talked earlier regarding the marketing strategy and the integration that we have, and we think about the markets. This started all the way back in kind of 2022, right? We saw that station 65 when you look kind of into that market was likely going to be a premium market long-term. We worked alongside Williams there, went out for their open season and were able to capture all the capacity there through our precedent agreement. That took a lot of time. I think you really have to have that foresight and then looking forward into the markets. The other thing I really want to capture is that is all in path, right, Charles. When you think about South Texas all the way through our Eagle Ford asset, all the way up into the Gulf Coast market, we can capture everything, the Delaware Basin with our existing transport, our new transport that we're going to have on Matterhorn, all that can get to that market. So a little bit of that all came together because, yes, you have a lot of these pipes that are coming into the Gulf Coast. As you've seen on some of our slides, especially related to gas sales agreements, you have to have end markets on the other side. We've been very forward-thinking there. You can see the ramp-up that we have in terms of other term sales that we have. You need to have the transport position, Charles, but then you also need to think about having strategic sales on the other side. I think that's another thing that really differentiates us that we've got that in place now and then also looking forward.

The next question comes from Paul Cheng from Scotiabank. Please go ahead.

Thank you. Good morning, team. Maybe this is for Jeff or maybe Ezra. I want to go back into artificial lift. I want to see that, I mean, the technology you use and how is that different than what is commonly available in the market today by some of the oil services. So in other words, that do you think your adoption that what gives you the edge comparing to your competitors? And whether that you can quantify, you talked about the base operation become better, how that improves your base decline rate? That's the first question.

Thanks, Paul. This is Jeff. Yes, that's a great question. With any of our technology that we developed, the beautiful thing about it is it's integrated within EOG with all of our different systems. So it communicates with all the data, is getting all of our production data, all the pressures, all the flow rates, temperatures, everything in real-time. So all that's flowing into the system, and you can see that. With a lot of other third-party systems, that's not possible. On top of that, it also ties directly into our centralized control rooms, which are in each one of our basins that watches our production real-time 24/7. As these systems are optimizing at the control room, they can monitor it and ensure that the iterated set points are correct, then notify any people in the field in real-time to check on a well or make any additional changes that need to be done. It really has to do with the integration within our systems, it really sets us apart from that aspect. Then on the decline rate side—or I should say, at least from a base production and what our forecast is, you always have a certain amount of downtime that goes along with normal operation of wells. What these optimizers really do is help minimize that downtime. Instead of having a handful of percentage, you're able to knock off a percentage of downtime to keep these wells flowing and maximize the production across our multi-basin portfolio.

Yes, Paul, this is Ezra. I think you broke up there just for a second. I’m not sure if you’re asking about the Bakken, Dorado or Utica, but obviously... I'm talking about Dorado. What will be the precondition for you to decide, okay, this is the right time, I want to increase activities and bring more gas to the market? Is it just simply price? Or are you looking for anything else? And is it simply the price or are you looking for anything else? And increasing 5 is their price mix of that will be buying the impact trick upon? Yeah. Thank you, Paul. So yes, with Dorado, I think the biggest thing to continue with any gas play, and for us, the dominant one is Dorado. As you can see right now in the current environment, how volatile gas prices are, you've got to be committed to being the low-cost supplier. You've got to be a low-cost operator on the gas side because as we all know, the margins are pretty skinny; you can make up for it with low operating costs, gas is easier to operate in liquids. But then you need to make up for it with volumes. The second piece is you've got to be exposed to diverse markets because the volatility of gas means that you'll have arbitrages come and go very quickly. If you've got the gas there exposed to the market, you can capture those. If you try to chase those arbitrages much like we saw in 2022 and 2023, by the time you can try to get your gas in position to capture an arbitrage, it might be gone. Those are the two things that we really focus on. In general, when you start talking about capital allocation to it, those comments you should read into why we've continued to stick with a rig activity down there, kind of a minimal level of activity so that we can continue. As Jeff highlighted, to learn, embed those learnings in the very next well and continue to be confident that when we see the emerging demand hit, which is coming in the next few years with a lot of LNG coming online, we'll be in a position to be able to bring to market low-cost reserves—low-cost gas reserves. Now on the completion side, we do have a lot of flexibility there. A great way to overspend is if you bring in a frac spread and send it out of the basin and bring it back, picking up water lines, laying them back down. That's why we try to keep a drilling rig going, as I've talked about in the past, that's kind of the first hurdle capturing economies of scale. The second one is trying to get your packages lined up. So when you bring a completion spread in, you can keep it for a significant number of wells and bring that on. What we look for to take the next step is not only internal learning's but also the returns we're generating. We're also looking at the macro market. As I said on a previous question, the price essentially follows inventory levels or it’s very lined out with that. We’re below the five-year average right now on pricing and above the five-year average on inventory levels. So inventory levels are a big driver of what we're looking for. We’re also cognizant of the supply and demand fundamentals for North America or just the U.S. In addition, you have 10 to 12 Bcf a day arguably under construction right now that should be on really beginning throughout 2025. In addition to that, as you look at the back half of the decade, I think we highlighted our forecast for potentially another 10 to 12 Bcf a day of demand increasing from things like electricity generation, coal power plant retirements, just an increase in Mexico exports, and finally, just overall industrial demand growth. So we really look at it internally, our ability to generate higher returns and embed our learnings, so that we're investing at the right pace. Externally, we look at supply-demand and ultimately the inventory levels, Paul.

The next question comes from Doug Leggate from Wolfe Research. Please go ahead.

Ezra, how are you? Thanks for having me on. Can you hear me okay?

Yes, sir, Doug, it's good to hear from you again.

Good. I wasn't sure if I had jumped in there, but I wonder if I could bring you back to the Utica for a moment. Delineation is usually a slow process for many companies, but you have moved quickly not only to secure the acreage but also to clearly demonstrate that, at least based on our numbers, it is beginning to look competitive compared to your Permian position. I'm curious about how you would describe the extent to which you have reduced the risks associated with the play at this stage and when you expect to have a more significant development plan moving forward. Is infrastructure the limiting factor, or is there another reason for the delay? It seems that geologically, you are making progress in understanding this area.

Yes, Doug, I appreciate that. I think everything you're saying is correct. It's how we feel about it too. Geologically, we're doing a great job figuring it out. I will point out the only caveat I'd maybe make is we have, as Jeff pointed out, concentrated right now in the volatile oil window. So, roughly, 225,000 out of the 445,000 acres. But you can see our confidence by the fact that we continue to put—we continue to put together some leased acreage as we increase the footprint about 10,000 acres. It's not overly complicated, Doug. We've got multiple packages now in the north, and we're seeing consistently strong results. I'd say we're feeling very confident there in the North. Certainly, as Keith and Charles were speaking about, we're not 100% satisfied with the spacing number if you wanted to get down that path. But in any North American shale play, you know as well as I do, the spacing is going to be between 600-foot and 1,000-foot spacing, probably on average, depending on the play. In the South, we only have one package really with any amount of data on there. So, we're a little bit further behind on delineation down there, even though that package did come online with our expectations. It's too early to talk about 2025, but just to call back, we have basically, we're planning on this year doubling the amount of wells to sales over what we did in 2023. I think you're spot on, Doug, that we are seeing to date with the early-time wells that we have, we're seeing that it's competitive with parts of the Permian Basin.

That's what we are seeing as well. And I think, to be honest, I think some of us were a little skeptical to begin with, and you're proving us wrong. So, congratulations on that. My follow-up, there's been a lot of questions this morning on gas and the extraordinary realizations you guys have had, I think it was pointed out earlier, but my question is on the proportion of gas that you're prepared to commit to international pricing. I think right now, I want to say if I look out to the back end of the decade at your current volume, you're about halfway locked in, whether it be Brent-related or the other things that you pointed out. But in terms of your preparedness to step up your international exposure, what are you thinking as we see incremental LNG plants start to come out of the woodwork, like the Woodside deal with Wheelan? Where would you be comfortable in terms of international exposure? I'm losing my voice, but in terms of international exposure as it relates to your total proportion of your volumes?

Yes, Doug, I appreciate that. We have, as you've seen, with Slide 11 in our deck that kind of highlights what we've done with our gas sales agreements to expose us to pricing diversification, including the international. I'd point out, Doug, the biggest thing is when we entered into these agreements, as you'll recall, we entered—we started negotiations and really entered into most of these in a counter-cyclic time period. When we look at these opportunities, we want to make sure that we're being a low cost—that we're entering into a lower cost contract or gas sales agreement that provides upside exposure. The sales agreements we've done to date limit our exposure to risk as well. One reason that we're able to enter into some of these agreements is just because of honestly the size and scale of what we've captured, mainly at Dorado, but also across other basins as Lance has talked about. Right now, as you pointed out, we're only really selling about 140 MMBtu per day that gets exposed to the uplift of JKM pricing. From 2020 to 2023, as we highlighted on Slide 11, it's added just over $1 billion worth of revenue uplift, which is outstanding. Even on small volumes, it can have a major impact on the revenue side. We're happy that's going to step up here in '25 and '26 as Corpus Christi brings on their Stage 3, and that will increase approximately to 720 MMBtu under a couple of different gas sales agreements that are outlined on that slide. We talked about last quarter, we made yet another - and I would call this counter-cyclic agreement because an agreement like this hasn't been done in North America for quite some time, but we actually have a Brent-linked gas sales agreement. When we think about the percentage of our portfolio that we would necessarily like to have exposed to international, I’m not sure if we have a set percentage that we publicize right now because it really depends on the types of agreements and marketing structures we see available at the time. But ultimately, our strategy is to get more of our gas exposed to diverse markets, and to get our gas offshore and exposed to the international markets.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Yacob for closing remarks.

We appreciate everyone's time today. Thank you to our shareholders for your support, and especially 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.