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Operator: 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.

Pearce Hammond: Thank you, Danielle, and good morning and 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.

Ezra Yacob: Thanks, Pearce. Good morning, everyone, and thank you for joining us. We delivered exceptional second quarter results, reflecting outstanding execution by our employees throughout our multi-basin portfolio. We earned $1.8 billion of adjusted net income and generated $1.4 billion of free cash flow. Every metric, production volumes, CapEx and per unit operating costs beat targets, driving another quarter of excellent financial performance. Our outstanding results year-to-date allow EOG to update our full year forecast for liquids production, cash operating costs and free cash flow. As seen on slide 5 of our investor presentation, we increased our target for full year 2024 total liquids production by 11,800 barrels per day.

Increased production, coupled with a modest increase to forecasted operational efficiencies reduces per unit cash operating costs by $0.15, driving a $100 million increase to our forecasted free cash flow to $5.7 billion for the full year at the same strip prices of $80 oil and $2.50 natural gas. Illustrating the benefits of EOG’s unique culture and decentralized structure. There wasn’t one single operation or play that drove our second quarter out performance. Our decentralized operating teams utilize technology and apply innovation across our portfolio of assets to improve unit costs, well costs and well productivity. We made gains in both drilling and completions and every asset contributed. 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 is a tremendous advantage, and our focus on premium drilling means each of these assets competes against our premium price deck, measuring direct well investments against a $40 oil and $2.50 natural gas price for the life of the assets. That capital discipline provides EOG the flexibility to invest thoughtfully across all of our assets to support the pace of operations that is optimal for each individual asset to continue improve. We can adjust to dynamic market conditions such as the broader macro environment and basin-specific economic factors. As a result, we don’t rely on any one basin, any one product or any one marketing outlet to drive our company’s success. Capital discipline is core to EOG’s value proposition, evidenced by our ability to generate free cash flow for eight years in a row and is what drives our ability to deliver the consistent performance that our shareholders have come to expect and to create long-term shareholder value through the cycle.

EOG’s outstanding and consistent operational and financial performance positions us to deliver on our cash return cash return commitments in 2024. Our strategy continues to be grounded in our regular dividend, which has never been suspended or reduced in 26 years and supplemented with special dividends and opportunistic share repurchases. Our disciplined and balanced investment in foundational plays, emerging assets, and strategic infrastructure, all supported with a pristine balance sheet is laying the path to increase near and long-term free cash flow. The overall macro environment remains constructive. Global oil demand continues to increase after a seasonally soft first quarter and is in line with our forecast. As anticipated, domestic oil supply growth has moderated since last year as a result of consolidation in the industry and reduced drilling and completions activity stemming from industry capital discipline.

Activity levels, as reflected in rig count indicate continued lower oil production growth through at least mid-2025. We expect Lower 48 U.S. supply to exit 2024 at roughly the same level as year-end 2023, with only modest gains to total U.S. oil supply from offshore — as offshore production increases. Regarding North American natural gas. During the second quarter, inventory levels move closer to the five-year average, and we expect this trend to continue due in part to supply curtailments and increasing year-over-year demand. We remain optimistic on the long-term outlook for gas demand beginning in 2025, as a result of additional LNG capacity coming online and continuing increases in demand from electricity generation. We will continue to prudently manage our Dorado activity as the current environment continues to highlight the importance of being a low-cost supplier of natural gas with access to multiple diverse markets.

This quarter, we have further expanded our marketing outlets, capturing 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 as well as updates on our ongoing infrastructure projects. EOG’s performance this quarter can be summed up as exceptional operational execution drives exceptional financial performance, resulting in more volumes and lower per unit operating costs for the same CapEx, yielding higher free cash flow for the year. Anne is up next to provide an update on financials and cash return to shareholders. Here’s Ann.

Ann Janssen: 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 free cash flow, helping fund cash return 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 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 return 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.

Jeff Leitzell: Thanks, Anne. 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 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 of 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 has 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 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.

Lance Terveen: 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 and 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 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 in place term sales, along with additional downstream connectivity. Next, in our emerging South Texas Dorado natural gas play, Phase 1 of 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 Pipelines 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 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 and expected to be in service in the first quarter of 2025 EOG is contracted for the entire 364,400Btu 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.

Ezra Yacob: 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 with 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.

Q – Arun Jayaram: 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?

Ezra Yacob: Yes, Arun. This is Ezra. Let me start 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 Rhino’s that we’ve talked about are right in line with the expectations in Northern Wells are consistently strong results and very repeatable. So ramping up the Utica, I mean, it’s 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 do 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.

Keith Trasko: 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 prospects down the south, the performance we’re seeing to date meeting expectations 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 really enhances the returns by voting the royalties down there. That has a really big financial impact. The Shadow package that we just recently brought on, that’s an offset to the Timberwolf’s. 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, so far so good. We’re excited about the consistency so far there. 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 are 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.

Arun Jayaram: 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?

Jeff Leitzell: 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. So for instance, and we’ve talked about it a little bit, we have a program that optimizes our gas lift. So it 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. And then if we ever have any kind of downstream interruptions, it can 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.

So — we’ve done that exact same thing with a 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’s 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. And 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.

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

Neil Mehta: 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.

Ezra Yacob: Yeah. Thanks, Neil. Appreciate the question, the opportunity to talk a little bit about the macro. If we started a little bit more of the broad level, I think what we’re seeing is global demand is increasing year-over-year, essentially in line with our expectations, which is quite a bit less than 2023 over 2022. Even China, I’d say that has a lot of questions China demand is even kind of in line, demand is in line with our expectations the year. For us, on US supply, I think we’ve talked about on previous earnings calls for crude, we’re looking — we feel somewhere between 300,000 and 400,000 barrels a day annually would be the increase. In total liquids maybe closer to 500,000 barrels a day. When you look at what’s happening in the Lower 48 specifically, as I said in the opening remarks, we think from December to December, it will be relatively flat.

We’ve had relatively flat DUC counts for the past months. And even though, as you’re highlighting, there’s — everybody seems to be reporting on the margin, some increased operational efficiency, it’s really rig count that’s remained flat and then completion spreads that have remained flat as well. And so when we roll all that up, we continue to see not only the effects of consolidation in the industry, but just overall industry discipline really being the drivers of that more moderate US growth. And we think that will continue not only into 2025, but really for the next few years moving forward. Immediately, as I discussed with the current rig counts where they have been for the last eight, nine months, and where they look to be finishing the rest of this year at, that should drive moderate, potentially even less growth year-over-year than what we’re seeing this year.

And the last thing I think I’d point out is just the amount of decline. The US has grown so much in the last decade on the oil side and many of those barrels have been switched out from conventional resources into obviously more unconventional resources that come with a bit of a steeper decline. And so after years and years of growing, the US is finally looking at a spot where we have a very steep decline year-over-year as a country that needs to be filled in before new barrels can actually add to the growth. And those are the kind of key metrics that we continue to look at. But ultimately, it starts in the field at the asset level, looking at the activity and the capital efficiency of the plays.

Neil Mehta: Thank you, Ezra. That’s really helpful perspective. And staying on the macro and then tie it into your business. On natural gas, we’ve seen a lot of volatility, good price to start the year, obviously, very weak prices now. This morning, we had the 6-month pushout of Golden Pass. So — just as you think about the ’25 plan, is it fair to say you’re going to try keep it a little bit more oil-weighted versus gas? And how does it affect how you want to deploy capital in gassier areas?

Ezra Yacob: Neil, it’s another good question. We — at this point, Inventory levels are clearly above the 5-year average. And commensurately — commensurate with that, the natural gas price is below the 5-year average. I will point out as we saw at the beginning of 2024, inventory levels can react very quickly on weather, specifically winter weather. But at this point, we do foresee that the inventory overhang will continue into 2025. I don’t think we’re alone with that idea. But we do forecast that we should bring down inventory levels to the 5-year average throughout 2025, assuming kind of a normal winter. And that’s not only due to the increase in demand throughout the year from LNG and increased electricity demand. Recently — certainly didn’t help, but this summer, we did experience some off-line demand in LNG.

But even with that, overall, we’re still seeing an increase in year-over-year domestic demand. I think electricity is trending on about a 4.5% increase year-over-year and so all those things continue to be positive in the longer term. So specific to what we’re talking about in 2025, we haven’t — we’re not prepared today to talk about 2025. I’m sure heading off a question that probably comes up later on the call with that. But what I’d say is we are actively managing our Dorado program. We’ve done that last year, and we did that this year. Longer term, as I said, we do expect we’re very bullish on pricing through there. And so we are managing the Dorado program to align with demand. We prefer to manage Dorado on the upfront kind of investment side.

I think Jeff mentioned in the opening remarks, the benefits we’ve seen of running a consistent rig program there, increased drilled feet per day by 13% year-over-year. I think if you look at the past 2 years, it’s closer to 30% over the past 2 years. But then once we get the gas molecules online, as Lance mentioned, we do have a low cash operating cost of $1 per Mcf. That’s a dynamic number as we sit here today. And so that gives us a lot of confidence and flexibility on how to invest and how to think about Dorado going forward.

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

Steve Richardson: Thank you. Good morning. Really impressive realizations in the quarter, particularly relative to what we’re seeing from the broader industry and can’t help, but think it’s largely to do with how unique your marketing organization is. Ezra, I guess the — I would wonder if you could expound a little bit on the nature of the organization, right? You don’t seem shy about deploying capital either in field or as we just heard with longer-haul pipes and everything else. But if you just take from the basis that you’re trying to get the highest realization for your products and getting to the best sales point. How do you organize — how do — how do you incentivize that organization on returns? And you think about capital deployed in that business? And how to — and performance of that business and how it adds value to EOG?

Ezra Yacob: 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 a 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. And so 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 in with good partners that understand that we’re trying to align our commitments with how — we think about our growth of the individual assets. And 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 is what will they do for us over the long term with margin expansion.

Lance Terveen: Yes. Right. And Steve, this is Lance. I think where I might add a little bit additional color too, when you think about how we’re differentiated. I just — it goes back to the culture, too. I think like our marketing teams like we’re integrated in with our division operations. I mean our division operations, 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 of our products. But then also when you get to like in-basin fundamentals, we have a strong grasp of that and what we see. And so then 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. So, I’d say all what Ezra put together with his comments and then just the integration that we have internally to, I think, is a real differentiator.

Steve Richardson: Appreciate all that additional info. Sort of — if I could just follow up really quickly on service costs. I appreciate the comments that you’re 50% to 60% contracted for 2024. I would be curious to hear what you’re seeing on the leading edge across the supply chain and thoughts on what the back half of the year could look like, at least on parts of the bill materials that isn’t contracted at this point?

Jeff Leitzell: 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 like 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 at the second half of last year. And it really varied kind of basin to basin based on activity levels. And the Permian, I would say, definitely had the most resilient pricing for service costs since ahead like 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 then workover rigs have reduced about 10%. And just an additional thing that I’d 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 kind of stabilizing. So the big point out there, I’d say, is with the high-spec services that 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, and it’s primarily around the gas plays and outside the Permian.

And then 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 we can of pricing that’s out there.

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

Leo Mariani: 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 kind of prudently manage that activity and how you’re thinking about it?

Jeff Leitzell: Yeah, Leo. This is Jeff. And 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. And as he said, we’ll just be able to monitor those prices through kind of summer and fall and see what happens as we move into the back end of the year. With that, though, yeah, we’re going to go ahead and maintain that 1-rig program really with no changes through the rest of the year. I mean the team has just done an exceptional job on building on their existing operational efficiencies.

And as Ezra stated, I mean, they’re already halfway through the year, they’ve seen a 13% improvement in their overall footage per day. So, the big thing is, if you look at the program, I mean, it’s only a 20, 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. And 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.

Leo Mariani: Okay. I appreciate that. And then just with respect to the Utica, you made some comments that wells are sort of performing in line with expectations, but you also mentioned the fact that you continue to kind of experiment with spacing and completion design. So don’t exactly know what the internal expectations are. But are you seeing the well performance trend better? Are the last two pads showing — maybe just better EURs per foot versus where they were in 2023? Just trying to get a sense of trends on these wells and whether or not they’re getting better and maybe that was what your internal expectation was?

Keith Trasko: Yeah, this is Keith. I’d say they’ve met our internal expectation. 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? And we see changes in geology along there. We see we’re going to have different spacing in different areas, different type curves in different areas, but we are constructive on the play overall everywhere that we’ve tested, and we think the variation that we’re seeing is within the norm.

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

Scott Hanold : Yes. Thanks. Good morning. Maybe sticking with the Utica and how you think about like marketing gas and some of your NGLs. Can you talk about the strategy as you look to eventually get to more scale development in the Utica? How you think about marketing those gas and NGLs?

Lance Terveen: Hey, Scott, hey, good morning, this is Lance. Yes, when we look at the Utica, one of the things I like is — I mean, it was — it’s very consistent. As we think about the early evaluation of the play. One of the things that’s unique, again, I know we’ve commented on this in the past, but when you think about it, I mean, you don’t really need a lot of major infrastructure build-out. I mean — so what we’ve really been focused on from a marketing, midstream and within our division up there is really just getting the local gathering systems in place and those are both commissioned and online, and we’re getting to the markets. I know we’ve talked a lot about there’s just a lot of ample redundant processing capacity.

Again, going back to my earlier comment about you don’t need to make a lot of real long-term commitments. It’s a place where we have measured pace, right? A lot of the acreage is all HBP. We can have a measured pace of production up there. But then from a commitment standpoint with being existing capacity and also very near to a pretty a pretty sizable local demand market on the crude oil side, too. So I think as you think about our strategy from a marketing standpoint, it will be very consistent with our other plays that we’ve had that have been very early in their development. So we’ll be very measured. The crude oil will probably start with lease sales and then we’ll kind of look at oil gathering. We’re setting up and selling a lot of our crude into the local refineries today that’s in that area.

So I would say it aligns very much with what we’ve done in many of our other plays. Scott.

Scott Hanold: Yes. Yes. And I guess delving into a little bit more specific on that, do you expect to try to get the gas that you produce out of the basin to get better pricing in with the NGLs? Would you try to find a way to maybe get to the export market in that area where you get much stronger pricing? So just more so on the NGLs than in the gas, like do you expect to get those out of basin? Or what’s sort of the short and longer-term plan there?

Lance Terveen : No, that’s a great question. I think, again, I mean, not to kind of go back to my earlier comments, it’s going to be a function of just the pace of the development there. And so commitments, we’re going to be very disciplined there. But as you think about the gas markets there, especially at the tailgate from a residue standpoint, into the markets, there’s a significant amount of just demand that’s there kind of going through the Midwest, you have a lot of interstate connectivity. It’s an extremely liquid market. So I think we’re going to be pretty disciplined there, and I’ve been using that word quite a bit, but it’s just not a need to really reach too further downstream. And then as you think about the NGL markets, there’s a lot of — it’s a little bit different than other plays in that you have a lot of the local fractionation is kind of there within the state, right?

And so a lot of the purity is being exported. So we’re kind of already kind of participating in some of those aspects as well, just because that’s some of the natural markets avenues for the products there on NGLs, Scott.

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

Charles Meade: Yes. Good morning, Ezra, to you and the whole EOG team there, I’d like to go back to the Utica and the ShadowPad. So it looks like a really attractive IP30 you showed us there, relative to the wider space wells. But I’m curious if you could maybe offer a little bit more detail or insight on how those — the spot rates are evolving from that pad. And if you have any sense of how long it will be before you’re able to say that that the spacing policy is a success?

Keith Trasko: This is Keith. So as far as how the — I think the — 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 like a 60% to 70% liquids mix for the UR product. And so 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 about a little over six months now, and we see closer to a 50% oil cut right now. So 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.

Charles Meade: Got it. That’s helpful. So maybe midyear next year. And then a follow-up on the TLEPP project. I wonder if you could — sticking on the theme with the midstream, but wondering if you could give us a narrative on how that project came together for you guys, particularly that I know a lot of people — a lot of marketers have been trying to get east from the ship channel to markets East of there and how this came together and how it came to be that you’re the 100% of capacity there?

Lance Terveen: 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, one of the questions kind of related to just the marketing strategy and the integration that we have and we think about like the markets. And was something that we looked at as you asked the genesis of that. I mean that started all the way back in kind of 2022, right? And so we saw kind of that station 65 when you look kind of into that market was likely going to be very much premium market long-term. And so we worked alongside Williams there, went out for their open season, and we’re able to capture all the capacity there through our precedent agreement.

So that took a lot of time, I mean, I think you really have to have that foresight and then looking forward like into the markets. And then I think other thing I really want to capture is just that is all in path right, Charles. So I mean, when you think about like South Texas all the way through our Eagle Ford asset, all the way up into the Gulf Coast market. I mean, we can kind of capture everything, the Delaware Basin with our existing transport, our new transport that we’re going to have on Matterhorn, all that that kind of gets in the path can kind of get into that market. So that’s a little bit of that all came together because, yes, you have a lot of these pipes that are coming in to the Gulf Coast. And so as you’ve seen on some of our slides that we have there, especially related to gas sales agreements, you have to have end markets on the other side.

So 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. So you need to have the transport position, Charles, but then you also need to be thinking about having strategic sales on the other side. And I think that’s another thing that really differentiates us that we’ve got that in place now and then also looking forward.

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

Paul Cheng: 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 competitor? 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.

Jeff Leitzell: Thanks, Paul. This is Jeff. Yes, that’s a great question. And 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 all the pressures, all the flow rates, temperatures, everything real time. And so all that’s flowing into the system, and you can see that, which 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 is in each one of basins that watches our production real-time 24/7. And as these systems are optimizing at the control room can watch it, monitor and make sure that the iterated set points are correct then notify any people in the field real time to be able to go out and check on a well or make any additional changes that need to be done.

So really, it has to do with the integration within our systems, it really kind of sets us apart from that aspect. And 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 operations of wells. And what these optimizers really do is they help minimize that downtime. So instead of having a handful of percentage, you’re able to actually knock off a percentage to downtime be able to keep these wells flowing and maximize the production across our multi-basin portfolio.

Paul Cheng: That’s great. The second question that I think, Ezra, you talked about. You guys can do quickly the rate if you want to increase activity level, what will be the precondition? I mean what do you look for in order for you to determine when is the right time for you to accelerate the rig activity or that even — how many wells that you bring on the market?

Ezra Yacob: Yes, Paul, this is Ezra. I think you broke up there just for a second. So I’m not sure if you’re asking about the Bakken, Dorado or Utica, but obviously…

Paul Cheng: 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 it is simply the price or that you are looking for anything else? And increase of 5, is there price mix of that will be buying the impact trick upon?

Ezra Yacob: Yeah. Thank you, Paul. So yes, with Drato, I think the biggest thing to continue to think about with any gas play, and for us, the dominant one is Drato. And you can see right now in the current environment, how volatile gas prices are is 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 with it with low operating costs, gas is easier to operate in liquids. But then you need to make up for it with volumes. And then the second piece of it 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. And if you’ve got the gas they’re exposed to the market, you can capture those.

If you try 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. So 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 is 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 learning’s in the very next well and continue to be confident that when we see the emerging demand hit, which is coming in next few years with a lot of the 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 — that’s on the drilling side. On the completion side, we do have a lot of flexibility there. A great way to kind of overspend is if you’re bringing in a frac spread and sending it out of the basin and bringing it back picking up water lines, laying them back down and things like that. So 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 to capturing economies of scale. Then the second one is trying to get your packages lined up. So when you bring a completion spread in, you can actually keep it for a significant number of wells and bring that on. What we look for in general to when we could take that next step. It’s not only internal learning’s, it’s not only the returns that we’re generating.

But it is also with respect to 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. But then we’re also cognizant of the supply and demand fundamentals for really North America or really just the US. And again, what we see is a lot of increased demand coming in the next few years. You have 10 to 12 Bcf a day arguably under construction right now that should be on really beginning throughout 2025. And then in addition to that, as you look at the back half of the decade, I think on the last earnings call, 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 then 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. And externally, we look at supply demand and ultimately, the inventory levels, Paul.

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

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

Ezra Yacob: Yes, sir, Doug, it’s good to hear from you again.

Doug Leggate: Good. I wasn’t sure if I had gotten into the — there, but I wonder if I could pull you back to the Utica just for a second. I mean, delineation is kind of a glacial event for a lot of companies. You guys have moved very quickly not only to lock down the acreage, but to demonstrably show that at least on our numbers, this is starting to look competitive relative to your Permian position. I’m just wondering how you would frame the extent to which you’ve derisked the play at this point and when you would anticipate a more meaningful development plan as you move forward? Is it infrastructure constrained? Or is there another reason that you’re waiting? Because it looks like geologically, at least you’re figuring this thing out.

Ezra Yacob: 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 fearing out. I will point out the only caveat, I’d maybe make is we have, as Jeff pointed out, concentrated right now in in the volatile oil window. So, roughly 225, 000 out of the 445,000 acres. But you can see our confidence the fact that we continue to put — we continue to put together some leased acreage as we increase the footprint about 10,000 acres. And it’s not overly complicated, Doug. We’ve got multiple packages now in the north, and we’re seeing consistently strong results. So, I would say we’re feeling very confident there in the North. Certainly, as Keith and Charles were speaking about, we’re not 100% satisfied with a 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 — it’s going to be between 600-foot and 1,000-foot spacing, probably on average, depending on the play. And then 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. So, 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. And 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.

Doug Leggate: 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, as 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 wood work, like the Woodside deal with Wheelan [ph], for example.

Where would you be comfortable in terms of international exposure? I’m losing my voice, but in terms of international exposure, Ezra, as it relates to your total proportion of your volumes?

Ezra Yacob: Yes, Doug, I appreciate that. We have — as you’ve seen, we’ve got 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 and kind of a counter-cyclic time period. And so the first thing to keep in mind is, when we look at these opportunities, we want to make sure that we’re being a low cost — we’re entering into a lower cost contract or gas sales agreement that’s going to provide us with upside exposure. And then in the sales agreements that we’ve done to date, we feel like it limits our exposure to risk as well.

One reason that we’re able to enter into some of these agreements is just because of to be perfectly honest, the size and scale of what we’ve captured, mainly at Dorado, but also across other basins as Lance has talked about. So 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. But from 2020 to 2023, as we highlighted on Slide 11, that’s added about just over $1 billion worth of revenue uplift, which is outstanding. So even on small volumes, it can be a major impact on the revenue side. We’re happy that, 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.

And then as we’ve talked about last quarter, we made it yet another — and I would call this countercyclic agreement because an agreement like this hasn’t been done in North America for quite some time, but we actually have a Brent link now gas sales agreement. When we think about a 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 is dependent on the types of agreements and the marketing structures that we see available at the time. But ultimately, our strategy is to get more of our gas exposed to diverse market and to get our gas kind of offshore and exposed to the international markets.

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

Ezra Yacob: 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.

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