EOG Resources, Inc. (NYSE:EOG) Q4 2023 Earnings Call Transcript

EOG Resources, Inc. (NYSE:EOG) Q4 2023 Earnings Call Transcript February 23, 2024

EOG Resources, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day, everyone, and welcome to EOG Resources Fourth Quarter and Full Year 2023 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, and good morning, and thanks for joining us for the EOG Resources fourth quarter 2023 earnings conference call. I’m Pearce Hammond, Vice President, Investor Relations. 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 today’s 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 and our forward-looking statements have been outlined in the earnings release, and EOG’s SEC filings. This conference call may also contains 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 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; Billy Helms, President; Jeff Leitzel, Chief Operating Officer, Ann Janssen, Chief Financial Officer, and Lance Terveen, Senior Vice President, Marketing. Here’s Ezra.

Ezra Yacob: Thanks, Pearce. Good morning, everyone, and thank you for joining us. Our outstanding performance last year demonstrates that EOG’s value proposition delivers results. We beat our volume targets and reached a production milestone, exiting the year producing more than 1 million barrels of oil equivalent per day. We earned adjusted net income of $6.8 billion for a return on capital employed of 31%. We generated $5.1 billion of free cash flow and returned more than 85% of that free cash flow to shareholders last year, handily outpacing our cash return commitment. Our regular dividend remains the anchor of our cash return strategy. We increased it 10% last year to an annualized rate of $3.64 per share, which represents among the highest regular dividend yields of our peers and is competitive with the broader market.

2023 was a year of record production and outstanding financial performance, and it’s not a one-off year. The real power of EOG’s value proposition is consistency. Over the last three years, since the start of 2021, EOG has generated about $20 billion of adjusted net income, over $18 billion of free cash flow, and returned over $12 billion to shareholders. EOG delivers reliable operating results that translate to consistent financial performance year after year through the cycle. And that’s EOG’s value proposition, sustainable value creation through industry cycles. Our strategy to deliver on that value proposition starts first with capital discipline, a returns-focused capital allocation strategy guided by our premium hurdle rate, which requires investments to earn at least 30% direct after tax return at $40 oil and $2.50 natural gas.

Capital discipline allows EOG to consistently achieve its free cash flow priorities and deliver on shareholder return commitments, positioning EOG as a compelling investment competitive with the S&P 500. The second principle of our strategy to deliver on our value proposition is operational execution. Our multi-basin organic growth portfolio is a competitive advantage. We have superior in-house technical expertise that supports leading-edge well performance while minimizing well costs. Our proprietary information technology enables real-time data-driven decision-making. We actively avoid falling into manufacturing mode where one well design is stamped out across a basin. Rather, we adhere to the discipline of continuous improvement such that the latest learnings get embedded into the next well and transferred to the next basin.

Integrated into our operations is our focus on sustainability, the third leg of our strategy to deliver EOG’s value proposition. Last year was a banner year with respect to our environmental performance. In addition to maintaining GHG and methane emissions intensity rates below our 2025 targets, we also achieved zero routine flaring throughout our operations. We achieved a wellhead gas capture rate of 99.9% and in the Delaware basin, our most active operational area, we increased water reuse to 90%. The final leg and foundation of our value proposition is EOG’s culture. Our employees embrace and embody EOG’s unique culture and are the number one reason for EOG’s success. Collaborative multidisciplinary teams drive innovation and sustain the cycle of continuous improvement and our technology leadership.

Our company is decentralized and non-bureaucratic to allow decision-making in the field at the asset level, which truly differentiates EOG relative to our peers and is a lasting competitive advantage. This culture is what drove our successful results in 2023 and provides the foundation to continue to deliver in the future. Ann is up next to discuss our cash return strategy and preview the details of our 2024 capital plan. Here’s Ann.

Ann Janssen: Thanks, Ezra. This morning, I’d like to review EOG’s cash return strategy. A growing sustainable regular dividend remains the foundation of our cash return commitment, which is now a minimum of 70% of our annual free cash flow. We believe the regular dividend is the best indicator of a company’s confidence in its future performance. It’s a commitment to our shareholders based on our ability to continue to lower our cost structure and sustainably expand future free cash flow generation. Since we began trading as an independent company in 1999, we have delivered a sustainable growing regular dividend. It has never been cut or suspended and its 25-year compound annual growth rate is 21%. Last year, we announced an increase in our regular dividend of 10%.

In fact, we have increased our regular dividend by at least 10% each year for the last seven years. The indicated annual rate is now $3.64 per share, which currently represents about a 3.2% regular dividend yield, among the highest in our E&P peer group. In addition to our regular dividend, we paid $2.50 per share in special dividends in 2023 and took advantage of increased market volatility to opportunistically repurchase shares. We bought back approximately 1 billion of our shares at an average price of $112 per share, repurchasing nearly 9 million shares. Since putting the $5 billion repurchase authorization in place over two years ago, the fundamental strength of our business has improved and we continue to get better through consistent execution of and commitment to EOG’s value proposition.

Last year, we also further strengthened our balance sheet by retiring $1.25 billion of debt. At year-end 2023, we had $5.3 billion in cash on the balance sheet, $3.8 billion in long-term debt, and over $7 billion of liquidity. We view a strong balance sheet as a competitive advantage in a cyclical industry. Our balance sheet is among the strongest in the energy sector and ranks near the top 10% in the S&P 500. Between our $1.9 billion of regular dividends, $1.5 billion of special dividends, $1 billion of buybacks, and retiring $1.25 billion of debt, 100% of EOG’s 2023 free cash flow of $5.1 billion is accounted for. With a financial profile more competitive than ever with the broader market, EOG has never been better positioned to generate significant long-term shareholder value.

This quarter, we included a three-year scenario on slide five of our investor presentation to illustrate our ability to create future shareholder value. We assumed a macro environment, commodity prices, and production growth comparable to the last few years for production that’s low single-digit oil growth and high single-digit BOE growth per year. In the current environment, this pace of activity has delivered exceptional results, and we expect to deliver more of the same. Using a $65 to $85 oil price range and a $3.25 natural gas price through 2026, we would expect to generate between $12 billion and $22 billion in cumulative free cash flow and an average return on capital employed of 20% to 30%. At the midpoint, the scenario estimates $17 billion in cumulative free cash flow, which represents about one-quarter of EOG’s current enterprise value.

We believe this three-year scenario highlights an extremely competitive shareholder return profile not only among energy companies, but also with the S&P 500. Turning more immediately to 2024, we forecast another year of strong operational and financial performance. We expect our $6.2 billion capital plan to grow oil volumes by 3% and total production on a BOE basis by 7%. At just $45 WTI, our plan breaks even. At $75 WTI and $250 Henry Hub, we expect to generate about $4.8 billion of free cash flow and produce an ROCE of greater than 20%. Based on our target of returning at least 70% of free cash flow, that implies a minimum return to shareholders of $3.4 billion this year. Now, here’s Billy to review 2023 operating results and proved reserves.

Lloyd Helms: Thanks, Ann. 2023 proved to be another exceptional year of performance, and I would like to thank each of our employees for their accomplishments and execution last year. For the full year, we delivered oil production above the original guidance midpoint set at the beginning of the year, while capital spending was at the midpoint. Overall, we were able to grow our oil volumes by 3% and our total production by 8% year-over-year. In the fourth quarter, we achieved a significant milestone, crossing the 1 million barrel of oil equivalent per day level of total production. EOG has been able to nearly double production over the last 10 years through our high return organic growth approach. Last year, our cross-functional teams worked to drive efficiency gains throughout our multi-basin portfolio.

For drilling operations, our EOG motor program continues to reduce downtime with our 2023 program yielding about a 15% improvement in footage drilled per rig. For completions, we continue to expand our super zipper operations across our multi-basin portfolio, reduce frac fleet move times, and decrease stage pump times due to increased horsepower for frac fleet. This improved our completed footage per frac fleet by about 7% in 2023. And we expect to continue seeing the benefit of those gains throughout 2024, which Jeff will run through shortly. Our production teams work to optimize production and expenses, reducing our cash operating costs to $10.33 per BOE. In addition, our facility and operating personnel continue to reduce our methane emissions while commissioning our first CCS injection well.

Our approved reserve base increased by 260 million barrels of oil equivalent last year, and now totals nearly 4.5 billion barrels of oil equivalent. This represents a 6% increase in reserves year-over-year, and proved reserve replacement of 202%, excluding price-related revisions, with a finding and development cost of just $7.20 per barrel of oil equivalent. Now here’s Jeff to discuss operations and the 2024 plan.

Jeffrey Leitzell: Thanks, Billy. For our 2024 plan, we forecast a $6.2 billion CapEx program to deliver 3% oil volume growth and 7% total production growth. We expect to see some deflation throughout the year, and our forecasting well cost to be down a low single-digit percentage compared to last year. The primary drivers are a 10% to 15% reduction in tubulars and ancillary service costs. Our plan reflects increased investment in long-term strategic infrastructure in the Delaware Basin and Dorado, which are expected to reduce operating costs and expand margins for the life of these assets. These projects are highlighted on slide seven of our presentation, and Lance will discuss them in greater detail in a moment. I’d like to highlight that our year-over-year direct capital efficiency is improving, which is illustrated in our capital program breakdown on slide six of our earnings presentation.

In addition to the operational improvements Billy mentioned, our company-wide average treated lateral length per well is increasing by 10% in 2024. These improved efficiencies and longer laterals have resulted in a decrease in the number of drilling rigs by four, frac fleets by two, and our net wells by 40 compared to last year. The ability to grow our volumes year-over-year for less direct CapEx is a testament to the improved well performance and operational efficiency gains we are realizing across our operating area. When looking at our activity in 2024, EOG remains focused on progressing each one of our plays at a measured pace that allows us to capture and implement valuable learnings while realizing consistent improvement. In our foundational plays, specifically the Delaware Basin and the Eagle Ford, our teams are executing at a high level, and we expect to maintain consistent activity compared to 2023.

For Dorado, we remain excited about this 21 TCF resource potential asset and the role it will play in meeting growing global natural gas demand. Throughout last year, our team made good progress on improving operational efficiencies and recoveries. For 2024, we expect to moderate activity compared to 2023. A balanced approach to our investment in Dorado will allow us to maintain consistent operations to advance and improve the play while continuing to remain flexible as we monitor the natural gas market. In the Utica play, our technical and operations teams continue to make great progress. Our latest three-well Xavier package delivered initial 30-day average production of 3,250 barrel of oil equivalent per day with 55% oil and 75% liquids. The Xavier wells were drilled at 800-foot spacing, which is tighter than the Timberwolf package at 1,000-foot spacing.

We are pleased that all of our package wells to date have come online at production levels exceeding results from our initial individual test wells. For 2024, we expect to increase our activity level to one full rig, continue to test well spacing, and delineate our acreage across the play. Our next four-well package, named White Rhino, is located in the southern part of the Utica, and we expect these wells to come online in the first half of the year. In the Powder River Basin, our team has continued to improve well productivity in the Mowry Formation. We have observed double-digit increases in oil and BOE productivity per well due to improved targeting and our consistent package development. Moving into 2024, we expect to moderate activity levels, and along with Mowry development, will begin testing packages in the shallower Niobrara Formation in our primary development area.

I would like to thank our employees for their hard work and dedication that has positioned the company for another outstanding year. We are excited about executing our 2024 plan. EOG remains focused on running the business for the long-term, generating high returns through disciplined growth, operational execution, and investing in projects that will lower the future cost bases of the company. Now here’s Lance to discuss infrastructure.

Lance Terveen: Thanks, Jeff. Infrastructure investments have been an essential element of EOG’s marketing strategy to maintain transportation flexibility out of a basin, diversification of in-sales markets, and control from wellhead to sales point for flow assurance and to maximize margins. More recently, we have invested in two new strategic infrastructure assets to lower the long-term cost bases of the company and enhance margins. In the Delaware Basin, we are constructing the Janus natural gas processing plant, a 300 million cubic feet per day facility, along with gathering pipelines up to 24 inches in diameter. This new plant and gathering system is expected to provide material savings over the life of our Delaware Basin asset and reliability and flow assurance in the most active oil play in the U.S. We expect Janus will go into service in the first half of next year and deliver cost savings and revenue uplift of about $0.50 per MCF.

While we enjoy great relationships with our third-party midstream providers, this new EOG-owned plant adds optionality consistent with our marketing strategy. The Delaware Basin is our largest asset by throughput volumes, and early high utilizations at our Janus plant provides for an anticipated 20% plus rate of return. In our emerging South Texas Dorado play, we’re constructing Phase 2 of the Verde 36-inch natural gas pipeline. We have taken a very disciplined approach to build out Verde commensurate with expansion of U.S. Gulf Coast demand. We placed Phase 1, which terminates in Freer, Texas, in service last year. And once Phase 2 is fully in service later this year, the Verde pipeline will extend to Agua Dulce, where we will have a premier position along the Gulf Coast with pipeline connections to reach multiple demand centers, including LNG facilities and additional local and Mexico markets.

We continue to see consistent well results in Dorado, and this new strategic investment supports lower future breakevens in a volatile natural gas market. We’re extremely pleased with the progress we’re making with these strategic infrastructure investments, which we expect will lower the cost basis of the company, provide substantial savings versus other alternatives, and increase operational control. In addition to strategic infrastructure, we continue to be a first mover in marketing our domestic natural gas to diverse indexes. We recently finalized a sale and purchase agreement for 140,000 MMBtu per day of our natural gas index to Brent, and another 40,000 MMBtu per day index to Brent, or a U.S. Gulf Coast gas index, beginning in January of 2027.

Adding a Brent-linked agreement with start date certainty further expands EOG’s pricing exposure to international natural gas markets and growing LNG demand. EOG is executing on its marketing strategy to diversify our access to customers across multiple end markets for our growing production of reliable and affordable natural gas. Now here’s Ezra to wrap up.

Ezra Yacob: Thanks, Lance. EOG’s business has never been better, and our financial position has never been stronger. Our 2023 operational and financial results were not a one-time event. Rather, the results reflect our value proposition at work. Capital discipline, operational execution, leadership, and sustainability, and a unique culture are at the core of our success and will continue to deliver consistent shareholder value, and it continues in 2024. We are investing across our multi-basin portfolio with a focus on optimizing both near and long-term free cash flow generation and delivering high returns, while staying flexible with respect to supply and demand fundamentals of both oil and natural gas. Our disciplined approach to premium oil investment, commitment to organic exploration, and strategic infrastructure investments drive our low breakevens and through-cycle value creation.

And you can see this discipline delivering consistent results across our three-year scenario. Our confidence in EOG’s ability to compete across sectors, create value for our shareholders and be a part of the long-term energy solution has never been higher. Thanks for listening. Now we’ll go to Q&A.

Operator: Thank you. [Operator Instructions] And our first question comes from Leo Mariani of ROTH MKM. Please go ahead.

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Q&A Session

Leo Mariani: Hi, guys. I wanted to just address the U.S. gas production guidance for 2024. It seems like it’s a pretty wide range this year versus the oil number, which is quite a bit tighter. I just wanted to get a sense if there’s kind of a concerted effort on EOG’s behalf to perhaps alter some of the timing of turn in lines during the course of the year to maybe try to avoid some of these weak months here for gas prices and potentially try to bring volumes on closer to next winter. And just any thoughts on your macro for gas in terms of kind of tying it in terms of how you see gas prices play out here.

Ezra Yacob: Yes, Leo. This is Ezra. Thanks for the question. Yeah. What I would say is you can expect out of Dorado similar treatment to what we did last year. I mean, to start with, we already reduced our activity level at Dorado by reducing the rig activity. And then we’ll be flexible just like we were last year with completions and when we’re bringing those wells on throughout the year with respect to the natural gas market. I think when you’re talking about the gas growth and the gas guide for the company in general, you bring up a good point. When we look at U.S. gas growth from Q4 exit rates to the 2024 midpoint guide, you’re really seeing about 80 million a day in the domestic gas growth. And then what’s a little bit unique to this year is the amount of gas growth we’re actually seeing out of Trinidad.

That’s actually contributing a significant amount of gas growth at the company level from the Q4 exit rates to the midpoint 2024 guide for Trinidad. You’re seeing about a 50 million a day growth rate there. So a little bit unique. And as you guys know, we’ve got a consistent program down in Trinidad. We’ve been in the middle of a drilling campaign for this year, and we’re also still under construction on a platform that we plan on placing at the end of this year. And the unique thing about Trinidad, of course, is that their current supply and demand fundamentals on gas are, quite frankly, almost opposite of what we’re seeing domestically here in the U.S. That’s a country which, up until the last decade, used to have a very robust supply of natural gas.

And in the last decade or so, that’s been decreasing. So they find themselves really undersupplied on the natural gas side for their domestic needs. And, of course, we sell all of our gas currently into the domestic market at pricing that’s slightly advantaged and makes those projects down there very competitive with the rest of our domestic portfolio. Outside of that, the U.S. gas growth is really — the majority of that 80 million a day is really associated gas that’s coming off of our liquids rich and oil plays.

Leo Mariani: Okay. That’s helpful. And then maybe just jump in gears over to the PRB. Obviously, that’s an important play that you guys have emphasized over the last couple years. I do see that there is some additional Utica activity this year, but it looks like you’re pulling back a little bit in the PRB, which maybe was a little bit kind of surprising to me. I think you’ve got 10 fewer wells in terms of completions this year versus last. I assume that you’re still trying to progress the science and the learnings on the play. So maybe you can just add a little color as to why some of the months pull back here in ’24.

Jeffrey Leitzell: Yeah, Leo. This is Jeff. And yeah, great point. So, we had a lot of great success as we talked about in our opening comments with our Mowry program there. We’re seeing increases in overall productivity in that target by about 10% year-over-year, both on oil and BOE. And really what it has to do with is just us getting the package development on our corridor and really understanding how to offset those parent packages with additional activity. So with that, though, we’ve also been able to really accumulate data with drilling all those Mowry wells up through that overlying Niobrara. So we’re going to shift gears here a little bit there since we’ve been able to refine our geologic models. And we’re going to go ahead and start testing some of the package development in that shallower Niobrara formation right along our primary infrastructure corridor.

So really when you look at our program, it’s just a slight step back on the Mowry and a little bit more focused now to kind of really figure out the geologic models in the Niobrara and get some package production performance on. So activity will be equally split really kind of between the Mowry and the Niobrara formations. So it’s very similar to what we did in the Delaware Basin. Really we developed from the bottom up and it’s a similar codevelopment strategy really just to maximize the value of the asset.

Operator: The next question comes from Neal Dingmann of Truist Securities. Please go ahead.

Neal Dingmann: Morning. Thanks for the time guys. My first question is on the Utica oil play. I’m just wondering, are you continuing to add acreage? It sounds like maybe you’ve recently added some and then secondly on that play, how far west in that black oil window do you all have confidence these days?

Lloyd Helms: Yeah, Neal. This is Billy Helms. We have continued to look for opportunities to pick up acreage where we see it. Just a reminder overall our acreage acquisition cost is probably around $600 an acre. So very low cost of entry, especially when you consider it compared to a lot of other opportunities to deploy capital. So we’re very pleased with our organic approach there and we’ll continue that trend and try to pick up acreage that’s accretive to our position. And then as far as how far west are we confident? We’re continuing to test out the play. Just a reminder, if you look on the slide in our investor deck, I think slide 17, it illustrates how that play extends 140 miles north to south. So far we’ve got a handful of wells where we have production data on.

We’ll grow that this year to about add another 20-plus or minus wells. So we’re very pleased with the activity we’ve seen, the results we’ve seen. We still have a lot of testing to do across that 140 mile span. We are seeing some data that tells us we can go a little bit further west, but we have yet to prove that out. So we’ll give you those results as we start seeing the performance of some wells in the future. But we’re still remain extremely excited about the potential of that play.

Neal Dingmann: Yeah, I look forward to what you all got going there. And then secondly, just on OFS materials, specifically, in the past you guys have done a great job using that strong balance sheet to optimize the stockpile of pipe and other materials. And I’m just wondering, can you speak to if you’re currently building any inventory levels or if you believe future prices could fall? So you’re just — I guess, running more in real time.

Jeffrey Leitzell: Yeah, Neal. This is Jeff. So yeah, we always tend to carry somewhere between a six-month to a 12-year inventory. And it really does give us an advantage to kind of strike on opportunistic purchases. And I think that’s one of the things, if you look at this year, really the primary drivers that we’re seeing, as far as deflation is really going to be those tubular costs, which we’re expecting to be down kind of 10% to 15%. That’s really a credit to our procurement team to be able to really find really opportunistic times to be able to buy the pipe and go ahead and add that to our inventory. So we’re able to see that price drop throughout this year. And then the other thing I’d say is really the other drop we’re seeing is in ancillary services really supporting kind of drilling and completions.

We see kind of a 10% to 15% drop in those support services such as coal tubing, wire line, cement and other such. So seeing some movement there on the deflationary front. We think from an overall tubular standpoint, we’re in great position for 2024.

Operator: The next question comes from Doug Leggate of Bank of America. Please go ahead.

Doug Leggate: Thanks. Good morning, everyone. Hope everyone’s doing well after a busy earnings season. Ezra, I always appreciate, we always appreciate the free cash flow visibility that you guys try and give us after last quarter in particular. I’m looking at slide five, however, and you’ve got about 7% growth this year. Presumably there is growth in future years through that ’26 plan. My question is, if I look at the cumulative free cash flow and just do the simple math, it looks like the free cash flow is flatlining over that period despite the growth. So I wonder if you could give us some color on the CapEx that goes along with that. And how at the end of the period your sustaining capital would reset given the larger volume you would have at that time.

Ezra Yacob: Yeah. Doug, thanks for the question. This is Ezra. Yeah. The cumulative free cash flow over the three-year period in the three-year scenario here that you highlighted on slide five, it’s roughly 10% higher than the previous three years here that we have. So you see expanding margins in that three-year scenario. And unfortunately what we haven’t given you is some of those specific details that you’re really getting into. What we have talked about, and we talked about this in November, and then you and I talked about it again in your conference there in November, is our maintenance capital number currently is midpoint of 4.5 under a variety of different scenarios for a multi-basin organic growth company like ourselves, that maintenance capital will kind of range from 4.2 to 4.8. And that depends on, again, are we trying to keep oil flat, equivalents flat.

Are we really just focused on maintaining production? Or are we actually investing in additional exploration and infrastructure and things of that nature? When you look and roll that into the three-year scenario, since we are growing volumes, you’re right, that maintenance capital should be trending up a little bit. That’s also going to be offset in the real world by some of the deflationary factors that we have moving towards us throughout this three-year plan. What I would say is that we don’t see that the free cash flow is flatlining. In fact, what we see is a 6% cash flow and free cash flow per share compound annual growth rate across that three-year scenario.

Doug Leggate: That’s helpful. We’ll take another look at it in the buybacks. We’ll certainly help that, I hope. My follow-up is a little bit random, perhaps. But clearly it seems with the Utica and Dorado, you can’t kind of help yourself, but grow gas with one rig in the Dorado, given how strong the volumes are, obviously. But it seems that the mix is kind of shifting a little bit over time. I think we also talked about that in November. My question is, what can we expect from the next steps of the organic strategy from EOG? If I could be a little specific, there’s a fair amount of speculation that you guys are looking hard again at Canada and the — should we think that organic growth could move in that direction? I’ll leave it there. Thank you.

Ezra Yacob: Yeah. Doug, to quote you, that is a bit of a random question. We’re always organically exploring for things. With regards to the Canadian assets, we were up there a number of years ago and we strategically exited that asset. At the real heart of your question, the way to think about the strategy for us is we’ve captured a tremendous resource down here in South Texas in the Dorado natural gas play. What we’re building is a low-cost gas business that really sits alongside our core oil investment. And so when we think about capital allocation, it’s not necessarily allocating more capital to gas rather than oil. It’s really looking at these assets in place independently and what’s the best thing for the company to continue to drive down our breakevens, continue to build value for the shareholders.

With regards to the Utica and some of the other emerging assets, in a lot of ways our premium and double premium return threshold makes us a little bit ambivalent or agnostic to the actual hydrocarbon type that we’re producing because again, these things are really a return-based question. When you layer in the macro environment, we do need to have consideration on that. Going forward with the gas market, this year definitely does look a little bit soft. We touched on that just a little with Leo’s question at the top of the Q&A. But we still do remain constructive on the U.S. domestic gas market, say, 12 months and further out from here as the LNG demand continues to come on. And with some of the announcements we’ve made today, you can see that we plan on being a part of that solution going forward.

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

Scott Hanold: Thanks. Hey, Ezra, EOG shares have laid some of its peers on both multiple bases and just in aggregate performance here. I can remember in the past when you all had commanded a pretty good multiple premium to everyone else. I’m just curious, you’ve shown the willingness and appetite to step in to buyback strategically over the last year. As you look at 2024 where your stock’s trading right now and in your strong balance sheet, is there a willingness to get more aggressive and use some of that balance sheet strength to underpin the intrinsic value seen in EOG?

Ezra Yacob: Scott, that’s a good question. I think when we think about buybacks, again, we think about what’s the best way to create long-term shareholder value. That’s it. You’re right. We’ve seen our multiple compressed. We’ve seen really multiples compressed across all of industry. I think you don’t have to look any further than the weighting of energy in the S&P 500 at approximately 5%, maybe a little bit under that, with close to 10% on forecasted earnings. So I do think we sit currently in what we’d say is a dislocated environment. And from that regard, I think as we move forward and generate a significant amount of free cash flow this year with our minimum commitment to shareholders to return 70% of that free cash flow to our shareholders, you could anticipate that being more in the form of buybacks right now.

Now, when we look back at what we have done historically on buybacks, in 2023, we were very active in the first half of the year, during some real dramatic dislocations, I would say, regional banking crisis and the debt ceiling conversations and things like that. Now, we did, as an example, take a step back on buybacks in Q3 as oil price rose from $69 to $93 throughout that quarter. And obviously, there was some share price appreciation as well. And then in the fourth quarter with volatility entering the sector, again, the continued multiple compression across industry and across EOG, we obviously stepped back into it. When we think about it, we think about the strength of the company as we continue to improve. I think you can see with our three-year scenario, we continue to expand the free cash flow potential of the company.

We continue to do that while generating high returns. I think really — like I said, currently, we would consider ourselves in a dislocated environment.

Scott Hanold: Okay. I appreciate the color. And then if I can pivot to the three-year outlook and kind of parlay the premium activity into that. You all provided that chart on the Permian where you show the mix of wells and an increasing overall cumulative production, but just a touch lower on oil. I know you guys do a lot of codevelopment, but can you talk about the trend investors should expect on how that mix shifts going forward and within that three-year outlook? A – Jeffrey Leitzell Yeah, Scott. This is Jeff and thanks for the question. Yeah. We are going to be completing a few more Wolfcamp M wells in our 2025 program, but it’s just part of our plan and our normal cadence of development as we move section to section and we move up in section and develop each one of the intervals.

The one thing about the M is you need to identify whether or not it has a good barrier between it and the upper Wolfcamp. If there is, you can go ahead and develop that target independently, but in many of our areas that we are going to be developing the Wolfcamp this year, it’s really optimal to codevelop those two targets together. And this is just strategic really to minimize any kind of depletion in these sections and maximize the value of each one of those targets. As a reminder, the Wolfcamp M does have more associated gas, but it’s also a very, very prolific oil producer. It’s got premium returns and the wells pay out in about eight months. So our goal in the Permian or any kind of stacked pay basins is always going to be to continue to execute a codevelopment strategy and really just focus on maximizing returns and NPV.

And I’m sorry, I think I said 2025, I meant 2024 program.

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

Neil Mehta: Yeah. Thanks, Ezra and team. First question on just going back to the macro, I think we’ve been surprised by the supply of natural gas from the U.S. over the course of the last six months. And one of the areas has been associated Permian supply. And so, Ezra, I love your perspective on how you see that evolving, especially as some of the wells mature, but maybe as U.S. production declines on the other side of it. And how that all ties into the way you’re thinking about mid-cycle views on gas?

Ezra Yacob: Yeah. Thanks, Neil. That’s a good point. I think you will continue to see — so far our models is here for U.S. growth might start there since we’re going to be talking about associated gas is really where your question is. It’s roughly around a 500,000 barrel total liquids. So roughly say 300,000 barrels more along the crude oil. And obviously, the significant amount of that is going to be coming out of the Permian, which in general, that basin is a little bit higher GOR than some of the historical plays like the Eagle Ford and the Bakken that we’ve had. And I think you’ll continue to see — our model would suggest you’ll continue to see an increase in the associated gas and more than likely a bit more of a differential struggles there with Waha.

We take that into consideration when we’re thinking about the development of Dorado. Like I said, you can’t forecast a supply and demand or forecast future gas, mid-cycle gas prices without having a recognition of what’s happening on the oil side. It’s one of the things that makes forecasting gas so difficult. So the ultimate thing, the way that we manage our business and we’re trying to grow this gas asset in concert with our oil plays is to really think about being the absolute low-cost producer. And that’s one reason you haven’t seen us ramp up aggressively in the Dorado asset. It’s one reason you’ve seen us last year and this year moderate activity, because we’ve captured a significant resource. We think geographically it’s located a place that gives us significant advantage.

We’ve invested in some additional infrastructure, including the Dorado pipeline that’s named Verde, that’s going to give us a margin expansion over the life of that asset. And that’s really the way that we’re focusing on developing a pure gas asset is really in concert with the growing future North American demand, which is dominantly driven from the LNG there along the Gulf Coast.

Neil Mehta: Thanks, Ezra. The follow-up is you have a different strategy than many of your peers. We’ve seen so much consolidation in the conventional space in the last year, and you’ve got a much more organic approach. And I guess I wanted to give you an opportunity to talk to the investor base about why you think that is the right strategy and what are the pluses and minuses that come with that strategy.

Ezra Yacob: Yeah. Well, as we’ve talked about before, we’re focused on creating shareholder value through the cycles. And the consistent way that we’ve been able to generate that value is through organic exploration, a focus on low-cost operations and a commitment to capital discipline. We have a high level of confidence in our existing portfolio, and it’s aimed at improving the financial performance of the company. And again, I think you can see that with expanded margins and expanded free cash flow in that three-year scenario we provided. It’s underpinned with a 10 billion barrel of equivalent premium resource. And we have meaningful upside with that resource, not only through future conversions, future exploration, but also just through the Utica resource that we’ve already captured and we’ve begun discussing.

When you think about our organic exploration effort, our first mover advantage on the three emerging assets, the Dorado North Powder — I’m sorry, Powder River Basin and the Utica, those three individual assets have the ability to represent, the equivalence of a smaller midsize E&P company, quite frankly. Dorado with 160,000 acres and approximately 20 TCF captured, the Powder River Basin with multiple targets across 380,000 acres, and the Utica asset with over 400,000 acres. So we continue to focus on improving the inventory, not just expanding it. Unproven resources, we do think trade at a wider discount these days than what proven resources do. And so we’re focused on continuing to prove up and drive down the cost of these assets and bring them forward to create that value for our shareholders.

Operator: The next question comes from Brad Brackett of Bernstein Research. Please go ahead.

Brad Brackett: Good morning. And thinking about the Utica, I look at the 90-day cubes. You can put a reasonable price against those volumes and compare it to a reasonable well cost, and it looks quite impressive. And maybe in the old era, that would lead to a flag dropping and a huge ramp in activity in volumes. Is there something that’s governing the pace at which you develop the Utica? And maybe it’s corporate strategy, or maybe it’s gas takeaway, or maybe it’s just getting costs of wells down. And will we ever see the sort of off to the races ramp that we saw in the old days in emerging shale plays?

Lloyd Helms: Yeah, Bob. This is Billy. Yeah, thanks for the recognition there for the Utica. We’re very excited about that play, and the performance of the wells that we’ve tested across the play seem to continue to meet or beat our type curve. So we’re very pleased with that. We haven’t given you a lot of details on the cost yet, but we continue to drive down our cost through increased efficiency gains. And early in any play, you do a lot of testing and a lot of science gathering data. And we expect to see that cost come down. And we haven’t really given you a lot of color yet on the EUR of those wells yet either, because we don’t have but just a handful of wells with limited production data. And we want to gather more time before we can give you some answers.

But I guess from all that, we still feel very confident that our previous estimates of being in that $5 finding cost range look very strong. And we’re still committed to that. And on top of that, as far as the ramp up and how we expect to see that continuing, as we gather more data, we get more confidence and we can be more diligent about how we want to choose to ramp to make the most cost-efficient way we can develop that asset. So we simply don’t need to ramp up any single asset very aggressively. And that’s why you don’t see us — I mean, that’s the advantage of being in a multi-basin portfolio is you’re not required to grow or meet certain targets out of one asset. We have the flexibility that provides us to grow gradually in pace with our learnings so we don’t outrun our learning curve.

And we can be the most efficient operator in any of those basins.

Brad Brackett: And maybe there’s never a huge incentive from your shareholder base that goes and tells you, hey, go build some gas pipe take-away, ramp this thing to 100,000 barrels a day. So we might never see sort of those huge levels of growth from the previous era.

Lloyd Helms: Yeah. I think you wouldn’t see the same levels of growth you saw in the past. I think our strategy would be to grow at a pace that’s commensurate with our understanding of the resource, how to best develop it over the long term for our shareholders, and bring that value forward the best. We don’t want to destroy value either by running too fast. So that’s the balance here is we want to develop at a pace that is commensurate with our understanding of each asset.

Operator: The next question comes from Roger Reed of Wells Fargo Securities. Please go ahead.

Roger Reed: Yeah. Thanks. Good morning. I’d like to come back a little bit more on the well efficiencies, kind of the well costs as you look at ’24 versus ’23,the longer lateral links. Just where should we think about that occurring? You just mentioned multi-basin, right? So is the lateral improvement or increase coming mostly out of the Delaware? Is it spread across all the operations? And what are, either opportunities or limitations on further expansion of the lateral links?

Jeffrey Leitzell: Yeah, Roger, this is Jeff. Thanks for the question. So the lateral links have been a pretty big driver in our efficiency gains. We’ve had an opportunity to test longer laterals over the last few years pretty much throughout our multi-basin portfolio, and all of them with good success. So based on — basically drilling longer where it’s applicable based on our acreage footprint. And that’s one of the limiting factors that we run into. In San Antonio, we’ve talked about, the years, our 15 years of drilling there, we’ve moved from the east, which has a little bit more robust geology out to the west, which has a little lesser geology. But we’ve been able to really optimize the economics there by utilizing longer laterals and really pushing our completion techniques to improve operational and capital efficiencies.

And we’re continuing to do that this year. So we’re seeing some extension there in the Eagle Ford. In the Utica, we’ve talked about, we’ve been doing delineation up and down the 140-mile oily fairway there. And now we’re starting to move into spacing packages and then just package development. So the majority of those wells are going to be three miles moving forward. So that’s an increase in the overall lateral length of the company there. And then in Midland, we’ve been testing three-mile laterals for the last couple of years, but not really in high volume. Last year we drilled about four or five of them. And we’ve seen really good success. And we’ve been able to find the correct blocks and places that works with our acreage. We’re going to increase that to about over 53-mile laterals there in Midland.

So when you kind of roll it all up across the company, the overall lateral length will be up about 10% versus 2023 program. And we talked about, with those efficiency gains from the lateral length and just what we’re seeing from some of the stuff Billy talked on the drilling and completion side, we’re going to require that four less rigs and two less frac fleets and then also four less net wells. But all while doing that, we’re still going to be completing a similar amount of total lateral length as we did with our 2023 program. So the way I’d look at it is we’re just riding a lot of momentum with our efficiencies and our lateral lengths coming out of 2023. We’ll just continue to look to build on that in 2024.

Roger Reed: Thanks. There was a lot in that question, so I’ll turn it back there.

Operator: The next question comes from Matthew Portillo of TPH. Please go ahead.

Matthew Portillo: Good morning, all. Just a follow-up question on the marketing side. In the Permian specifically, you highlight the ability to build out the gas processing plant, which lowers your cost structure. I was curious how you see the fairway for long-haul gas takeaway out of the Permian over the next few years. I know Matterhorn will start to clear the basin towards the end of 2024, but it does feel like it remains pretty tight in 2025 and 2026 plus. So just curious what role EOG might play in long-haul takeaway out of the Permian as it relates to potentially taking on some incremental capacity to make sure that gas is able to flow.

Lance Terveen: Yeah, Matthew, good morning. This is Lance. Maybe I’ll start. When you think about just kind of the macro, you’re right. You have Matterhorn that’s coming on, and you’ve had other pipes that have been expanded with like horsepower, right? So we kind of see going in — you’re going to see the basis going to continue to kind of be wide moving this year and probably potentially into next year. But what I would want to really highlight is just we’ve continued to be a leader as we think about like our transportation portfolio. And we have been a part of many of those pipes. So we were actually very early on pushing on those pipes to make sure that we have a pretty significant transportation portfolio for not only the gas, but then also the crude oil.

But from a natural gas standpoint and then the long-haul pipes from an EOG standpoint, we’re very well positioned with over a BCF a day of residue takeaway that hits into what we think are some great markets along the Gulf Coast.

Matthew Portillo: Great. And then maybe as a follow-up question. I just wanted to come back to the Powder, highlighting obviously the opportunity set to delineate the Niobrara, which I think carries an oilier horizon to it. I’m just curious, the learnings you’ve had so far in terms of the drilling environment. I know trying to drive down the well cost has been a big part of improving the economics as well as the productivity uplift you all talked about. And is this just a pause in the overall program? Or should we be thinking about this as potentially a pull of capital permanently towards the Utica going forward?

Jeffrey Leitzell: Yeah, Matt. This is Jeff. No, I wouldn’t look at it as a pause necessarily in the program. I think it’s just a shift. We’ve gathered really good data. We’ve had great results in that Mowry target. We’ve had great efficiency gains and cost improvement. And our plan always was once we were able to gather some really robust data sets on the overlying to go ahead and step into the Niobrara a little bit, which, with that we’ll back off with our packages in the Mowry to do so. So, Niobrara as far as from — in the Mowry from a drilling aspect, they’re a little bit different. The Niobrara is going to be a little bit easier drilling, I would say, compared to the Mowry because the Mowry is deeper. And then also in there you have some [indiscernible] you can get caught into and have some issues.

The Niobrara, on the other hand is — there’s clinaforms [ph] and really we’ve mapped those clinaforms out well to find out what the better producers are. So we really want to be strategic as we mark across our acreage to make sure we’re staying in those right clinaforms. And I think that really has to do with the discipline pace that we’re looking at there in the Powder.

Operator: The next question comes from John Freeman of Raymond James. Please go ahead.

John Freeman: Thanks a lot. Just a follow up on what Scott asked earlier regarding sort of the development in the Delaware Basin. And it’s obviously clear you all are taking a long-term strategy the way that that’s developed with the codevelopment strategy with multiple targets as opposed to just sort of cherry picking, just drilling the oiliest zones because gas is weaker. It does look like those targeted intervals, Wolfcamp oil and the combo, it has moved around a lot kind of each year, not to get too far ahead, but since you did give the three-year outlook. Would it be safe to assume that if you were thinking out ’25, that that sort of shifts a little bit back more towards the oilier zone, just as a nature of the way that you’re codeveloping the package?

Ezra Yacob: Yeah. John, great question. And yeah, you pretty much hit it on the head. It really just flexes as we move kind of across our acreage into different sections and as the geology changes. So you will see that. If you look at the last four years, you really do see that flex back and forth because we’re moving section to section and with our codevelopment strategies strategically codeveloping up from the bottom up to the top of it. So yeah, it will flex kind of through the next handful of years that you see in that three-year scenario.

John Freeman: Great. And then just my follow-up, when we look at the infrastructure projects, obviously this year they stepped up with what you’re doing at Dorado and Delaware. When we think about something like the Utica combo, is it going to continue to get more and more scale and grow? Should we assume that that kind of infrastructure bucket within the total CapEx, that sort of stays at kind of the level it was this year as a percentage of the budget? Does that potentially go higher when you’re looking at kind of that three-year outlook and having these kind of emerging plays like you do?

Lloyd Helms: Yeah, John. This is Billy. Let me answer that in a couple of different ways. The infrastructure span, just to address that real up front here. Those are discrete projects that offer long-term support to plays that are going to be developed over multiple decades. So that’s a very specific direction for those infrastructure projects that continue to lower our cost in the plays for the company going forward and expand margins for a long, long period of time. For the Utica, there is adequate processing capacity up there, so we’re not seeing those kind of projects as an opportunity for the company. I think we’re going to be looking at largely gathering process or gathering lines in that area as we develop each play out.

Typical of any other normal play, we don’t see the need at this point to develop out the large strategic infrastructure in that area. And so I would expect to see over time the infrastructure will stay in that 15% to 20% of our normal capital budget going forward when you take out these two discrete projects.

Operator: The next question comes from Arun Jayaram of JP Morgan Securities. Please go ahead.

Arun Jayaram: Yeah. Good morning. My first question is regarding your marketing agreement with Chenier to sell some volumes on a JKM link basis tied to Corpus Christi Stage 3. A question for you is on their conference call, they mentioned that the project is undergoing perhaps an accelerated timeline with first LNG possible by the end of this year and for some meaningful full production at this project in 2025. So I was wondering if you could give us some thoughts — would the marketing agreement kick in earlier coincident with an earlier receipt of first gas?

Lance Terveen: Arun, this is Lance. I’m not going to comment on the confidential nature of the agreement, but what I can tell you is we’re very excited and we’ve heard the same comments in terms of effectively probably taking a little bit of feed gas to start some of their operations. And what I want to really point you to is we saw that early, right? I mean, getting that agreement put in place. But I’d say more importantly, right, as you heard Ezra talk about and Billy too on the strategic infrastructure, having that pipeline connectivity, we’re going to have a direct connection to Chenier and to that facility. So we’re actually very excited and want to be very helpful from that startup of that facility just because that’s a major increase of demand that we’re going to see that’s going to help here within the U.S. as we think about LNG demand.

So I really want to point more to that than just we’re positioned is what I’ll tell you, Arun, we’re very well positioned that we can meet that. And so if there’s an early startup, great. If not, we’re going to be positioned there with our pipeline at the second half of this year to be able to commence deliveries.

Arun Jayaram: Okay. Just to clarify, it sounds like if first gas is earlier, you would be able to market your volumes earlier. Is that fair, Lance?

Lance Terveen: We would be able to sell into our agreement. That’s right.

Arun Jayaram: Okay, great. My follow-up is several or a few of your E&P peers have claimed an R&D tax credit, maybe associated with exploration-type activities. I was wondering, just given EOG’s historically spent money on exploration, do you qualify for that tax credit? And just give us some thoughts on what it takes and maybe the magnitude if you do qualify.

Ann Janssen: We took it — this is Ann. We took an R&D credit several years ago. Can’t remember the year off the top of my head. But we’re not planning on taking anything going forward. We don’t have the opportunity to take anything forward. And we went and researched again back several years ago on the R&D and took what was available to us.

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

End of Q&A:

Ezra Yacob: Thank you. We appreciate everyone’s time today. And we want to thank our shareholders for their support, and special thanks to our employees for delivering another exceptional quarter.

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