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.

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.

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.

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.

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.

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?

Operator:

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

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.

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.

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?

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.

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.

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?

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?

Operator:

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

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.

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.

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?

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?

Operator:

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

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.

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...

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.

Doug Leggate:

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

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.

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?

Operator:

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

Operator:

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

Operator:

Good day, everyone, and welcome to the EOG First Quarter 2024 Earnings Conference Call. As a reminder, this call is being recorded. [Operator Instructions].

Pearce Hammond:

Good morning. And thank you for joining us for the EOG Resources First 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.

Keith Trasko:

Thanks, Jeff. We're very happy with the results of our first 3 packages of development wells in the Utica combo play. We now have over 6 months of production data from the first 2, the Timberwolf and Xavier, which continue to outperform our expectations. Daily production rates per well have averaged more than 1,000 barrels of oil NGLs and 4 million cubic feet of gas over the first 6 months. On average, these 7 wells have produced more than 200,000 barrels of oil per well since being brought online in the second half of 2023. We recently brought on our third package, the White Rhino.

Operator:

[Operator Instructions]. And our first question today comes from Steve Richardson with Evercore ISI.

Ezra Yacob:

Yes, Steve -- the last part you touched on is exactly the right way to think about it. It's the way that we think about it. We don't want to outrun our pace of learning. Now we are very constructive on the longer-term gas forecast for demand in North America. And we've talked about it before. We think Dorado is advantaged, not only with the cost of supply, but really with the geography where it's located, so we can service all the upcoming demand along the Gulf Coast.

Operator:

And our next question comes from Arun Jayaram with JPMorgan Securities.

Ezra Yacob:

Yes, Arun. This is Ezra. I'd say last year, we did return to the market through buybacks and specials and our regular dividend, about 86% of the cash flow. So having higher quarters is not out of line. The big difference, as you highlighted is that it was all biased towards buybacks rather than specials. And that's really been the trend over the last few quarters and I think that trend will probably continue.

Arun Jayaram:

Great. My follow-up, Ezra, based on the 2Q guide, you're spending around 56% of your full year CapEx in the first half. I was wondering how the timing of some of the strategic infrastructure spend you highlighted last quarter, how that's influencing the first half CapEx? And just thoughts on confidence in the hitting the $6.2 billion full year CapEx guide for 2024?

Operator:

Our next question comes from Neil Mehta with Goldman Sachs.

Jeffrey Leitzell:

Yes, Neil, this is Jeff again. With the Eagle Ford, we've got a really good, consistent program this year. We're going to be completing about 150 net wells there. And as far as looking at the well performance, everything has been in line and right with our expectations. With any mature asset, you're going to see some productivity degradation. I mean we started out in the East where we had a little bit more prolific geology. And then more recently, we've moved out to the West, where it's slightly lower quality pay, but the key takeaway is we've been able to continue to improve the economics in that play year-over-year. And we've really done that just through -- as you talked about, increasing operational efficiencies and focusing on drilling faster, completing faster with super zippers, longer laterals and cost reductions that have continued to improve the capital efficiency of the play.

Neil Mehta:

And then Billy, I just want to extend my congratulations to you on your retirement and thanks for the insight over the years. My follow-up is just on the macro, on the oil macro specifically. We've got OPEC meeting coming up here in the next couple of weeks and a lot of uncertainty on both the demand and supply side. So -- just how is this year from a commodity perspective -- oil commodity perspective trended relative to your expectations? And I know you have a big in-house operation looking at the macro. What's the crystal ball telling you, Ezra?

Operator:

Our next question comes from Neal Dingmann with Truist Securities.

Keith Trasko:

Yes. This is Keith. You're right, we have been delineating mainly north south through the valid oil trend. It's a 140-mile area. The first thing we need to -- kind of on the west is we need to acquire seismic data. We're in the process of doing that. We need to see the degree of structural complexity kind of before we don't -- before we start developing. But geologically, in general, we don't see significant changes in thickness or pay from east to west. On the West, you're going to have a little bit lower maturity, which would equate to less pressure. But in our other plays, such as the Eagle Ford, less pressure reduces the well productivity, maybe a little bit, but it also reduces costs. So your economics are still really comparable to all the other portions of the play.

Neal Dingmann:

Very good details, Keith. And then just a second quickly on -- look at the supplement Slide 12, I like that slide you talked about just your marketing opportunity is. Statistically, I'm looking at sort of around the oil side, the U.S. oil. Is there opportunities to increase around the export side if opportunities present? Or maybe just talk about the optionality or flexibility you might have around those markets?

Operator:

Our next question comes from Scott Hanold with RBC Capital Markets.

Ezra Yacob:

Scott, this is Ezra. Yes, I think we're very happy with where we're at. It's over a 400,000-acre position. As Keith highlighted, it's 140 miles north to south. And let's be honest, we've got 2 packages on right now. Now the 2 packages are fantastic. They're exceeding what we initially had in our type curves, and they're more than confirming some of our early thoughts on the spacing test. So at this point, everything is going in the right direction.

Operator:

Our next question comes from Leo Mariani with RothamKM.

Ann Janssen:

The DD&A, you saw an increase in the first quarter was just due to a onetime prior period adjustment due to some natural gas production being used in our gathering systems. We did come in at guidance level, and you can't expect that DD&A to moderate over the remaining 3 quarters for the year, respecting about $10.50 for the remainder of the year.

Ezra Yacob:

Yes, Leo, this Ezra. I don't know if I'd call it bullish on '25, but I would say that we're constructive. As I said, we've seen a surprising upside on the amount of natural gas demand for power generation over the last couple of summers, and we continue to think that's going to be true this summer. That -- a big part of that is coupled with coal retirements.

Operator:

The next question from Paul Cheng with Scotiabank.

Operator:

Our next question comes from Derrick Whitfield with Stifel.

Keith Trasko:

Yes. This Keith. So yes, it's still early in the play. We're learning more every day about how the geology ties to production. It's going to obviously vary over the 435,000 net acres. But in general, the Utica is thicker in the North. The South is a little bit better pay, but it has better geomechanics and rock properties. That has to do with frac barriers and keeping the frac energy more contained near the wellbore.

Jeffrey Leitzell:

Yes, Derrick, this Jeff. So yes, we've made a lot of really good strides there in the PRB. We started out really focusing in on that deeper Mowry really to refine our geologic models kind of throughout the whole section. And we had good success with the Mowry with that. We went into package development last year, and we saw with package development, a really good uptick in overall productivity there, about 10% in Mowry. So once we accumulate enough data, we went ahead and we're moving up in section in the package development there in the Niobrara. and just really started drilling some wells this year, having really good success operationally, and we'll look to be bringing some of those on later in the year here.

Nitin Kumar:

Congrats to Bill on the retirement. Thanks for all the help over the years.

Jeffrey Leitzell:

Yes. This Jeff. We obviously keep our finger on kind of what's happening with refracs and that technology out there. We've done tests in the past in multiple basins. And what we really find is just with our robust inventory across our multi-basin portfolio. The opportunity for refracs, we're much better to either go in and offset an existing completion that was maybe poor or lesser or just go ahead and drill a new well in a new section from that aspect.

D. Terveen:

This Lance. Yes, I mean, it's still pretty early on the AI front. But I'd say when you think about us, you're right. I mean we do have a lot of capability and a lot of reach with the marketing arm. We are very pleased with the execution that we have. We talked a lot -- you heard even Ezra talk about the pillars that we have there with diversification and control the flexibility. All those things provide the reach that we need as we think about our price realizations [ sync ] into the most attractive markets.

David Deckelbaum:

I just wanted to ask a follow-up just on the Utica, particularly as you fit into some of the analogs and other plays that you've been in, in the life cycle of that exploration and development program. How do you think about testing longer laterals in the Utica specifically over time? Which seems to be a play that's quite amenable to even lateral lengths beyond 3 milers versus attempting to get down your footage cost? Sort of where are we in the theoretical innings there?

Ezra Yacob:

Yes, David, this is Ezra. Those are fixed projects, the strategic infrastructure that we're talking about. And so the best kind of way to look at it, maybe is to reference that 3-year scenario that we have out there. Now that is not guidance, but it is a scenario that potentially assumes a similar macro environment to what we've seen in the last few years. And what we could do going forward.

Operator:

Thank you. This concludes the question session. I would like to turn the call over to Ezra Yacob.

Lloyd Helms:

Thank you, Ezra, and thanks to all of you for your kind remarks, and I truly have enjoyed the chance to meet all of you and work with you in the past. Let me just add, I've been blessed to be part of this company, and its unique culture for the past 43 years.

Operator:

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

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.

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.

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.

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.

Operator:

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

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.

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.

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?

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.

Operator:

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

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.

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.

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?

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.

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?

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.

Operator:

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

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.

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.

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?

Roger Reed:

Thanks. There was a lot in that question, so I'll turn it back there.

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.

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?

Operator:

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

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.

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.

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?

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?

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.

Operator:

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

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:

Good day everyone, and welcome to EOG Resources Third Quarter 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks, Tim. Good morning, everyone. Over the past five years, EOG has increased production 33%, decrease per unit operating costs 17% generated over $20 billion of free cash flow and over $20 billion in net income. We've increased our regular dividend rate nearly 350% and including both regular and special dividends paid and committed to have returned about $13 billion directly to shareholders, all while reducing total debt by more than 40%. At the core of our historical and future success of EOG's employees who embrace and embody the EOG culture. And our third quarter results continue to reflect our employees outstanding execution, strong performance and our foundational Delaware basin and Eagle Ford assets, as well as continued progress across our emerging plays have delivered production volumes, capital expenditures, and per unit operating costs better than expectations, and enabled us to raise our full year oil production guidance and reduce our full year cash operating costs guidance. In addition to announcing third quarter results yesterday, we demonstrated our confidence in the outlook for our business by increasing the regular dividend 10%, announcing a $1.50 per share special dividend and raising our cash return commitment to shareholders beginning in 2024, to a minimum of 70% of annual free cash flow. Our annualized regular dividend is now $3.64 per share, which represents the highest regular dividend yield amongst our peers and is competitive with the broader market. This dividend increase reflects two things. First, the progress we continue to make on our cost structure by leveraging technology and innovation sustainably improves EOGs capital efficiency. Furthermore, we expect the advantages of operating in multiple basins will drive additional improvements to EOGs cost structure and returns and reduce the break-even oil price to fund the dividend in the years ahead. Today we estimate that we can maintain our current level of production and fund the $2.1 billion regular dividend commitment at an oil price as low as $45 WTI. Second, this dividend increase reflects our confidence in EOGs expanding portfolio of premium plays to grow the company's future income and future free cash flow. This quarter we've highlighted recent well performance results in the newest addition to our premium portfolio of assets, the Utica combo play. Over the last several years, our success in organic exploration continues to add low-cost reserves and consistently drive down our DD&A rate enabling EOG to create value through industry cycles. Beyond our regular dividend, which we've never cut or suspended, we raised our cash return commitment to shareholders to a minimum of 70% of annual free cash flow beginning in 2024. Alongside our portfolio of premium assets, and our cash flow margins EOGs balance sheet continues to strengthen allowing us to supplement the dividend with a larger commitment of future free cash flow through special dividends and share repurchases. In addition to the $1.50 per share special dividend declared yesterday, we executed additional opportunistic share repurchases for the third consecutive quarter. For 2023, we estimate our committed cash return will be about 75% of free cash flow. EOG continues to consistently execute lower our cost structure through innovation efficiencies, and organically grow the quality of our portfolio to improve capital efficiency and free cash flow potential. Our transparent cash return strategy is anchored to a sustainable growing regular dividend and backstopped by an impeccable balance sheet. EOG is in a better position than ever to deliver value for our shareholders through industry cycles and play a leading role in the long-term future of energy. Here's Tim to review our financial position.

Billy Helms:

Thanks, Tim. EOGs operational performance continues to improve and this quarter is another example. We exceeded our third quarter forecast across the board on volumes per unit operating cost and CapEx. Thanks goes to our employees for consistently delivering the EOG value proposition quarter-after-quarter. Third quarter volumes exceeded guidance largely due to accelerated timing of activity within the quarter driven primarily by improved efficiencies, as well as some benefits from better well productivity. Efficiencies in our completion efforts have reduced the time to bring wells to sales. For example, in our Eagle Ford play, the completed lateral fleet per day has increased 19% year-over-year. The team has also reduced non-productive time by 31%, which is the added benefit of lowering total well cost. In addition, our new completion design continues to drive performance improvements in the Delaware basin, with targeted laterals realizing a 20% increase in productivity. Well productivity improvements is the primary reason we were able to increase the full year oil guidance by 1500 barrels of oil per day. Last quarter, we reduced our full year guidance for total unit cash operating cost, mostly due to lower release operating expense and reduced transportation cost. Our third quarter performance continued that trend. Our production teams are optimizing both production and cost through our many technology applications that allow for real-time decisions to maximize production and reduce interruptions of third-party downtime. These cross functional efforts by our production, marketing and information systems teams continue to pay dividends. Once again, we are lowering our guidance for full year cash operating costs by approximately 2% this quarter, bringing our total reduction since the start of the year to 3% or nearly $0.30 per BOE. Capital Expenditures in the third quarter were lower than expected due to timing of infrastructure projects, as well as variances in activity across our multi-basin portfolio. We expect to maintain our current levels of activity for the remainder of the year, and our full year capital guidance is unchanged. For 2024, we are currently evaluating this year's results as we develop our plans for each of our plays. As a reminder, we invest to generate returns and growth is a byproduct of the investments in our highly economic multi-basin portfolio. We are very pleased that the levels of activity across our portfolio are at a pace that allows for continuous learning and improvements, and thus we'd expect to maintain similar levels of activity through 2024. With the strong results we're achieving in our emerging plays, we anticipate a few additional wills in both the Utica and Dorado. As we typically do each year, we will remain focused on managing costs through the cycle by contracting for about 50% of services and leveraging our scale and consistent activity levels to build and maintain strong partnerships with service providers. As a result, we're able to take a longer-term view to sustainably lower well cost over time. This year is shaping up to be another solid year performance for EOG. And I remain excited about the opportunities we see through the remainder of the year and into 2024. Now here's Jeff to talk about the updates on the Utica play.

Lance Terveen:

Thanks Jeff. In our South Texas Dorado play, we recently completed two projects to service future gas flows from this premium, dry natural gas play and natural gas treatment facility and the first phase of a 36-inch pipeline. The facility was recently placed in the service to treat gas from the Dorado play prior to transportation through our 36-inch natural gas pipeline to sales near [indiscernible], Texas. Both projects were delivered on time and under budget, a testament to our operational team and foresight to procure a pipe counter-cyclically, along with other long lead time materials. The second phase of the natural gas pipeline will kick off construction in early 2024 and is expected to be complete late next year. Phase 2 of the pipeline will terminate in the Agua Dulce, which provides access to three other pipelines with connectivity to the growing demand along the Gulf Coast and Mexico, and potential premium pricing relative to Henry Hub. Our pipeline will be instrumental in expanding our gas sales options for the 21 TCF of net resource potential we've captured in Dorado, and perhaps more importantly, save $0.20 to $0.30 per MCF in transportation costs over the life of the asset versus third-party alternatives. Now here's is Ezra to wrap up.

Operator:

Thank you. [Operator Instructions] And our first question comes from Scott Hanold of RBC Capital Markets. Please go ahead.

Ezra Yacob:

Yes, Scott, thanks for the question. The decision to raise minimum cash return to 70%. Overall, it just demonstrates our commitment our shareholders. It reflects our continual improvements since the initial commitment was made nearly two years ago. And really to your question on the business model change, it's really just our ability to deliver that shareholder value. It's grounded in the fact that our strong cash return generation capacity continues to improve the strength of our industry leading balance sheet continues to improve and our commitment again to just being disciplined with our reinvestment across the entire portfolio. So we're in a position now where we feel very confident that and proud that we can increase that minimum commitment to 70%. And we look forward to being able to deliver that to the shareholders.

Ezra Yacob:

Yes. That's right, Scott. As we continue to invest in these higher-return, lower-cost reserves and bring them into the base business, we continue to do some strategic infrastructure spending to lower the overall cost of the company going forward. That continues to expand the free cash flow potential of the company. And that, in addition to strengthening the balance sheet, everyone knows we retired a $1.25 billion bond earlier this year, and we've been able to be not only net zero but actually put a little bit of cash on the balance sheet. All of those things are what gives us confidence in the base business going forward and the fact that we can continue to increase this minimum cash return to our shareholders from the 60% up to the 70%.

Leo Mariani:

You guys spoke about sort of similar '24 activity versus 2023, but also kind of said that there might be a handful of more wells in the Utica, in the Dorado. So I just kind of wanted to get a sense there. I mean, do you see this as kind of a give-and-take proposition, where if you do a little bit more in some place, you might have kind of a few less wells and some other plays? And just trying to get a sense of how maybe costs are trending overall in wells today.

Leo Mariani:

Okay. No, that's helpful. So maybe just to kind of jump over to the Utica. Obviously, you brought a new package of wells online here. I know it's sort of early days, but when you look at these wells, do you tell yourself that you've already been able to see some improvement over the last year? Just trying to get a sense, are these wells a little better than they were, say, a year ago? And then on the cost side, in the Utica, are you starting to see maybe the cost come down a little bit here? Or maybe it's kind of early. I think you've had a target of sort of sub-$5 F&D, just not really sure kind of where you're at today.

Operator:

The next question comes from Arun Jayaram of JPMorgan Securities. Please go ahead.

Billy Helms:

Yes, Arun. This is Billy. Let me try to weigh in on that for you. And I apologize if I missed some of your question, you were breaking up a little bit there. As far as 2024, as I said earlier, it's a little bit early to give specifics on the plan, but I would say just look at our activity levels we're seeing today. And I would expect to see similar levels of activity on our core foundational plays going into next year, give you some hint as to what activity levels we might have. I would expect a few additional wells next year in our emerging plays, such as the Utica and maybe Dorado. And then, as far as service costs, let me just weigh in a little bit on that while we're talking about that. We certainly understand service costs have moderated in the industry as industry activity has dropped throughout the year. The magnitude of those declines certainly varies between the services and in which basins we're operating in. We remain focused on just continuous improvement that we see in our efficiency gains throughout our operations. So we tend to use the latest technology in the highest-performing crews, which includes super-spec rigs and frac fleets. That equipment continues, as you know, to be in high demand with service pricing proving to be more resilient. We have seen drops in tubular and casing costs for next year that will tend to reduce overall well cost. But again, the magnitude of that effect on overall well cost is yet to be quantified. So as we go into next year, certainly, we expect to maintain our activity levels that we see in our core plays, a few extra wells, some softening on well cost. Overall, I think that's kind of where we're headed.

Jeff Leitzell:

Yes. That would just be the general type curve in mix across the 140 miles kind of from North to South there in the play. So it's pretty consistent. You can see on the slide that we put our first handful of wells on there, and that's really what a lot of the type curve was going to be built off. And you can see the Timberwolf package is the most recent one that we brought on and the outperformance in that one.

Philips Johnston:

Just a few quick follow-ups for Jeff on the Utica. First, on the 55% oil cut, what sort of API are we talking about on that crew? Or is it more of a quasi-condensate type of mix there?

Philips Johnston:

Okay. Sounds good. And then, the wells so far are pretty much all been up along the eastern edge of the acreage. And I'm pretty sure you guys have previously cited the black oil window. It's sort of in the exploratory phase still. But how does the geology change as you go West? And when would you expect to test other parts of your acreage?

Operator:

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

Ezra Yacob:

Yes, Neal, this is Ezra. We're pretty happy with the footprint that we've been able to put together since we entered the play. I think we highlighted on the call that we've added an additional 25,000 acres, bringing our total up to 425,000 acres at very low cost. And let me just highlight again that we actually own the minerals across 130,000 mineral acres down in the southern portion of the play. So when we look at it right now, as Jeff said, we're drilling some initial spacing packages, some delineation tests where we currently have seismic. We're also this year acquiring seismic in a couple of different parts of the play. So we can continue to step out and gather results on that and provide a bigger better estimate of what we've captured here for you guys. As far as being limited on incremental activity. I want to think of it that way. Like I said, we've put together a very large contiguous acreage position. And really, our activity right now as far as investment in pace, as Billy said, is going to be determined on our ability to collect data and integrate the production data that we're seeing back into the front-end of our geologic models. The activity is really always considered to be at a pace where we can continue to learn and incorporate those learnings on the next set of wells.

Lance Terveen:

Yes, Neal. This is Lance. Good morning. I think what makes this place so unique is that it is just positioned to so much existing capacity. I mean, actually, in fact, when -- there's even some idle processing capacity and fractionation, ideal processing capacity that's nearby on our acreage. So when we look at that just from an infrastructure standpoint, we've been focused on more just the gathering infrastructure. And as Jeff mentioned, we put into service our pipeline in the North and then we're going to have a pipeline in the South as well. So we're going to have plenty of running room, just long-term running room as we think about the infrastructure that we're putting in place along with third parties and then also the available capacity that's in place.

Doug Leggate:

I'm not loving the new dial-in system, but thanks for getting me on. Ezra, I wonder if I could hit first two things. I want to hit the cash return change and the evolution of the portfolio as you look forward. So dealing first with the 70% number, that obviously is subject to whatever the level of capital is. And I guess, the flow on the machine is that 60% of free cash flow or 70% of free cash flow is still free cash flow, which means it's entirely dependent on what you decide as a discretionary spending, which to me doesn't mean a whole lot. So what commitment can you give or at least guidance or framework for what the level of spending looks like in order for us to interpret what the increase in free cash flow commitment actually means?

Doug Leggate:

I appreciate the new breakeven number, Ezra. That's very helpful. Thank you. My follow-up is on portfolio evolution because, I guess, we all know that 10 years is not the number, I guess, for EOG. But yet your slide deck continues to refer to 10 years of double premium. So if I assume that's dominated by the Eagle Ford and the Permian given that you're happy with that level of activity, how does it evolve if the next leg of growth is Dorado, Utica in terms of mix? And I guess what I'm really driving at is, our channel checks on midstream suggests you could potentially be drilling north of 300 wells in the Utica in 2026. Does that sound reasonable to you in which case, what's the implication for mix?

Operator:

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

Billy Helms:

Thanks, Charles. Yes, this is Billy. For '24, we've kind of said it's a little early to get specifics about things. But I would point you to the fact that we're running at a pretty decent level of activity now. We're going to maintain that same level of activity going into next year. Now just a reminder, we're spending about $6 billion on our CapEx program this year, and it has proved to be fairly ratable through each quarter of the year. Similar levels of activity, there will be some upward movement maybe on efficiency gains. Like you said, we'll have a little bit more efficiency gains to factor in maybe some cost reductions due to casing cost, those kind of things. We'll still have some infrastructure spend. We may drill a few more wells in the Utica and Dorado plays. And we're trying to quantify that as we go towards the end of the year. But directionally, that kind of hopefully points you towards what next year might look like. We're not going to see a big ramp up in activity in any play as we see today, small changes in capital efficiency and well cost as we go into next year, we have some infrastructure spend.

Billy Helms:

Yes. Charles. This is Billy again. Let me give you kind of an overview and then Jeff may add some more color. The 3-mile laterals in the Utica, yes, we're very excited about that play and its ability to do these longer laterals very efficiently on the operational side. We're drilling these things in record times and making progress with each pattern of wells we drill. And we feel we have line of sight on being able to continue to reduce cost over the longer-term period as we apply learnings from other plays into this area. So that's going to continue. Now we're also drilling longer laterals in some other plays. We've drilled some 3-mile laterals in the Eagle Ford and we're drilling 3-mile laterals in the Delaware Basin. So we expect that trend to continue in each of our plays. Now Jeff might want to add some colors on what we're seeing on performance there, too.

Operator:

The next question comes from Scott Gruber of Citigroup. Please go ahead.

Jeff Leitzell:

Yes, Scott. Just there's no major updates this quarter, especially just in the Permian with the Wolfcamp. We're still seeing the outstanding strong results that we talked about earlier. Consistently 20% uplift in the first year production in EOR. The thing I would say is there in the Permian, we do have a handful of tests up in the shallower targets, and that's really where our focus is shifting out there. We hope to bring those on towards the end of this year and kind of the first half of next year. And once we get those results, we'll go ahead and share those with. But then around the rest of the plays, we talked about in the Powder River Basin, we do have a test in the ground we're currently evaluating there. And then more so over in the Utica, obviously, we started applying that with all of our new designs there. So seeing good results, but we're still just kind of collecting data and we'll see exactly what formations that we have success with moving forward.

Billy Helms:

Yes, Scott. This is Billy. Phase 2, first of all, we're very excited about that project. Getting that pipeline is going to give us access to multiple markets in that basin. The pace of activity in Dorado is really governed by our learnings and results more so than the pipeline date. Certainly, we're excited about the pipeline, because as Lance laid out, it's going to allow us to save $0.20 or $0.30 in Mcf over the life of those reserves, which is 21 Tcf of reserves, But the pace of activity is really governed by how we see the macro and our learnings as we progress to play really independent of the pipeline.

Operator:

The next question comes from Derrick Whitfield of Stifel. Please go ahead.

Billy Helms:

Yes, Derrick, this is Billy. Yes, the CCS pilot project, we're very excited about that project, what we've learned and how we can move forward with the play. So as far as how we've learned, there's a lot of operational things we've kind of uncovered as we develop that project, how we think about the CO2 we're sequestering, how we store it, how we move it, the pipeline infrastructure, the equipment we need, those kind of things. But also technically, what we've learned there as well. One thing we bring to the table on all these CCS projects, we have an immense amount of understanding of geological areas to store the carbon and our ability to map out those zones. And then we're also very good at drilling wells. So applying those 2 things give us some advantage on projects as we move forward. What we've learned in some of the monitoring we've done so far is very supportive of our initial thoughts on the play and how we can store the CO2 and observe its movement in the ground and be able to have confidence that we can store that for a sustainable period of time. So we're learning a lot. We're very pleased with the results we're seeing. Now we're also looking beyond our pilot project to see where else we can apply that technology. And it's early to say yet where we're going to take that, but needless to say, we're encouraged with what we're doing and excited about the opportunities moving forward.

Billy Helms:

Yes, Derrick. This is Billy again. Certainly, for offshore, as you mentioned there, the rig utilization is pretty tight or I'd say it's pretty high. So the market remains pretty tight on offshore rigs. We are very happy and pleased with the activity we have ongoing in Trinidad. We've been in the Trinidad, just a reminder, we've been in Trinidad for over 30 years. And currently, we have line of sight on probably one of our longest running programs we've ever had in the history of that play. And so we've secured a rig there for that operation and very pleased with the results we've seen to date. So now moving forward, as far as our exploration activity, certainly we're interested in pursuing other shallow water offshore opportunities in the company, and mainly because we've built quite a bit of expertise of drilling these offshore wells very efficiently and cost competitively compared to the industry. So we think that gives us a strategic advantage being able to pursue these kind of opportunities around the world. So we're continuing to look for those opportunities. And certainly, those opportunities would factor in the cost of doing business today the current offshore rig environment. And they'd have to be competitive with what we're doing in the rest of our portfolio. So looking at it that way, we see opportunities to continue to pursue that and excited about what that looks like going forward.

Nitin Kumar:

Why don't we go back to the Delaware for a minute? As I look at your slides, and there were 2 things that you were doing in the Delaware this year. You were also increasing the mix of your Wolfcamp oil in the drilling schedule and then there were the enhancements that you made. Could you break out the improvement that you're seeing between the mix and then the new technologies that you're talking about?

Nitin Kumar:

Great. I guess the reason I'm asking this question is one of your peers in the play has talked about improving recovery rates, not just optimizing the well but actually improving recovery rates with the application of technology and they've talked about 20% gains. So I guess, given your experience in shale and, of course, your track record, I'm curious to see if you have seen technologies or are seeing technologies that could help that recovery factor increase not, just optimizing the wells but really a step change in what you're drawing from the rock.

Operator:

Next question comes from Josh Silverstein of UBS. Please go ahead.

Ezra Yacob:

Yes, Josh. This is Ezra. Ultimately, I think the answer to your question is that 70% is a minimum hurdle. In the last couple of years since we first came out with the initial cash return guidance, we had a minimum cash return commitment of 60%. In 2022, we were at 67%, and this year you see that we're on track to be north of 70%, probably closer to 75%. So I think that's the way you should be thinking about the guidance on there. And really, the big thing with our free cash flow commitment, it's a minimum of that 70%. But again, it's really founded in and hopefully, it doesn't remove the focus from our regular dividend. The regular dividend, we feel, is the best indicator of a company's ongoing performance, the improved capital efficiency going forward. And it's a commitment that we give to our shareholders based on our ability to continue to lower the break-evens and expand the sustainable future free cash flow generation in the company. It's backstopped with a pristine balance sheet. And in this quarter, when we raised it to 10%, One of the ways that we raised is by looking at what does it take on a breakeven there. And as we talked about before, we can support this new $2.1 billion regular dividend in commitment. At a range of maintenance CapEx scenarios, the higher end of that range would be with a $45 WTI price. And when I say a range of maintenance capital scenarios, let me be clear when I say that. For a company like ours that has multiple basins, differing amounts year-over-year of infrastructure spend or exploration, different product types. We look at maintenance capital through the lens of what does it take to keep production flat for a 5-year period, but also across those different investment scenarios. Are we investing in the health of the company longer term with exploration or are we really just narrowing it down to just a focus on maintaining production? And so we end up with basically a range of maintenance CapEx between $4.2 billion and $4.8 billion and so a midpoint of about $4.5 million. And as I said, at the higher end, that's where we can maintain that level with the $45 WTI.

Billy Helms:

Yes, Josh. This is Billy. Let me give you a little bit of hint maybe of kind of what we're looking at. Certainly, we have a deep portfolio of unconventional plays in the things we're currently drilling today. But our active exploration program is continuously looking for all opportunities. And they're geared towards, first of all, generating solid returns and being competitive with what we're investing in today. So they will include things that are conventional or unconventional, offshore or onshore, U.S. or not. So we're looking at all kinds of things that are competitive with what our portfolio is generating today.

EzraYacob:

Yes. I'd just like to say that we appreciate everyone's time today. One final takeaway I'd like to leave you with is that EOG's cash return announcements in the third quarter demonstrate our commitment to creating long-term value for our shareholders. We've increased our free cash flow payout minimum to 70% and increased our regular dividend 10%, and we're confident in the sustainability of our regular dividend due to the consistent execution of our value proposition that improves the company year-after-year. EOG is in a better position than ever to deliver value for our shareholders through industry cycles and play a leading role in the long-term future of energy. Thank you.

Operator:

Good day, everyone, and welcome to the EOG Resources Second Quarter 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks, Tim. Good morning, everyone. Our second quarter results reflect exceptional execution throughout our multi-basin portfolio. Production volumes, CapEx, cash operating costs and DD&A all beat targets driving another quarter of excellent financial performance. We earn $1.5 billion of adjusted net income and generated $1 billion of free cash flow, year-to-date we've generated free cash flow of $2.1 billion. That free cash flow and cash on the balance sheet funded year-to-date cash returned to shareholders of $2.2 billion, including more than $600 million of share repurchases executed during the first half of the year. Taking into account our full year regular dividend, we have committed to return $3.1 billion to shareholders in 2023, or about 67% of our estimated 2023 cash flow assuming a $75 oil price well ahead of our target minimum return of 60%. EOGs peer-leading regular dividend is currently the majority of the $3.1 billion of cash return and committed to shareholders this year. Our sustainable growing regular dividend which we have never cut nor suspended remains the first priority to return cash. We also continue to leverage special dividends and buybacks to return additional cash depending on market conditions through the first two quarters of 2023 we've deployed more than $600 million to opportunistically repurchase shares during times of increased volatility. And while our cash return strategy remains consistent, what has evolved since putting the $5 billion repurchase authorization in place over a year and a half ago, is the fundamental strength of our business. And we continue to get better through relentless execution of and commitment to EOGs value proposition. We invest in high return projects across our multi-basin portfolio, adding lower costs reserves, which reduces our breakeven and expands our margins. We are now actively investing in five premium basins, more than any time in our history. Our foundational assets in the Delaware Basin an Eagle Ford continue to consistently deliver and we're pleased by the outstanding progress across our emerging Southern Powder River Basin, Ohio Utica Combo, and South Texas Dorado plays. Well productivity and cost performance are meeting or beating expectations across our portfolio as we invest and develop each asset at a pace that supports consistent execution and continued innovation. We continue to lower the cost basis of our company, utilizing technology and innovation that improves well performance and lowers well costs to sustainably reduce our finding and development costs, efficiencies and infrastructure investments are lowering current and future unit operating costs and contribute to our emissions reduction efforts. Finally, we have further strengthened our pristine balance sheet this year, while generating significant free cash flow and funding our transparent cash return strategy, which is designed to deliver consistent shareholder value through the cycle. And heading into the second half of 2023. Our continued performance gains will be complemented by strong fundamentals. Oil demand has been resilient despite volatility in the first half of the year, and demand is showing signs of continued growth through the second half of the year. Strong inventory drawers since the start of the year have pulled oil inventories below five year averages and refinery utilization remains high. Production growth in the U.S. is on pace to deliver similar rates as 2022, while exiting the year with significantly less activity as public companies continue to demonstrate discipline. And it appears OPEC+ are following through on an ounce production cuts. The culmination of these actions should further reduce inventory levels and place upward pressure on pricing through year end. Regarding North American natural gas, while inventory levels remain above the five-year average, prices have firmed up recently, reflecting a reduction in natural gas drilling, and an increase in demand from both power generation and LNG exports. These trends should support a more balanced supply and demand environment late this year and heading into 2024. We remain constructive on the longer term gas story for the U.S. supported by recent LNG project approvals, and the growing petrochemical complex on the Gulf Coast. And we're especially pleased with Dorados place in the market, as one of the lowest cost supplies of natural gas in the U.S. with an advantage location and emissions profile. EOGs value proposition is delivering results and the strength of our business has never been better to deliver value for the shareholders through industry cycles and play a leading role in the long term future of energy. Now here's Tim to review our financial position.

Billy Helms:

Thanks, Tim. I would like to first thank our employees for their commitment and dedication that led to another quarter of exceptional execution. EOG once again meet our forecasted targets and delivered a near perfect quarter. As a result, we have completed the first half of the year ahead on volumes, and ahead on total per unit cash operating cost. Our volume performance in the first half of the year is due to several factors. The performance of new wells is outpacing our forecast, primarily in the Delaware Basin, part of which is due to our new completion design. We're also experiencing less downtime due to market interruptions than previously planned, our investments in infrastructure along with real time data analytics provided the control and flexibility needed to redirect sales volumes to different markets to maintain production. Unit cash operating costs through the first half of the year average 5% below the midpoint of our quarterly guidance, due to a combination of several factors including lower lease operating expenses, as well as reduced transportation cost. Lower workover and compression related expense reduced LOE, while transportation costs benefited from the flexibility to sell into more favorable markets throughout the quarter. Credit goes to the cross functional efforts of our production, marketing and information systems teams, who remain focused on sustainable, low cost operations quarter after quarter. We have line of sight to maintain these cost improvements throughout the year, and as a result have reduced our full year guidance for total unit cash operating cost. Operationally, EOG is firing on all cylinders. Our foundational Eagle Ford and Delaware Basin plays are delivering exceptional results. While our emerging plays benefit from learnings and technology transfer across our multi-basin portfolio. Our decentralized structure supports innovation in each operating area, which much and much like independent technology incubators, and compounds the impact of that innovation by taking ideas born in one area and expanding them across multiple basins and across multiple functions. Across every operating area, our frontline engineers and geologists work that technology every day to lower cost and improve well performance. We look for strategic opportunities to vertically integrate certain services within the supply chain, where we find an opportunity to better align those services with our goals. That includes areas like downhole drilling motors, drilling mud, sand and water. Developing such capabilities in-house significantly improves the cost structure of the company. This quarter we're highlighting drilling performance improvements in the south Texas Dorado, South Powder River Basin Mowry and the Ohio Utica Combo plays. Our emerging plays are moving up the learning curve faster due to the benefit of drilling advancements, and the application of technology over the past decade. We continue to evolve our proprietary suite of applications, powered by real time high frequency data and analytics to assist our frontline employees to collaborate and make decisions faster. The combined benefit of these efforts has already contributed to an increase of up to 25% in drilling feet per day for wells and our emerging plays this year. In our Ohio Utica play, we recently drilled a 15,700-foot lateral in 2.6 days and 100% in zone. Capitalization expenditures for the first half are also a running light, due primarily to the infrastructure span that has been deferred into the second half of the year. It is worth noting the economic impact of our investments in EOG owned infrastructure. Our realized U.S. oil price in the second quarter was $1.23 above WTI. And U.S. natural gas was essentially flat to Henry Hub. CapEx for our drilling and completion program are right on track. The rate of change for inflation this year is consistent with what we'd anticipated started the year. So we still see line of sight to limit year-over-year well cost inflation in ‘23 to just 10% While any additional softening of service cost in this year has the potential to impact 2024. It's simply too early to predict. The market remains too dynamic, particularly given the constructive outlook for oil in the second half of the year. Furthermore, we remain focused on generating long-term, sustainable cost reductions, driven by utilizing the highest quality equipment and the highest performing teams, which are less exposed to the leading edge price declines that we see in more marginal equipment. Our $6 billion capital program is focused -- is forecasted to deliver 3% or volume growth and 6% total liquid growth. In Dorado, our South Texas Natural Gas play, we delayed the timing of plant completions earlier this year, and about five wells had been pushed into early 2024. Thus, we reduced our full year gas volume guidance accordingly. We maintained our drilling pace in Dorado to build operational momentum and capture the corresponding efficiencies. As a result, we're seeing a 16% improvement in our drilling times for Dorado. As shown on slide 11 of our updated Investor Presentation. We’re constructive on natural gas longer term, and believe Dorado will be one of the lowest cost and lowest emission supplies of natural gas in the U.S. and will compete on a global scale. This year started out with many challenges, but also many opportunities to continue to improve the company. I am very pleased with the progress our teams continue to deliver and remain optimistic about the second half of the year, and how the company has positioned for the future. Now I'll turn the call over to Ken to discuss progress on lowering our emissions.

Ezra Yacob:

Thanks, Ken. Our second quarter results demonstrate once again that EOGs value proposition works. We invest in high return low cost assets across a diverse multi basin portfolio. We leverage technology and innovation to sustainably lower well costs and reduce emissions. These high return low cost investments generate significant free cash flow to fund our transparent cash return strategy backstopped by a pristine balance sheet to deliver consistent shareholder value through the cycle. Most importantly, our culture is at the core of our value proposition and is our ultimate competitive advantage. Thanks for listening we'll now go to Q&A

Paul Cheng :

Thank you. Good morning. Can you hear me okay?

Paul Cheng:

Thank you. Two questions, please. First, on the cash return on the free cash flow, thank you that you are paying more than 100%. Just want to see how you determine that this is the right time to pay more than 100%, or how should we reset into the future given you're already in a net cash position, should we think that there's a little bit change in the management view and the payout is going to perhaps closer to 100% until that maybe that market condition change. And also that whether we should read the second consecutive quarter of the buyback means that management now see the buyback as more of an ongoing part of the toolbox on your cash return? That's the first question. Second question that on Dorado, the decision that to delay the five well in this year. Can you -- maybe share with us, I think Billy has mentioned that, can you share with us then what's the thinking behind the delay? I know that the Street has been bugging you that you should delay the Dorado, and you guys do it in this quarter. But I want to understand a little bit better in terms of the decision-making process behind. And the full year guidance reduction, I think it's all related to that, right? Thank you.

Billy Helms:

Yes. Good morning, Paul. On Dorado, we had indicated earlier in the year that we were evaluating the potential to delay some of our completions in Dorado and we are consistent with that strategy. We elected to maintain our drilling operations there, and we're seeing the benefits of that decision to play through the efficiencies we're gaining on the operational side. And we've given some color on that in our new investor deck illustrating the improvements in drilling times there in that place. So we're very pleased with that progress. But don't forget, our investment strategy includes a gas price of investing for $2.50. That's our premium price deck when it relates to gas prices. We certainly were watching inventory levels on the gas side and just prudently decided to delay a little bit of the completions there until we saw the fundamentals improve, and so we'll be just laying some of those completions as we go into the late this year, which pushes five wells into the next year. So that's simply the thinking on that.

Neal Dingmann:

Good morning, guys. Nice quarter. As for my questions on well productivity, specifically looking at that Slide 10 of yours, certainly it appears that your Delaware wells continue to notably improve, and so what I'm wondering is this driven more by just continued D&C efficiencies. Or is it more an informational targeting? I asked that, I just was looking at the bottom through the left corner of those pies. It looks like over the years, not only the wells improving, but it looks like they're becoming more focus on that Wolfcamp oil. So I'm just wondering what is driving that, it does look very positive.

Jeff Leitzell:

Hi, Neil. This is Jeff. On our Permian productivity, we've been really happy with how the wells have performed in the Delaware through the first half of the year. So all of our primary targets, they're performing right now as forecasted or better. And I'd say this is primarily due to just our stacked pay co-development strategy in combination with the new completion design we talked about, which has continued to be really successful in our Wolfcamp targets. And in regards to that new completion design, just kind of a quick update, we're still observing a 20% increase in both first year production and EUR for both oil and BOEs in the Wolfcamp. So for the full year of 2023, we're planning on bringing on about 70 total Wolfcamp wells with this new design, which is nearly twice the number we've completed in 2022. And also with it, as we talked about, we're continuing to test and expand the technique in other areas and targets in the Delaware Basin along with all across our emerging plays in our multi-basin portfolio.

Billy Helms:

Yes, Neal. This is Billy. So certainly, we're seeing the service prices start to soften. But these savings from lower service costs really probably won't manifest into a lower well cost until later this year and certainly into 2024. These leading-edge prices are falling across various products and services for the industry. And certainly, it varies depending on the product in the area. I'd add that there are several factors that kind of reflect kind of where our '23 capital program is. As a company, as you mentioned there, we focused on sustainable cost reductions through our operational efficiency gains. As a result, we do seek out the highest performing equipment in cruise, super-spec rigs, electric frac fleets, et cetera. That's really less exposed to some of these headline inflation numbers that we're seeing on the more marginal and equipments on the spot market. And the second part of that is we really anticipate that service costs would moderate through the year when we put our plan together since rig count really peaked back in November, and we built our plan in February, expecting well costs would increase no more than 10% relative to this last year. So things are really playing out exactly the way we planned. Another point there is we do try to secure about 50% of our well costs in the start of any given year that really helps insulate us from inflationary impacts to our activity levels. And then lastly, based on how we do manage our business, we are less exposed to the volatility in service cost in any given year. And I would remind you, as you kind of alluded to there, our well cost really only increased about 7% last year compared to the over 20% inflation that we saw in the market. So yes, it really helps us kind of manage our activity level with confidence as we go through the year. And we'll certainly remained flexible as we look into next year to see how we can position ourselves for next year.

Arun Jayaram:

Yes, good morning. I was wondering if you could help us think about the second half oil production profile for EOG. It looks like your updated guidance points to a slight sequential decline in 3Q. And I just wanted to get some thoughts on to hit if there's still kind of confidence in hitting the midpoint of the oil guidance range because that would imply fourth quarter oil production number in the mid-480s to upper 480s. So help us think about the sequential movement in volumes in the second half of the year?

Arun Jayaram:

Great. Just a follow-up, I wanted to get some thoughts on the Ohio Utica. One of the midstream providers highlighted how they're building out, call it, a backbone in the Utica looks like you may be the anchor E&P for that investment. But I'd love to get some thoughts on the Utica. We did see that you may be pulled your TIL guidance down a little bit this year, but just an update would be helpful.

Ken Boedeker :

Yes, Arun, this is Ken. I just want to give you a quick update on the Utica. We're making excellent progress on that program this year. We do plan to bring a 4-well package online this month and our frac crew will be starting up again in a few weeks. So the wells we drilled and completed in 2022, we do continue to deliver our expected performance, and we also continue to add acreage and look for additional low-cost opportunities to add to our position up there.

Doug Leggate:

Thanks. Good morning, everyone. Ezra, it's a long time since we had to worry about the U.S. growing too quickly and all the whole market share battle issues that we all lived through over the last four, five years with OPEC. But in your opening remarks, you did talk about Saudi's decision to support the price or extended cuts. So I'm wondering when you sit in the boardroom and you look at what is an artificially high oil price because Saudi is cutting production arguably to support price. How do you think about what that means for your business, the appropriate level of spending the right allocation of one could call it, windfall cash flow because it's not -- it's an artificially supported price by definition? So I'm just curious how you think about what that means to your business your cash flow is basically being subsidized again by Saudi.

Doug Leggate:

An interesting dilemma. Ezra, thank you for your perspectives on that. A quick follow-up, hopefully, is a quick one. I wanted to touch on, I think this was asked earlier, but I wanted to elaborate just a little bit. The comments about inflation limiting to 10% this year, but it's too early to talk about 2024. You're pretty much the second to last company to have your earnings call this quarter. And pretty much everybody else has been pointing to, yes, we're going to see some deflation in 2024. I'm just -- are you just being conservative, or do you genuinely believe that there's still upside risk to capital in '24 from inflation, I mean.

Operator:

Next question comes from Leo Mariani of ROTH Capital Partners. Leo, please go ahead.

Ezra Yacob:

Yes, Leo, this is Ezra. Yes, we continue to see very limited competition domestically on any exploration, I think, and you can kind of see that to just in the public comments that are made. Most operators, companies, whether private or public, have really kind of picked the basin and are honing in on more of a drill down kind of specialist manufacturing mode. We continue to explore. And as Ken said, we're still looking to put on low-cost, high-quality bolt-on opportunities in some of those plays. With respect to the Utica and PRB in specific. It's a little bit early this year on Utica. We're pleased with what we're seeing on the operations side. And as Ken said, we'll get a completion spread in there and get some results here coming up. On the PRB, we've had a very strong year. Everything has really fallen in the line there. And again, the PRB in Dorado are really benefiting from more of a continuous operations program this year as we focus on Austin Chalk and a little bit of co-development in the Eagle Ford and Dorado, and then we center most of our focus in the PRB in the Southern PRB is basically on the Mowry this year. And then shifting to international for just a minute on the exploration side. As you guys know, we both explore onshore and offshore and shallow water internationally. I would say onshore, there's still limited competition on the exploration side for unconventionals in what we see. Of course, it's still a high bar that we have for international opportunities to -- they really do need to compete with our domestic portfolio. We're not just exploring internationally to try and say that we've got something internationally, it really needs to compete and deliver value for the shareholders. And then in the shallow water, probably a bit of the same, maybe a little bit more exploration out there. But dominantly, I think what you're hearing about in in offshore international exploration is a bit more in the deep and even ultra-deepwater and really in the shallow water that we're focused on.

Billy Helms:

Yes, Lee, this is Billy. So on the CapEx, I'd say our drilling and completion activity has been very ratable throughout the year, and we're pretty much on track with what our plan has laid out. The reason third quarter is up is simply due to the timing of our non-drilling and completion capital, and it moved from the second quarter into the second half of the year. Everything else, all of our drilling and completion CapEx is really on pace with what we laid out. We've spent about half the CapEx for the year, and we've completed about half the wells that we're planning for the year. So I'd say everything is pretty much on track. But fourth quarter will be a reflection of how that non-D&C non-drilling and completion CapEx gets spent in the third.

Scott Gruber :

Thanks. And good morning. I'll just go ahead and ask two questions up front here since they're related you guys know to continue the efficiency gains in the emerging plays. What are you seeing in terms of efficiency gains more broadly across the portfolio? Obviously, the gains are always greatest in the new plays, but I'm curious if you're still seeing solid gains more broadly across the portfolio. And if you are, without adding rigs and frac crews next year, just curious how much the overall well count could potentially grow next year just on the back of those efficiency gains? Is that a kind of low single-digit type figure potentially a mid-single-digit figure?

Operator:

Our next question comes from Derrick Whitfield of Stifel. Derrick, please go ahead.

Ken Boedeker :

Yes, Derrick, this is Ken. Really, longer laterals are a way we're increasing our capital efficiency in the Eagle Ford. If you look at it, we've drilled over 85 wells with laterals over 2.5 miles long across the Eagle Ford. And we've utilized these longer laterals over the last five-plus years, where appropriate. You think about it, the faulting across the Eagle Ford does make these longer laterals challenging, but our data-driven approach and multidisciplinary teams enable us to steer the laterals within some narrow target windows and apply an optimal completion design to maximize that capital efficiency. These longer laterals have really contributed to us lowering our cost basis in the Eagle Ford and are an example of how we're focused on increasing our efficiencies even in that play where we've been developing it for over 10 years.

Operator:

Our next question comes from Neil Mehta of Goldman Sachs. Neil, please go ahead.

Ken Boedeker :

Yes, Neil, this is Ken. As far as the way that's tracking, the five wells that we've deferred, we would see that we'd be completing those early in next year. And it's still early in the play and the wells in our core area are really performing as we've anticipated.

Ezra Yacob:

Yes, Neal, this is Ezra. I think we've been 30 years strong as an organic exploration company, 20 years separated there. And I think that's -- the thing about that is the way we look at these deals is that it's similar to how I described every investment decision is, it's a returns-based decision, and how is that investment going to create long-term shareholder value. We don't think of M&A versus exploration. But as a first mover, looking -- trying to capture the sweet spots of new plays, obviously, you can get a lower cost of entry and that offers a higher return. So the exploration, I think, organic exploration stands on itself. With regards specifically to M&As, we're aware of opportunities. We evaluate many, many opportunities. And the challenge with it always comes back to, is that opportunity really going to be additive to the corporate portfolio? Is it really going to be something that we -- is better than what we're already drilling is it's something that's going to add to the returns and add to the 10 billion barrels of equivalents that we've already captured as premium resources. And we continue just to evaluate opportunities, but kind of come up short with that evaluation.

Roger Read :

Good morning. I'd like to come back to two things that have been discussed a little bit. One, Ezra, just you talked about the low carbon advantage or the emissions advantage of Dorado. I was wondering if you could go in a little more depth on specifically what you see there. And then my other question will be on the inflation side. With oil at 80, 85 right now, aren't we sitting in a situation where inflation pressures might be reversing rather than behind us? And if that's not the right way to look at it, I'd be curious what you are seeing that says deflation is the right track here.

Billy Helms:

Yes, Roger, this is Billy. On the inflation question, I think you're spot on. I think that's why we're saying, certainly, we see deflation in the market today, but it's too early to think about 2024 because of the dynamic markets that we're seeing play out. And we're kind of be patient and watch the market and see how it develops before we make any comments about where cost would go in 2024. I think as a company, we're certainly well positioned to take advantage of any opportunities that are presented in our strategy about contracting and seeking out the highest-performing crews are things that drive really our focus on sustainable cost improvements through the long term, and that's really what drives our advantage over trying to capture the premium barrel, premium price for all of our products.

Ezra Yacob:

We appreciate everyone's time today on the phone call. Thank you to our shareholders for their support, and I just want to give a special thanks to our employees for delivering another exceptional quarter. Thank you, everybody.

Operator:

Good day, everyone, and welcome to the EOG Resources First Quarter 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks, Tim. Good morning, everyone. Strong first quarter execution from every operating team across our multi-basin portfolio has positioned the company to deliver exceptional results in 2023. Production, CapEx, cash operating costs and DD&A all beat targets, which underpinned our excellent financial performance during the first quarter. We earned $1.6 billion of adjusted net income and generated $1.1 billion of free cash flow. Free cash flow helped fund year-to-date cash return to shareholders of $1.4 billion through a combination of regular and special dividends, and share repurchases executed during the first quarter. Combined with our full year regular dividend, we have committed to return $2.8 billion to shareholders in 2023 or about 50% of our estimated 2023 free cash flow assuming an $80 oil price. We are well on our way to achieve our target minimum return of 60% of annual free cash flow to shareholders. Our first quarter results demonstrate the value of EOG’s multi-basin portfolio. We have decades of low cost, high return inventory that spans oil, combo and dry natural gas basins throughout the country. Our portfolio includes the Delaware Basin, which remains the largest area of activity in the company and is delivering exceptional returns. After more than a decade of high return drilling, our Eagle Ford asset continues to deliver top tier results while operating at a steady pace. And beyond these core foundational assets, we continue to invest in our emerging Powder River Basin, Ohio Utica Combo and South Texas Dorado plays, which contribute to EOG’s financial performance today, while also laying the groundwork for years of future high return investment. Our portfolio provides flexibility to invest with discipline and develop each asset at a pace that allows it to get better. It provides optionality to actively manage our investments to minimize impacts from inflation. Diversity of our investment portfolio also translates to diverse sales market options, enabling us to pursue the highest netbacks. Our shift to premium drilling several years ago has helped to decouple EOG’s performance from short-term swings in the market. The result is an ability to deliver consistent, operational and financial performance that our shareholders have come to expect and that drives long-term value through the cycle. Recession risk and the near-term demand outlook for oil continues to drive volatility of prices month-to-month. However, our outlook remains positive, inventory levels currently near the five-year average are reducing as we progress through the year, global demand continues to increase and is forecast to reach record levels by year-end and new supply has moderated from pre-pandemic levels of growth. Longer term, with the reduced investment in upstream projects the last several years, we remain constructive on future pricing. For North American gas, near-term prices reflect high inventory levels due to this year’s warm winter and reduced LNG demand during repairs at Freeport. As such, we are currently evaluating options to delay some activity at Dorado. The medium- and long-term outlook for natural gas, however, continues to strengthen. Currently, U.S. LNG demand is at record levels, with an additional 7 Bcf a day capacity under construction or through FID with expected startup between 2024 to 2027 that should position the U.S. as a leader in the global LNG market. Our confidence in the outlook for our business is demonstrated by our capital allocation decisions in the first quarter. Disciplined reinvestment in our high return inventory continues to lower our breakeven and expand the free cash flow potential of EOG. We strengthened our balance sheet by retiring debt, paid out nearly 100% of free cash flow in regular and special dividends, and we utilized our repurchase authorization to buy back $310 million worth of stock late in the quarter during a significant market dislocation. I am confident EOG has the assets, the technology and the people to deliver both return on capital and return of capital for years to come. In a moment, Billy will discuss why we believe our foundational assets in the Delaware Basin and Eagle Ford will provide higher returns, margins and free cash flow in the years ahead, and why we remain excited about the progress we are making in our emerging assets, Powder River Basin, Ohio Utica Combo and South Texas Dorado. But first, here’s Tim to review our financial position.

Billy Helms:

Thanks, Tim. EOG’s operating performance continues to improve with the first quarter generating outstanding results. Our first quarter volume, capital expenditures and total per unit cash operating cost performance came in better than our forecasted targets. I’d like to thank our employees for their dedication and outstanding execution, giving us a great start to 2023. Our full year 2023 capital and production plans are unchanged. We forecast a $6 billion capital program to deliver 3% oil volume growth and 9% total production growth. We maintained the pace of activity from the fourth quarter of last year in the Delaware Basin and Eagle Ford. Our core foundational plays and continue to expand development in our emerging Powder River Basin, Ohio Utica combo and South Texas Dorado plays. Well productivity and cost performance are meeting or beating expectations across our portfolio as each play sustains sufficient activity to support continued innovation. As Ezra mentioned, our foundational assets in the Delaware Basin and Eagle Ford are performing exceptionally well and were a big part of our overall strong first quarter results. Sustaining a consistent level of activity in these core plays is driving operational improvements and continues to be one of the primary hedges to offset areas of cost inflation. We are excited about the outlook for these assets in the years ahead. Even as these assets mature, we can apply technical learnings, operational innovation and leverage prior infrastructure investments to continue to improve the operating margin and capital efficiencies of these world-class assets. In the Delaware Basin, we expect well performance will continue to improve this year, delivering productivity and returns well above the premium hurdle rate. Last year, our Delaware Wolfcamp wells delivered an average six-month cumulative production of about 34 barrels of oil equivalent per foot and are expected to improve this year. See slide 10 of our updated investor presentation for details. While well mix can impact the relative contribution of oil, NGLs and natural gas, overall performance is improving in large part due to continued innovations like our new completion design. We have now tested 39 wells in the Wolfcamp that are yielding an average increase of 22% in the first year production, with a 20% uplift in the estimated ultimate recovery compared to the similar wells and targets using our previous completion design. With these encouraging results, we now expect to deploy this new design on about 70 wells this year. This new design is continuing to show promise, as we expand the number of wells and test the design across different targets and basins. Operationally, maintaining a consistent level of activity in the Delaware Basin, combined with our culture of continuous improvement is generating noticeable results. Drilling times continue to improve and are generating peer-leading performance aided by our drilling motor program and high-performing staff. The amount of footage drilled per motor run improved by 11% in the first quarter as compared to last year. Similar progress is being achieved with our completion operations with the expansion of our super zipper technique. These efforts, combined with the opportunities that co-developed multiple targets in the stacked pay resource by using our existing surface footprint and an infrastructure are expected to drive significant efficiency gains and continue to improve our margins in the Delaware Basin for years to come. The first -- we first introduced the super zipper completion technique in the Eagle Ford in 2020. Since then, we have expanded its use throughout the play and have more than doubled completions efficiency as measured by completed lateral feet per day. As indicated on page 12 of our quarterly investor slides, the amount of lateral completed per day year-to-date has increased by another 18% compared to last year. In the first quarter, we also set a record in the Eagle Ford, drilling our longest well to-date, reaching a measure depth of nearly 26,500 feet with a lateral length of over 15,500 feet. We expect to continue to see completion efficiency improvements as we extend laterals in the Eagle Ford to 3-plus miles where feasible. As a core operating area that has been under development for more than a decade, the Eagle Ford also benefits from our existing infrastructure from over 3,700 producing wells. Leveraging existing investments made in strategic water, oil and gas infrastructure minimizes future CapEx needs and lowers operating costs. Ongoing improvements to completion operations and leveraging the benefit of existing infrastructure, enable our Eagle Ford finding and development costs to continue to decline. Last year, the Eagle Ford’s rate of return was the highest in the plays history. Longer term, we have over a decade of drilling inventory in the Eagle Ford, allowing us to maintain the current production base, while generating high returns and lowering breakevens. As previously mentioned, we are maintaining activity in our core plays and progressing our newer emerging plays. This year’s plan in Dorado contemplates eight additional wells completed compared to 2022 in order to achieve a consistent level of activity to drive performance improvements. Our drilling operations are realizing a 29% improvement in the footage drilled per day since 2021. Completion operations will be conducted on a few wells in the second quarter. However, we are evaluating options to delay additional completions originally scheduled later this year due to the current natural gas price environment. To-date, operational progress towards improvements and Dorado’s well performance is meeting or exceeding our early expectations. Activity in the Utica combo play is just commencing, yet we are already witnessing the compounding effects of sharing technology across our multiple plays. For example, drilling performance for recent wells is improving on the order of 20% to 30% compared to last year’s results with the benefit of our proprietary drilling motor program and precision targeting. We expect similar levels of improvement from our completion program once we begin completing wells in the third quarter. Now for a little color on inflation and industry service costs. As we had anticipated in building this year’s plan, the upward inflationary pressure that we witnessed last year appears to have plateaued, which still leaves us confident that our average well cost should increase no more than 10% compared to last year. Early indicators are showing signs of service cost moderation, which is more prevalent in some basins and less than others. We would expect that any softening of service and tubular costs will be slow to manifest into lower well cost and cash operating costs until much later in the year or more likely in 2024. As the year unfolds, we will continue to look for opportunities to leverage our scale and the flexibility of our multi-basin portfolio to manage costs across all operating areas. We also remain highly focused on sustainable cost reductions through innovation, operational performance and execution improvements to mitigate inflation and further drive down our cost structure. Now I will turn it back to Ezra.

Operator:

Thank you. [Operator Instructions] Our first question is from the line of Paul Cheng with Scotiabank. Paul, your line is now open.

Billy Helms:

Yeah. Paul, this is Billy. Let me give you a little highlight maybe of the Permian program and what we are seeing there. And then I will probably ask Jeff to give some more detailed color to help explain some of the improvements we are seeing. Overall, we are very pleased with the progress our Permian plans are showing. In general, our results are playing out just as we anticipated. In our plans, we had planned - all of our type curves are modeled and forecasted, and the results are meeting or exceeding our forecasted results including the co-development of different targets at the same time. But I’d like to go ahead and turn it over now to Jeff to maybe talk a little bit about the new completion design and the results that we are seeing and then some of the productivity improvements.

Billy Helms:

And then, Paul, the other part of your question was on Dorado and really what triggered the change of pace that we have thinking about. We put together a plan originally just to remind everybody that really, it was not a huge acceleration in activity planned for. We’re only adding eight wells. So the plan never contemplated a huge amount of growth in the -- in Dorado to start with. However, we always remain flexible on our program and with -- that’s the benefit of having a multi-basin portfolio as we can move activity around based on market conditions or other factors as they present themselves. Naturally, with gas prices remaining weak and moving into the year, it’s only natural to think about options that we might be able to explore with Dorado activity. We are exploring the option to delay some completions that were scheduled for later in the year and we will give more color on that as that unfolds.

Leo Mariani:

Yeah. Hi. Just wanted to follow-up a little bit on the buyback versus the special dividend. Obviously, there was no new special dividend, I guess, announced this quarter instead, you got certainly lean on the buyback as you described in March. I just wanted to kind of confirm your thinking around this. I mean it still sounds like the buyback is going to be reserved only for kind of very opportunistic situations, where there is this dislocation. And generally speaking, it’s probably more reasonable to expect the special going forward with the buyback kind of maybe every once in a while, is that kind of how to think about it?

Leo Mariani:

Okay. That’s helpful. And I just wanted to see if there’s any more of a robust update on the Utica. I think the last time you guys kind of rolled that out. I think you had four wells on production with a fair bit of history. Just trying to get a sense of the more wells producing at this point in time in the Utica and just any thoughts around some of the long-term performance of those prior wells have been on for, I guess, over a year at this point?

Operator:

Thank you, Leo. The next question is from the line of Scott Hanold with RBC. Scott, please go ahead.

Ezra Yacob:

Good morning, Scott. Yes. This is Ezra. Those are all accurate to the tune of how we kind of look at these opportunities. As we have talked about in the past, it kind of begins with the macro, first of all, right? What’s happening on both global and domestic supply and demand balances. As far as dislocations go, we do measure, we look at the intrinsic value of our business relative to different pricing scenarios, both short- and long-term. And we do evaluate trading multiples, not just at EOG versus the peers, but actually for the entire peer group and see what’s happening. And so one comparison that could be made is the dramatic sell-off that the industry saw last summer, which was associated with a pretty dramatic pullback in oil prices, that was really fundamentally supported by a change we felt in the macro outlook. There was a significant announcement there for roughly 300 million barrels of petroleum reserves that would be hitting the market on the supply side from across the globe. What we saw in the first quarter was not really supported by a big change in the forecast on the fundamentals. Potentially really just triggered from the banking crisis, potentially an increased fear on the demand side from increased recession, but we really feel like most of that has already been priced in to the market on the demand side. And so when we saw a pullback there in a dislocation with the market, really again associated in late March there with the banking crisis. We really didn’t hesitate and we have able to step into the market and do that $300 million share repurchase and we think we have really created a significant amount of value there for the shareholders.

Lance Terveen:

Hey, Scott. Good morning. This is Lance. Thanks for the question. Yeah. The -- our realizations continue to be excellent, and I mean, when we think about it, it’s really just the capability that we have. When you think about the multi-basins that we have, but just our transport position and then the capacity that we have taken out. You hear us talk a lot about control and having control all the way to the water is exceptionally important. So I would just say, as you think about our position and the price realizations too and then extracting additional premiums, I think, our ability to just transact very quickly and with the supply, the scale that we have, I mean, we can definitely walk in with further opportunities.

Scott Gruber:

Yes. Good morning. I want to circle back on the Wolfcamp development strategy. After looking at slide 10 here in the deck, last year you layered in more Wolfcamp M wells. But this year, the percentage of Wolfcamp M will be slowing back down some. Is that impacted by where you will develop and deploy the new completion design or is that a reflection tend to be more selective with where you co-develop the Wolfcamp M, just what guidance shift in mix?

Scott Gruber:

Got it. And then maybe just one for some more color on the new completion design. You said it was initially developed and rolled out the Eagle Ford. Did it become a dominant design in the Eagle Ford and will it become the dominant design in the Permian and how quickly it can be rolled out to some of your new plays?

Operator:

Thank you. The next question is from the line of Derrick Whitfield with Stifel. Derrick, please go ahead.

Billy Helms:

Yeah. Derek, this is Billy Helms. So, yeah, the second quarter CapEx has gotten to be a little bit higher than the first quarter and it’s mainly due to some non-drilling and completion capital, the indirect or infrastructure and those kind of things that we put in our program that it was recently scheduled to occur at the latter half of the first quarter, it turned out to be pushed into the second quarter. That’s the reason the first quarter under -- was under our own CapEx and the second quarter is a little bit higher. And that really sticks to our original plan, we had always planned for about 52% of our CapEx to be spent in the first half of the year and so we have still on target for that in the 48% in the back half, so that’s kind of the way the program plays out.

Ken Boedeker:

Yeah. Derek, this is Ken. I’d like to start off by really crediting our team there in San Antonio for driving down that finding cost that you talked about. Really by focusing on improving the efficiency of every portion of the process, we have been able to drive down costs over the past several years. And increasing our lateral lengths, while improving targeting and focusing on bit and motor performance in conjunction with the advent of super zipper completion operations have really allowed us to improve efficiencies and really drill and complete more lateral footage in a day compared to a few years ago. That’s really showing up on a lower cost basis. And one thing to note is we do have over 10 years of high-return drilling in this play that can sustain our current production levels and continue to expand our margins.

John Abbott:

Good morning. This is John Abbott on for Doug Leggate. Our questions -- first our question are really on Dorado. We understand that you have going to potentially delay activity this year. But one of the goals that you set out this year was to try to just begin get greater economies of scale into play. When do you think you need to achieve that size and scale, noting that you have additional LNG capacity coming on, exposure in 2026?

John Abbott:

I guess…

John Abbott:

That’s extremely helpful, which leads to the next question. Assuming there was not an issue with gas prices, how do you think about the optimal level of production for that play or activity long-term? I mean, how big does it came to get to? How do you think about that program -- that -- from an efficiency program longer term?

John Abbott:

You can…

Operator:

Thank you. The next question is from the line of Neal Dingmann with Truist. Neal, please go ahead.

Jeff Leitzell:

Yeah. Neal, this is Jeff. No. We have outstanding results there in the Powder right now and it’s some of the lowest finding costs that we have seeing there in the whole portfolio. So, yeah, we still have between kind of our full South Powder River Basin and then moving up to our North, about 1,600 net undrilled premium locations. So just looking at our program, everything is on pace this year. The wells are performing as we expected. Q1 we have completed about 15 gross wells, which two-thirds of those were Mowry and we have seeing a lot of benefits also by getting some consistent activity up there in the Powder. We have running a consistent two and -- two to three rigs and one full frac spread with that, which is really allowing them to kind of push their efficiencies. And then we also have a lot of confidence in the play just with the overall performance and stuff with the Mowry. And then from there, as we talked about, we want to go ahead and gather the data in the upper overlying formations like the Niobrara, so we can develop that later in the future. Also, additional confidence in the play, I think, would be really -- should be said is that the infrastructure acquisition that we had. We had noted that in our 10-Q, we acquired Evolution. And I will go ahead and let maybe Lance say a couple of things on that.

Neal Dingmann:

Was that…

Neal Dingmann:

Was that plant helped a deeps there as well? I am just wondering would you mention with that plant, would that boost the deeps there a little bit as well?

Operator:

Thank you. The next question is from the line of Bob Brackett with Bernstein. Bob?

Ezra Yacob:

No. I’d say it’s attributed to our co-development strategy. I mean it’s -- really, it’s been a process over time. So if you look at back in 2016 in the Wolfcamp or I should say our strategy through the whole Permian, we had six unique targets and kind of fast forward here, we have up to 18 unique targets. Obviously, with that, the spacing has changed both in zone and from a vertical perspective. So our teams have methodically obviously tested this. They have taken into account the actual spacing, how they interact, the depletion to it, and we have come up obviously with the best co-development strategy really to maximize the overall production of those intervals and then obviously maximize the economics related to it.

Ezra Yacob:

No. It’s really -- it’s about maximizing the overall resource there, as you said. So we do have the optimal amount of communication that we have actually able to optimize the recovery and then like I said, really maximize those economics.

Arun Jayaram:

Yeah. Good morning. I wanted to come back to the new completion design. You highlighted how you have tested this on 39 wells and you plan to go to 70 wells. And my question is, was the 20% uplift relative to wells in the same area or relative to the -- to your type curve? And maybe the follow-up is, are the 70 wells contemplated for this calendar year and was that part of your guidance, did that include that or would that reflect an upside risk to your oil guide?

Arun Jayaram:

Okay. And just my follow-up is, any update on Beehive and Australia timing?

Operator:

Thank you.

Operator:

The next question is from the line of Charles Meade with Johnson Rice. Charles, please go ahead.

Billy Helms:

Yeah. Charles, this is Billy. Certainly, it really is not triggered on a specific gas price, but just the overall softness we see in the current market conditions and the need to simply bring more gas on in this current condition. As we talk near-term, we understand the near-term softness in the market but longer term, medium and longer term, we have still very bullish on the long-term outlook for gas. So we do look at the different flex -- the flexibility we have in the program and we have evaluating options to be able to successfully push those back in the year. And we have just continue to remain disciplined on our investment to make sure we have maximizing the value to the company over the long-term.

Jeff Leitzell:

Yeah. This is Jeff again. Yeah. That is correct. It’s not necessarily a one size fits all across. It really does have to do with the geology that we have applying it to. And when looking particularly there in the Permian, we primarily just applied it down in the deeper Wolfcamp targets. So that would basically be just kind of the up or down through the middle in a co-development standpoint. Now we are testing on those shallower targets, but there are quite a few different rock types. So right now, I’d say it’s area by area, and from a percentage basis, you kind of hate to put an actual percentage on it. But right now we have still evaluating that, and it will be a case-by-case basis.

Neil Mehta:

Yeah. Good morning, team. My question was on the natural gas liquids market where realizations, obviously, have been trending lower. I am just curious on your perspective on what gets NGLs to firm up relative to WTI and what are you seeing real time in the export markets? Thank you.

Neil Mehta:

Great. And then just curious on your guys’ perspective on the gas markets as well. You have talked a little bit about slowing down potentially in terms from a drilling perspective, but how do you see the balances moving from here in a weather normal way over the course of the year?

Operator:

Thank you. The next question is from the line of Josh Silverstein with UBS. Josh, please go ahead.

Lance Terveen:

Yeah, Josh. Hey. This is Lance. I believe when we think about our guidance, I think, we were just below the midpoint of the guidance on our realization so from a gas standpoint. And then you have seen kind of our guidance for like the full year and we expect a lot of that’s going to be driven, obviously, we have the diversification that we have with our California exposure. We have -- you can see on our supplemental slide, slide eight, you can obviously see the large exposure that we have into the Gulf Coast and then obviously, our JKM exposure as well. So I think we have going to hold with the existing guidance that we have.

Ezra Yacob:

Yes, Josh. This is Ezra. When we came out with that cash return guidance with a minimum of 60%, we really did just mean that, but it’s a minimum. In fact, last year we returned excess of this 60% free cash flow to our shareholders. And we started with that 60%, because we feel confident on that, especially when we roll in kind of almost a peer-leading regular dividend that we would be able to compete and deliver that through the cycles. So when we think about a specific target for cash on hand, I wouldn’t say that we have a real target. We have spoken about some indicators and things that we strategically think about as far as holding a cash balance. The first, of course, is we like to have a bit of cash on balance just to run the business to make us allow us to stay out of commercial paper, and historically, that’s around about $2 billion kind of depending at what point you are in the cycle. And then in addition to that, we do like to have cash on hand so that we can be strategic and counter cyclically invest in opportunities as they arise, whether that’s at times investing in casing or line pipe or last year we were able to step in and do an acquisition in one of our emerging players there in the Utica, where we actually purchased approximately 130,000 mineral rights. And then lastly, of course, just the stock repurchase, which we exercised here in the first quarter. We have talked about being able to utilize that opportunistically and really part of our strategy, the reason that you can actually step into a dislocated market and have the confidence to do a buyback is that you have got the strength of the balance sheet, which includes cash on hand. That’s really what we have going for and so I think that provides another compelling reason to carry potentially a higher cash balance than the company has historically done.

Ezra Yacob:

I just want to thank everyone for participating on the call this morning and I especially want to thank our employees for the outstanding results they delivered in this first quarter. Thank you.

Operator:

Good day, everyone, and welcome to EOG Resources Fourth Quarter Full Year 2022 Earnings Results Conference Call. As a reminder, the call is being recorded. At this time, for opening remarks and introductions, I would like to turn the call to the Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks, Tim. Good morning, everyone. EOG's growing portfolio of high-return assets delivered outstanding results in 2022. We earned record return on capital employed of 34% and record adjusted net income of $8.1 billion, generated a record $7.6 billion of free cash flow which funded record cash return to shareholders of $5.1 billion. We increased our regular dividend rate 10% and paid four special dividends, paying out 67% of free cash flow, beating our commitment to return a minimum of 60% of annual free cash flow to shareholders. And we strengthened what was already one of the best balance sheets in the industry, reducing net debt by nearly $800 million. We continue to deliver on our free cash flow priorities this year by declaring an additional special dividend of $1 per share yesterday. Outshining our financial results were achievements made by our operating teams working in a challenging inflationary environment. Credit goes to the innovative and entrepreneurial teams working collaboratively across our multi-basin portfolio. Together, we leveraged the flexibility provided by our decentralized structure to deliver exceptional operational performance. Production volumes, CapEx and per unit operating costs were within guidance set at the start of the year. We offset persistent inflationary pressures that exceeded 20% during the year to limit well cost increases to just 7%. Our exploration teams uncovered a new premium play, the Ohio Utica combo, and advanced two emerging plays, the South Texas Toronto and Southern Powder River Basin. We've progressed several exploration prospects including the Northern Powder River Basin. We expanded our LNG agreement, currently estimated to take effect in 2026 to 720,000 MMBtu per day, which will provide JKM-linked pricing optionality for 420,000 MMBtu per day. Last year, the revenue uplift from our current 140,000 MMBtu per day LNG exposure was more than $600 million net to EOG. Preliminary results indicate that we reduced our GHG intensity and methane emissions percentage, achieving our 2025 targets. And we initiated an expanded deployment of our new continuous methane leak detection system called iSense. Led by the tremendous performance in our Delaware Basin and Eagle Ford plays, our operating performance and financial results in 2022 are a reflection of our asset portfolio and the unique organizational structure in place to support it. Seven teams in North America and one international team operates 16 plays across nine basins. Our decentralized structure empowers each operating team to make decisions in real time at the asset level to maximize value. This differentiates EOG and enables us to consistently execute our strategy and produce outstanding results year after year. Our multi-basin portfolio provides numerous high-return investment opportunities and we remain focused on disciplined investment across each of our assets. In addition to our premium well strategy, in which wells must generate a minimum of 30% direct after-tax rate of return at a flat $40 oil and $2.50 natural gas price for the life of the well, we invest at a pace that allows each asset to improve year-over-year, lowering the cost and expanding the margins generated by each asset. Disciplined investment means more than just expanding margins at the top of the cycle. It means delivering value for the life of the resource and through the commodity price cycle. It's not only developing lower-cost reserves, but also investing strategically to lower the operating cost of these resources, which positions EOG to generate full cycle returns competitive with the broad market. Looking ahead to 2023, EOG is in a better position than ever to deliver value for our shareholders and play a significant role in the long-term future of energy. Our ability to reinvest in the business, deliver disciplined growth, lower our emissions intensity, earn high returns, raise the regular dividend and returned significant cash to shareholders, all while maintaining what we believe is the best balance sheet in the industry is due to our differentiated strategy executed consistently year after year. Now, here's Tim to review our financial position.

Billy Helms:

Thanks, Tim. I would like to first thank each of our employees for their accomplishments and execution last year. 2022 was a challenging year, and the commitment and dedication of our employees remain steadfast as they delivered outstanding results. Last year can be characterized as a year of heightened inflation where we witnessed increasing commodity prices, accompanied by higher levels of activity across the industry. The result was a much tighter market for services, labor and supplies. We were able to offset most of this inflation through efficiency gains and capital management across our portfolio to limit well cost increases to just 7%. For the full year, oil production was above the midpoint of guidance, while capital expenditures were $4.6 billion, were only 2% above the original guidance midpoint set at the beginning of the year. Our operating teams working throughout the Company leveraged efficiencies to help offset inflation. This is most evident in our core development plays, which sustain sufficient activities to support continued experimentation and innovation. In the Delaware Basin, we expanded use of our Super Zipper completion technique to increase treated lateral feet per day by 24%. In our Eagle Ford play, the completions team increased completed lateral feet per day by 14% and the amount of sand pump per day per fleet by 27%. Our decentralized operations teams are continually striving to improve performance and share learnings across our portfolio to limit well cost increases. These learnings are then deployed in our emerging opportunity plays. For instance, in the Southern Powder River Basin, Mowry play, the drilling team decreased drilling time by 10% with improved bid and drilling motor performance. In our South Texas Dorado gas play, the operations team reduced drilling time by 12%. Through technical and operational advancements, they promise to continue to drive improvements in 2023. Beyond cost reductions, a new completion design implemented last year in the Delaware Basin is realizing positive improvements in well performance in certain target reservoirs. This new design was tested in 26 wells last year and is yielding as much as an 18% uplift and estimated ultimate recovery. We're also making great progress towards our long-term ESG goals. Our wellhead gas capture rate exceeded 99.9% of the gross gas produced. And preliminary results indicate that we lowered GHG intensity and methane emissions percentages in 2022. We now have approximately 95% of our Delaware Basin production covered by iSense, our continuous methane monitoring technology. Now turning to the 2023 plan. We forecast a $6 billion capital program to deliver 3% oil volume growth and 9% total production growth. We expect total volumes on a Boe basis to grow each quarter through the year. First quarter will show more growth in gas versus oil due to the well mix and timing of several Dorado gas wells that were completed late in the fourth quarter of last year. The plan can be summarized in the following four points. First, drilling rig and frac fleet activity in our core development programs, specifically the Delaware Basin and the Eagle Ford, will be relatively consistent with the fourth quarter of last year. The longer-term outlook for the Eagle Ford is to maintain the current production base where we have over a decade of continued opportunities to generate high returns and cash flow. After a decade of stellar operational improvements in the Eagle Ford, it has become a highly efficient, high-margin play with existing infrastructure and access to favorable markets. In the Powder River Basin, the plan builds off last year's positive well results and infrastructure installation with an additional 20 Mowry completions. We expect to complete a few additional wells in our emerging Utica play in Ohio as we continue to delineate our acreage position and drill a few wells in the Bakken and DJ Basins. In Dorado, our plan is to achieve an activity level that creates economies of scale and develop a continuous program to allow for innovation that drives improved well performance and cost reductions. This results in a moderate increase in activity, completing about 10 additional wells versus last year. In Trinidad, a drilling rig is now scheduled to arrive in the third quarter, which is about a six-month delay. So, international volumes decreased 60 million cubic feet per day or 10,000 Boes per day versus our earlier estimates. Overall, we increased activity in our emerging plays. The average EOG rig count for the year is expected to increase by about two rigs and one additional frac fleet. Second, we have line of sight to efficiencies that we expect will limit additional inflation pressure on well cost to just 10% versus last year. Year-over-year increases in tubular costs as well as day rates for drilling rigs and frac fleets are the main drivers of the increase. As part of our contracting strategy, we stagger our agreements to secure a base line of services and secure consistent execution. For this year, we have locked in about 55% of our well cost, which is a similar level to previous years. Approximately 45% of our drilling rigs and 65% of our frac fleets needed for the year are covered under term agreements with multiple providers. By maintaining this consistent base of services, we expect to find additional opportunities to drive performance improvements and eliminate downtime, thus potentially providing an opportunity to offset some additional inflation. Third, our 2023 capital program includes additional infrastructure investment. Typically, funding for facilities and other infrastructure projects comprises 15% to 20% of the CapEx budget. And this year, we expect that number to be closer to 20%. In Dorado, we commenced construction late last year on a new 36-inch gas pipeline from the field to the Aqua Dolce sales point near Corpus Christi, Texas. This pipeline will help ensure a long-term takeaway, fully capture the value chain from the wellhead to the market center, help support expanded LNG export price exposures due to come online around 2026 and broaden our direct interstate pipeline capacity to reach markets along the entire Gulf Coast corridor. We're also undertaking smaller infrastructure projects in other areas, like the Utica to lower the long-term unit operating cost. Fourth, we plan -- the plan includes capital that represents the next steps towards our vision of being among the lowest emissions producers of oil and natural gas. Our first CCS project has begun injection and we will continue to explore opportunities to enhance our leadership position in environmentally prudent operations. These projects offer healthy returns while also providing reductions in long-life unit operating cost and lower emissions. EOG remains focused on running the business for the long term, generating high returns through disciplined growth, improving our resource base through organic exploration, improving our environmental footprint and investing in projects that will lower the future cost basis of the Company. I am excited about 2023 and the opportunity it brings for our employees to further improve the Company. Now here's Ken to review year-end reserves and provide an inventory update.

Ezra Yacob:

Thanks, Ken. In conclusion, I'd like to note the following important takeaways. EOG Resources offers a unique value proposition. First, it begins with our multi-basin portfolio of high-return investment opportunities anchored by the industry's most stringent investment hurdle rate or premium price deck. Second, our disciplined growth strategy optimizes investment to support continuous improvement across our portfolio. Our employees utilize technology and innovation to increase efficiencies and allow EOG to remain a low-cost operator. Third, we are focused on generating both near- and long-term free cash flow to fund a sustainably growing regular dividend, support our commitment to return additional free cash flow to shareholders and maintain a pristine balance sheet to provide optionality through the cycles. Fourth, we are focused on safe operations and improving our environmental footprint across each of our assets, utilizing both existing and internally developed technologies. And finally, it's the EOG employees that make it happen. Our culture is at the core of our value proposition and is our ultimate competitive advantage. Thanks for listening. Now we'll go to Q&A.

Paul Cheng:

Two questions, please. First, Ezra, with Dorado, how is your investment program changed in many of the changing landscape in the natural gas price? I would imagine, at this point, there's more economic to drill for the oil play than the gas play? How that changed your outlook for the next several years on that play? Second question is on the CapEx. Maybe that it seems like you are investing for the future. So what is the sustaining CapEx requirement to maintain a flat production at this point for your program? And also, if we're looking at, say, for the remainder of this year, is there any area that you think we will start to see some softening in the cost and which may not be reflected in your current budget?

Billy Helms:

Yes, certainly. On the inflation front, I think it's safe to say that everybody has seen commodity prices falling. We've seen inflation rates have peaked and come down. And so we're seeing a lot of the service costs, at least, have plateaued going into this year. And so, as I mentioned on the call, we've got about 55% of our wealth costs secured through existing contracts with our event. And that leaves us the opportunity to capture any upside that we might see in lower rates going into the year. So we're sitting in a fairly good position. I think we're going to be poised and waiting to see what happens and take advantage of opportunities as they present themselves. But I think inflation, at least, is showing that we've plateaued. We baked in about a 10% inflation into our plan. And as we see opportunities, we'll continue to look for ways to improve that.

Billy Helms:

I think what we've seen is one of the biggest drivers this last year on inflation was certainly tubulars casing cost. And I think we've seen different things and different parts of that make up. I think the ERW products is mostly the surface and intermediate casings, those have rolled over and are softening a little bit more than the production casing, which is your seamless products, which are still largely exposed to imports. And so you're seeing some opportunities on casing, but I think there's still yet to come on most of that. On the service side, I think we haven't really seen anything manifested yet, but I think we've all seen rig counts have largely been flat since September, and they're down off their peak of -- in November of probably 20 to 25 rigs. And with the drop in gas prices, I think everybody is expecting maybe we'll see some more softening on the rig activity level. So that may lead to some opportunities to capture some markets. The one advantage that we have, and I'll go ahead and throw this out, we may expand on it later, but the benefit we have is operating in multiple basins. And so we see certainly more service tightness and labor constraints in areas with the most activity, which would be the Permian. But we have the opportunity to shift activity to our other basins to enable those to take advantage of more available equipment, more available capacity to add services at favorable rates. So that's the advantage that we have as a company.

Arun Jayaram:

Ezra, you have a net cash, a balance sheet and if we run through, call it, the $80 case, 55 -- or $5.5 billion in free cash, if you return 60% of that, you're looking at a balance sheet that would be, call it, $3 billion of net cash at year-end. So I wanted to get your views on uses of that cash that you have on the balance sheet and where your heads at in terms of thoughts of increasing cash return to shareholders versus looking at inorganic opportunities, including bolt-ons or M&A? And how do you prioritize some of those opportunities as we think about 2023?

Arun Jayaram:

Great. My follow-up is Ezra, just given the size of the Company, you're approaching 1 million Boes per day in terms of overall output, and most of your activity is short cycle oriented. And I wanted to get your thoughts on exploring longer cycle opportunities. You've seen some of your peers invest in areas such as Alaska and LNG. And I wanted to get your thoughts on EOG looking at the long cycle and perhaps an update on where we stand for -- to drill Beehive in Australia?

Operator:

Our next question today comes from Doug Leggate from Bank of America. Your line is now open.

Billy Helms:

Yes, Doug, this is Billy Helms. Let me take a stab at that. So first, there's probably three buckets you can probably put the increase in. First of all, is inflation in our well cost. That's probably a good piece of it, 1/3 of it. It's about -- we're anticipating about a 10% well cost inflation in our program versus last year. And yes, that's maybe 10% over and above last year. But still last year, we achieved only a 7% well cost increase in spite of probably, arguably, 15% or 20% inflation. So I think our teams have done a great job on offsetting inflation with efficiency gains. We're expecting more of that this year, but we've baked in about a 10% cost increase. The second part of that is going to be infrastructure. We've talked about already our Dorado gas pipeline. That's been initiated. And we're also building out some infrastructure in some of our emerging plays, like the Utica to start the testing of those plays. And then we've also included some capital for our ESG projects that we're advancing. So those are kind of the buckets that we look at. And then obviously, we have some additional wells on top of that in these various plays. So as we pick up the two additional rigs and one extra frac fleet, of course, that's going to accompany some additional well count. So those are the three main buckets that I would characterize the increase in the capital versus last year.

Ezra Yacob:

Yes, Doug, that's a good question. Yes, I think the difference is between 2019 or pre-COVID with the oil versus what we're doing in Dorado right now. So like I said, the Dorado volumes are anticipated to support. It's basically the output of a single completion spread program this year. And the benefits that we see of running a consistent program there to learn about this asset, continue to drive down costs, support putting in some infrastructure, things like water takeaway and in-basin gathering, that outweighs the near-term volatility in the gas price because what we see is in a very not-too-distant future, we see a pretty dramatic increase in the offtake and the demand coming on along the Gulf Coast. Now we are backstopped and supported, obviously, with investing on the return side in these premium wells. So we measure the investment on here at a $2.50 natural gas price. And while at today's prices, that's below, we run that $2.50 all the way through the life of the asset. The rest of the gas that we're growing this year is, honestly, as we -- as I said at the top of the Q&A is really associated gas coming out of the Delaware Basin, where the returns there are dominantly driven obviously on the oil and liquids side. And we're really running a maintenance program or a flat activity level program to Q4 across the Delaware Basin.

Leo Mariani:

I was hoping you could update us a little bit on maybe some new well results, if there are any from some of the emerging plays. Most interested in hearing about any recent Utica well performance or any Utica wells that may have come on? And then similar, just in the PRB, did get a sense if you've seen improving wells there as well. You've talked a lot about cutting costs in PRB, but just curious as to whether or not some of those wells have seen improvements as you guys have gotten more experience?

Jeff Leitzell:

Yes, Leo, this is Jeff. Yes, just a quick update. In 2022, we continue to delineate our acreage there in the Southern Powder River Basin. We completed about 31 net wells across the four primary targets. And all of those, we had excellent results. And we've been shifting our primary focus there, as we've talked about previously to the Mowry. So in 2023, we're going to ramp up the activity a little bit there. We're going to run kind of a consistent two- to three-rig program with one frac fleet. So that will be about 55 net wells. And the majority of those, as we talked about, will be in the Mowry. It's about a 75% increase year-over-year there in the Mowry. And then we'll continue to focus on optimizing that Mowry program there in our Southern Powder River Basin core area. We'll collect a lot of valuable data, and then we'll look to utilize it in the future on our overlying Niobrara formation and then the North Powder River Basin position that we announced earlier on.

Ezra Yacob:

Yes, Leo, this is Ezra. That's a great pickup. It's a good question because that's exactly what's happened is that it is raising up with respect to the returns and the way they compete for capital. Over the last couple of years, kind of coming out of the pandemic, we've reduced our -- there. And the result of that, we've been trying to right-size the investment. The result has been really back to back years of the highest drilling -- rate of return drilling programs that we've seen in the history of developing that asset. As everybody knows, it's a very high-margin oil play where we've got a lot of infrastructure and a tremendous amount of industry knowledge there. Simply, the asset now is commanding a lot more capital investment this year. We are looking to invest to maintain flat production, as you said. The production has decreased a bit over the last couple of years. And one advantage that we are seeing in the Eagle Ford, and Billy touched on this, and maybe I'll let him add a little more color on it, is really how the inflation and service availability has manifested itself across these different basins and why the Eagle Ford's a bit more attractive.

Operator:

Our next question today comes from Neal Dingmann from Truist. Your line is now open.

Ken Boedeker:

Yes, Neal, this is Ken. I'll take a shot at that. We -- what we talked about earlier, and the way we really look at it, is we have 10 years of double-premium inventory at our current activity level. So locations really aren't a concern for us. What we're really trying to talk about and show is the value proposition of our 10-plus billion Boe resource base that has a finding cost less than our current DD&A rate. Investing in this inventory will use to DD&A and improve earnings and return on capital employed. Our well counts are really constantly changing as our development plans evolve, acreages swapped and laterals are extended. And all those changes improve our finding costs and returns and modify our location count. So what we're really focused on now is lowering our cost basis as we invest at high returns.

Ken Boedeker:

Sure, Neal. The Bakken creates significant returns, and it is one of our highest percentage plays that we have in the Company. So where it's appropriate and when it's appropriate for development, which is we're going to be putting some money into it this year, we'll try to run about a one-rig program there the foreseeable future.

Scott Gruber:

So I saw in your supplemental debt that you mentioned that continuous pumping operations are helping to drive completion efficiency in the Delaware. I believe that's one of the benefits you're seeing for running your frac fleet. Is that accurate? And just a bit more detail on how continuous fracking is having completion efficiency above and beyond doing zippers?

Scott Gruber:

Got it. And then you also mentioned taking advantage of any softening in -- frac rates if they do manifest this year. How is your contract coverage for both currently following the period of tightness? Would you be able to capture any deflation before year-end? Or would that really benefit more at '24 just given contract coverage?

Operator:

Our next question comes from Jeanine Wai from Barclays. Please go ahead.

Billy Helms:

Yes. Jeanine, this is Billy. Happy to give you some color on that. The Delaware Basin is certainly one of our most capital-efficient plays, quickly followed by the Eagle Ford. The advantage we have in the Eagle Ford is, as I mentioned earlier, the tremendous efficiencies that have been driven in that play. You're right the cum per foot is probably a little bit lower in the Eagle Ford but the well cost is also significantly less. And so we can put a lot more wells to sales in a lot shorter time frame than we can in the Delaware Basin. And then going back to that also, we didn't really feel that we wanted to ramp up activity anymore in the Delaware Basin, but instead leverage on our multi-basin portfolio to increase activity in areas where equipment and crews are more available to leverage into our operation. And so that's what we've chosen to do. But I think the Eagle Ford is still one of our most capital-efficient plays we have in the Company, and we're excited about that opportunity to keep sustaining volume going forward.

Billy Helms:

Yes, Jeanine, this is Billy again. The base declines have been fairly consistent, I would say, year-to-year. And we don't see a measurable change really in our base declines going forward. I think last year was a pretty good year as compared to this year, and I expect the declines would be similar.

Derrick Whitfield:

With my first question, I'd like to lean into the new completion design you've implemented in Delaware that achieved an 18% AUR uplift. Could you perhaps elaborate on the nature of the enhancement and if it would to be across and outside of the basin?

Derrick Whitfield:

Perfect. And as my follow-up, perhaps shifting over to the Eagle Ford. We noticed the legacy wet gas position was seemingly reengaged in your supplement update. If I recall, that initial position was in the order of 26,000 acres. Could you perhaps comment on what has brought it back to life and the amount of activity you're expecting over the next couple of years?

Operator:

Our next question comes from Charles Meade from Johnson Rice. Your line is now open.

Billy Helms:

Yes. Charles, this is Billy Helms. Yes. The new design is -- really starts with an understanding of the rock we're applying it to. I think we've talked in the past about how all of our designs are tailor made to every wellbore and whatever the geology is telling us is the right application for that. So is it something that we could apply to all zones? I would say probably not, but it's certainly more attractive than other zones. But it is also being done in the core of the play. It's not just applying to the fringe intervals or the fringe of the plays, but some of our core plays or target intervals and we're seeing dramatic improvements. Now it's going to be -- continue to be tailored based on what the geology tells us is the right application, and we'll tweak it and be able to transfer that knowledge as we see it develop.

Billy Helms:

Sure, Charles. The rigs are pretty much in operation today. We started kind of picking up rigs at the end of the fourth quarter going into this year. And as we mentioned, the fourth quarter run rates in the Delaware Basin and the Eagle Ford will be pretty consistent throughout the year. And so, we've also started drilling in some of the other plays, some of the new emerging plays, such as the Powder River Basin and Dorado. So those are kind of ongoing. We'll be picking up rigs at different times and some of the other plays, like the Bakken or the DJ or the Utica. And those will kind of come and go. Those aren't going to be really, yet full rig lines. They'll kind of ebb and flow based on the timing of each individual play. But the base program is pretty much going to be set, and I'd say the rig count is not going to fluctuate much beyond where it is today.

Ezra Yacob:

I'd just like to thank everyone for participating in the call this morning and especially thank our employees for the outstanding results delivered in 2022. Thank you.

Operator:

Good day, everyone, and welcome to EOG Resources' Third Quarter 2022 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks, Tim. Good morning, everyone. The quality of EOG's diverse multi-basin portfolio of high-return assets continues to grow and improve. Yesterday's announcement of the large position we captured in the Utica Combo play demonstrates yet again that EOG's robust exploration pipeline delivers results. Over the last two years, our organic exploration efforts have brought forth Dorado, our premium dry natural gas play in South Texas, the emerging Northern Powder River Basin oil play in Wyoming and now the emerging Utica Combo play in Ohio. The value of our multi-basin portfolio can't be overstated. With the addition of the Utica Combo, we are now positioned to operate 7 premium resource basins, which reinforces several of EOG's competitive advantages. First, our decentralized cross-functional operating teams innovate independently, but collaborate to compound the impact of learnings and efficiencies across the company. Second, our flexibility to allocate capital optimizes reinvestment across our portfolio, enabling us to develop each asset at the right pace to maximize returns. And third, our geographic and product diversity gives us the ability to plan around basin-level market dynamics. Our goal is to expand and improve the overall quality of our portfolio by identifying higher return inventory. Our approach is to build a diverse portfolio of premium assets predominantly through low-cost organic exploration, which adds reserves at lower finding and development costs and lowers the overall cost basis of the company. The end result is continuous improvement to EOG's company-wide capital efficiency. Our track record of successful exploration, coupled with strong operational execution, is how EOG has continued to improve over time and position the company to create shareholder value through industry cycles. We demonstrated our confidence in EOG's improving cost structure yesterday by increasing the regular dividend 10%. Our peer-leading annualized dividend is now $3.30 per share, competitive with the broad market. We also delivered on our commitment to return at least 60% of annual free cash flow to shareholders with our fourth special dividend of the year. By year-end, we will have returned $5.80 per share of special dividends. Combined with the regular dividend, we will return $8.80 per share or $5.1 billion in cash to shareholders, which exceeds our 60% cash return commitment using current forecasts. Looking forward, we expect 2023 will remain dynamic with respect to the supply chain, oil and gas prices and other global macro drivers. Our diverse low-cost asset base puts us in an excellent position to capitalize on opportunities no matter the environment. EOG continues to consistently execute, lower our cost structure through innovation and efficiencies and grow the quality of our portfolio to improve capital efficiency and free cash flow potential. Our transparent cash return strategy is anchored to a sustainable, growing regular dividend and backstopped by an impeccable balance sheet. EOG is in a better position than ever to deliver value for our shareholders through industry cycles and play a leading role in the long-term future of energy. Next up is Billy with an early look at our 2023 plan, followed by Tim, who will review our financial performance. Ken will then provide background and details on the Utica Combo play. Here's Billy.

Tim Driggers:

Thanks, Billy. We are very pleased to increase the regular dividend by 10% to $3.30 per share annual rate. This increase reflects two things. First, the improvements we've made to the cost structure. Efficiencies and technology continue to sustainably improve EOG's capital efficiency. Furthermore, we expect the advantages of operating in multiple basins will drive additional improvements to EOG's cost structure and returns in the year ahead, lower the cost of supply and lower the breakeven oil price to fund the dividend. Second, this dividend increase reflects our confidence in EOG's expanding portfolio of premium plays to grow the company's future income and free cash flow potential. Over the last several years, our success in organic exploration continues to add low-cost reserves and consistently drive down our DD&A rate, enabling EOG to create value through industry cycles. We also remain committed to returning at least 60% of free cash flow to shareholders each year. As a reminder, we look at this on an annual basis, not quarter-to-quarter. Based on current commodity prices, we estimate the $1.50 special dividend declared yesterday will bring free cash flow return to shareholders to about 67% for 2022. We will start 2023 in an exceptionally strong financial position. We ended the third quarter with $5.3 billion of cash on the balance sheet against $5.1 billion of debt. We generated $2.3 billion of free cash flow during the quarter, along with inflows of another $1.3 billion of cash from working capital, primarily from the drawdown of hedge collateral. Now here's Ken.

Ezra Yacob:

Thanks, Ken. The takeaway from today's call are centered on EOG's fundamental value proposition. First, EOG's multi-basin organic exploration focus continues to improve the quality of our inventory, Capturing Tier 1 acreage across multiple high-return opportunities provides geographic diversity, product diversity and the flexibility to allocate capital across each asset at the correct pace to optimize returns. Second, EOG is a low-cost operator. We use technology to increase operational efficiency and capture select pieces of the value chain to keep both capital and operating costs low, thereby helping to reduce our breakevens and increase our free cash flow and income-generating potential. Third, Tim highlighted our financial performance and commitment to financial discipline that results in a 10% increase to our peer-leading regular dividend, a commitment to additional cash return with our announced special dividends and a best-in-class balance sheet. Fourth, our recently published sustainability report illustrates our progress to reach near-term greenhouse gas and methane emissions intensity goals and our commitment to develop new technologies and pilot new projects, such as our CCS project, to help reduce our environmental footprint. And fifth, it is EOG's employees and unique culture that continues to drive our success. Thanks for listening. We'll now go to Q&A.

Neal Dingmann:

Congratulations for some nice results. My first question is on, to jump right to it, the Utica Combo play. Specifically, looking at that Slide 10 of years, it appears, and you talked about this -- some of you guys talked about this already, that the primary folks looks like it's on that volatile oil section or window. Just wondering, have you identified this is sort of how the economics look in this window and sort of why focus here? And secondly, maybe just talk about the takeaway situation for you all there.

Ken Boedeker:

Sure. As Ezra mentioned, we are in the volatile oil window. And we do expect oil, gas and NGL production will vary some across that window both from north to south, but more so from east, which will have a higher gas cut to west, which is oilier. On an ultimate recovery basis, we expect that there will be 25% to 35% oil and similar percentages for natural gas liquids and residue gas. So when you think about that, this play is really focused on the 60% to 70% liquids development. And from that, as far as the economics go, it gives us premium and double-premium numbers. That's $40 oil, $16 NGL and $2.50 gas. The other thing to note on these wells is it's early, but we are expecting, depending on where we're at in the play, 2 million to 3 million barrels of oil equivalent for an EUR with a 3-mile lateral. So that type of performance really leads us to a low finding cost and it will definitely be additive to our cost basis.

Neal Dingmann:

That's fantastic details, guys. It's great people to you coming back there. My second question, maybe just a bit on capital allocation, specifically, I realize you won't have detailed '23 guide for a few more months. I'm just wondering if you all have talked a bit -- I think, on the plan talked today about maybe a bit more activity next year. I'm just wondering, is that just to keep production stable? Or are you still kind of considering a maintenance plan next year? And I'm wondering if you would consider a bit more growth if prices continue to be as strong and maybe costs would back off a little bit?

Operator:

The next question comes from Leo Mariani. You may proceed.

Ken Boedeker:

Yes, Leo, this is Ken. As far as that 2,500 barrel a day rate that we highlighted there, we produced that for a couple of weeks. So we're very comfortable with that rate. As far as the other 4 wells go, they had varying lateral lengths. We can move those to a 3-mile -- when we move those to a 3-mile development plan, they're definitely double-premium-type economics. That 2,500 barrel a day well that's got the 12,000-foot lateral is the longest lateral we've drilled to date. The others do have a shorter lateral as we drilled them. One thing I really wanted to highlight on that 12,000-foot lateral well is the operations team that we have at Coloma City. It was the longest well that we've drilled. And once they got into the lateral, they drilled that 12,000 feet in a little over 6 days and stayed 99% in an 8-foot target. So just outstanding operational performance there. As far as well costs go, we've really just highlighted that we anticipate being less than $5 a barrel on the F&D cost.

Billy Helms:

Yes, Leo, this is Billy Helms. Let me maybe start with the answer, and then maybe Lance can give some more color on it. So the 36-inch pipeline, yes, it's an effort to try to not only get that gas to market, but also make sure we continued our focus on keeping our cost as an operator low. So that's part of our longer-term plan. We've recognized that the value of installing infrastructure is really helping lower the long-term cost basis of the company. And so this is just another step in that vein. The 36-inch pipe will be constructed over a couple of years, so it's not all being done in 1 single year. It's important to be taking it to the market center where we are. And then the LNG that we certainly recognize the value of having the gas in this area. It's in South Texas, where all the LNG demand is, so it's advantage from that standpoint. So that's kind of how this kind of works into the overall market dynamics with this play. So I'll let Lance maybe add a little bit more color on the pipeline itself and the market.

Operator:

The next question comes from the line of Doug Leggate. You may proceed.

Ezra Yacob:

Yes, Doug, this is Ezra. Thanks for the question. Like anything, we allowed the -- our geologic model to kind of drive where we are interested in acquiring acreage. We were able to get in there and put it together in a variety of different ways. Probably the most noticeable one is that we were able to purchase the minerals down to the south that Ken highlighted earlier. It's about 135,000 acres of minerals that we purchased as part of transaction. But in general, I'd say it fell right in line with our strategy of identifying where we want to be in the basin, trying to capture Tier 1 and Tier 2 acreage countercyclically, if you will, so we can continue to have a low cost of entry which, of course, is critical is not only as you get out and delineate the plays, but also obviously, as you really think about full cycle economics in these resource plays.

Ezra Yacob:

Yes, Doug. The short answer is that we're agnostic based on our premium price deck, the $40 and $2.50 natural gas pricing that we use to measure our investments. But in general, I'd say we do have a bullish view long term on natural gas and NGLs, obviously, on oil as well. But specific to Dorado and some of these combo plays, we're seeing natural gas. We think we'll continue to see increased demand from power gen, some of the coal switching that we've seen this year. And also, it's going to have, in the upcoming years, continued exposure to the international markets with LNG development there along the Gulf Coast. NGLs obviously span the entire broad spectrum of the economy, from plastics and rubber to heating to fuel blending and so on. And that's not to say those two won't experience volatility at times where supply is potentially outpacing demand. And likewise, demand is -- could be outpacing supply. But that comes back to our approach as a disciplined operator. First, we evaluate, like we just talked about, based on the premium price deck that we use internally, and that means that we're investing based on returns first and foremost. Second, we evaluate that macro supply and demand fundamentals for short-, medium- and long-term signals. And I'd say it's one reason we are excited about the way we enter some of these positions, especially the Utica, by owning the 135,000 acres with the minerals, we can control the pace of development. And the remaining leasehold in that play is dominantly held by production. And so that, again, is another lever that allows us to really optimize our pace of development and investment.

Operator:

The next question comes from the line of Scott Gruber. You may proceed.

Ken Boedeker:

Yes, Scott, this is Ken. As far as the split, it's really early in the development of the Utica. We have 4 wells in it. We want to do some additional drilling and testing across the acreage before we really come up with some kind of a resource or a well count or a well spacing estimate. As far as premium versus double premium, we actually think that we have double premium potential across the entire acreage position. So we're really just excited about the play and look forward to developing it next year.

Billy Helms:

Well, as Ken -- this is Billy. As Ken just mentioned, the Utica, we're very excited about the potential of the play to be double premium. And so it definitely competes on a capital allocation standpoint. But we are early in the play. So as we see things today, we'll plan on drilling somewhere in the order of 20 wells next year and then from that determine on how what the go-forward plan looks like. As far as capital allocation for next year, we're still early and still developing our plans. But as we see things today, the benefit of having these multiple basins is it gives us a lot of flexibility to move capital between the different basins. We don't have to leverage all of our activity in one basin. In particular, we're going to try to keep from seeing a lot of activity increases in areas where we're seeing the most inflation and supply chain constraints that exist mostly in the Permian Basin today. So I would expect our activity levels there to remain pretty consistent with what we're doing today. We can pull levers in the other plays to meet whatever objectives we set forth as we move towards the end of the year.

Charles Meade:

I'd like to ask about these 4 wells that you drilled in the Utica. Can you talk about what you did differently, perhaps, from previous operators, whether it's targeting of a zone or your completion design? And also perhaps, did you test different concepts across those 4 wells?

Charles Meade:

And 20 wells next year, that looks like it's -- maybe should we be thinking about 2 rigs with -- since it might take a while to drill these 3-mile laterals in an overpressure setting?

Operator:

The next question comes from the line of Bob Brackett You may proceed.

Ezra Yacob:

Bob, this is Ezra. Yes, this year, you're right, we've -- as we talked at the beginning of this year, we had a number of different exploration plays at a number of different places and evaluation. This year, we're drilling some initial wells, kind of wild cats in the play. Some of the plays are a bit further along and we're trying to delineate because remember, our exploration program, it's not really about producers and dry holes. It's really about how or if these prospects are going to be additive to the quality of our existing inventory. That's what we're really looking for here. Depending on how you bucketize the 20 wells we're talking about here in Point Pleasant is probably the most important thing. It's -- it will basically be another delineation type of year for us across the 400,000-acre position that we've put together. Outside of those 20 wells, that will be the biggest part of next year's kind of exploration delineation type of program, if I'd put it there. We have some ongoing prospects in other areas that we've talked about in the past. Some of those other ones, again, extend similar types of areas, places that have been sleepy in the past, places that are in known oil and natural gas producing areas, places where we're trying to bring modern technology, our advancement of horizontal drilling and completions technologies and combining them with our rock, the understanding of the geologic environment and seen if we can turn those into premium and double premium types of plays, it would be additive to us. And we'll just continue to evaluate as they go. To give you a hard number right now, though, it's just a little bit early, as Billy said, but we'll break that out in February.

Ken Boedeker:

No, I mean, Bob, this is Ken. We do stay in the Point Pleasant. I think the secret sauce here is really a combination of everything. It's a combination of what we've learned in our other plays and then being able to operationally perform on that. So getting the right petrophysical model to understand that targeting and understand how that targeting varies across the area, and then looking at the 8-foot window that we've kept it in really speaks to being able to perform. This really goes back to just our culture. It really is about the people, and it's about our ability to always attempt to get better, to work on getting better and try to make the next well better than the last. So you put all that together, and that really is the secret sauce for our entire company, let alone our exploration effort.

Ken Boedeker:

Yes, Bob, I think that's why we're in the volatile oil window. We have enough gas in the volatile oil window to help us lift our wells. At this point in time, we don't see that we'll need much artificial lift through the life of these wells. It's being right on that the right portion of that phase window.

Jeanine Wai:

Our first question, maybe just following up on Bob's question here. You've disclosed 7 premium operating basins, which is fantastic. The decentralized model has worked very well for EOG so far. But from an organizational perspective, how many basins would be considered too many basins because you're clearly still evaluating other opportunities?

Jeanine Wai:

And then for our second question, in terms of operational momentum, are you able to provide any color on what activity looks like heading into year-end and early '23? We noticed that 4Q oil guidance is flat at the midpoint quarter-over-quarter. CapEx is up, but that sounds to us like it could be timing-related.

Operator:

The next question comes from the line of [Kevin MacCurdy]. You may proceed.

Ken Boedeker:

Yes, this -- Kevin, this is Ken. What we're talking about now is those are 2 million to 3 million-barrel wells that we've talked about and less than a $5 F&D cost. We really haven't given out a number as far as what our development costs will be because we have some additional testing, and we really do want to drill some of our wells on pads and drill them in packages to see what that ultimate development cost will be. So you can use the $5 F&D in the 2 million to 3 million barrels to get a reasonable estimate for well cost.

Lance Terveen:

Yes, Kevin, this is Lance Terveen. Thanks for your question. I'd say even like I talked about earlier, like the marketing component of it is integrated very early on. So I mean we recognize the nat gas like realizations are weaker, but still when we look at our overall portfolio and then how the Utica Combo competes, it's very competitive. And so your earlier question was just as it relates when you think about just kind of downstream takeaway in that. Again, it comes to just the liquids focus that we have in anticipation. I think there's some misconception on kind of the gas rates that those are going to look very similar to like the dry gas wells to the east and other competitors that are in the region when we're going to see lower gas rates that are going to come out of our development. And so when we look at that on a go forward and with the relationships that we have with the capacity that we see on the processing side, the gas sales and the takeaway, we're not foreseeing an issue right now.

Neil Mehta:

This is Neil Mehta. Can you hear me okay?

Neil Mehta:

Okay. I'm sorry about that. Yes, it's Neil Mehta here from Goldman Sachs. So as I had more of a macro question here, which is we haven't seen U.S. oil production, at least in the weekly, move since April of 2022. They've been kind of hanging around this plus/minus 12 million-barrel a day range. And are you surprised that we haven't seen the pickup in U.S. production that a lot of people were anticipating? And I want to tie that into Slide 9 of your deck, which is showing relative maturity of some of the oil plays like the Bakken and increasingly the Eagle Ford and even the Delaware. Are we getting to the point where shale is going to have a tougher time growing and we should be thinking about peak shale production in the United States in the foreseeable future?

Neil Mehta:

Yes, that's helpful. And then a follow-up just on the balance sheet. You guys are clearly have a fortress balance sheet position in a net cash position now. Just talk -- remind us again how you're thinking about minimum cash balances? And what is the Pareto optimal capital structure as you think about your leverage profile?

Operator:

That concludes the question-and-answer session. I will now pass the call back over to Mr. Yacob for final remarks.

Operator:

That concludes the conference call. Thank you for your participation. You may now disconnect your lines.

Operator:

Good day, everyone. And welcome to the EOG Resources’ Second Quarter 2022 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 Chief Financial Officer, EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks, Tim. Good morning, everyone. Yesterday we declared a third special dividend for the year, demonstrating our commitment to deliver long-term shareholder value through our cash return strategy. The $1.50 dividend is supported by another outstanding quarter. We posted adjusted earnings of $2.74 per share and nearly $1.3 billion of free cash flow. So far this year, we have declared $4.30 per share of special dividends. Combined with our peer-leading annualized regular dividend of $3 per share, we are on pace to pay out a minimum of 60% of annual free cash flow. What continues to differentiate EOG is our people and our assets. We have cultivated an inventory of premium and double premium wells that provide a 20-year runway for the company through our focus on organic exploration, supported by a decentralized organizational structure. Our multi-basin portfolio is predominantly the result of having seven North American and one international cross-functional exploration teams that work independently, but collaborate on shared learnings. Our role here in Houston beyond capital allocation is to facilitate those shared learnings across all eight teams. The result is a robust exploration pipeline that continues to both improve the quality of and expand our more than 20-year inventory of premium and double premium wells. Our portfolio includes the Delaware Basin, which remains the largest area of activity in the company and is delivering exceptional returns. After more than a decade of high return drilling, our Eagle Ford asset continues to deliver top tier results while operating at a steady pace. And our emerging South Texas Dorado dry natural gas play and Powder River Basin Mowry and Niobrara combo plays are contributing to EOG’s success today and laying the groundwork for years of future high return investment. In addition, we have tested our Mowry and Niobrara plays in the northern Powder River Basin. Our initial results have demonstrated the untapped potential of this oilier part of the basin as a compliment to the outstanding performance in the southern part of the basin. EOG’s current multi-basin portfolio, offering exposure to both geographic and product diversity alongside several other prospects in our exploration pipeline will continue to expand EOG’s premium inventory and provide through the cycle value creation. Disciplined reinvestment within any given play depends on where we are in the development life cycle of that play. Our multi-basin and portfolio of high return assets, all competitive against our premium hurdle rate, provides invaluable flexibility to invest at the pace that allows each play to get better. It also allows us to plan around basin level market dynamics, impacting services and infrastructure to minimize inflation and bottlenecks. We are able to optimize reinvestment across our total portfolio to add reserves at low refining costs, lower the overall cost base of the company, and continue to improve EOG’s company-wide capital efficiency. This quarter, we are highlighting, iSense, our continuous methane monitoring system that we piloted in the Delaware Basin and are now deploying in our most active development areas. iSense is yet another example of how EOG’s decentralized model, not only fosters innovation across eight teams, but also compounds the impact of innovation by taking ideas born in one operating area and expanding them across multiple basins. From the latest information technology-driven solutions to reduce emissions, to innovation focused on drilling and completions operations, to procurement of casing and sand EOG is unique in its ability to leverage its culture and operating structure to get incrementally better every year. The tremendous inventory and cost improvements we have made over the last several years, provides high confidence in the low breakevens and operational flexibility of our business. This confidence in our business, along with the strength of our industry-leading balance sheet, [indiscernible] this quarter to terminate a significant portion of our oil and natural gas hedges. Going forward, we expect to hedge significantly less than the 20% to 30% of volumes we typically hedged in prior years. The current operating environment is challenging given the volatility of commodity prices and inflation headwinds. Through it all our employees have remained focused on execution and have improved the business. Our second quarter performance is proof of that. We delivered more oil for less capital and in the face of a unique inflationary environment, our forecast for capital expenditure this year remains unchanged. EOG’s, consistent execution, low cost structure, reduced hedge position and transparent cash return strategy based on a regular dividend that we have never suspended or cut that has grown 21 of the last 24 years and is now competitive with the broader market, puts EOG in its strongest position ever to deliver significant value to shareholders through the cycle. Here is Billy with an operational update and early look at 2023.

Ken Boedeker:

Thanks, Billy. This quarter, we are providing details on our continuous methane monitoring project, which is an example of the progress we’re making in our emission reduction efforts. Over the last several years, our leak detection and repair program, or LDAR has advanced from sound, sight, smell surveys to surveys using more accurate optical gas imaging, to today’s deployment of scalable solutions of the latest technology, continuous methane monitoring. This technology detects potential leaks and provides real-time alerts to help accelerate repairs and will provide data and trend analysis to potentially prevent future methane releases. We’ve been evaluating continuous methane monitoring technology for a few years. There are several third-party systems and technologies available to monitor and detect potential methane leaks, which use intermittent or continuous monitoring technology. About 18 months ago, we began a pilot project using a solution we built in-house named iSense, which is a fence-line monitoring solution that uses methane sensing technology to continuously monitor facilities and provide real-time alerts of potential leaks to a central control room. We tested iSense against monitoring solutions in use and available in the market today and confirmed that our sensor detected methane release events consistent with these third-party systems. The results from these tests confirmed that iSense is the most effective solution for EOG to use, to detect and accelerate leak repairs while also being scalable and economic. Like so many of our innovations, this technology is being spearheaded by our employees across the company. Since the pilot, our employees are rapidly deploying iSense in the field, prioritizing areas of highest potential impact. The initial installations are focused in the Delaware basin and currently cover about 60% of our production. We expect that most of the remaining Delaware basin production will be monitored by iSense by year-end. We’ll continue to roll out iSense in other operating areas next year. Using our proprietary system allows us to own the data creation, flow and storage, which is a priority with all our information systems, owning the iSense data and retaining direct control of its collection provides invaluable flexibility to improve both data quality, as well as the tools to analyze and integrate iSense data with existing operational data from our production facilities. This data, along with our ability to monitor our operations for many of our four control rooms will enhance the 24/7 capability to continuously identify, prioritize and repair leaks. In the future, when data from iSense is paired with other real-time production data, we expect to be able to make improvements in the design of facilities to minimize releases. We’re also optimistic that we will be able to more readily predict the likely size and source of a methane release. Leveraging technology to enhance our methane leak detection and repair program is another great example of EOG’s culture of continuous improvement throughout all our operations. Our employees have embraced the company’s a mission reduction efforts and I’m excited to see how EOG’s culture of innovation and technology will continue to drive creative solutions. Now here’s Jeff to discuss the progress we’ve made in our premium combo play in the Southern Powder River Basin.

Lance Terveen:

Thanks Jeff. As we look further downstream, the investment in infrastructure that has lowered the cost structure in the Southern Powder River Basin also allows us to apply our time tested marketing strategy of establishing multiple connections to provide market pricing diversification. Today, we hold sufficient processing, transportation and fractionation capacity for natural gas liquids out of the PRB. We have access to both the Mid-Continent at Conway, Kansas, and the Gulf Coast at Mount Bellevue, Texas, and underappreciated aspect of the Mowry and Niobrara wells is the prolific NGL production and the heavier post-processing mix of NGLs they produce. After processing to minimize ethane extraction, our Powder River Basin in NGL barrel contains approximately 10% ethane, 45% propane, and the remainder being butanes and more of a heavier NGLs resulting in an NGL to WTI price ratio of over 50%. In the first half of this year, our NGL price realization was $53.01, which is a $7.17 premium to the Mount Bellevue typical barrel. In addition, the quality of the Powder River Basin oil has an average API gravity of 44 to 47 and remains in high demand. During the first half of this year, realized prices for our oil production out of the PRB were WTI plus $1.63 with access to both Wyoming and Cushing, Oklahoma markets. Stepping back, I’d like to review our marketing strategy for the company as a whole and all our active development areas we want to retain control of our products and establish multiple sales points, which adds significant value. For example, in the first half of this year, we transported an average of 188,000 barrels of oil per day for export, which represents about 30% of gross production with optionality to sell based on a WTI or a Brent Index with the widening of the Brent WTI spread, we have the opportunity to take advantage of our capacity to deliver up to 250,000 barrels of oil per day for export. For propane, we have delivered 19,000 barrels per day for export at premium prices to Mount Bellevue. We also continue to see strong uplift in our natural gas price realizations due to our early mover advantage, securing 140,000 MMBtus per day, linked to JKM through Cheniere LNG facility in Corpus Christi. Cheniere recently announced FID or final investment decision on Stage 3 in Corpus Christi. When Stage 3 goes in service, EOG will triple its exposure to JKM to 420,000 MMBtus per day. We continue to see constructive long-term demand for all our products, both domestically along the Gulf Coast and internationally. To unlock that value, you need control of your products, transportation capacity, and an early mover advantage to capture spreads quickly. As we look down the road, EOG is well positioned to capture the strength of prices in these export markets to generate additional cash flow and value to shareholders. Next up is Ezra for concluding remarks.

Operator:

Thank you. The question-and-answer session will be conducted electronically. [Operator Instructions] Our first question comes from Leo Mariani of MKM Partners. Leo, please go ahead.

Ezra Yacob:

Yes, Leo, this is Ezra. I appreciate your question. Really, what we’ve always talked about is that our growth is really the output of our ability to generate high returns from a disciplined reinvestment strategy. And that’s really what we’ve tried to describe today is as you pointed out, first of all, it is early to talk about 2023. But ultimately, we’re committed to remaining disciplined. We want to focus investment in each of our assets at a level where they can continue to improve every year. Directionally, as we see it today, how the supply and demand balances look, the constraints on services, the associated inflationary pressures, oil growth will likely be similar to this year. And as Billy highlighted, we’d expect to direct additional investment towards our Dorado natural gas play based on the positive results that we’re seeing there.

Billy Helms:

Yes. Leo, this is Billy Helms. Yes, the small change in well count is really just a result of two things, one is timing. Some of the wells that were scheduled to complete at year-end are going to slip into the next year. It’s just a timing thing. The other factor that plays into that is a change in working interest in some of our plays. We’ve had slightly lower working interest in some of our Delaware Basin wells in the second half of the year. Just to illustrate how minimal that is, that’s only about a 2% average change in working interest across the year. So it’s a very minuscule amount, but that explains the change in the well count. As far as the CapEx, we’re very pleased, as you can tell from the comments we made about the ability of our teams to continue to innovate and drive efficiencies in our business to offset inflation. Inflation turns out to be just a little bit higher than we anticipated this year, so we are going to see a slight increase in our well cost as we go through especially the second half of the year, but we’re still confident we’re going to stay within our guidance and don’t expect to face additional costs that will increase our budget.

Operator:

Our next question comes from Arun Jayaram from JPMorgan Chase. Arun, please go ahead.

Billy Helms:

Yes, Arun, this is Billy. As far as capital allocation, as we see it today, there’s a lot of factors play into that, of course, and it’s early to say where we’re going to be still we’ll have quite a bit of activity in the Delaware Basin going forward. It is a premier play in the company, and certainly, that will continue to command quite a bit of capital. Eagle Ford has been, as you know, a performance engine for the company for the last decade or longer. And that will – and they’re generating outstanding results. So that will still command capital. As we compare – we allocate capital based on returns and certainly, the encouragement we’re seeing from Dorado and the activity there is showing us the ability to be able to continue to fund that program going forward. And then the confidence we have in the new emerging Powder River Basin gives us a sense that, that will also come in quite a bit of activity. So the ratios, I would say, are going to stay similar. As far as the Powder River Basin and our overall capital plan, that will depend on the outlook for commodities at that time, but the – what we’re going to see in the Powder, just to be clear, is a shift of activity from some of their older traditional plays, the Turner and the Parkman to some of the deeper, more emerging plays and then Mowry more specifically and the Nio. So you’ll see that shift. The amount of capital allocated to that play will also depend on just the commodity price outlook that we see for the year once we get closer to that. But overall, we’re – the takeaway from that, I would think, would be that the flexibility we have with the multiple plays we have to chase to continue to add value long-term to the shareholders.

Tim Driggers:

Yes. This is Tim. As far as the bond, that is 2023. It’s in the first quarter of 2023 is when that will mature. We have no plans to pay it off early. As far as the collateral they run off kind of like the hedges that we’ve given you the timing of when those hedges are in our 10-Q. So it kind of runs off as that timing comes off. It all depends, of course, on where the strip goes, how that comes off. But right now, it’s based on the strip, and that would be how it would come off, just as those run off.

Operator:

Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Scott, please go ahead.

Lance Terveen:

Hey Scott, this is Lance Terveen. Thanks for your question. Yes, when you think about the price realizations, I think the broader message is just you can really just see how competitive the Powder is with all our other plays. I mean, operationally, I mean, you heard Jeff kind of outline a lot of things in the opening comments, but even for our products, we continue to just really see it being in high demand. For example, like even on the crude, you have to remember one of the important attributes up in the Powder, especially related to EOG, is just think about the crude quality. I mean today, we’re kind of seeing right around 44, 45. We expect that to kind of be a 44, 47, kind of over time. And so we really want to protect that quality. We’ve secured 500,000 barrels of storage is kind of in the field. We’ve got firm capacity to both Guernsey and the Cushing market. So having that multiple flexibility where we can show that kind of high demand barrel and the API quality that we have keep it kind of segregated with that API quality, it’s really a value when we sell direct to our refiners. And so just being able to have that value and have that quality and consistency is key, and so we draw a lot of that experience from what we’ve done in the Eagle Ford and also in the Powder – I mean, I’m sorry, in the Delaware Basin. But yes, that’s – it’s – the quality is what you’re seeing on the price realizations. And then as you think about the NGLs, you’re seeing mostly ethane rejection that’s happening there. So most of that, you’re seeing the ethane that’s going to be going more towards like an MMBtu or selling that as a gas. And so that is a heavier barrel that you’re seeing that we kind of show. But again, we have the market flexibility. We can show that barrel in Conway. We can also show that barrel in Mont Belvieu. So we can kind of are that flexibility to and look at those spreads. So getting kind of back to your question, I mean, really the quality and then the flexibility that we have with the multiple markets and it’s in an area that’s absolutely in demand as we.

Billy Helms:

Yes, Scott, this is Billy Helms. So for Trinidad, we’ve had, as you know, a long successful history of really maintaining pretty much flat production with minimal investment, and it generates quite a bit of cash for the company – cash flow for the company. So it’s been a very successful project for multiple decades now. We still see exploration opportunities and are still counting on exploration success going forward just based on the things we see today. The small guide down in gas production, especially in the next, say, the rest of this year, is based on some turnaround projects we have on some of the compressor stations and platforms in the field. So it’s just an operational issue really in the manifest in the third quarter mainly. So -- but as we start to drill some of these exploration wells, we still have confidence that production base will continue.

Billy Helms:

Yes, that’s right.

Operator:

Thank you. Our next question comes from Scott Gruber from Citigroup. Scott, please go ahead.

Billy Helms:

Yes, Scott, this is Billy Helms, again. On the inflation question, I think I would distinguish a little bit there. I think we’re recognizing the inflation that everybody else in the industry is seeing. We’re able to combat that really through a lot of the efficiencies we drive through our business. And that’s really a result of the culture we have of continuous improvement and the quality of the staff we have in each of our operating divisions. So now the contracting strategy has always been a long-term thing for EOG. We worked with our vendors, our partners on the service side. And our contracts are always a little bit staggered so that all the contracts don’t roll off at the same time. That gives us a lot of flexibility to also manage the commodity cycles to make sure we have a consistent operating performance level going into the year. We always start about this time of year. So I wouldn’t say we’re starting any earlier than we typically do. I think we always started sometime here in the middle part of the year to start securing services for the next year as we see things play out. We take opportunities as we see those emerge to make arrangements with vendors and our service partners to secure those services in the upcoming year and that determines the level of services that we secure for next year’s well cost. We typically like to think about securing about 50% to 60% of the well cost ahead of any given year. And that range depends on the opportunities we see with service partners to lock in those services. This year, we expect to be somewhat the same as we go into next year, but it -- we’ll see as we get closer to the year-end, but that’s how we see the inflation. Obviously, we expect with the tightness in the market, we’re going to see some additional inflationary pressure going into next year. So just anticipating that, we could see another uptick in our well cost going into next year, but we expect to, again, moderate a lot of that with our efficiency gains.

Ezra Yacob:

Yes, Scott, this is Ezra. Just a little bit of color on that. Obviously, the Board decides the dividend each quarter. They review our business needs, the macro environment, the cash position, so on and so forth. And as you said, the $1.50 per share special this quarter, which brings the total dividend commitment to right at $7.30 per share is on pace to achieve the minimum of a 60% free cash flow return. And I think that’s the emphasis on there is that the 60% is a minimum. Ultimately, it’s up to the Board, like I said, to return additional cash in 2022. The way to think about those early terminations of the hedges is really a reflection, I think, of our confidence in improving the financial profile of the company. Our ability to navigate inflationary pressures this year flexibility to allocate capital across multiple resource plays, which are each delivering exceptional returns and really our ability to continue to lower the cost base of the company. These are all things that deliver expanded free cash flow opportunities for EOG.

Operator:

Thank you. Our next question comes from Neal Dingmann from Truist Securities. Neal, please go ahead.

Ezra Yacob:

Yes, Neal, this is Ezra. Thank you for the question. Basically, we evaluate a buyback just like any other investment decision. And really, what we do is we look to see how it’s going to create long-term shareholder value. And as you highlighted and as we’ve discussed previously, the $5 billion share repurchase authorization that we have in place, we’ve talked about using it opportunistically. And what that means for us is using it during times of what we would say are significant dislocations in the market. And that’s as opposed to a more programmatic system. And quite frankly, this year, during Q2, we didn’t really see a what we would say was a significant dislocation. We definitely witnessed a lot of volatility, I think, rather than a dislocation. The volatility was due -- is driven by changes to the oil inventories that we saw that was really due to the SPR releases. We saw some concern over demand destruction associated with the inflationary pressures across the broad market. We saw some potential for weaker demand associated with the uptick of COVID cases. But ultimately, in our view, these are all kind of short-term events that really don’t change the fundamental supply and demand picture.

Billy Helms:

Yes, Neal, this is Billy. Certainly, on the self-source sand, you named one of the primary ones. It’s a big part of our program. We’ve been doing that, as you might remember, for more than a decade. And what we’ve been able to do is find ways to get the source of the sand closer and closer to the wellhead, minimizing not only the cost of the product, but also the transportation involved in getting it to the wellhead. We are expanding that through the rest of the year such that we’ll be able to continue to supply greater and greater amounts from our own self-sourced mines, so we’re excited about the growth in that. Other areas that we self source, there’s a number of them. I mentioned briefly in the prepared comments, a note to our efforts to take control of the drilling motors that we use in our drilling operation. That’s a small thing maybe, but it’s a big driver of performance when it comes to that part of the business. And we recognized that a couple of years ago, built up some expertise in our staff to address that. We worked specifically to not only design, but also build and oversee the maintenance of those motors that ultimately drives the improved performance and we’re seeing great results from that program. And that’s another differentiator in our drilling performance that allows us to continue to offset inflation. Some of the other things, as you know, we’ve been managing our tubular inventory for many, many years as well. we deal directly with the steel mills, which gives us a lot of advantages in the sense of having some clarity or some certainty on the market and kind of what that’s indicating to get ahead of issues where we see it, take advantage of opportunities to secure those at lower cost and make sure that we have pipe for our programs on a go-forward basis. So those are maybe a couple of other things that would give you some color on what we’re doing.

Operator:

Thank you. Our next question comes from Doug Leggate from Bank of America. Doug, please go ahead. Doug Leggate, your line is now open. You can proceed with your question.

Ezra Yacob:

Yes, Doug, we haven’t released that and we did remove the breakeven slide from earlier this year, because of the significant change in gas prices that have gone on in the first six months of the year. The best thing I can point to is the fact that we continue to bring on lower-cost reserves, basically focused on the premium and double premium wells into the cost base of the company. You can look at the reduction in our unit costs and the reduction in our DD&A rate year-over-year to kind of infer the reduction in our breakevens.

Ezra Yacob:

Yes, Doug. The first thing I would say is that, that’s right, I think it’s stating the obvious that that I feel that our stock is undervalued right now. But again we look at that buyback and investment in that buyback we compare it against other opportunities in the business to create shareholder value – long-term shareholder value. And when we do that, when we compare it versus reinvesting in the business drilling these double premium, these premium wells at a 30% and a 60% direct after tax rate return based on $40 oil and $2.50 natural gas. It’s a very, very high hurdle. So when we think about what can create longer term value for the shareholder, we see the benefit of reinvesting in the business, driving down our long-term well cost, lowering the break evens as we talked about has a very, very competitive portion of allocation. Now with regards on the transitory nature comparison with the transferring nature of a special dividend, I think again it goes back to the way that we look at the buyback with regard to our shareholders. Buying repurchasing shares during a volatile movement in the stock price, I think our shareholders prefer to have the assurity of special dividends coming back to them as opposed to us trying to time the volatility in the markets. Now that’s different from what – again, I would go back to what we call a significant market dislocation, where I think though you’d have an opportunity there that would compete very favorably to create long-term shareholder value.

Ezra Yacob:

Thank you.

Paul Cheng:

Thank you. Good morning. Two questions please. Ezra, could you comment on the A&D market in, for example, in Eagle Ford, I think you gentlemen have said the asset is getting a little bit tired. So do you see opportunity to make maybe more sizeable bolt-on acquisition that to beef up the operation there? And secondly, that just wondering that have you guys get a chance to review the new tender proposal on the tax law changes? And how that – what would be any major impact to EOG? Thank you.

Tim Driggers:

Sure. Paul, as far as the proposal we’re in the process of reviewing that as is everyone else currently. But specifically looking at the minimum tax proposal, we do not see that is having any detriment to EOGs. We are a full taxpayer already, so as we model it currently, it will have no impact on EOG.

Jeanine Wai:

Hi, thanks for taking our questions. Maybe just following up on Paul’s question there, low cost bolt-ons have always been part of your capital allocation strategy, and we noticed the cash flow statement had about $350 million of that in there. Any color on whether that was primarily blocking and tackling in your active areas, or is that more on the exploration front?

Jeanine Wai:

Okay, great. And then maybe just a quick-one on marketing, you talked about – you’ve got optionality for up to 250,000 barrels a day of brent exposure. You’re not electing that much right now, but we’re looking at your production levels out of the Permian and the Eagle Ford, and so what’s the capacity to increase beyond that 250,000 or maybe to get to that 250,000? And if you were to take on some more exposure on that, is this really looking at things more on the contract side, or are you also securing to, or are you also open to securing more dock space on your own? Thank you.

Jeanine Wai:

Great. Thank you.

Neil Mehta:

Hey, good morning Ezra and team. Just one question for me, it’s just – can you give us the lay of the land of how the Dorado program is shaking up – shaping up and how do you think about the net asset as we go into next year from a planning perspective, but as we continue to see the gas curve is firmed up here? How do you think Dorado can fit into the overall U.S. gas picture? Thank you.

Neil Mehta:

Thanks Ken.

Ezra Yacob:

Yes. We want to thank everyone for participating in the call this morning and thanks to our shareholders for their continued support. We especially want to recognize our employees for their performance this quarter. Our discussion today highlights their focus on making EOG a low cost operator, generating high returns and lowering our environmental footprint each and every year. Thank you.

Operator:

Good day, everyone. And welcome to the EOG Resources First Quarter 2022 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 Chief Financial Officer of EOG Resources, Mr. Tim Driggers. Please go ahead, sir.

Ezra Yacob:

Thanks Tim. Good morning, everyone. EOG’s cash return strategy demonstrates our commitment to deliver long-term shareholder value. Yesterday, we declared a second special dividend for the year of $1.80 per share following last quarter’s $1 per share. Combined with our peer-leading annualized regular dividend of $3 per share year-to-date, we have announced $3.4 billion in cash return to shareholders in 2022. EOG has a strong history of cash return. 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 23-year compound annual growth rate is 22%. Since the transition to premium drilling in 2016, our dividend compound annual growth rate has been even higher at 28% including doubling our dividend last year. Today, our regular dividend not only leads our E&P peer group. It is more than competitive across all sectors of the market. More recently, we have supplemented our regular dividend with significant special dividends, reflecting our commitment to both capital discipline and returning cash to shareholders. While we are proud of our cash return track record, we acknowledge shareholders desire for more transparency and predictability. To provide both, we recently formalized and yesterday announced our cash return commitment of returning a minimum of 60% of annual free cash flow. Going forward, our intention is to evaluate and pay the regular dividend and consider options for additional cash return every quarter. The addition of quantitative guidance to our cash return framework reflects our confidence in our business. The pandemic driven volatility in the oil and gas market is stabilizing. However, the macro environment continues to evolve with the war in Ukraine and other geopolitical events. We have proven to ourselves over the last several years that our business is resilient through the cycle, including unprecedented shocks to the industry. Credit for EOG’s resilience for the steady improvement in our ability to generate free cash flow in any environment and the ability to make this free cash flow commitment to our shareholders goes to our employees who embrace our premium return hurdle rate six years ago, which requires that all investments are in a minimum of 30% direct after tax rate of return using a $40 flat oil and $2.50 flat natural gas price. Last year, we doubled the minimum return to 60%, both the premium and now double premium hurdle rates have positioned the company to have an outstanding year in 2022. In spite of the ongoing inflationary and supply chain issues facing our industry, our employees outperformed during the first quarter and are positioned to deliver on our annual capital and volumes plan. We have decades of low cost, high return inventory that support the consistent financial performance that our shareholders have come to expect and that drives long-term value. Our inventory spans multiple assets across oil, combo and dry natural gas basins throughout the country, which enables us to pursue the highest net backs by diversifying both our investment and sales market options. We also continue to explore. A year and a half ago, we announced Dorado a premium dry natural gas play, where we’ve captured 21 Tcf of resource potential net to EOG. In a moment, Ken will update you on the progress we’ve made on well performance and well costs and what we believe is the lowest cost and lowest emission source of natural gas onshore U.S. Our organic exploration program has grown our premium inventory by more than 3.5 times since the premium metric was introduced in 2016. So our exploration program isn’t focused on adding more. We are looking for better inventory. New plays like Dorado and the potential we see in our current exploration pipeline gives us confidence we will continue to grow and improve our double premium inventory in the future as we have done in the past. While we have earmarked and committed to return a minimum of 60% of annual free cash flow, our longstanding framework and priorities for total free cash flow are unchanged, a sustainable growing regular dividend, a pristine balance sheet, additional cash return to shareholders through special dividends and opportunistic stock buybacks and low cost property bolt-ons. Sustaining and growing the regular dividend remains our highest priority and reflects our confidence in the long-term performance of the company. A pristine balance sheet is a strategic advantage functioning as a shock absorber that also provides the flexibility to exercise a buyback when the opportunity arises and to take advantage of other counter cyclical investments. Additional cash returns through special dividends and buybacks complement our other priorities and together with our free cash minimum return guidance support our goal to create significant long-term shareholder value. Now, here’s Tim to review our financial position.

Billy Helms:

Thanks, Tim. We’ve had a great start to the year. Our first quarter volume, capital expenditure and total per unit cash operating cost performance exceeded our forecasted targets. We’re also pleased with our progress to-date, offsetting inflation and managing well cost. Our drilling teams continue to reduce drilling days and generate consistent performance improvements. Use of self-sourced downhole tools as well as minimizing downtime and mud losses remain areas of focus to improve performance. For example, drilling times in our Eagle Ford oil play continue to improve, decreasing 28% in the last five years. The average well is now drilled in less than five days. On the completion side, we have increased the amount of treated lateral per day by about 10% over the last year, as we further deploy the super zipper technique. We are now using this technique on more than half of the wells completed in the company and expect to increase its use further as we progress through the year. In addition, our self-sourced sand program is providing a tremendous advantage that we expect to further offset additional inflation throughout the year. When we establish our plan at the beginning of the year, we knew the unusually tight supply constraints initially sparked by the economic recovery from the pandemic would present a unique challenge. Taking these headwinds into account, this year’s plan was devised with known efficiency improvements that would maintain well cost flat with last year. While we have since seen increased steel and fuel prices directly associated with the war in Ukraine, we are confident we can still deliver on the CapEx and volume targets in our original plan. Rather than accept inflation as a given, our employees remain proactive. We have a track record of lowering cost and developing efficiencies through periods of economic expansion and other drivers of inflation. Our operating teams are ever more diligent in their quest to identify new areas of performance enhancements that will lower well cost. EOG’s advantage lies with our people and our culture. Today’s challenges are met with innovation and value creation in the field through our multi-basin decentralized approach. This period of inflationary fuel prices is a primary driver of the 2% increase in our full year per unit cash operating costs versus our previous guidance. However, higher commodity prices also present an opportune time to enhance our workover program, which will be reflected in LOE expense. These additional workovers bring on low cost production that pay out within weeks and increase the long-term performance of our assets. All in all, we’re thoughtfully managing our assets to offset a small effect from inflation. While we have flexibility to adjust our plan in any given year to respond to unique or extreme marketing conditions such as the pandemic in 2020, our capital plan is thoughtfully planned across all our assets to support the pace of operations that is optimal for each individual asset to continue to improve. We believe we have the best people, assets, and plan to mitigate any headwinds and continue to improve the company for the long term. Here’s Ken to discuss the incredible improvements we made in our premium gas play, Dorado.

Ezra Yacob:

Thanks Ken. I’d like to note the following important takeaways from the call today. First, formalizing our cash return strategy demonstrates our commitment to our free cash flow priorities that along with high return discipline reinvestment offers significant long-term shareholder value. Second, EOG is realizing another tremendous year of improvement. We are set to deliver outstanding returns while demonstrating capital discipline within an inflationary environment, delivering on both volumes and capital as announced at the beginning of 2022. Third, our most recent organic exploration announcement Dorado has positioned us with over 20 Tcf of low cost natural gas with access to multiple markets. Our progress in Dorado is on pace to make this North America’s lowest cost of supply. Thanks for listening. Now, we’ll go to Q&A.

Doug Leggate:

Well, thank you. Good morning, everybody. And Ezra I think I speak for everybody in saying we’re delighted to see the framework you’ve introduced for cash returns. I do have a question around this, however, and it is – I’m just curious what’s changed to move you in that direction? And I wonder if I could ask you to – you’re obviously talking about percentage in free cash flow. So I wonder if you could frame some similar parameters around how you think about reinvestment rates or the planning assumptions that go around that so we can get some kind of idea as to what free cash flow ultimately looks like versus the level of spending if you see my point.

Doug Leggate:

I appreciate the answer, Ezra. As I said, we all welcome by what you’ve done. So thank you for that. My follow-up is hopefully a quick one. So some years ago, you guys pivoted away from natural gas, Dorado, obviously, the exception today. But you also took a light off of a lot of your legacy gas assets. The world has obviously changed. So I’m just wondering within the company, is there any effort or I guess, initiative to pivot back to some of those legacies – some of the legacy gas assets that are obviously still in your portfolio in light of what’s going on as it relates to LNG expansion longer-term. I leave it there. Thank you.

Doug Leggate:

[Crushing] (ph) for sure. Thanks for taking my question. Thank you.

Charles Meade:

Good morning, Ezra, and to the whole EOG team there. Ezra, kind of picking up on the point you just made. I’m curious does - I get that you evaluate all your projects at 40 and 2.50, and that services the best oil projects and best gas projects. But is there any concern or discussion inside EOG that maybe evaluating projects that something so far below the strip is actually giving you a suboptimal relative ranking across oil and gas assets?

Charles Meade:

Okay, thank you for that insight. And perhaps going back to Dorado, I caught during the prepared comments that I think that the two-year cum is 80% higher than your 2018 case and part of that is longer laterals. And I think that the base was the kind the 2018 case was 9,000 foot lateral. So is, am I making, am I in the right ballpark to thinking that if 80% higher, two year cum, some of that’s longer laterals, so we’re looking at maybe 40% or 50% higher productivity per lateral foot in the Dorado play versus the earlier case?

Charles Meade:

Yes. But no, you don’t care to offer any comments on the productivity per lateral foot, I guess, and that’s fine. Thank you.

Charles Meade:

Thank you, Ken.

Arun Jayaram:

Yes. Good morning. My first question is just on the supply chain, you guys are holding the line on CapEx. A number of your peers have raised CapEx expectations. So I was wondering if you could comment what’s unique about the way you’re managing the supply chain to give you confidence on delivering the $4.5 billion CapEx budget, and do some of these supply chain headwinds we’re seeing within the industry. How does that influence your thoughts about 2023 given shortages of OFS equipment labor and just broader – just challenges on things like OCTG?

Jeff Leitzell:

Yes, good morning, Arun. This is Jeff Leitzell. So as Billy stated, our ability to counter these inflationary pressures and some of the supply chain constraints that you talked about, it’s really just a huge credit to our team’s operational execution, their innovative culture and really continuing to improve on the efficiencies. So just to give you a little bit of color and some examples, start off with our drilling operations, our teams continue to increase their efficiencies and that’s primarily with EOG’s in-house motor program and our proprietary bit cutter development, which we can kind of design both of these uniquely around all the formations we drill in each of our plays. And our Eagle Ford operations, they’re just a perfect example of this. We’ve increased the drilled footage per day by over 17% this year. And this is one of our more mature plays that we’ve been drilling in for 13 years. So really to EOG, no matter how far along we are in development, there’s always improvements that can be made. And then on the same topic there with the Eagle Ford, they’ve just done an outstanding job of reducing their drilling fluid costs also, even as diesel prices have risen and that’s primary base in those fluids. We’ve done this by optimizing the density and the additives and the drilling fluid in each area, really to try to reduce those fluid losses, which has resulted in a per barrel savings of about 20% so far in 2022. And then just a couple more basic examples in completions, our field team, they continue to see really good improvements there and they’ve increased their overall completed lateral per foot per day by 10% compared to 2021 for the total company. And as we’ve talked about in the past, one of the main drivers in this is really our continued implementation of super zipper operations. So we talked about last year, we were about a third of our activity with super zipper and this year we had a goal of trying to get to 60%. And we’re just about there right now. So this is really significant because pretty much every additional well that we super zipper, we realize the savings of up to $300,000 per well or that equates to about 5% of the total well cost. So another kind of new process on the innovation side that we’ve been implementing and testing is something called continuous frac pumping operations. So just a little bit of a rundown, typically in any completion operations, you have some unplanned maintenance and in order to be proactive, our field teams have started planning some of that scheduled maintenance periods of about three to four hours every three days. And what this has helped us do is really minimize any of that unplanned maintenance and really greatly – increase our overall efficiencies. So in the past quarter, really primarily in the Eagle Ford, we’ve started some testing in the Delaware basin, but we’ve been able to increase our completed lateral per foot per day by roughly 30%. So that’s really just a huge time in cost savings there. And what we plan on doing is we optimize this process, we’ll continue to roll it out to all of our operating areas. And then lastly more on the supply chain and material side of things, I just wanted to touch on a couple of our savings from the water and the sand cost side of things. In the Delaware basin, our team continues to reduce their water costs by optimizing the reuse process, which right now is approximately 90% of all their sourced water. And they’re really doing this just through increasing the automation of all of our infrastructure and reducing the overall treatment cost per barrel, which we realized about a 9% reduction in each barrel of reuse water for 2022. And this is pretty significant, not just for CapEx, but also on the operating expense because every barrel we’re allowed to reuse, is one less that we have to dispose of. And then finally here, over on the sand logistics side, EOG, we’ve been in the sand business in self sourcing for about 15 years now. And we continue to reduce those costs across the company. For example, out in the Delaware basin, we continue to advance our abilities to get that sand closer to the wellhead and ultimately reduce the amount of trucking needed. And plans are, we’re going to open up a second plant in the second half of next year. And we really anticipate to see some pretty good savings from Q1 through the rest of the year of about 20% per pound. So these are just a few of the many examples of how our operations teams just performing and really giving us great confidence that we’ll be able to counter a lot of these inflationary pressures and supply chain constraints through 2022. And as Billy will talk about here 2023.

Arun Jayaram:

Yes, appreciate the detail, Billy. My follow up is – maybe for Ezra or Tim, you guys have now committed to a 60% minimum return of free cash flow kind of framework. I wanted to get your thoughts on the other 40% bucket and what the priorities are between the balance sheet additional cash return and the bolt-ons. I know last quarter, Tim did message EOG’s intention to build more cash on the balance sheet for countercyclical opportunities at other points in the cycle. So I wanted to – if you could give us some updated thoughts on that?

Arun Jayaram:

Great. Thanks, Ezra.

Jeanine Wai:

Hi, good morning, everyone. Thanks for taking our questions. Our first question, maybe if we can just hit back to Dorado, nice update on that. In the slides, you highlight potential export markets. Can you talk about how much midstream capacity EOG has currently or maybe what you see down the line in order to get Dorado gas to those sales points?

Jeanine Wai:

Okay, great. Thank you. And then maybe just following-up on Arun’s question. Ezra, we appreciate all the details you just provided about the cash build up there. And I guess just generally speaking, and I know it’s never the simple about back solving to a cash number, but is net cash or is that like a suboptimal place for the business or would you be perfectly fine with the balance sheet getting to that point? Thank you.

Jeanine Wai:

Thank you.

Leo Mariani:

Hi guys, wanted to follow-up a little bit on the gas macro here, obviously, very topical these days. In the past, I know EOG has spoken about kind of a longer-term oil growth target kind of 8% to 10% per annum. Do you guys feel that at this point in time just giving the changes in the world that U.S. gas is really just going to be higher for longer and you think it would be appropriate to maybe do something similar on the gas side as well. And obviously you kind of talked about the accessibility of your gas to LNG markets down there as well. So just wanted to get a sense if you guys are actively working on perhaps expanding activity over the next few years of Dorado and trying to get that gas international markets.

Lance Terveen:

Yes, Ezra. Yes, Leo, good morning. Maybe just add a little bit more color too, as you think about just LNG and kind of LNG off-take, but I mean the – it’s an exciting time and it’s been excellent having some exposure, especially as you think about our JKM exposure and the first mover advantage that we have, because the pendulum like you’re saying – you’re seeing in the environment today, the pendulum the swinging, you’re seeing more of a demand pool. And so as we think about that, especially from a customer standpoint, I mean we’re very well-positioned. I mean the way we think about it, there’s really three important components of it. And one of them that’s critical is investment grade status and the pristine balance sheet that we have that absolutely puts us and differentiates us. And then as you think about the control that we have with our firm transportation, when we think about LNG off-take, it’s not just from Dorado, but we have firm off-take that can get us from each of our major plays. And then also when you think about supply flexibility too, I mean we have a lot of scale and a lot of flexibility. And so we’re excited about it. Obviously you saw the deal that we’ve done with Cheniere, that’s expanding and increasing our sale that we have there. We feel that that’s very strategic. That helped commercialize Stage 3, which were anticipating hopefully by the end of 2025, I think expected maybe an early 2026. All kind of in line with what we’ve been talking about for a long time. We’ve been working LNG since 2017 and entered into our first agreements in 2019, and then just recently expanded that again. So yes, we definitely have a constructive views. We think about LNG and all those components that I just talked about earlier, we feel puts us very advantage because we can transact quickly and we can move with scale because we have the supply flexibility as well.