EOG - NYSE

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.

Thank you. Good morning and thanks for joining us. This conference call includes forward-looking statements. Factors that could cause our actual results to differ materially from those in our forward-looking statements have been outlined in the earnings release and EOG’s SEC filings. This conference call also contains certain non-GAAP financial measures. Definitions and reconciliation schedules for these non-GAAP measures can be found on EOG’s website. Some of the reserve estimates on this conference call may include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC’s reserve reporting guidelines. Participating on the call this morning are Ezra Yacob, Chairman and CEO; Billy Helms, President and Chief Operating Officer; Ken Boedeker, EVP, Exploration and Production; Jeff Leitzell, EVP, Exploration and Production; Lance Terveen, Senior VP, Marketing; and David Streit, VP, Investor Relations and Finance. Here is Ezra.

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.

Thanks, Ezra. EOG delivered excellent operating and financial performance in all areas in the second quarter. Oil production increased 3% year-over-year while total production increased 5%. Per unit cash operating costs remained essentially flat from the prior year period despite industry wide inflation. Compared to the first quarter, however, per unit cash operating costs declined by 5% and were lower in all four categories. We're beginning to see the benefits of lower cost improve our operating margin. The DD&A rate fell by 10% year-over-year driven by the addition of reserves at lower finding costs compared to our production base. Capital expenditures came in at $1.5 billion $130 million below our target and just slightly above the first quarter level. The difference was mostly due to the timing of non-well related costs such as infrastructure projects. Year-to-date CapEx of $3 billion is 50% of the full year budget. The improving capital efficiency of our assets, consistent operational execution, along with the application of innovation and technology to lower costs is making a big impact on the financial performance of the company. We earned adjusted net income of $2.49 per share in the second quarter, and generated free cash flow of $1 billion. Return on capital employed for the last 12 months is 29% at an average WTI oil price of $81 and Henry Hub natural gas price of about $5. Here's Billy to review operations.

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.

Thanks, Billy. We're continuing to make outstanding progress on our emissions goals. As a preview to our 2022 sustainability report that will be published in September, we are excited to announce that we've reached three significant near term goals well ahead of schedule. First, our 2022 GHG intensity rate of 13.3 metric tons of CO2e per Mboe as less than our 2025 goal of 13.5. Second, our 2022 methane emissions percentage is 0.04% of our natural gas produced and is significantly less than our 2025 goal of 0.06%. And third, we have achieved our zero routine flaring goal in 2023, well ahead of our 2025 target, and significantly ahead of the World Bank initiative, which strives to attain zero routine flaring by 2030. We have also confirmed that our wellhead gas capture rate for 2022 was 99.9% of the gas produced. We continue to expand our in-house continuous methane monitoring technology named iSense and finished 2022 with 95% of our production in the Delaware Basin covered by iSense monitoring. As a reminder, the power of iSense is incorporating continuous methane monitoring data with our production and facilities data and monitoring this data on a 24-hour basis in one of our four control centers. This enhances our ability to identify potential leaks, and prioritize repairs that are needed in the field to minimize fugitive emissions. As with a number of EOG operations, it is anticipated that collection and integration of iSense data will lead to continuous improvement in facilities and production design and operations. We're excited about the progress we've made in the last several years on our emissions performance and are very proud that we have such dedicated employees who are continuing making our operations more efficient. Their innovative solutions and push to beat expectations have driven us to exceed our goals early. We are currently assessing new goals with our operations groups and anticipate publicizing those goals in the first half of 2024. Now, here's Ezra, to wrap up.

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

[Operator Instructions] Our first question comes from Paul Cheng of Scotiabank. Paul, please go ahead.

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

Yes, sir. Paul, go ahead, please.

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.

Sure, Paul. This is Ezra. I think I'll take that first question and then Billy can address the second question regarding Dorado. So yes, on the first one, it's kind of a broad question on our cash return strategy. So hopefully, I hit on all the points that you're trying to get at. But first, let's start with our guidance, which has always been the minimum of 60% of free cash flow. So we've never guided to that 60% as being a specific target, it's always been a minimum of 60% of our free cash flow. The reason we like that guide is, honestly, it's pretty simple and dynamic, it's easy to understand and communicate. The minimum of 60% is -- it can be supported over a range of price scenarios, especially when there's a pullback in prices. And really, we can underpin that with the growing sustainable regular dividend that we highlight and talk about so much. And that's what can provide really a meaningful amount of cash return through the cycle. Again, I do want to emphasize, we consider that regular dividend to still be the true hallmark of a strong and improving underlying business, and we like the message that it sends. We increased that regular dividend commensurate with the strength of the business, lowering the cost basis of the company, and also in consideration with strengthening our balance sheet. More specifically to kind of payouts that you've seen this year, we do recognize the value of opportunistic buybacks as part of that cash return strategy is a way to create shareholder value. So I would say that really, the decision that you've seen is consistent with our overall capital allocation strategy where we buy back shares in an opportunistic manner as a means to return cash above and beyond that minimum of 60%, in addition, to our regular dividend and at times, instead of paying a special dividend. We basically evaluate that buyback, just like we do any of our other investment decisions, whether it's exploration or drilling high-return oil and gas wells or investing in infrastructure. It's how is that investment going to create long-term shareholder value. That's what we primarily focus on. And so the percent will fluctuate depending on a specific moment and time and what the circumstances are around our cash return strategy. But what we have guided to and what you can bank on is it's the minimum of 60% now. We highlighted -- we paid 67% out last year, and we're very well positioned halfway through the year right now where we've already committed or paid 67%, as I highlighted in the script. And all -- for the Dorado timing, I'll hand it over to Billy.

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.

Our next question comes from Neal Dingmann of Truist. Neal, the line is yours.

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.

Thank you, Neil. This is Ezra. I'm actually going to let Jeff Leitzell step in and address your question.

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.

It's very helpful. And then -- and sorry about that. My second question is just on OFS costs. In the past, you all have been among the best not only just what I would say renegotiating contracts, but I know in the past, you've been able to stockpile type at the right time and all those sort of things. I'm just wondering if maybe give us a little bit of details on how you see the market now?

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.

Our next question comes from Arun Jayaram of JPMorgan. Arun the line is yours.

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?

Yes, Arun, this is Billy. Yes, I think the thing to keep in mind is we do operate in more than one basin and multiple plays, and we have varying sizes of well packages in each play. So the timing of really the quarter-to-quarter variance in production is really driven by the timing on a quarter-to-quarter basis of how these packages across different plays come online. And even within the quarter, how that varies month-to-month within the quarter can vary -- can drive the volume profile. And I would remind you, and I just ask you to go back and look at the change from the first quarter to the second quarter, it's actually larger than what you're seeing in the forecast from the third quarter to the fourth quarter. So we would -- we are maintaining ratable activity throughout the year and just as a matter of simply timing on bringing on some of these larger packages. So, so far this year, we've either met or exceeded our volume forecast and have complete confidence in being able to meet the midpoint of our guidance.

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.

Arun, good morning. This is Lance. Yes, I would say what we're most focused on right now is just getting all the midstream infrastructure in place. So we do have two ongoing projects that are going on. We've got 1 in the north and then another one in the South as well. So what we're really focused on is linking our production to the available processing capacity. And really, what's happening is it's a consistent strategy that we've done and all are plays, where we're going to have a balance of EOG-owned infrastructure along with strong relationships with really good working third parties. We're going to need both in the Utica Combo up there. And so right now, just focused on setting up 2024 and beyond with the infrastructure.

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.

Our next question comes from Doug Leggate of Bank of America. Doug, the line is yours.

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.

Good morning, Doug, Thanks for the question. This is Ezra. Yes, it's a dynamic environment. We had a large SPR release last year that increased the inventory levels kind of entering this year. And as those have started to come down, now they're going to start all indications that they're going to start coming down significantly faster because OPEC Plus, as I said, it looks like they are going to support their cuts to kind of bring those inventory levels down. So your point is, it's a very interesting one, and it's one we discuss regularly, obviously, and we do different scenarios around. So in general, what I'd say is, on this year, what we look at is whether it's crude products, gasoline, distillates, either globally or domestically, inventory levels are basically in the lower half of a five-year range. Now that's a choppy five years, like we said, because of 2020 with COVID and then, of course, with 2020 with half of the year being exceptionally low and then half of the year being somewhat artificially higher with the SPR. Outside of the last month, the last month, we've seen kind of gasoline and distillate demand being just a bit weaker domestically. But otherwise, products demand has really been in line all year with our expectations. Crude demand, has continued to increase, continue to grow. And not only with the high inventory levels that we entered the year with, but really supply, I think, has surprised everybody a little bit to the upside. And it's not necessarily, as you pointed out, U.S. growth or new barrels, but it's really historically displaced barrels that are back online. And dominantly, what I'm talking about is Venezuela and Iran, and maybe a little bit of -- I think everyone has been a little bit surprised at least we have on the resiliency of the Russian barrels to hit the market. So we don't forecast those as having a significant longer-term effect. And one thing that we think about when we talk about the spare capacity that's now offline with OPEC Plus is some of that spare capacity is really offsetting the previous spare capacity I just highlighted from Venezuela and Iran. So it is a little bit different from prior years. Ultimately, what we see is the increasing oil demand overall exiting this year, most estimates have it at least at 102 to exit the year, which would put us at a significantly high point. Now to your ultimate question on how we actually look at that internally, our planning begins with everything we just talked about kind of an evaluation of the macro environment with respect to supply and demand fundamentals, including spare capacity that's off-line just by choice and spare capacity that's offline for true geopolitical reasons. But then more than that, Doug, it really does come down to evaluating across all of our premium assets both individually and collectively, we evaluate the correct investment level for each of those, the activity levels to make sure that each asset will deliver improved metrics year-over-year. And ultimately, that will be driving optimized returns and free cash flow generation at the corporate level, and that's what will continue to set up EOG to create shareholder value in the near and long term. Honestly, the growth ends up being a real output of our ability to invest and continue to lower the cost basis of the company and provide both near-term and future free cash flow generation.

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.

No, Doug, I don't think we are anticipating that you'll see inflation into next year. I think what the comment was when we started out the year let me just clarify something. We saw inflation last year coming in the business. Rig counts kind of peaked in November of last year. We anticipated we would see a deflation in the market going into this year. And so we built our plan based on the fact that our well cost in 2023 would increase no more than 10% relative to 2022. So that's where the 10% comment comes from. As we go into '24, I think we recognize and clearly, we're seeing deflation in our business. I'd say it's too early to predict what that level of deflation is going to do to our well cost next year. There's still a lot of market dynamics that we see in the business as Ezra just went through. And so it's early to predict what that impact that's going to have on next year's capital program as well as kind of how we choose to develop our plays across the different plays that we have to invest in. So that's the comment about too early for next year. It's just too early with the market dynamics we have for next year.

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

Yes, good morning. Just wanted to kind of touch base on some of the emerging plays, really thinking about kind of Utica and PRB. And also some of the undisclosed exploratory plays out there as well. Just trying to get a sense if generally speaking, you've seen any increased competition in these plays during the course of 2023. I mean it still seems like EOG being a bit of a lone wolf in pursuing some of these plays where others maybe aren't doing as much, but maybe there's more kind of going on behind the scenes that you guys can help out with here.

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.

Okay. Appreciate that. Just wanted to turn to CapEx for a minute here. You talked about this a little bit in your prepared comments, but you guys are kind of at 50% of the budget in the first half kind of right on where you expected here. Looking at guidance, third quarter CapEx is up a fair bit versus second quarter. So do we expect to see kind of a commensurate drop in 4Q capital to kind of get you back to that kind of midpoint on the full year? Just trying to get a sense of kind of CapEx cadence in the second half?

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.

Our next question comes from Scott Gruber of Citigroup. Scott, the line is yours.

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?

Yes, Scott, this is Billy. We're still seeing continued improvements, although as you noted, at a lesser pace than our more active foundational plays like the Delaware Basin and the Eagle Ford, simply because we've been active there for a long period of time. And as you noted, the emerging plays benefit from that transfer of technology more rapidly, I guess, than some of the existing plays. And really, I'd just like to tie that back in a little bit. We still experiment quite a bit with applying technology across all of our assets and especially true of our foundational plays, the efforts we've gone to, to put in our data systems and track data across our plays gives us a lot of insights on how to -- how things are performing. That goes back to our bringing in-house our drilling tools, our drilling motors, those kind of things. So we still see improvements in some of our supplemental deck in the back, you can see some of the increase in drilling times say, in our Permian program, and how that's improved over time, and we continue to drive that down. And so that's an effort there. And then the same for the Eagle Ford, I think those are some of the spots in the back of our deck. So we're still seeing improvements in both the drilling times and the completed lateral feet per day, and we're very encouraged with that because that enables the technology transfer enables quickly to go to the emerging plays and continue to reduce our cost. How that translates into next year. Again, I'd say we're still a little bit early to see how things are going to play out on the macro side, depending on what the market looks like. So it's early to see, but I'm encouraged with the efficiency gains that we're seeing that we'll continue to find sustainable ways to improve our business and lower our cost basis going forward.

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

Good morning, all. For my first question, I wanted to focus on long lateral development, which has been seen throughout Q2 and its development you're highlighting in the Eagle Ford with an over 15,000-foot lateral this quarter. As it relates to the Eagle Ford and perhaps more broadly for your portfolio, are there considerations beyond lease geometry and legacy development that would limit your ability to pursue more 15,000-foot laterals?

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.

Yes, Derrick, this is Billy. I just might add, the lessons we're learning from our longer laterals, we're pushing in the Eagle Ford, we're applying across all of our portfolio. And so we're seeing those opportunities across every asset that we have.

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

Thanks very much. The first question is just around Dorado. Maybe you could talk about how that's tracking versus your target. How do you think about the timing of recompleting those Dorado wells?

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.

Timing dynamic. And then would love your perspective stepping back to talk about the M&A market. We've seen a pickup in consolidation throughout U.S. shale. How do you think of EOG's role in future consolidation? And is the best strategy given the exploration program that we've been talking about here is to continue organically to grow the business? Or do you think there are going to be opportunities [indiscernible] to bolt-on?

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.

Our next question comes from Roger Read of Wells Fargo. Roger please go ahead.

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.

Yes, Roger, this is Ken. I'll go ahead and answer the first part of that with Dorado. We're really confident that our gas production at Dorado generates significant returns and that development will be both operationally efficient and have a small emissions footprint because of the dry nature of the gas and really the proximity of that gas to the Gulf Coast markets.

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.

We have no further questions on the phone line. So I'll hand back to Mr. 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.