Earnings Call Transcript - EOG Q2 2023

Operator, 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.

Tim Driggers, CFO

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.

Ezra Yacob, CEO

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 earned $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%. EOG's peer-leading regular dividend is currently the majority of the $3.1 billion of cash returned 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. We continue to get better through relentless execution of and commitment to EOG's value proposition. We invest in high return projects across our multi-basin portfolio, adding lower cost 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 and 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. 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 draws 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. It appears OPEC+ is following through on announced 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. We are especially pleased with Dorado's place in the market, as one of the lowest cost supplies of natural gas in the U.S. with an advantageous location and emissions profile. EOG's value proposition is delivering results, and the strength of our business has never been better to deliver value for 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.

Tim Driggers, CFO

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 costs 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.

Billy Helms, President and COO

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 met 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 costs. 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, 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 multiple functions. Across every operating area, our frontline engineers and geologists work with that technology every day to lower costs 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 in 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. Capital expenditure for the first half is also running light, due primarily to the infrastructure spending 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 is right on track. The rate of change for inflation this year is consistent with what we'd anticipated at the start of the year. So we still see line of sight to limit year-over-year well cost inflation in 2023 to just 10%. While any additional softening of service cost 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 forecasted to deliver 3% 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.

Ken Boedeker, EVP, Exploration and Production

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 is 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, 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 to make 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.

Ezra Yacob, CEO

Thanks, Ken. Our second quarter results demonstrate once again that EOG's 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, Operator

Our first question comes from Paul Cheng of Scotiabank. Paul, please go ahead.

Paul Cheng, Analyst

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

Ezra Yacob, CEO

Yes, sir. Paul, go ahead, please.

Paul Cheng, Analyst

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, whether we should read the second consecutive quarter of the buyback means that management now sees 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 wells 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.

Ezra Yacob, CEO

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. 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% can be supported over a range of price scenarios, especially when there's a pullback in prices. We can underpin that with the growing sustainable regular dividend that we highlight and talk about so much. Again, I 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 as 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 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. The percent will fluctuate depending on a specific moment in 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 that 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. As for the Dorado timing, I'll hand it over to Billy.

Billy Helms, President and COO

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. We've given some color on that in our new investor deck illustrating the improvements in drilling times there in that place. We're very pleased with that progress. Don't forget, our investment strategy includes a gas price of investing for $2.50. That's our premium price deck in relation to gas prices. We were certainly 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 delaying some of those completions as we go into late this year, which pushes five wells into next year. So that's simply the thinking on that.

Operator, Operator

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

Neal Dingmann, Analyst

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 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 focused on that Wolfcamp oil. So I'm just wondering what is driving that; it does look very positive.

Ezra Yacob, CEO

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

Jeff Leitzell, EVP, Exploration and Production

Hi, Neal. 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 are performing right now as forecasted or better. 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 regarding 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. 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. 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.

Neal Dingmann, Analyst

It's very helpful. My second question is about OFS costs. In the past, you have excelled not just in renegotiating contracts, but also in effectively stockpiling at the right time and similar practices. Could you provide some details on how you view the current market?

Billy Helms, President and COO

Yes, Neal. This is Billy. So certainly, we're seeing the service prices start to soften. However, these savings from lower service costs probably won't manifest into lower well costs until later this year and certainly into 2024. These leading-edge prices are falling across various products and services for the industry, and it certainly varies depending on the product in the area. I'd add that several factors reflect where our '23 capital program is. As a company, as you mentioned, we focused on sustainable cost reductions through our operational efficiency gains. As a result, we seek out the highest performing equipment in crews, super-spec rigs, electric frac fleets, etc. That's really less exposed to some of these headline inflation numbers that we're seeing on more marginal equipment on the spot market. The second part of that is we anticipated 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 try to secure about 50% of our well costs at the start of any given year, which helps insulate us from inflationary impacts on our activity levels. Lastly, based on how we manage our business, we are less exposed to the volatility in service costs in any given year. And I would remind you, our well costs really only increased about 7% last year compared to the over 20% inflation that we saw in the market. Yes, it really helps us manage our activity level with confidence as we go through the year. We'll certainly remain flexible as we look into next year to see how we can position ourselves for next year.

Operator, Operator

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

Arun Jayaram, Analyst

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. I just wanted to get some thoughts to hit if there's still confidence in hitting the midpoint of the oil guidance range because that would imply a 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?

Billy Helms, President and COO

Yes, Arun, this is Billy. 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. The timing of the quarter-to-quarter variance in production is driven by the timing on a quarter-to-quarter basis of how these packages across different plays come online. How that varies month-to-month within the quarter can also drive the volume profile. 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 are maintaining ratable activity throughout the year. Just as a matter of timing on bringing on some of these larger packages. 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.

Arun Jayaram, Analyst

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 have pulled your TIL guidance down a little bit this year, but just an update would be helpful.

Lance Terveen, Senior VP, Marketing

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

Ken Boedeker, EVP, Exploration and Production

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. The wells we drilled and completed in 2022 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.

Operator, Operator

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

Doug Leggate, Analyst

Thanks. Good morning, everyone. Ezra, it's been 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 or five years with OPEC. But in your opening remarks, you did talk about Saudi's decision to support the price or extend 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 what you could call windfall cash flow because it's not 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.

Ezra Yacob, CEO

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 entering this year. As those have started to come down, indications are they’re going to come down significantly faster because OPEC Plus appears to be supporting their cuts to bring those inventory levels down. Your point is interesting, and we discuss it regularly. We do different scenarios around this. In general, this year, our focus is whether it's crude products, gasoline, distillates, either globally or domestically, inventory levels are in the lower half of a five-year range. That being said, it's a choppy five years because of 2020 with COVID and half of the year being exceptionally low, while the other half was somewhat artificially higher with the SPR. Outside of the last month, we've seen gasoline and distillate demand be just a bit weaker domestically. Crude demand has continued to increase. Notably, supply has surprised everyone a little bit to the upside. It’s not necessarily U.S. growth or new barrels, but historically displaced barrels are coming back online. We're particularly observing Venezuela and Iran, and maybe a little bit of the resiliency of the Russian barrels hitting the market has surprised most. We don’t expect them to have a significant longer-term effect. One thing we consider when we talk about spare capacity offline with OPEC Plus is how some of that spare capacity offsets the previous spare capacity I just highlighted with Venezuela and Iran, making it look different than in prior years. Overall, we see increasing oil demand exiting this year, putting us at a significantly high point. To your ultimate question on how we look at this internally, we evaluate the macro environment regarding supply/demand fundamentals, including spare capacity that's offline due to political choices. More importantly, we assess the correct investment level for our premium assets individually and collectively to improve metrics year-over-year. This drives optimized returns and free cash flow generation, which will contribute to shareholder value now and in the future. Growth ultimately results from our ability to invest and continue lowering the company’s cost basis.

Doug Leggate, Analyst

An interesting dilemma. Thank you for your perspectives on that. I have a quick follow-up that I hope will be brief. I wanted to revisit a point that was raised earlier and elaborate a bit. You mentioned that inflation is expected to be limited to 10% this year, but it's too early to discuss 2024. You're almost the last company to report earnings this quarter, and nearly everyone else has indicated that we will see some deflation in 2024. I'm just curious if you're being cautious, or do you truly believe there remains an upside risk to capital in 2024 due to inflation?

Billy Helms, President and COO

No, Doug, I don’t think we are anticipating inflation into next year. The comment about the 10% inflation was based on the fact that we saw inflation last year coming into the business. Rig counts kind of peaked in November of last year, and we anticipated seeing deflation in the market going into this year. We built our plan based on the assumption that well costs in 2023 would increase no more than 10% relative to 2022. Acknowledging you are correct that we’re seeing deflation in our business, it’s too early to predict what that level of deflation will do to our well costs next year. There are still many dynamic market aspects that could affect this. It’s early days to make predictions regarding our capital program and how we choose to develop our plays across the various assets.

Operator, Operator

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

Leo Mariani, Analyst

Yes, good morning. Just wanted to touch base on some of the emerging plays, really thinking about kind of Utica and PRB. 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.

Ezra Yacob, CEO

Yes, Leo, this is Ezra. We continue to see very limited competition domestically on exploration. You can kind of see that in public comments made. Most operators, whether private or public, have kind of picked a basin and are honing in on a drill-down specialist manufacturing mode. We continue to explore. As Ken mentioned, we're looking to put on low-cost, high-quality bolt-on opportunities in some of those plays. In terms of Utica and PRB, it's a little early this year. We're pleased with our operations side, and as Ken stated, we will get a completion spread in there shortly. On the PRB, we’ve had a very strong year, and everything has aligned. The Dorado and PRB are benefiting from more of a continuous operations program this year as we focus on Austin Chalk, co-development in Eagle Ford and Dorado, and then our core focus is in the Mowry in the Southern PRB.

Leo Mariani, Analyst

Okay. Appreciate that. I 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, right on where you expected. Looking at guidance, third quarter CapEx is up a fair bit versus second quarter. So do we expect to see a commensurate drop in 4Q capital to get you back to that midpoint on the full year? Just trying to get a sense of CapEx cadence in the second half?

Billy Helms, President and COO

Yes, Leo, this is Billy. Regarding CapEx, our drilling and completion activity has been very ratable throughout the year. We're pretty much on track with our plan. The reason third quarter is up is simply due to the timing of our non-drilling and completion capital, which has moved from the second quarter into the second half of the year. All of our drilling and completion CapEx is on pace with what we laid out. We've spent about half the CapEx for the year and have completed about half the wells that we're planning for the year. Everything is pretty much on track. Fourth quarter will reflect how that non-D&C spending is completed in the third quarter.

Operator, Operator

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

Scott Gruber, Analyst

Thanks. And good morning. I'll just go ahead and ask two questions up front here since they're related. You guys continue to achieve efficiency gains in 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. If so, without adding rigs and frac crews next year, just curious how much the overall well count could potentially grow next year just based on those efficiency gains? Is that a kind of low single-digit type figure potentially or mid-single-digit figure?

Billy Helms, President and COO

Yes, Scott, this is Billy. We're seeing continued improvements, although, as you noted, at a lesser pace than our longer-term foundational plays like Delaware Basin and Eagle Ford, simply because we've actively worked those for a long time. The emerging plays benefit from technology transfer quickly. We still experiment with technology across all of our assets, especially true for foundational plays. Our data systems are providing insights on how things are performing, from drilling tools to drilling motors. We still see improvements in drilling times and completed lateral feet per day, which is encouraging because that technology transfer enables us to continue lowering costs. How that translates into next year is still a bit early to see how this will play out given market conditions. However, I'm optimistic about the efficiency gains going forward.

Operator, Operator

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

Derrick Whitfield, Analyst

Good morning, all. For my first question, I wanted to focus on long lateral development, which has been seen throughout Q2 and is being highlighted in the Eagle Ford with an over 15,000-foot lateral this quarter. As it relates to the Eagle Ford and possibly 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?

Ken Boedeker, EVP, Exploration and Production

Yes, Derrick, this is Ken. Longer laterals are a way we're increasing our capital efficiency in the Eagle Ford. We've drilled over 85 wells with laterals over 2.5 miles long across the Eagle Ford. We've utilized these longer laterals over the past five-plus years where appropriate. 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 capital efficiency. These longer laterals have contributed to us lowering our cost basis in the Eagle Ford and demonstrate our focus on increasing efficiencies even in that play where we've been developing it for over ten years.

Billy Helms, President and COO

Yes, Derrick, this is Billy. The lessons we're learning from our longer laterals, we're pushing in the Eagle Ford, and we're leveraging those opportunities across every asset we have.

Operator, Operator

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

Neil Mehta, Analyst

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?

Ken Boedeker, EVP, Exploration and Production

Yes, Neil, this is Ken. As for how that's tracking, the five wells that we've deferred, we see the timing to complete those early in next year. It's still early in the play, and the wells in our core area are performing as we anticipated.

Neil Mehta, Analyst

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? Is the best strategy, given the exploration program that we've discussed here, to continue to grow the business organically? Or do you think there will be opportunities to bolt-on?

Ezra Yacob, CEO

Yes, Neal, this is Ezra. We have been 30 years strong as an organic exploration company, separated over 20 years. The way we look at deals is that it’s similar to how I described every investment decision; it’s ultimately about return. Is that investment going to create long-term shareholder value? We do not see M&A versus exploration in dichotomy terms. Being a first mover, capturing the sweet spots of new plays could provide a lower cost of entry and higher return. So, I believe organic exploration stands on its own. Regarding M&A, we assess opportunities. However, the challenge remains whether an opportunity is truly additive to our corporate portfolio and whether it offers better returns than our current drilling. We evaluate these opportunities but often conclude that they do not add significant value to our portfolio.

Operator, Operator

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

Roger Read, Analyst

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 into a little more depth on specifically what you see there. 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? If that's not the right way to look at it, I'd be curious what you are seeing that indicates deflation is the right track here.

Ken Boedeker, EVP, Exploration and Production

Yes, Roger, this is Ken. I'll go ahead and answer the first part concerning Dorado. 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 the proximity of that gas to the Gulf Coast markets.

Billy Helms, President and COO

Yes, Roger, this is Billy. On the inflation question, you raise a valid point. I think that's why we're seeing deflation in the market today, but it's too early to think about 2024. The market dynamics that play are still very volatile. As a company, we’re well positioned to leverage any new opportunities that arise. Our focus on contracting and seeking the highest-performing crews drives our long-term sustainable cost improvements and represents our strengths in capturing a premium for all our products.

Operator, Operator

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

Ezra Yacob, CEO

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

Operator, Operator

Thank you for joining. This concludes today's call. You may now disconnect your lines.