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.

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 and 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 reconciliations for these non-GAAP measures can be found on the EOG's website. In addition, 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; Jeff Leitzel, EVP Exploration and Production; Lance Terveen, Senior VP Marketing; and Piers Hammond, VP Investor Relations. Here's Ezra.

Thanks, Tim. Good morning, everyone. Over the past five years, EOG has increased production by 33%, decreased per unit operating costs by 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 are EOG's employees who embrace and embody the EOG culture. 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 which 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 by 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 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 and reduce the break-even oil price necessary 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 EOG's 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, EOG's 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.

Thanks, Ezra. EOG delivered superb operating and financial performance in the third quarter. Oil production increased by 4% year over year, while total production was up 9% year-over-year. Per unit cash operating costs declined by 5% from the prior year period, and the DD&A rate fell by 9% year-over-year driven by the addition of reserves at lower finding costs compared to our production base. Capital expenditures came in at $1.52 billion, $140 million below our target, mostly due to the timing of non-well related expenditures, such as infrastructure projects. Year-to-date, CapEx of $4.5 billion is 75% of the full year guidance. We earned adjusted net income of $3.44 per share in the third quarter and generated free cash flow of $1.5 billion. We announced a $1.50 per share special dividend and during the third quarter we spent $61 million on share repurchases, bringing total 2023 share repurchases through the third quarter to $671 million, at an average price of $108 per share. In total, we're on track to return $4.1 billion of cash to shareholders this year in the form of regular dividends, special dividends, and repurchases. This equates to about 75% of our estimated 2023 free cash flow, higher than our 2023 minimum commitment of 60% of annual free cash flow return to shareholders. Overall, it was a strong quarter driven by solid operational execution and improving capital efficiency. Here's Billy to review operations.

Thanks, Tim. EOG's 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 by 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 are the primary reason we were able to increase the full-year oil guidance by 1,500 barrels of oil per day. Last quarter, we reduced our full-year guidance for total unit cash operating cost, mostly due to lower lease 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 from 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 wells 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 costs over time. This year is shaping up to be another solid performance year 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.

Thanks, Billy. In addition to sharing new well results, I'd like to review a few unique characteristics of our Utica asset that provide distinct advantages, including our low cost of entry, our mineral rights position, held by production status, geologic operating environment, and downstream infrastructure status. This year, we added 25,000 net acres and have now accumulated 430,000 net acres predominantly in the volatile oil window across a 140-mile trend running north to south. Our leasehold cost of entry remains less than $600 per net acre. We've also acquired 100% of the mineral rights across 135,000 acres of our leasehold. Mineral rights significantly enhance the value of this play by adding 25% to our production and reserve streams for no additional well cost or operating expense. Furthermore, over 90% of the Utica acreage is held by production and requires only a handful of wells to be drilled every year to maintain. The result is more control over our development to allow us to invest at an appropriate pace to capture and incorporate technical learnings and continually improve the play. Another unique advantage of the Utica is its geologic operating environment. Due to the play's favorable geologic properties, the opportunity to drive down costs through efficiencies is significant. The target zone is both shallow and consistent, which lends itself easily to drilling 3-mile laterals, and we anticipate testing even longer laterals as we continue to delineate and collect more data. Consistent geology also allows for precise targeting of the very best, most productive rock. We're able to regularly drill 99+ percent in zone within a narrow 10-foot window. As a result, this play provides an excellent geologic environment for significant efficiency improvements and low-cost operations. On Slide 11 of this quarter's investor presentation, we highlighted our strong and consistent well results spanning our acreage position from the north to the south. Our initial 4-well Timberwolf package was drilled at 1,000-foot spacing and has been performing well above type curve. These 3-mile laterals each deliver an initial 30-day production averaging 2,150 barrels of oil equivalent and an 85% liquid cut. With a large amount of liquids in the product mix, all of the wells we have drilled today support double premium potential across our acreage position. The Utica also has the advantage of abundant midstream infrastructure; the existing processing, fractionation, and residue build-out eliminates the need for significant new build commitments, which was a well-recognized advantage when we evaluated the play. In the north, we have placed into service a pipeline running east of our acreage into the market center. In the south, we have an established reliable third party completing a new pipeline expected to be in service late this year. With these trunk lines in place, investments will be limited to in-field gathering as we prepare for a modest increase in activity next year. Our current plans for 2024 are to run approximately one full drilling rig that will continue to test optimal well spacing and improve operational efficiencies. Our Utica asset is another textbook example of our differentiated approach 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 and strong operational execution has positioned the company to create shareholder value through the industry cycles. Here's Lance with a marketing update.

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, including a natural gas treatment facility and the first phase of a 36-inch pipeline. The facility was recently placed in service to treat gas from the Dorado play prior to transportation through our 36-inch natural gas pipeline to sales near Corpus Christi, Texas. Both projects were delivered on time and under budget, a testament to our operational team and foresight to procure 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 region, which provides access to three other pipelines with connectivity to the growing demand along the Gulf Coast and Mexico, as well as 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 Ezra to wrap up.

Thanks, Lance. EOG continues to deliver on our value proposition and our approach remains differentiated for several reasons. First, our premium return standard investments are governed by one of the highest hurdle rates in the industry—30% direct after-tax rate of return using $40 oil and $2.50 natural gas pricing. Second is organic exploration; by prioritizing organic exploration, we add inventory and reserves at lower finding and development costs. Third, our assets are unique. By remaining focused on the first two returns and organic exploration, we have built one of the largest, highest return, lowest cost, and most diverse portfolios of assets in the business. We operate in 16 plays across nine basins and have amassed resources of 10 billion barrels of equivalents with an average finding and development cost of just $5 per barrel. At our current production level, that's equivalent to about 30 years of low-cost, high-margin inventory, and our assets continue to grow. Fourth is technology; we have never considered our operations as a manufacturing process. We leverage both infield technology and information technology to improve well productivity and efficiencies. Our goal is to lower costs and expand our margins to constantly improve our existing assets and new discoveries. Thanks for listening. Now we will go to Q&A.

Thank you. Our first question comes from Scott Hanold of RBC Capital Markets. Please go ahead.

Thanks. Good morning. Congrats on the strong quarter. Ezra, I think it was pretty notable, the way you all took a step up in your fixed dividend payments. I mean, you've got a history of doing that, but it was a good step up this quarter, in addition to boosting the shareholder return program to 70%. So, can you talk about some of the more significant factors like, why make those pretty pronounced moves now? Is there something in the business model that gives you more confidence at this point to make those moves?

Yes, Scott, thanks for the question. The decision to raise the minimum cash return to 70%. Overall, it just demonstrates our commitment to 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, and the strength of our industry-leading balance sheet continues to improve, as does our commitment to being disciplined with our reinvestment across the entire portfolio. So we're in a position now where we feel very confident and proud that we can increase that minimum commitment to 70%. We look forward to being able to deliver that to the shareholders.

So when you look at those breakeven points to do that, sort of this base business, is that breakeven point then lowered from, say, where you were a year or two ago to where it is now?

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. Additionally, we strengthened our 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 factors contribute to our confidence in the base business going forward and the fact that we can continue to increase this minimum cash return to our shareholders from 60% to the 70%.

The next question comes from Leo Mariani of ROTH MKM. Please go ahead.

You guys spoke about sort of similar 2024 activity versus 2023, but also kind of said that there might be a handful of more wells in the Utica and 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? Just trying to get a sense of how maybe costs are trending overall in wells today.

Yes, Leo. This is Billy. Yes, as far as 2024, certainly, it's too early to get into many specifics about the plan. But I would say that our plan will be based on a couple of different factors. One would be the macro environment, kind of what that looks like going into next year. The other one is really governed by the optimum level of activity across each of our plays that supports the objective of having continuous improvement. On that note, for our core plays, say, our foundational plays, the Eagle Ford and the Delaware Basin, we're very pleased with the activity levels we currently have there. We would expect to maintain similar levels of activity in those plays. The advantage of that is we are seeing continued improvement in each of those plays, as we've talked about already on this call. Then, for our emerging plays, the Utica and the Dorado, for instance, we're very pleased with the results we're seeing to date. So as we move into next year, we certainly want to continue that learning, and you may see a few additional wells in those plays on top of what we've done this year. As far as the cost trends go, that's one reason we like to maintain these levels of activity; it allows us to improve our cost basis and operational efficiency. We are seeing the benefits of that play out. So I'll maybe leave it at that and see what your follow-up is.

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.

Yes. Thanks, Leo. No, we're really excited about the latest package that we brought on. That's our Timberwolf package that we highlighted on Slide 11. It's in a 1,000-foot spacing test. Notably, as we've talked about our new completion design in the Permian and the Wolfcamp, we were able to implement that here as well. You can see from the initial results we talked about—the 30-day IPs show that it's averaging 2,150 BOE per day over that 30-day period—so we're very excited about how that's turning out from this spacing test. We have an additional package; we highlighted in our slide deck that we're going to tighten the spacing on to 800 feet, and we should have results coming soon. So we're very excited about those results. In terms of cost, we haven't disclosed specific costs in the Utica yet, as we're still in the early stages, focusing on collecting learnings in this play. However, we feel really confident in supporting that sub-$5 F&D cost.

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

Ezra, I wanted to get your thoughts at a high level on 2024. On the third quarter call of last year, you provided some soft guidance. I was wondering if you could give us some thoughts on overall how you see the year kind of playing out. If I look at consensus forecast, it's for about $6.1 billion of CapEx.

Yes, Arun. This is Billy. Let me try to weigh in on that for you. 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. I'd expect similar levels of activity on our core foundational plays going into next year, which can 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. As for service costs, let me just weigh in a little bit on that while we're talking about it. We certainly understand service costs have moderated in the industry as activity has dropped throughout the year. The magnitude of those declines varies between the services and the basins we're operating in. We remain focused on the continuous improvement we're seeing in efficiency gains across our operations. We tend to use the latest technology in the highest-performing crews, including super-spec rigs and frac fleets; this equipment continues to be in high demand with service pricing remaining resilient. We have seen drops in tubular and casing costs for next year, which will help reduce overall well costs. However, the magnitude of that effect on total well costs is yet to be quantified. But as we go into next year, certainly, we expect to maintain our activity levels in core plays, a few extra wells, and some softening on well costs. Overall, I think that's kind of where we're headed.

Okay. Fair enough. Maybe one for Jeff. Jeff, if you can give some more details. You've provided your Utica type curve on Slide 11. Just wanted to get a sense of is that type curve for the entire play? Is it for the volatile oil window only? And would that be representative of both the northern and southern portions of the play?

Yes, that would just be the general type curve mix across the 140 miles from north to south 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 is going to be built off. The Timberwolf package is the most recent one that we brought on and the outperformance in that one.

The next question comes from Philips Johnston of Capital One Securities. Please go ahead.

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?

Hey, Philip. This is Lance. Yes, what we're seeing is still early, but we're seeing APIs kind of in the 40s to 50s.

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

Yes, good question. To start off, the reason we started off on the east is that we had good quality seismic data there when we were first starting out. That's really important, so you get a good look at the detailed subsurface, and identify any drilling hazards to ensure clean tests. We started the delineation there, have spacing tests in place, and as we start to zero in on that spacing, we will be able to step out more to the west and apply those techniques to further develop that area. We expect to see some variation in productivity, and as you mentioned, we do expect it to get more oil-rich as you move to the west.

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

I'll maybe stick with the Utica. Just my first question, would your AMI on the eastern side of the play limit any thoughts about incremental activity or potential additional acquisitions in that Eastern oil window?

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. Let me highlight again that we own the minerals across 130,000 acres down in the southern portion of the play. When we look at it right now, as Jeff said, we're drilling some initial spacing packages and delineation tests where we currently have seismic. We're also acquiring seismic in a couple of different parts of the play this year to continue stepping out and gather results. As for being limited on incremental activity, we’re not viewing it that way. We've put together a large contiguous acreage position, and the pace of investment is determined by our ability to collect data and integrate production data back into the front-end of our geologic models. The activity is paced to ensure we continue learning and incorporating those learnings on the next set of wells.

Great details, Ezra. Just to follow up, I want to make sure I understand. I want to stick with the Utica. It seems like you have more than ample takeaway if I hear right, on the Southern Utica, but I just want to make sure it was clear for plans for the Northern portion. Bill, I think you were one of the guys just talking about it. Maybe talk about the infrastructure plans and if that would capture any upside if you decided to boost activity in that northern area.

Yes, Neal. This is Lance. What makes this play unique is that it is positioned to existing capacity. In fact, when considering the available processing and fractionation capacity nearby on our acreage, we have been focused on gathering infrastructure. As Jeff mentioned, we placed into service our pipeline in the North, and there's another pipeline in the South as well. We're going to have plenty of long-term running room as we think about the infrastructure that we're building out along with third parties and the existing capacity that's in place.

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

Ezra, I wonder if I could hit first on two things. I want to focus on the cash return change and the evolution of the portfolio. First, on the 70% number, that obviously is subject to whatever the level of capital is. At the end of the day, 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 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?

Yes, Doug, it's a good question. We based our cash return model on free cash flow for a couple of reasons. It's simple but also dynamic, and it's closely related to our intentions across a range of price scenarios. We are not entering an area where we need to modify the commitment going forward. It's something that, once shared, I hope our shareholders can see by our track record that once we set a target, we're consistent with it. The 70% return is a minimum of free cash flow and consistent with our longstanding strategy, which is to build shareholder value and position the company to achieve it through industry cycles. This ensures reinvestment at the right pace in our highest-return inventory, which is the best way to create shareholder value. Ultimately, the cash return strategy begins with our commitment to a growing, sustainable regular dividend, which again, we raised by 10%. That dividend has never been cut or suspended over the 25 years that we've been paying one. In addition, we've now committed to return either additional special dividends or buybacks to reach that 70% minimum commitment. I hope the increased commitment, the reason we like the 70% of free cash flow is that it keeps the emphasis on our regular dividend, which we think is peer-leading and competitive with the S&P 500. We are confident we can maintain current production levels and cover this base dividend at WTI prices as low as $45.

I appreciate the new breakeven number, Ezra. That's very helpful. My follow-up is on portfolio evolution because, I guess, we all know that 10 years is not the number for EOG. But yet your slide deck continues to refer to 10 years of double premium. 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? What I'm really driving at is, our channel checks on midstream suggest 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?

Yes, Doug, I'm not going to speculate on 2026. As Billy said, it's a little bit early to be predicting for 2024. What I would come back to is our disciplined approach to investment. We have a lot of flexibility in the Utica; roughly 90% of the acreage is held by preexisting production and the drilling commitment is minor. So we're in a great position to develop that asset at a disciplined pace, enabling us to increase activity in line with our learnings. Our exploration efforts have yielded high returns, particularly in combo plays or in Dorado's case, a gas play. However, most of our exploration and emphasis is dominantly more oil-focused due to the higher margins we observe in oil. Importantly, with our premium investment hurdle rate at bottom cycle pricing of $40 oil and $2.50 natural gas throughout the asset's life, we're somewhat agnostic to the product mix. That does require a significant effort by Lance to identify new market potentials, and we continue investing in various aspects of the infrastructure and supply chain to lower costs and break-evens.

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

Billy, I'm going to make one more run at the '24 outlook. I think you've laid out that the activity levels are going to be pretty similar to '23. If I look at or if I try to think about the big moving pieces, you're going to have some efficiency gains and capital efficiency gains, especially as some costs come down. On the other side, you have slightly higher base production. So, is it a reasonable stake in the ground to think that you guys can have similar results to '23 in the sense of low single-digit oil growth and kind of low-teens NGL and natural gas growth?

Thanks, Charles. Yes, this is Billy. For '24, we've kind of said it's a little early to get into specifics about things. But I would point you to the fact that we're running at a decent activity level right now, and we're going to maintain a similar level of activity going into next year. Just a reminder, we're spending about $6 billion on our CapEx program this year, which has proved to be fairly consistent throughout each quarter of the year. As for activity levels next year, I would not expect a big ramp up in activity across any play, just small changes in capital efficiency and well costs as we move into next year, coupled with some infrastructure spending.

Got it. Thank you, Billy. And then I'm not sure who this would be best for, but I'm curious about your 3-mile laterals in the Utica. While you seem pleased with the results, you mentioned considering even longer laterals in the Utica. Can you address that point? Additionally, can we expect to see 3-mile laterals in other key plays for you guys? If yes, where? If no, what's special about the Utica that makes it work there and not in other places?

Yes, Charles. This is Billy. Let me give you kind of an overview, and then Jeff may add some more color. We are very excited about the play in Utica and its ability to efficiently implement these longer laterals operationally. We’re drilling them in record times and making steady progress with each pattern of wells we drill. We feel we have a clear path to continue reducing costs over the long term by applying learnings from other plays into this area. However, we are also drilling longer laterals in other plays. We've drilled some 3-mile laterals in the Eagle Ford and are rolling out 3-mile laterals in the Delaware Basin as well. So we expect this trend to persist across our plays moving forward.

Yes, just to add in. In the Delaware, Eagle Ford, and Utica, we’ve had great operational efficiency with our 3-mile laterals. As we stretch out the length of these laterals, it's vital to ensure that operationally we don't encounter issues during drilling and are able to optimally complete them. We've seen strong results and, by drilling these longer laterals, we’re able to supplement one vertical well with a 3-mile lateral instead of using two verticals and a 2-mile lateral. We've realized substantial cost savings, anywhere from about 15% to 25%. We are definitely enthusiastic about our results and are looking to expand this across plays in the upcoming year and beyond.

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

The enhanced completion technique in the Delaware appears to be a success, if I heard correctly, with a 20% uplift in productivity. However, there has been some question regarding its applicability as you've discussed in the past. What's your latest thinking on how widely applicable the technique is across the play, and will there be an increase in the number of wells completed using this technique next year?

Yes, Scott. No major updates this quarter, particularly in the Permian with the Wolfcamp, but we're still seeing outstanding results with consistent 20% uplift in first-year production in EOR. The focus is shifting to test shallower targets in the Permian; we hope to bring those online towards the end of this year and into early next year. Once we have those results, we’ll share those findings. We are testing in the Powder River Basin and have a test in progress that we're currently evaluating. In the Utica, we're applying that completion design across all our new designs, and we're very pleased with the resulting performance. We're in the phase of data collection to see the specific formations we achieve success with moving forward.

Got it. Additionally, regarding the South Texas pipeline, does the completion of Phase 2 of the pipeline next year influence how you think about the cadence of activity in Dorado? Are you considering adding rigs in the play later in '24 to prepare for stronger growth once the pipeline is complete?

Yes, Scott. This is Billy. We’re excited about Phase 2 of that project. Getting that pipeline operational will provide access to multiple markets in that basin.However, the pace of activity in Dorado is really driven by our learnings and results more than the pipeline schedule. Certainly, we’re enthusiastic about the pipeline as it will allow us to save $0.20 or $0.30 in MCF over the life of those reserves, which amounts to 21 TCF of reserves. The pace of activity is driven by the macro environment and our learnings in progressing the play rather than pipeline completion.

And this is Lance as well. Some of the other strategic improvements in mind for Phase 2 will enable existing market access with our offtake agreements in place, including one with Cheniere and another with Transco that will link us to premium markets. We’re excited about the momentum we've built and the strategic implications that have for us going forward.

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

I have two questions regarding topics that haven't yet been covered. First question: I wanted to focus on your CCS pilot. With a year of experience from the pilot, I wonder if you could discuss some of the learnings thus far and the applicability of the pilot to your larger operations as a means to achieve net zero.

Yes, Derrick, this is Billy. We're very excited about the CCS pilot project and all we’ve learned—both operationally and technically—as we advance with the play. We've learned a lot regarding how we sequester CO2, how we store it, our pipeline infrastructure, and the needed equipment. Additionally, our comprehensive understanding of geological areas for storing carbon lets us map those zones accurately. We've also been monitoring underground movement, substantiating our confidence that we can store that CO2 sustainably for extended periods. So we're seeing good results, and we are optimistic about these opportunities going forward.

Great. Moreover, I wanted to discuss your shallow water exploration schedule. With offshore drilling rig rates nearing historic levels and industry messaging indicating sustained strength, how does that impact your timeline for exploration wells and, more importantly, development activities, assuming exploration success?

Yes, Derrick. This is Billy again. Certainly, for offshore, as you noted, rig utilization is pretty tight, and the market remains competitive. However, we're very pleased with our ongoing activity in Trinidad. We’ve been engaged in Trinidad for over 30 years and currently see one of our longest-running programs in the history of that play. We've secured a rig for that operation and are happy with the results we've seen. As for future exploration activities, we’re still interested in uncovering opportunities for shallow water offshore due to our expertise and ability to drill efficiently and competitively. Those opportunities will factor into the current offshore rig environment and need to be competitive with our existing portfolio investments.

The next question comes from Nitin Kumar of Mizuho. Please go ahead.

Why don't we revisit the Delaware for a moment? As I look at your slides, you were doing two things this year: increasing your Wolfcamp oil mix in the drilling schedule and enhancing the techniques. Could you break out the improvement you're observing between the mix and then the new technologies?

Yes, this is Jeff. Our technical teams are doing an outstanding job of enhancing our understanding of the subsurface geology and geologic models, significantly increasing the value of each of our development units by maximizing the overall NPV. Our wells are performing outstandingly, with marked improvement year-over-year. Specifically, the Wolfcamp has led the way due to the new completion design. We have a large acreage footprint of over 400,000 acres and a high number of unique targets based on the distinct geology across different areas. Thus, when you analyze individual well results or even rolled-up performance across the play, you might see variations in productivity and performance. Nonetheless, we're very satisfied with all the results and meeting our expectations; everything has been factored into our forecasts.

Great. The reason I'm asking is one of your peers in the play mentioned improving recovery rates—not just optimizing wells, but enhancing recovery rates with technology, boasting about 20% gains. Given your experience in shale and your strong track record, I'm curious if you've seen technologies that could help increase that recovery factor, not just optimize wells but create a step change in what you're extracting from the rock.

Yes, Nitin. This is Billy again. We're constantly seeking to enhance long-term recovery across all our plays—it goes back to the foundation of our company and has been a historical focus. We leverage various technologies to improve how we engage with the plays and complete each well. This encompasses examining the frac design itself, changing aspects such as the type of sand pumped, spacing of perforations, and how we target reservoirs by analyzing geological data. These innovations have led to significant production improvements, serving as a proxy for increasing the recovery factor over time. The advancements we've seen in our Wolfcamp play serve as a recent example, showcasing a consistent 20% uplift in production performance due to our completion strategies. All these factors contribute to enhancing our overall recovery factor.

The next question comes from Josh Silverstein of UBS. Please go ahead.

Regarding the updated 70% shareholder return level, how are you contemplating excess free cash flow beyond this? Will you look to increase the exploration budget, or, theoretically, could you increase shareholder returns to 90%? Any insights here would be valuable, considering the growing cash balance next year without any maturity until 2025.

Yes, Josh. This is Ezra. Ultimately, the 70% is a minimum hurdle. Over the last couple of years since we introduced our initial cash return guidance, the initial minimum was 60%. In 2022, we reached 67%, and this year we’re on track to exceed 70%, likely approaching 75%. This is how you should evaluate our guidance. The significant aspect of our free cash flow commitment is that it’s a baseline of 70%. However, it centers on our regular dividend, which we consider the best indicator of ongoing company performance and improved capital efficiency going forward. We are backstopped by a pristine balance sheet. When we raised it by 10%, the basis was assessing what it takes for breakeven. We've articulated that we can sustain the $2.1 billion regular dividend commitment at various maintenance CapEx scenarios, particularly at the higher end alongside $45 WTI prices. Our maintenance capital range spans $4.2 billion to $4.8 billion, with a midpoint of approximately $4.5 billion.

Got it. Lastly, regarding your portfolio, how are you considering any long cycle or conventional opportunities like Trinidad in light of potential growth for unconventional projects?

Yes, Josh. This is Billy. Let me provide a bit of insight into what we are evaluating. We have a robust portfolio of unconventional plays actively in development; however, our exploration program consistently searches for all competitive opportunities. These may include conventional or unconventional projects, offshore or onshore, U.S. or beyond. We consider all types that can generate solid returns compared to what we invest in now.

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

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 by 10%. We’re confident in the sustainability of our regular dividend due to the consistent execution of our value proposition, which improves the company year after year. EOG is in a better position than ever to deliver value for our shareholders through industry cycles and to play a leading role in the long-term future of energy. Thank you.

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