EOG - NYSE

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

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

Thanks, Billy. In addition to sharing new well results, I'd like to review a few unique characteristics of our Utica asset to 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 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 in 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 place favorable geologic properties, the opportunity to drive down cost 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 plus 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 result to span our acreage position from the north and to the south. Our initial 4-well Timberwolf package was drilled at 1000-foot spacing and has been performing well above type curve. These 3-mile laterals each deliver an initial 30-day production averaging 2150 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 that runs east of our acreage into the market center. In the south, we have an established reliable third-party building out a new pipeline that is expected to be in service late this year. With these trunk lines in place investment 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 EOGs 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 and natural gas treatment facility and the first phase of a 36-inch pipeline. The facility was recently placed in the service to treat gas from the Dorado play prior to transportation through our 36-inch natural gas pipeline to sales near [indiscernible], Texas. Both projects were delivered on time and under budget, a testament to our operational team and foresight to procure a pipe counter-cyclically, along with other long lead time materials. The second phase of the natural gas pipeline will kick off construction in early 2024 and is expected to be complete late next year. Phase 2 of the pipeline will terminate in the Agua Dulce, which provides access to three other pipelines with connectivity to the growing demand along the Gulf Coast and Mexico, and potential premium pricing relative to Henry Hub. Our pipeline will be instrumental in expanding our gas sales options for the 21 TCF of net resource potential we've captured in Dorado, and perhaps more importantly, save $0.20 to $0.30 per MCF in transportation costs over the life of the asset versus third-party alternatives. Now here's is Ezra to wrap up.

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 a mass 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 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. [Operator Instructions] And 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, you guys get more confidence at this point to make those moves?

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

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 2 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. And that, in addition to strengthening the balance sheet, everyone knows we retired a $1.25 billion bond earlier this year, and we've been able to be not only net zero but actually put a little bit of cash on the balance sheet. All of those things are what gives us confidence in the base business going forward and the fact that we can continue to increase this minimum cash return to our shareholders from the 60% up to the 70%.

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

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

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 what's the optimum level of activity across each of our plays that supports the objective of having continuous improvement. And so on that, on 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. And we'd expect to maintain similar levels of activity in those plays. We see the advantage of that is we are seeing continued improvement in each one of those plays, as we've talked about already on this call, And then, for our emerging plays, the Utica and the Dorado, for instance, we're very pleased with the results we're seeing to date. And 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, that's one reason we like to maintain these levels of activity. It allows us to improve our cost basis, improve operationally on how we're executing these wells, and we're 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 space test. And of note there, as we've talked about our new completion design down there in the Permian and the Wolfcamp, we were able to go ahead and implement that on that. And as you can see from the initial results that we talked about, the 30-day IPs on that or 2,150 BOE per day over that 30-day period. So really excited about how that's turning out from the spacing test. We have an additional package. We actually highlighted in our slide deck, Xavier. We're going to tighten the spacing on that to 800 foot, and we should have results coming on here fairly shortly. So we're very excited with the results. And with that application of new completion design, it's going to be tough to tell if that's really what the big mover is, but we're extremely excited about the results that we're seeing so far. And from a cost standpoint, we really haven't disclosed specific costs in the Utica. We're still in the early stages, as we talked about in learning in this play. We've got a lot of room for operational efficiency gains. We've got some infrastructure, small infrastructure to develop that we can install like water gathering, reuse and sand to drive down costs. And then as we said, with the well results we're seeing, 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 maybe at a high level in 2024. On the third quarter call of last year, you provided some soft [Technical Difficulty]. I was wondering if you could maybe 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 with [Technical Difficulty]. So I want to get your thoughts if you could give us some soft guidance around next year.

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

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 North and the Southern portions of the play?

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

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 what we're seeing is kind of APIs in kind of the 40s to 50s.

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

Yes. Good question. So to kind of start off, why do we started off on the East, really the big reason with that is just we had good quality seismic data over on the east side of it when we were first starting out. And obviously, that's really important, so you can get a really good look at the detailed subsurface, any kind of drilling hazards to make sure you perform really, really clean tests. So where we started, where that seismics at, obviously, we started the delineation. We've got spacing tests in place. And then as we start to zero in on that spacing, we'll be able to kind of step out more to the west and be able to apply some of those spacing techniques to start developing out there. But we do know there's going to be variation in productivity. And as you did state, we do expect it to get more oilier as you do move out 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, typically, would your AMI in the eastern side of the play limit in any way 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. And let me just highlight again that we actually own the minerals across 130,000 mineral acres down in the southern portion of the play. So when we look at it right now, as Jeff said, we're drilling some initial spacing packages, some delineation tests where we currently have seismic. We're also this year acquiring seismic in a couple of different parts of the play. So we can continue to step out and gather results on that and provide a bigger better estimate of what we've captured here for you guys. As far as being limited on incremental activity. I want to think of it that way. Like I said, we've put together a very large contiguous acreage position. And really, our activity right now as far as investment in pace, as Billy said, is going to be determined on our ability to collect data and integrate the production data that we're seeing back into the front-end of our geologic models. The activity is really always considered to be at a pace where we can continue to learn and incorporate those learnings on the next set of wells.

Great details, Ezra. And then just to follow up, I want to make sure, I'll stick with the Utica. Just it sounds 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 on the Northern portion that. Bill, I think you're one of the guys just talking about it. Maybe just talk about the infrastructure plans and if that would capture any of the upside if you decided to boost activity in that northern area.

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

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

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

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 it's also pretty dynamic, and it's close to the intentions that we have over a range of different price scenarios. So we're not entering into an area where we need to modify the commitment going forward. It's something that once we come out with that commitment, hopefully, our shareholders can see by our track record that once we come out with something, we're very consistent with it. The 70% return is a minimum of free cash flow is pretty consistent with our longstanding strategy, I would say, to build shareholder value and position the company to be able to do it through industry cycles. And that means that reinvestment at the right pace in our high-return inventory, that's the best thing we can do to create shareholder value. Ultimately, the cash return strategy, it begins with our commitment to a growing and sustainable regular dividend which, again, we raised that. We increased that just 10% and that dividend has never been cut or suspended over the 25 years that we've been paying one. In addition, we've committed now to return either additional specials or buybacks to reach that 70% minimum commitment. For us, hopefully, the increased commitment, the reason we like the 70% of free cash flow is, it's consistent with our free cash flow return in that it puts the emphasis on our regular dividend, which we think is peer-leading and competitive with S&P 500. And again, we feel that we can maintain current levels of production and cover that base dividend at WTI prices as low as $45.

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

Yes, Doug, I'm not going to speculate on 2026. As Billy said, it's a little bit early to be speculating on 2024. What I'd come back to is our disciplined base of investment. We have a lot of flexibility in the Utica. Specifically, we've got over 90 or roughly 90% of the acreage there is held by preexisting production. We only have a minor drilling commitment there. So we're in a great spot where we can actually develop that asset in a disciplined ability to increase activity commensurate with the increase of our learnings. Now overall, your question is recently our exploration efforts have yielded very high return, more combo plays, or in Dorado case, a gas play, and that's true. And there's something to be said for that. Our exploration and emphasis, I would say is dominantly more oil-focused because the margins are a bit more forgiving on oil from what we see. But ultimately, with our premium investment hurdle rate, and that's at bottom cycle pricing of $40 oil and $2.50 natural gas through the life of the asset, we're somewhat agnostic to the product mix. Now it does require a heavy lift, by Lance, to discover new market potentials for us. And we continue to invest in different parts of the infrastructure and supply chain to lower our costs and lower our break-evens. But ultimately, we're investing in high-return assets and we continue to build out the inventory in a high return framework. More than the 10 years of double premium drilling, I think I'd steer you towards the 10 billion barrels of equivalents overall that is, at a finding and development cost, lower than our current DD&A rate. And as I said in the opening remarks, that contemplates maintenance levels at current levels of production, roughly 30 years of production. So we're very confident in the high-return inventory that we put together and believe that it's going to continue to deliver great shareholder value in the future.

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, some capital efficiency gains, especially as some costs come down. On the other side, you have a slightly higher base production. So is it a reasonable stake in the ground to think that you guys can have similar results of '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 specifics about things. But I would point you to the fact that we're running at a pretty decent level of activity now. We're going to maintain that same level of activity going into next year. Now just a reminder, we're spending about $6 billion on our CapEx program this year, and it has proved to be fairly ratable through each quarter of the year. Similar levels of activity, there will be some upward movement maybe on efficiency gains. Like you said, we'll have a little bit more efficiency gains to factor in maybe some cost reductions due to casing cost, those kind of things. We'll still have some infrastructure spend. We may drill a few more wells in the Utica and Dorado plays. And we're trying to quantify that as we go towards the end of the year. But directionally, that kind of hopefully points you towards what next year might look like. We're not going to see a big ramp up in activity in any play as we see today, small changes in capital efficiency and well cost as we go into next year, we have some infrastructure spend.

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. It seems to me like you're pleased with the results because you mentioned that you're even considering longer laterals in the Utica. But curious if you could address that point? And then also whether we can expect to see 3-mile laterals in other key plays for you guys? And if yes, where, or if no, what's special about the Utica that it works there and not in other places?

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

Yes. Just a little bit to add in. In the Delaware, in the Eagle Ford and in Utica, we've had great operational efficiency with our 3-mile laterals. And that's one of the things, as you start stretching out the length of these laterals, you want to make sure that operationally you don't have any issues on the drilling side and you're able to optimally complete that. And we've seen really, really good results with that. The other thing we're also seeing is by drilling these longer laterals, we're able to supplement 1 vertical with a 3-mile lateral versus 2 verticals and a 2-mile lateral. So we're able to see substantial cost savings there anywhere from kind of 15% to 25%. So we're definitely excited about where we're seeing it. Obviously, it ties in with our leasehold, and we have to see where we can actually drill 3-mile laterals. But we are looking to expand that across our plays moving into next 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, 20% uplift in productivity. But there has been a question regarding applicability as you've talked about 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 with the technique next year?

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

Got it. And then a follow-up on the South Texas pipeline. Does the completion of Phase 2 of the pipeline later next year influence how you think about the cadence of activity in Dorado? Are you inclined to add rigs into the play later in '24 to set the stage for a stronger growth once the pipeline is complete?

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

And then this is Lance, too. Some of the other strategic things we've done as you think about Phase 2, once we go in service, just to start, we already have existing capacity with other existing markets that are in place. But as Billy mentioned, really excited about getting to what we're going to potentially see as premium markets because we've got offtake agreements already in place, 2 of those which are very strategic. One of those, obviously, is with Cheniere and excited to see the development and momentum they're getting with the Stage 3 facility where we'll be a big piece of. And then, just two, the Transco, we'll have a strategic connection there. And that's going to give us access all the way up essentially the Gulf Coast Corridor, getting all the way into the premium market. So again, really excited about that as well, just from an offtake capability as well.

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

I have two questions related to topics not covered yet. So first question, I wanted to focus on your CCS pilot, was the benefit of a year of experience in the pilot. I wonder to see if you could speak to some of the learnings to date and applicability of the pilot to your larger operations as a means to achieve net zero.

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

Great. And then, second, I wanted to lean in on your shallow water exploration schedule. With offshore drilling rig rates approaching historic levels and industry messaging sustained strength, how does that impact your views on the timeline for exploration wells and, more importantly, development activities, assuming exploration success?

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

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

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

Yes. This is Jeff. The first thing I'd say is in the Delaware, our technical teams, they're doing an outstanding job of continuing to build on their understanding of the subsurface geology, their geologic models. And really what they're focused on is increasing the value of each of our development units by maximizing and improving the overall NPV. So really, we look at it from kind of a total bench standpoint when we go into development. Now when we're looking at productivity and you talk about that, the wells are looking outstanding and we're kind of seeing a marked improvement year-over-year. We've seen good increase in productivity across the majority of our benches, and really the Wolfcamp as about a lot is kind of leading the way due to that new completion design. But the one thing that we always want to go ahead and highlight is, we have a large acreage footprint, over 400,000 acres. We've got high number of unique targets that we co-develop based off the very unique geology in each one of these areas. So you're going to see when you look at individual well results or even roll-up for the play, you're going to see that quarter-to-quarter variations in productivity and well performance. But ultimately, we're really happy with all the results that we see and it's hitting all the expectations and we have all of that built into our forecast.

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

Yes, Nitin. This is Billy. Let me give you a little more color on that in general. As far as the recovery factor, we're constantly improving or working to improve the long-term recovery in all of our plays, and it's something that goes really back to the foundation of the company and is something historically we've done, as you mentioned. We leverage a lot of technology to help us understand how we're targeting those plays and how we're completing each well. And so it involves a lot of things. And let me just talk about that in the sense of how we think about it. I mean, these unconventional plays, the completion efficiency is really important how we evolve over time. And so just thinking about how we've applied new technology, it goes back several years where we talked about the frac design itself, how we change the way we attack the well from the type of sand we pump, the spacing of the perforations, the cluster spacing, the frac rate, how we target reservoirs, our understanding geologically of how we understand the best place to place the target so we can co-develop like zones and those kind of things. So that evolution over time has caused us to see dramatic improvements in production, which is a proxy for a recovery factor over time. And the most recent example is, this is what Jeff just talked about, the improvements we've seen in our Wolfcamp play. And you can readily see, the 20% uplift we're seeing in completions in production performance is due to the completion approaches. So all those things over time lead to improved recovery factor.

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

Just on the updated 70% shareholder return level. How are you thinking about excess free cash flow beyond this? Will you look to increase the exploration budget, or could you, in theory, increase the shareholder returns to 90%? Any thoughts would be helpful here just to get the cash balance can keep growing substantially next year and there's no maturity until 2025.

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

Got it. And last for me. As you guys are thinking about the portfolio, how are you thinking about any kind of long cycle or conventional opportunities like Trinidad to kind of add in relative to bringing on some additional unconventional growth opportunities? Thanks.

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

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