As we're going to get started with the next session. So this morning we have EOG Resources. EOG, as you know, is the gold standard in U.S. E&P. They've got growth and duration in the best-in-class Delaware. And this platform allows them to pursue some interesting options in respect of the Eagle Ford oil window and Dorado. This year they've made a ton of progress. To tell us what they've done this year, here we have Jeff Leitzell, Chief Operating Officer of EOG. Jeff, really happy to have you here today.
It's great to be here, Clay. Thanks for having us.
I want to start with what you guys announced in the most recent quarter, which is the update to the buyback program and how you're thinking about it. Can you simply explain what you guys have done and the rationale behind it?
Yeah, really what it is, is it's more guidance on the balance sheet standpoint, you know, that ultimately will flow through to cash return to shareholders. And what I'd say is it's really, it's an evolution of our balance sheet just with where we are, the size of the company, the strength of the balance sheet that we've had. And it really will help make the capital structure of the company a whole lot more efficient. Also, on top of that, it's timed, you know, around to where we do have a maturity that's coming due next April, about $500 million. So it's a good time that we started thinking about, do we want to refi that or do we want to go ahead and pay it off? And then also you're seeing on the interest rate side, you know, the Fed has started to drop interest rates.
I mean, we've got a spectacular credit rating. So it's probably a good time just with where we're at as a company to leverage ourself a little bit more. So what that really kind of rolls up to is we put a target out from the debt side of it to where really we want to be about less than one times total debt to EBITDA ratio. And if you look at it like at $45 oil, that's about $5-$6 billion of debt. And then on the cash side of it, you know, we've been extremely comfortable with where we've been at over the last handful of quarters. We've been right around kind of in that $5-$6 billion range. So I think it's just a little bit more efficient way to be able to run the capital structure of the company.
And then also what it's going to be able to do is allow us to be a little bit more opportunistic through countercyclical opportunities. And then also, at least in the near term, be able to return in excess of 100% of our free cash flow to shareholders. And that's really where it would tie back into those additional returns through either the buyback or special dividend.
I feel with the messaging this quarter, you sort of distilled your options down from buyback and special simply to buyback, given where the share price is trading. It seems like a good opportunity. You've put a lot of definition around the cash balance that you're hoping to hold at $5-$6 billion. It's a definition that I don't think we've seen before. Can you talk a little bit about why the $5-$6 billion is the right amount of cash to hold?
So what we've really seen is, you know, we usually hold $2 billion to run the business. And then with the opportunities that we see out there, whether it's a dislocation to where we can lean into the share buyback, if it's strategic bolt-on acquisitions that are out there, small acquisitions even, there's a lot of opportunity that we see out there. So having that additional kind of $3 billion-$5 billion to be very opportunistic, it seemed like a very, very good level for us and a good marker to kind of stick with.
What kind of opportunistic things would be on the list of things that you look at?
Exactly what I just talked about there. I'd say one of the big ones is if we see additional dislocations on the buyback side. And as you've talked about, we have leaned more into the buybacks as of recent. And I think really what that is, is us, you know, betting on EOG, we see where the company's at. We see the improvement quarter over quarter in the company. We see where our exploration, you know, assets are at. And, you know, we feel there's a lot of value in the stock. So that's really why we've been leaning in on those opportunistic buybacks at this point. You know, beyond that, you know, we're one of the only explorers in the U.S. So when you're doing that, we have a lot of opportunities.
You look from a prospect standpoint of just ideas or concepts we're looking at, we could have 15-20 domestically. So there's a lot of opportunity to go on and get acreage or get bolt-ons on a lot of those exploration plays or even just offset some of our current core development plays.
You guys have been very disciplined in how you reinvest your capital. You are allocating more towards your dividend. There's a 7% increase this quarter. And I imagine that's going to continue to rise. How do you guys think about where you want your break-even to be with respect to that growing dividend?
So we've come out with a couple different numbers, but I mean, we're in the $40s when you look at a break-even number for our CapEx and then our regular dividend. So, and that's very healthy. Obviously, we've got a very, very high investment rate with our premium rate. And what that does is obviously it just lowers the cost basis of the company and continues to drive down that break-even. So we feel really great about where the break-even is for the company right now to cover that regular dividend.
Let's shift gears and go asset by asset. Let's start with the Permian Basin, so can you sort of help us visualize, to set the stage here, help us visualize where EOG sits on the development spectrum? Is it more of a really large project sort of approach like in ExxonMobil? Is it more piecemeal? How would you guys fit yourself into that spectrum?
So any asset that we have, what I would say is we don't go cookie cutter with any of them. We surgically dissect each one of our assets well by well, foot by foot of rock. And that's really how you actually, you know, push forward the results. And the Permian is a perfect example of that. You know, we really feel like the Permian is in the absolute sweet spot right now and just continues to improve for us. So we're getting better every single day operationally, you know, from an efficiency standpoint. We continue to increase well performance and get better and understand how to increase well performance. So we continue to add in additional resources through additional targets.
And when we break down the Permian and we look at our development methods, you know, we have over 20 unique targets in the close to a mile of stratigraphic column. And, you know, within those 20 targets, you know, we end up developing the most wells per section in the Delaware. We tend to have the tightest spacing in each individual target. And then when you boil it down to ultimate results, we have top-tier well productivity and well cost. So, you know, we just continue to see added value every single year come in and it continues to improve and continues to get better. And we were talking about this morning, the Delaware, I mean, first production in the Delaware happened back in the 1920s.
So we're literally 100 years in and you can see we're by far at the most prolific point in its overall development from that aspect. And that has to do with technology advancements. It has to do with, you know, continued innovation, longer laterals, you know, going in with the completion technology, really refining your designs, higher pump rates. And I think all those things are reaping benefits to higher productivity and better wells.
The E&P landscape over the last several years has bifurcated itself into a camp that grows oil and a camp that's embraced ex-growth. EOG is still one of the companies that is growing oil. Can you talk to us about whether that's a target of your program or simply an output? And if it's an output, where do you expect it to plateau?
Yeah, great question. So capital allocation for us in the process, what we do is we look at each one of our assets, where they're at right now, currently in the life cycle, and are they improving? Are they getting better every single day? Are they meeting our return thresholds? And are they maximizing value from a development aspect? And if they meet all those thresholds, then we'll go ahead and invest. If they aren't meeting those thresholds, we'll either pull back or we'll, you know, reassess what we want to do there. So ultimately, when we put our plan together, you're absolutely correct. We roll all that together on the optimum investment of each asset to improve it. And growth is just an output from that aspect. And what we truly with capital allocation focus on is we're focused on returns.
We want to make sure we're maximizing the value of the asset. We've got the right development plan. We are continuing to improve and maximize the resource and the NPV of it ultimately flowing through to the free cash flow of the company. So anyway, I think we're obviously from a capital allocation standpoint, we're extremely capital disciplined and it's all about continued improvement.
When you impose this maximum return strategy onto your asset base, there's a growth. Growth falls out. How long do you think growth will continue to fall out of that program?
At the level we're at currently, you know, it really just kind of depends. We've got a handful of emerging divisions that are coming up, as you talked about, and I'm sure we'll get a chance to visit on with the Utica, and you know, we continue to ramp up activity there, and in a lot of our core assets, you know, we're really, we're not seeing any falloff and we're seeing continued improvement, so we'll obviously take the macro into account when we're looking at what our overall roll-up for the program is going to be or the barrels needed out there, but we'll still go through the same process to really see where each of the assets are in the life cycle and what's the optimum level of improvement.
EOG is one of the companies that likes to do things in-house. One of those things is midstream infrastructure. You have the Janus plant coming up in the Delaware over the next six months or so. Can you talk about why you've chosen to do more of that stuff in-house? What does it do for you?
Yeah. So really on the indirect side, that is very, we call it strategic infrastructure spend because it is outside the norm. We don't normally invest in those kind of opportunities, but it came in a time in the market a handful of years ago where we went out and said, okay, let's see what the fees or the agreements look like on the gathering, processing, and transportation side. One with the Janus plant out there in the Permian Basin. And then also there's the Verde Pipeline down in South Texas. And with both of them, what we found is the market kind of moved away from us. And we didn't find the rates very attractive and it wasn't something we wanted to sign up for long term. So at that point, we stepped back and said, is this something we would like to invest in ourselves?
Does it make sense from a returns basis and ultimately for the betterment of each one of the basins that they're in? And what we found is they had very good returns. Both of those projects are anywhere from 20%-30%, you know, rate of return. And the upside of it is on the gas plant Janus out there in the Permian, we get either a GP&T reduction or a price uplift of about $0.50/Mcf for every molecule that we run through that plant. That's a 300 million a day plant that we build that's expandable up to 600 million a day. And then the same thing happens for our Verde Pipeline that's down in South Texas. It's a 36-inch pipeline, a 36-inch pipeline that goes 100 miles.
We bought the pipeline at an extreme discount off of one of the canceled pipelines in the past, and when you look at that one, we get about a 50-60 cent uplift in either GP&T and overall price realization. So it just made sense. They're extremely strategic, and once we do that, we created additional competition in the market. And we've actually seen a lot of the third parties come back to us with much more attractive rates at this point. So what I would say is, and we talked about this on our earnings call, our strategic infrastructure spend this year was around $400 million. That's rolling off quickly. Really, we've just got to finish that Janus plant as we head into next year, and we've got a few other little things we're going to finish up on the Verde pipeline from a facilities aspect.
But I think our spend next year will be somewhere about an additional $100 million for the year of 2025 on strategic infrastructure. And then beyond that, unless another opportunity presents itself, we'll get back to those historic levels where we're normally between 15% and 20% on the indirect side.
Over what period of time do you think you can advance that capacity at the Janus plant from 300 to 600?
That one's actually in the core of our field. Just with our current producing volumes and just with the uplift that we see, we've got ultimate flexibility with our current marketing agreements that as soon as we have that come online, we'll be able to load that plant up and take benefit of it just with the, you know, the amount of gas that we already have produced out there.
Within the E&P landscape, there's a lot of companies that look at their Permian portfolios and look for assets to high grade. EOG has not been a part of that behavior. What's the philosophy in not selling or divesting Permian assets from the portfolio?
So we, I mean, across the whole portfolio, not just even the Permian, we do divest assets, but we'll divest them once we know there is absolutely no upside potential on them moving forward. And that's really what we find that some of the best places to explore, I mean, we'll explore everywhere as long as there's data and there's the opportunity. But some of the easiest places to explore is obviously on your acreage. You've already got penetration points. You've got data. You've got 3D seismic. You already understand what your marketing structure is going to be. So really, I think that's what it is. We'll look to divest assets that obviously are, you know, nowhere within our portfolio or within the view of it we're going to develop.
We want to make sure that it doesn't have any additional upside targets or additional resource that it either can be economic with our portfolio today or we can move forward with technology in the future.
This one's a little bit contentious because it's related to regulatory. But in New Mexico, they produced a study suggesting that they would benefit from enhancing their drilling restrictions. Can you talk about how you understand that piece of that study and how it could potentially impact your business?
Sure. Yeah. So, you know, they've obviously been doing a recent setback study for about a year now. And we've been well aware of it. The first thing I'll say is we're the largest producer in New Mexico. We have an absolutely outstanding relationship with the regulators and, you know, the government officials. And we've always prided ourselves at kind of having a seat at the table with regulation and being able to work with them on what's going to be, you know, the best move for the stakeholders. And our assessment on it, when we run through even, you know, the recommended setbacks in the study, it's not going to affect our operations at all. The majority, if you look at our acreage, we've really focused on staying away from heavily populated areas.
And I don't know if anybody's been to Southeast New Mexico, but it's not a very populated area from that aspect. And then there are some additional with wetlands, with lakes, with rivers as far as that goes. But a lot of the setback rules ultimately end up being surface setback rules, and they can be managed from a subsurface perspective, you know, with the regulator. So we really don't see any impact from the study with any kind of regulatory outcome that came with it.
Can you talk a bit a little bit about the complexity of your targets in the Permian Basin this year and how you would expect those to evolve in the coming years?
As far as the targets that we're developing?
Yes.
It's all across the board. So really what we do strategically is we went in and we'll go into sections and we like to develop deeper first. The reason is if you develop deeper, you're getting a penetration point all the way through the overlying lithology and you're able to collect very valuable data on it. And that's usually the starting point as we move into new areas. So systematically, you'll see kind of the well mix as far as those 20, you know, individual targets. It'll ebb and flow from year to year depending on where we're moving and where we're at in the life cycle of the section and, you know, moving up in section to do either the higher targets, you know, with starting lower in that section.
And then also what we do is we don't go in and we don't do, you know, any kind of big cube type development there. What we do is we look to try to find where the flow barriers are within the reservoir in that one mile worth of productive reservoir. And those flow barriers, I mean, they may get fracked through, but ultimately they close off. And we're trying to minimize any kind of depletion effect between benches. And we'll go in and we'll do, you know, multiple stacks and staggers within one of those flow benches, and then we'll move on to the next one and move on to the next one. And that's ultimately the goal is to be able to retain ultimate value, minimize depletion so you can maintain that surge and well performance in it. So that's really how we think about development.
If you wanted to look at it from a well mix, it's going to ebb and flow from year to year just as you're moving up in section and moving out across the acreage.
This question is intended to be a segue into your Dorado and Utica developments. The question is, EOG has managed a very predictable capital program for a long time. These programs within it are commanding a very small part of your capital, somewhere around 10%. When you step back and assess the opportunity, how much scale do you think you can get from these two assets? How big could they be?
You know, there's a lot of growth potential there. The first, I'll start there in the Utica. So we have 445,000 acres, you know, and 135,000 we actually own minerals on down in the south, which obviously helps out immensely with the economics. And we've got an absolutely great liquid performance out of the play. Operationally, it's one of the probably the best operating environment that I've ever worked in. The rock drill is extremely easy. We've got a record. We've actually drilled 12,000 feet in one day with one rig. I mean, unbelievable as far as how fast you can drill. And then also the depths are very conducive to hydraulic fracturing because they're lower pressure. So you're able to really apply high intensity fracs to really maximize the overall productivity of it. So the one thing that I'd say about that is the growth potential is great there.
And I think it will move into being one of our next fundamental or foundational plays, I should say. And the beautiful part about it is you don't necessarily need as much activity as you would some of the basins just because of that operational environment. You can drill so fast and complete fast up there. So I think you can ultimately, you can do a lot with a handful of rigs up there in the Utica. And you can drill a pretty substantial program with, I'd say, three or four rigs up there. Moving down to Dorado, now that's a little bit different of it. So really what we did down in Dorado is we kind of stood up a separate gas asset, and it's extremely prolific. So the wells down there, it's a 20 Tcf resource, and the wells come on at 20 million a day.
And they'll stay there choked back. I mean, on a, you know, third-inch choke at 20 million for about six months. So you've got the opposite in there in Dorado to where you don't need as much activity because you can just imagine you go into a five well pad, you drill it, you bring it online, there's 100 million a day. So very quickly you can grow volumes in Dorado and you really don't need as much activity. So the world has really changed. I think both of them will be huge growth engines for us. Dorado primarily as a gas asset to go ahead and get over to, you know, the coast to get the gas offshore. And then I think Utica really is going to rise to be our next foundational liquids play in our portfolio.
Gas is super topical, so let's stay there. A few years ago, you discussed Dorado's breakeven as being somewhere around $1, $1.25. That breakeven gets reduced as you bring on the Verde Pipeline because it's reducing your cost to market. Can you talk about where that breakeven sits today, understanding that time has passed, you've got better well control, better understanding of the asset?
Yeah. So we've made great progress in just the handful of years that we've been operating in Dorado. And the most recent guidance kind of color we've given on it is we're somewhere around $1 on our cash costs right now. And that's outstanding with how early we are. We continue to drive down overall F&D there. So what we see with Dorado is, and as I said, you know, we really stood up a separate gas business and we knew to do that, you know, it had to kind of meet a handful of criteria is what we say. So the first thing is it's got to have scale and be prolific. And we talked about that. It's, you know, 20 Tcf and very, very big wells. You know, the second thing that it has to have is it's got to be proximal to the markets.
You know, the Northeast, it's got prolific gas that I think could really benefit the world. The unfortunate part is it's stranded and we can't get it off. But we do have the benefit when down there on the Gulf Coast that we do have the access to be able to get it offshore. So Dorado sits in Webb County. It's a little over 100 miles from the coast. And we've actually put in, as I talked about, that 100-mile, 36-inch pipeline to get us to Agua Dulce, the primary market center, so we can feed all LNG third parties up and down the coast based off our agreements. Or we can actually get into the Transco TLEP line and go all the way up around to the Southeast market center up there.
So it checked that box and it's definitely proximal to where we want to be compared to any other gas. And the third box it has to check is what you're talking about is it has to be the lowest cost gas in the U.S. And with how prolific it is and with how quickly from a, you know, overall operational efficiencies that we're seeing gains in it. And then not only that, you know, just the overall improvement, you know, from a completion design. And I think iteratively every year we continue to make the wells better and better and drive down the overall cost. We definitely see line of sight in the very near term, it will be the lowest cost gas in the U.S.
So once you check all of those boxes, we think we really have kind of a premier gas asset that's, you know, perfectly located to take advantage, you know, even through very low cost gas environments, but it'll also be around to take advantage of when we see those spikes in the gas price.
There are a lot of molecule counters on the gas commodity side trying to figure out how big this play could be. Are there any breadcrumbs you can point us to to suggest what an ultimate size of this development could be?
You know, we haven't come out with total, but you can tell by that resource it's pretty immense. You don't have to drill a lot of wells to get your volumes up very quickly. And I won't give you any numbers, but I'm sure there's some engineers that can run the hydraulics on a 36-inch pipeline that's 100 miles long and you can come up with some pretty big numbers. So it's definitely very scalable and we can do it very quickly with how prolific it is.
There's some flexibility built into your 25 gas strategy. As some different pipelines come online, you have some optionality of where to supply it from. That gas could come from the Delaware Basin or it could come from your Dorado asset. How are you thinking about utilizing that flexibility? What are some key price points we should be looking for to suggest that that gas will come from Dorado or it's going to come from Delaware?
You know, I think first off we have such a, you know, high investment hurdle. A lot of those decisions come out. I think it really the key goes back to what you're talking about is to making sure we've got an extremely diversified, flexible marketing strategy that we have a lot of control in. And we have numerous outlets in each one of our basins where we can really focus on not flow assurance because we're well past that. We really want to talk about overall what's our ultimate, you know, price realization that we see that we're getting. And that's really what we focus on from the marketing strategy. So in real time, all of our volumes, we monitor 24/7. We control what markets they go to to really maximize that overall net back that we're seeing in it.
So really the strategy is kind of a real time on a day-to-day basis with it where I'll use, for instance, Waha. We all know Waha can go negative, you know, relatively often. And we've got very low exposure, less than 5% to Waha. But we've got enough flexibility in the portfolio. If we did have any exposure there, we can very easily move the molecules around to be able to limit that. And that's what we really want ultimately in our marketing strategy is that ultimate flexibility to really maximize those net backs.
As you stated, you're developing a diversified marketing strategy on top of that asset, but people are still going to look at key pieces of infrastructure that are being built out in your backyard, so Rio Grande is kind of case in point here. How important is that to the ultimate plateau of the asset in Dorado?
It really doesn't have an effect. You know, with the backing off of the permit there, that really doesn't affect us at all. We've taken out adequate capacities. Really the goal of our marketing team is to stay well out in front of our assets and, you know, give us a lot of flexibility and make sure we've got the volumes that we need and secured. Where we sit right now on the coast is we've got close to a Bcf that will be coming online over the next handful of years from an LNG export capacity. The big chunk of that is obviously with our Cheniere agreement down there, which we're currently exporting about 140,000 MMBtu. That's what's beautiful about the Cheniere agreement is we can elect on a monthly basis to either JKM pricing or Henry Hub pricing.
So you can imagine that was a very unique agreement. It's been very advantageous and we've taken advantage of it. That 140,000 here in the next couple of years will go up to 420,000. It'll be linked the exact same way to JKM or Henry Hub. And then we'll get an additional 300,000 MMBtu on top of that from Cheniere that will be linked directly to Henry Hub without any deducts. And then so we went back out to the market to try to, you know, okay, let's try to find another agreement that is as good as this. And, you know, we really couldn't find anything. It was a very unique agreement. So our marketing team kind of went back to the drawing board and, you know, they actually found a partner.
We were able to sign a Brent-l inked agreement recently where we took out an additional 140,000 MMBtu. That's scheduled to come online at 2027. So we've got quite a bit of flexibility there as far as our LNG offput and in the markets that we have all the way around that Gulf Coast center. So really the Rio Grande didn't affect us at all.
How do you think about sizing that LNG exposure piece?
So obviously we know what our capacities are. The first thing is we don't want to link it to one play as we talked about. But we've got, you know, obviously a lot of growth that we can supply out of Dorado. We've got a lot of molecules that are out there in the Permian. We feel comfortable right now with where our agreements are, but we're always being, you know, trying to be out in front of things. We're looking for additional offtake on it. I think one of the big things that we've ran into is just finding the right terms in the agreements. You know, if we're going to do it, like I said, we're focused on price realization. So we want to make sure that, you know, we're getting ideal premium terms that really benefit the full portfolio.
We haven't seen as many of those as of recently. The team continues to look for opportunities to get in there and diversify it. They will into the future. We'll be patient about it. We'll make sure it's under the right terms.
You mentioned having a lot of gas in the Permian Basin. Over the last several years, I think the market has gotten more comfortable with Waha being in negative prices. But perhaps there is a bigger ask to earn a return on that gas today than there has been in the past. How are you guys thinking about monetizing those Delaware gas molecules?
You know, obviously we're in great shape out there as far as our takeaway and the markets that we have getting it both out to California or getting it over east and stuff to the primary market center there. So the big focus we have out there really is Waha. And we've minimized our exposure there. And most recently, Matterhorn has come online and we do have additional capacity on that. And that's really taken any additional pressure that we have there in that Waha. So just those moves alone have really helped us maximize, you know, what our overall net backs are for those molecules. And, you know, that should handle us at least for the, you know, foreseeable future.
We'll continue to look for additional volumes that we can go ahead and tier and stack onto that to make sure we don't have any additional negative exposure.
Let's shift over to the Utica here. The Utica Exploration Appraisal Program has been yielding very strong results this year. And it feels like the pieces are coming together to transition into more of a development program. Can you talk about where that program is in its life cycle? Is it getting closer to development here?
It is. It's getting very close, so, you know, as I said, we've got 445,000 acres we put together up there, and what we originally started doing is we started developing, or I should say delineating on the 225,000 acres of the volatile oil window, and the reason for that is we had good geologic data. We had good penetration points across it, and it was really where we refined our model and, you know, felt the most comfortable to start, so we went in with single well development with great success, we went in with package development. We basically split it into three areas across the 140-mile footprint of the acreage, a north, a central, and a south, and we did single delineation wells. We've done package wells, and now we've actually come in and offset those packages with even tighter spaced packages.
Happy to report, you know, the liquids production on them looks absolutely outstanding. We're meeting or beating our forecast. You know, we really feel great about the spacing that we've seen from the results too because even with tighter spacing, we're still getting really solid results out of this. The goal I think this next year is, as we've talked about, we're going to increase activity in the Utica about 50%. While we're doing that, we're going to focus on that 225,000 acres and, you know, really finish off understanding the spacing in each one of the areas so we can transition into full development.
One thing that we noticed in this quarter is that you've been feeding that data from the Utica all year. There seems to be some convergence in terms of well performance in your various areas in the north, in the central, and in the south. Is that consistency validating your geologic thesis?
Yeah, I think so. Absolutely. And there's also, you know, you've got to look through the details in a lot of that. So, you know, in the north, we were able to go in. We drilled an original package with outstanding results. And then we did a spacing test off of it, package directly offset at tighter spacing. And the results, you know, almost overlay. They look absolutely outstanding. So really there are different variable changes in there. And that's really where we're getting into the optimization of the development. We've done the same thing in the central. We recently went in and did a five-well package, Wolverine package we talked about that offset our existing package. And just absolutely outstanding results with that too. You know, and you've got an additional interval inside that package. So that definitely plays into the effect.
Then you move down to the south where we originally brought on the White Rhinos at 1,000-foot spacing. Then we moved over to our most recent package and we've done 800-foot spacing. And the results look really, really solid there. So, as I tell everybody, we really haven't had a miss there yet. And we're excited to get into 2025 and continue to kind of push the limits on this play and extract as much value out of it as we can.
Can I ask you to get a little bit technical? So this quarter you brought on the Wolverine package. That was five wells, 800-foot spacing. And there is another package that's nearby that's four wells, also 800-foot spacing. What additional learnings did you extract from the new Wolverine pad versus the other one?
Consistency of the reservoir and the rock. I'd say, you know, ultimately if you even just look at the rates, the Central is some of the most prolific area within the Utica oil. And what we really wanted to just test is really the consistency of it. And also to go in, it made sense from a development standpoint to add in the extra well. But it also gives you that extra data point of one more in there to see how in larger package development it really holds up against that original well performance. And as you stated, it looks absolutely outstanding. So that was really the goal and is just to really quantify and make sure we've got consistent geology in the area.
So this year there's been a ton of spacing tests. But there was also a single well that was drilled in the north this quarter.
Yep.
Can you talk a little bit about that and what you learned?
Sure. It was a Whitaker well that we had a permit on and a single well. It was actually right close to some existing development that we already had. So we wanted to go ahead and just do the test on the well. And yeah, the well looks good. It came in kind of right on expectations and forecast of where we thought. It's just another data point that just really proves out just the premium potential of the play.
So EOG has a very large surface area position in the basin. A lot of the tests so far have focused on the volatile oil window. But there's a lot that is still unexplored. When do you anticipate getting to those targets? What do you expect to see?
Yeah, we, I mean, we're excited to get out and test some of the different areas in the Utica. I think we've got so much of a head start. The first thing is we're gathering so much great data on the 225,000 acres in the volatile oil window, and we're continuing to refine our geologic model and our understanding of it, which is good, and the more data that we can capture, I think the better it sets us up for those additional areas and how, you know, the reservoir actually works and how it works as you go down dip or you go up dip in the reservoir, so the other thing I'd state is we're in a very blessed situation to where we don't have to rush with the Utica.
The vast majority of it's all held by production because there's shallow Clinton producers on it. So we don't have to rush necessarily to get out there. We can really take our time, make sure we're extracting the most value out of that primary 225,000 acres. And once we get to a better understanding of the depositional model, we'll be able to step out into those additional, you know, areas in the next couple of years.
This is kind of the second era of the Utica. There was some excitement about 10 years ago where guys were first exploring the oil and volatile oil windows. And you're kind of going back to it and having a lot of success. But in that original buildout, I imagine that there was a lot of infrastructure that was being built out on the gathering and processing side. Can you talk to me if there was enough midstream there to support your growth plans in the basin? Or do you think that there needs to be more?
So you hit it on the head. A lot of people ask, you know, how did you find this? Well, everybody's been, we were looking for it 15 years ago. I was actually stationed in Pittsburgh and we mapped it all up and tried to sell it to a former CEO. And then we didn't get it across the finish line. But the thing I tell people is, first off, I'm glad that didn't happen because technology's advanced and our understanding of the basins and the geologic models has really advanced and it's allowed us to find it. But you are right. In anticipation for it, a lot of the markets, you know, they were built out processing and gathering for liquid-rich molecules. And when we first started running our economics on the Utica, we figured you probably aren't going to get a whole lot of money for the gas.
So we built that into our models. But once we really started doing the homework on the marketing side, we found out there was adequate processing capacity. And actually, they preferred those molecules that were liquid-rich up there. So what we've done is we built a trunk line out of the acreage in the north. And then we worked with a third party to build a trunk line out in the south. And based off of what our marketing agreements that we have and the capacities we have, we see we're in great shape for the foreseeable future up there. And we really don't need a lot of additional buildout.
Assuming that the Utica oil window is going to be a success, there's going to be a lot of oil coming out of this region. Who do you sell it to? Where does it go?
So there's a primary refiner and third party up there that's kind of the big entity. So we work with them. They've got quite a bit of infrastructure all the way around Ohio and a lot of different receipt points. So what we see on the oil side up there is there's enough running room with oil for probably the next five years or so. And then, you know, once we start getting outside of that, you know, we'll have to look at maybe some additional outlets to be able to get it out there just with what the growth profile of the Utica oil, you know, actually could look like.
Just kind of wrapping up here in the Utica, there's a lot of learnings that happened this year. There seems to be maybe some other appraisal tests on the horizon to help advance the ball. But it doesn't seem like you need to learn a lot more to move into development mode. What more do you need to see?
I think the first thing is just refining the spacing. You don't want to put too many wells into the ground unless you've got the optimal spacing in any play. If you do that, you're going to go ahead and you're destroying value, right? And you're also at the same time, you put more packages in without having your optimal development plan in place. You create depletion sinks. So you lose value there. So the pace of play is very important. You know, you want to make sure you're moving forward and you're constantly improving. That is a hallmark of what we do here at EOG. So we're not going to get rushed into trying to say, hey, we figured it out. Because what we've seen over time is in every single play, we're constantly evolving. We're constantly getting better.
We just want to make sure that we put our best foot forward in the Utica. We get to a point we think we're, you know, close to optimal development with it before we really pick up major activity.
We've got a couple of minutes here left. If anyone has a question, please raise your hand. We've got a roving microphone in the room and they'll come to you. Maybe as we wait for a question to materialize, I can ask you about M&A. So build versus buy has been sort of a market debate for EOG this year. Exploration success has sort of garnered favor for your efforts making this less of an issue more recently. But when you look at the U.S. and Canadian markets, do you see any resource themes that you think EOG should have more exposure to?
Yeah, absolutely. We want exposure to any low-cost resource that is at the top end of our portfolio, any of it. And that's why I think we're one of the only explorers right now. So we still see a lot of potential in North America for exploration. And because as I talked about, you know, we have numerous prospects. We always have in the lineup shooting of those prospects. You know, we're testing anywhere from three to five each year. So yeah, we see a lot of potential, a lot of upside, not just in North America, but also international with our exploration program.
When we look at our exploration program, really compared to, as you talked about with the, you know, the buy versus build, you know, on the M&A side, you know, you have to pay large amounts for the acreage on the front end, which dilutes down the asset. You load up the net book value. And then it's very difficult to deplete down that DD&A rate and get margin expansion on it. And with our entries, the Utica is a perfect example of that. You can get into a play at $600-$800 an acre. I mean, the initial value on the front end is just immense. So we're always going to continue to be an organic explorer. We think there's tons of upside still out there.
You know, obviously we think there's a really bright future as far as additional resources that we'll be able to exploit.
Do we have any questions from the room? If we have no questions to the room, I'll close it out with this one. Jeff, as you know, we launched coverage on your stock this year. And we basically rebuilt everything. So kind of help us do that. We leaned on materials that were printed in 2021 because that's the last time you gave really detailed disclosure on each one of your assets. Given the progress that you've made in both Dorado and the Utica, it feels like there's some information that the market would like to have in order to have a better bolt-on view on the value of your company. When do you think you can provide us with an update?
So I think you got to look at it from where the company's actually, where it's been and where it's come to now and what it's grown into. I mean, even coming out of the pandemic, we're a completely different company, you know, just of size and magnitude. So I think really from the information that we get out there, you can see that in a lot of our core assets and there's large activity and development with them, there's not a need because when you're running that many rigs and you're running or drilling that many wells, really it's ultimately about the ultimate roll-up of the basin. But where we do see that additional disclosure is very important is definitely with these emerging plays and these exploration plays.
The reason for that is, I mean, there's not very much data out there to really understand, is it going to work? Should it work? So that's why, especially in the Utica, you've seen us really lean into giving a lot more detailed disclosure on each individual well set up there. So we can bring along, obviously, the investors through the process of it so that we can show the successes and we continue to improve through it. And I think you'll continue to see that. I mean, as far as trying to give a little bit of additional color, especially on some of those exploration and emerging plays. But ultimately, as a high level, as a company, I think at the size and the magnitude we've got at, some of the resolution that we used to supply data really just doesn't have its merit anymore.
We're at the stop. We're out of time, Jeff. We'll shut it down there.
All right.