EOG Resources, Inc. (EOG) Earnings Call Transcript & Summary

Thank you, everyone. I realize we're on the lunch time spot here. So I appreciate everyone getting back to their seats. I am truly delighted to introduce Ezra Yacob, who I'm sure is no stranger to any of you, but, Chairman and CEO of EOG. And EOG is obviously iconic in the industry, not least because of the technology leader, I think, partly under your watch, of course, it's a gold standard for how a lot of people think about the unconventional oil and gas business. So Ezra thank you for being here. I've got a bunch of questions I'd like to go through, and we'll give, hopefully, have an opportunity for the audience to ask later on in the session.

But I do want to kick off, Ezra, with some comments you made over the most recent quarter I think for the first time in quite a while, you talked about your breakeven capital, your sustaining capital and it made me think oil has just fallen $20 in the last couple of weeks. Gas prices are all over the place. How do you plan long-term your business with that kind of volatility? What is your macro view?

Yes. Let me just briefly, Doug, start and say thanks for hosting the conference here. I appreciate you and BofA hosting the conference here in Houston, especially during this time of year, since it's an important time of the year for the industry. Notwithstanding the volatility that you're mentioning here, but how do we think about the business? We focus on, and it drives really our mission here is we focus on trying to be the lowest cost operator operating high returns and a leading environmental performance. I think both in oil and gas, that's what you have to be committed to. And what I mean by that is when you're investing, oftentimes, people talk about the investment, is it the growth versus return argument. And while we've grown quite a bit and we have the ability to grow, that's never really been our focus for us. For us, it's been investing in the business where you can generate high returns, but really where you can get better every single year, every asset. And the way we measure that is, are you dropping that breakeven? Are you getting any bit of margin expansion through that? And that really is what determines the pace. And that is we have a premium price deck that we talk about. It's $40 oil, $2.50 natural gas. And we use that to measure all of our investments. We try to achieve a 30% direct after-tax rate of return on that, knowing that, that will provide us an avenue to be able to generate returns through the cycle. If you're excited that you're generating a 50% wellhead rate of return today at $78, $79 oil. Well, what happens when those prices move away from you, right? You may have recouped your cash, that's right, but do you have an opportunity to actually generate income or earnings over the long-term? Can you actually compete with the broad market with an ROCE or a full cycle returns number? And that's how we think about it is that during the good times, it's a great opportunity to strengthen your balance sheet, explore, invest potentially in some infrastructure that will, over the long-term, help you to lower those breakevens, but you've got to pay attention and you got to be disciplined on every dollar that you're investing to make sure that you're actually making the business better as you go forward.

Noted. The emphasis is obviously on oil when we think about breakevens, but there's been a fairly decent pivot in your portfolio mix, at least in terms of the next wave of development towards gas. How does your gas macro view play into, for example, Dorado and Utica?

Yes. So let me back up. I missed the first -- your last question here on the macro view of oil. We are bullish long-term for both oil and natural gas, of course, think one thing we've seen in the last 2 years, everyone has seen is that the conversation around a potential transition or energy transition, energy evolution. Oil and gas are still going to play a prominent role. Every -- there are a number of different scenarios out there. But in any scenario you look at, it still requires investment, current investment right now in oil and gas in the future, right? It just depends on what level of oil. On the gas side, it's the same thing. In the Gulf Coast here, we're seeing a massive ramp up here by the end of the decade in LNG demand. We anticipate to see another petrochem. We also see power demand continuing to grow. For us, we're excited about what that means for natural gas in North America that will be a little more connected with the rest of the world. And Doug is right, our 2 most recent exploration plays, Dorado, which is a natural gas play there in South Texas. We anticipate that should be a big part of North America's LNG future and then also the Utica, in Ohio, which is really -- it's a combo play. It's definitely -- the economics are driven by the liquids that you receive upfront, but it does come with a lot of gas and NGLs. So on our exploration strategy, we do prefer oil because the margins are a little bit more forgiving. For gas, you absolutely have to be committed to being a low-cost operator. But because we invest on the $40 price deck of oil and $2.50 natural gas, that allows us to be a little bit agnostic. And so again, did we strategically go out and look for combo plays or for gas plays? Well, we did see an evolving natural gas market, that's for sure. But ultimately, we're driven by returns. And when we look for exploration opportunities, we're dominantly looking for things that will be competitive with our existing portfolio. What can compete with the portfolio on a returns basis, and again, not only wellhead but over the long-term.

I mean committing to -- let's isolate it to -- we'll get into the play details in a little while. But actually, I think it's to Dorado specifically. It's a dry gas play. Some folks have suggested that the entire Permian could be an enormous gas resource if E&Ps decided to target that particular part. What gave you the confidence to pivot towards a dry gas play when gas was still $2 when you made the decision?

Yes. Again, it's the returns that we saw. When we started with Dorado, it was actually an outgrowth over some of our drilling underneath our Eagle Ford oil window, where we identified some Austin Chalk potential, and we're actively developing and drilling the Austin Chalk. And really, we started to explore for the Austin Chalk all along the Gulf Coast. We leased a couple of different areas that we saw some are oil, some were combo and Dorado, obviously, was natural gas. And after drilling some test wells in there, this is just a good old-fashioned oil and gas exploration story, we actually saw that this was the prospect that was going to compete. As far as looking at what's the macro environment now, can we actually support this play? Well, that's why we have that $2.50. When we look back at historical, let's call it, mid-cycle price ranges over the last 5 years, over the last 10 years, you're right around $3.50 on Henry Hub. And so we feel like that investing at a 30% wellhead rate of return on a $2.50 price, well, that's going to give us that cushion. That's going to give us a little bit of margin as we go through the cycles. Dorado met that hurdle rate. We have actually this year taken the extra step. We've installed transportation pipeline from the basin. Eventually, we're done with Phase I, Phase II will take it all the way to a sales point there along the Gulf Coast. And that will allow us to save on transportation about $0.20 to $0.30 per MMcf. When you think about that, again, it's all about lowering that breakeven as we've talked about. So we're investing on a $2.50 natural gas price there. We're saving almost 10% or expanding that margin, almost 10% by capturing that transportation for ourselves. So again, it really comes back to the rock quality and the opportunity set we had there. If we wouldn't have been able to compete then I think you're right. There are other gas plays in the U.S. that could overtake that. Part of the thing that we like about Dorado is that it is in South Texas. So not only does it have a very attractive finding and development cost, but it's that transportation fee so we can outcompete with a number of the other players that are out there.

So it's interesting how you frame the development of Dorado as an outcrop of what you were doing in the Eagle Ford. But to go back to the Utica, kind of surprised, I think a lot of people that you're taking perhaps is 15-year-old fracking technology. You're going back with current fracking technology and making an old play work. What is the business development process? How does the leasing evolve within the portfolio as it relates to how it hits your desk and how you get to select where you're going to go next?

Yes. Again, it's -- at risk of sounding like a broken record, it starts with the subsurface for us. And I would point out, it's not the first time we've looked at the Utica. It's not like we looked at the Utica and the light bulb went off that this will work. We've actually been kind of exploring at the Utica, we've had, I'd say, 3 different phases of it. Once back in kind of 2010, '11, '12, when some of those initial wells were drilled. Our technology, our completion style, basically pretty similar to what was being done at that time and tested, and we arrived at a similar solution. The area would struggle utilizing that technology. We looked at it again in kind of 2017, 2018, couldn't get comfortable with some other geologic factors that were in the play. And then we started to really look at it more recently with, again, a little more access to data everyone's seen that the other operators out there have been moving a little bit up, dip out of the gas window into some of the areas where it's a little more liquids-rich. And just some of the modern technologies. A big piece for us internally was comparing it to another existing play that we had, where we had developed internally to EOG, we developed some mechanical stratigraphy model. So kind of looking at not only how the rock breaks, where you're actually stimulating it, but what's happening above and below where you're actually targeting. Some of that technology is what we utilized into the Utica. And I'd say it opened our eyes to different potential -- to the different potentials of how the reservoir might react to our horizontal completions technology. That gave us the confidence to start to look for some various entry strategies to start to look for opportunities to pick up some leases. Commensurate with that, we've developed some technology internally that allows us on the reservoir engineering side and production side where we can take some vertical production or production from these older horizontal wells, and tweak them to what we think the different rock properties would look like if we landed in a different zone, to tweak them if we had more clusters, more sand, more water, different completions parameters in there. And then we look and see what the actual uplift would be on the production. We gained confidence because there was actually an operator out there that we're watching. And we modeled what we thought the uplift with their current design based off of a 2012 well that they were very near. We kind of modeled what they were doing, where they landed their horizontal, how they completed the well differently from 2012, and we anticipated, okay, they are going to see an uplift, we guess, and we said, but we think they'll see this type of uplift. And our model actually became very, very close to what they really saw. So again, that -- those little pieces of data continue to provide you confidence and encouragement that your geologic model is working, your understanding of the operations area is working and then your reservoir model is working. And then it's not just EOG, industry is looking at the Utica and you're seeing long laterals are being drilled out there. It's a very capitally efficient looking play. It's an environment that we thought would lend itself very, very well to our horizontal drilling and completions technology. And it's early in the play, but the early results are very promising.

Maybe we could just address sort -- what -- characterize for us, what is the current activity level? How many wells have you drilled to frame your conclusion that the play will work?

Yes. So we have -- we've drilled a handful of individual wells, and then we've got our first spacing package, which is the one we talked about on the earnings call, space at 1,000 feet spacing. So on North American shale standards is probably a little bit conservative for how tight that rock is. But the well results look very promising. They look very good and had an IP, initial production on a 30-day rate of just over 2,000 barrels of equivalents per day. It was dominantly liquids-rich early time, like we had talked about. But again, it's early. We've got that combined with a number of single wells spread across the trend is approximately 130, 140 miles from north to south. So it is a big area. And we're still continuing to work on the delineation. We feel like we've got enough vertical control that goes into our reservoir modeling, but now it's all about confirming what we have modeled and what we see is true. It's early in the play. By the end of this year, we'll have about -- we'll be drilling about 10 wells this year to bring them online. And I think, for anyone who listened to our earnings call, we talked about, depending on our results, we'll increase our activity level moderately next year, potentially try to run almost a full-time rig next year is kind of what we're sitting here today looking at and just continuing to push that forward. We'll have another spacing test coming on later this year at the last -- at the very end of this year, with a little bit tighter of a spacing test, we'll be down to, I think, 825-foot spacing or something right around there. And again, we'll take it one step at a time and see how the play turns out, but we're very encouraged with what we're seeing early on.

It seems to be the one that's got -- well, certainly for us, it's got the market's attention. But there's an oil window in there as well. It seems to get a lot shallower. Are you focused in just the combo area, or is there an opportunity across the entire acreage position?

Yes. Right now, we're focusing where we've got seismic first of all, because structure will be an issue down there. And we are focusing into the volatile oil window. I think other operators have shown that the condensate window definitely has potential in there. But right now, we're into the volatile oil window. And we're collecting data and modeling and doing the subsurface work you would on more of the black oil play, but we're not there yet.

So this puts you, I think, in you're going to correct me here, about 16 different plays across the Lower 48. It seems that -- is diversification is a good thing to that extent?

Yes. For us, we think it is. It's 16 plays. It is just across 9 basins, right? Because everyone knows the Permian is so stacked, right? So a number of those are in the Permian. For us, the advantage of being a diversified operator, an operator with multiple basins. It's an amazing opportunity. It's a competitive advantage for us. It's because though we're a data hungry shop. And so being able to collect data, compare data, both geologic, how drilling and completions are working in different geologic environments, different pressure regimes, how do our completions technology work in different areas. What are other operators doing in those different basins? What other technology or logging type of technologies exist in the other areas? That's what really forms the basis of our exploration effort, our effort to innovate and drive technology forward across our operations. It's the ability to have those large data sets and process through that. For us, being in multiple basins is a real competitive advantage. And then it takes an extra step further, where our company is organized in a decentralized way. And this is something I love talking about, love discussing, because from my seat, what I feel is another unique aspect to EOG has been our commitment to operating in a decentralized organization. And that doesn't just mean having multiple offices across the U.S., it means honestly trying to push decision-making responsibilities, accountability to those offices making -- those who are working the data every single day, your frontline employees, really responsible for the decisions -- empowered to make decisions that really drive the value of the business. There's no way working in 16 plays, 9 basins, having drilled thousands of wells that -- we can sit in Houston and try to identify the best way to complete wells, which targets we should be drilling in, which things we should explore for. Those decisions are best made by the individual engineers, geologists, land folks that are actually working and touching the data, seeing the real-time results every single day. That's really the beauty to it. It's the decentralized effort, and part of that is, again, it goes hand-in-hand with being in multiple basins. It also allows us at times to capitally allocate differently between those basins, right? We can move around if there are infrastructure or marketing delays, things of that nature, we can go ahead and flex throughout the year at any given moment to bring on wells in different plays. And then the last thing I would point out, which is another advantage that we're seeing as we get more of these plays going and we start to capitally allocate across more of them are, each of these plays and basins have slightly different characteristics. Some have exceptionally high IP rates, right? So they help with your wellhead rate of returns. Others have shallower decline potential. Some places are combo, as Doug mentioned before, dry gas, heavily oil-weighted. So all of these things really give us at the portfolio level, what we consider to be kind of a perfect exposure or exposure to what we almost sarcastically sometimes call within the company, a perfect play. Something that has scale, something that has relatively shallow decline yet has a very, very high return and low finding and development costs. If you could find a play that has all of those things and some of those things kind of work opposite of one another. Those are the things that really drive the business forward and allow the company to be creating value for the shareholders.

I think I'd like to get into a couple of those points, but it would be remiss of me not to bring up one topic because I guess our discussion so far has talked about the organic exploration-led how you built that business. We've seen you recently, M&A has become topical again. It's never really been in your DNA, but when I -- and I guess the question I'm trying to ask is that when I think about the technology you deploy across your business, but you see other companies with similar acreage absent the technology. Why does that not present an arbitrage for you for M&A to actually fit in your portfolio?

Yes. We -- I appreciate that. I don't doubt there are opportunities where we could apply our technology and [indiscernible] from the top left. We do have, like I said, a lot of data. The challenge that we come into is it's -- it really comes down to is it going to be additive to what we have already captured in the corporate portfolio. And to be honest, when you need to pay for PDP, for production, that's arguably a low rate of return deal. And at some point, you're going to be making some sort of bet on the commodity prices. And then secondly, you're really stepping into proven acreage, which if it's going to be additive to the quality of the acreage that we already have, that we've already proven, it's going to come with a high dollar. And that unfortunately makes it very difficult to generate those full cycle returns that we've been talking about. For us, trying to gather the data and try to look for something that's new, now it does come with the fact that it's unproven, but that also means that we can be a first mover enter into these plays for lower cost and develop these. And ideally, we're trying to find, quite frankly, in North America, it's all bypassed pay, but we're trying to find bypassed opportunities that we can utilize the technology to for the uplift and make these things even more competitive with the portfolio, that's where we see the real value creation. That's where we see our core competencies. And historically, we've done it very successfully. And I really think, for us, that's the better avenue for shareholder value creation.

So you have this discussion with folks in your position, you say, well, when you see a data room, do you -- are you just agnostic to looking at agnostic's the wrong word, are you inclined to just not look at M&A opportunities? Or do you look at everything generically and stack it against what you can do organically? What's the process?

Yes. We do review opportunities. We want to make sure, I mean, we want to make sure that we're not missing anything, quite frankly. So I wanted to say that we're absent of the opportunity sets or anything like that. But what I would say is consistently when we review proven assets that are out there on the market, we have a difficult time making them compete with some of the pre-existing inventory that we already have from a full cycle kind of rate of return perspective, on that full cycle returns perspective, but also really compete with some of the opportunities that we see on the exploration side within the company.

Okay. I mean, I guess we'll watch -- Yates is the only thing I seem to recall you doing, was that a meaningful size?

Yates is the one that people would go to. And if you recall, it came with a low PDP, it wasn't a real known entity there. It had a lot of undrilled acreage. It was an opportunity where we not only a very hand in glove fit with the acreage in the Delaware Basin, but also in the Powder River Basin. And so it was a fantastic deal and really gave the company a tremendous amount of value. And that would be -- that was a fantastic opportunity. Most of the time, what we see opportunities for us to create the value are on smaller bolt-on things. We've talked about I think some of us -- some people even made fun of us for highlighting 25,000 acres a few years ago, put together in the Permian, because they're put together across a series of 8 different deals. So that's the type of small things that we look at. But again, those are the deals that you can say, how is it going to affect the return profile of the company? Are we actually going to get out there and drill it? Is it additive? And the #1 question we ask any of our employees when they pitch even a small bolt-on acquisition or trade is, what are the plans to drill it? Are you going to be drilling that in 6 months, 12 months? Is it under acreage we already have? Does it fit right into infrastructure? What are the plans for it? Are you just getting it because you think at some point, you might get out there and drill it. It looks really good on a map, it fills in a hole. Tell us where is it really going to fit in? Because again, for us, we look through it at a lens of how is it going to affect the returns of the company?

So it's an opportunistic question. You brought up the Powder River. You still categorize it as oil. Obviously, you still characterize it as an emerging play. Why after all this time, is it still an emerging play?

Yes, it's really the Mowry and Niobrara that are still emerging plays. And it's quite frankly, that basin by far more than anything else in our portfolio really suffered during COVID. We were at a point where we were drilling sands in that basin, Turner, Frontier and Parkman Sands and really started to transition in 2020 to focusing in on the Mowry and Niobrara. They were at a point in 2020, similar to where I talked about the Utica, a few months ago. We had our delineation tests out there. We had one, I think, package of spacing, and we were really starting to get on the spacing and development there, and due to 2020 during the COVID year, we pulled back all activity there as far as drilling. Fortunately, at the time, we decided to continue to invest in a little bit of in-basin infrastructure, things like water gathering lines, a little bit of gas gathering and things of that nature. So when we came out of the COVID in '21, we had very limited activity there. And then really last year was the first year that we got back on track, I would say. So unfortunately, it has. It's been stuck in this emerging asset type of category as a result of COVID. What we've got this year is, this is the first year that we've run basically a full-time rig in the Mowry development. We've decided to focus on the Mowry this first year as it's the deepest target there. It is a little bit more combo than Niobrara overline, it has a higher oil cut to it. But the Niobrara, they're both resource plays spread across the whole basin, but I'll say the Mowry is structurally complicated, the log signatures, the pay zones, it doesn't change that much, but there are a lot of faulting in fracturing there. The Niobrara is the exact opposite. While there's not a lot of faulting in fracturing, the stratigraphy, if you will, or the way that the rock changes, it actually changes pretty dramatically for a shale play. Most people think shale is just a blanket over there. This one changes quite a bit. And so there's an advantage to drilling through it to get to the Mowry every time because we're able to collect data as we go through it that we think ultimately will lead to better development of that resource.

I'm going ask a couple of questions about how you characterize your asset base. I just want to give everyone a heads up. I'll come to the floor in a second, see if anybody's got any questions. But I'd like you to kind of take a step back and look at how you describe double premium. It used to be premium, now its double premium. And then you heard the industry talking about Tier 1, Tier 2, there seems to be an awful lot of generalization. How would you present your portfolio in terms of longevity of the returns that you're prepared to accept. Today, you're talking about 10 years, it sounds like that's really conservative. How would you characterize it?

Yes. honestly, the best way that we talk about it internally, and so for Doug, he's brought up our premium metric, which is at 30% direct after-tax wellhead rate of return, and that's a wellhead rate of return, double premium is at 60% at that $40, $2.50 natural gas price. The logic, let me back up to -- I know everybody's frustrated with wellhead rate of returns, nobody can calculate them. I'm going to say the reason we started with a 30% originally on $40, $2.50, is historically, when we add in everything else, seismic, land, all this other stuff, you're all in rate of return ends up being about half of that. And so what we got at was, if we want to be able to be an ongoing concern and compete with the broad market through the cycles, right? How do we do that? And it's a 30% direct after-tax wellhead rate of return will flow through to about a 10% or 15% all-in rate of return is where you get there. And you can roughly see that in some of our financials now. We've been doing this strategy for about 8 years, and you can see that we've driven our -- and this slide is in our deck, but you can see we've driven the price required for a double-digit ROCE for 10%. We've driven that down to about a $41 oil price. So it's working. It takes some time to get those lower cost reserves in there. But to back up to the heart of Doug's question, the way we think about inventory internally is really that we've captured 10 billion barrels of equivalents with a finding and development cost of about $10 per BOE, less than $10 per BOE, the median on that is actually $5 per BOE. And the reason we think about it that way is we're going to finish this year close to 1 million barrels of equivalents per day, kind of as an exit rate within rounding there. So that contemplates about 30 years' worth of production on the resource. And so we've moved a little bit away because of the changing, the evolution of capital efficiency and technology. So I don't know if these are 1-mile laterals, 1.5, 3-mile laterals. One day, they're going to be 4-mile laterals, right? But it's basically 10 million barrels of equivalent, so 30 years' worth of production. And that has a fine in development cost at $10 per BOE or less. Our current DD&A rate in the company is at about $10 per BOE. So arguably, we've got that reserve base. We've got that production that will allow us to continue to expand our earnings potential across that amount of time, because we've identified lower cost reserves than what we already have in the base of the business. That's how we talk about our inventory. It begins with a recognition of premium and double premium returns because you do want to be able to invest and get your money back out, cash on cash, right? But longer-term, we think about the cost of reserves, because what happens after you get your cash back out? As prices are volatile, and they're moving around, are you going to be able to continue to produce those and produce value out of those reserves? So finding and development costs in another way that we look at it. It's a constant battle when you're developing these assets to try and balance returns and NPV. You don't want to lose resource behind, but you've got to focus on returns, right? And this gets into the spacing arguments and targeting and depletion and all these things. But ultimately, on a well by well on a drilling unit basis, that's what you need to be balancing every time, is what is the incremental? What's the incremental value of any NPV you're chasing for your returns profile? So that's how we think about it internally. The double premium really was an outgrowth of our shift to premium. When we first started premium, we had 3,000 locations in the company. And as we high-graded our exploration effort and really put that standard out there for our teams, we eventually, over a number of years, grew that to be about 12,000, 11,000 total locations, and it almost lost its impact. And so shifting in a double premium was really nothing more than giving our employees that hurdle, that emphasis. Here's what you need to focus on, focus on the upper end of this inventory. And I will say, and we've talked about this on calls before, the goal is not to drill 100% double premium wells every year, right? Because you don't want to stifle that innovation. You don't want to stifle technology. Quite frankly, on any of these emerging assets, until you get into a full development mode, have a full-time rig working, things of that nature, you simply won't get that cost structure to be able to get to a double premium potential. But when the plays are in there, in the thick of it, when they're in their sweet spot, Permian, obviously, is one of them, Eagle Ford is one of them. Yes, the emphasis should be on generating those high-level returns that we characterize as double premium.

I think analysts tend to oversimplify these things because it gives the impression that each individual well is reaching a particular threshold return. But in a multi-stack development, does that mean it's an aggregate of wells that might not otherwise have been drilled on their own had they not been part of a development plan, are those included in double premium?

Yes. They're not included as double premium. But again, that goes back to one reason why the goal is not to have 100% double premium wells, right? Because you don't want to leave behind quality resource. But as everyone knows from depletion, trying to come back and infill drills doesn't really work in these tight unconventional rocks. That's why I say it's a constant balance over NPV and returns. You want to be able to focus in and ideally what you're doing. One of the things we look at is when we develop our packages or develop a DSU, we typically target landing zones in the Permian because it is a stacked basin. We target these landing zones that are going to be in flow communication with one another. So typically, we don't have to develop all the targets all at once. We look for natural geomechanical or geologic barriers in there that's going to allow us to come back later and not be affected by some of the pressure issues or depletion issues. And so we'll develop those targets in there such that the package kind of hits a double premium. So you've got some that are far in excess, some that are under. But that double premium gives our employees kind of that target rate. This is what you're doing. The idea is to make the company better, make every asset better year after year. This is the goal, and this is how you're going to do it.

It's a tricky one because we're sitting in a backward end of the oil curve. And if you have assets which are top of your Tier 1, if you like, and then you've got whatever the balance of the rest of the portfolio is, if you're planning at a much lower oil price for your threshold breakeven, why wouldn't an elevated forward curve encourage you to drill your worst wells first?

Yes. So it's tricky. What you need to do is you need to look at -- you need to end up looking at the incremental returns of those reserves. And as far as drilling your worst wells first, we continue to have a lot of faith in technology. Every year, as we lower well costs or make productivity gains, just incremental, I'm not talking about massive uplifts, but just little things, you're increasing those returns. Think about it, it's another way to scale and circle back to what we talked about the Utica. Parts of the Utica were drilled in 2012 when they were on economic. We just simply didn't have the technology there, whether it's EOG or industry or whoever you're talking about, but now look at what we're doing. The wells -- the early time well results look very, very promising because you've given yourself a chance to learn and apply new techniques and new technology, identify different landing zones, that is still occurring in the Permian today, right? And so the idea of Tier 1, Tier 2, Tier 3, to get back to what we were talking about a little bit, it depends. It really does depend on how you're qualifying those. Tier 2 wells, it's not to say that they're uneconomic, I don't want to talk about again, EOG, just industry in general. I think a good way to talk about Tier 1 wells because it's important for everyone at the macro level, those are the types of wells that will spur U.S. growth. Those are wells that they produce a lot of oil. Tier 2 wells, well, maybe it's more of a maintenance mode for the U.S. They're not going to have that type of capital efficiency. But as the industry drives down cost, to drill longer laterals that become more capital efficient, putting in strategic pieces of infrastructure, those wells can still generate a very, very solid return, but they just can't do it on day 1. They need to have the technology, the learnings, the benefit, the innovation of learning on those Tier 1 assets.

Again, putting yourselves in the seat of a CEO versus a seat of an analyst, we're trying to figure out what do we think -- how do we frame how the market will recognize value for your portfolio? And when you put in your slide deck, and I asked you this question on the call, you talk about a 10-year double premium inventory to which I then ask, well, what are you drilling in 10 years?

Yes. Well, so we've got 2 different things. We've got 10 years of double premium drilling inventory. We've got 30 years of 10 billion barrels of premium. So it's 2 different levels of things there. And every single year, as I said, we expand our portfolio through 2 different ways, driving down well costs and increase in well productivity in existing assets. And every year, that means you've got wells that are 25% rate of return on the $40 price deck. You drop cost just a little bit and they become 30%, so they make our premium threshold. You've got wells that are 45% on a $40 price deck. You increased well productivity just a little, you drop costs just a little and all of a sudden, they become 60% premium. So we're high-grading continuing to improve the existing inventory, in our known assets and our development assets. And then the second thing we're doing is our organic exploration efforts. Again, and you've got things like Dorado, you've got things like the Powder River Basin, you get things like the Utica. And that's where you get obviously large, you get exposed to large sections of the inventory that you're adding on. So it is, it's 10 years' worth of double premium drilling is what we have line of sight right now. That doesn't include anything that we may come up with on the Utica. And then we've got, like I said, the 10 billion barrels of equivalents. Basically, with the finding and development cost or cost of reserves that are at or below our current cost reserve base within the company.

I'm glad you brought that up because on the call this time around, you talked about -- you've been drilling in the Delaware for what, 7 or 8 years now? When you talked about a new completion design, it seems things are still evolving. What -- it's kind of an imputing question. Why after 8 years, is the completion design still changing? What's -- how is it evolving?

Yes. It's -- we actually took -- and I think we said this on the call, this completion design that we're doing in the Wolfcamp right now where we've seen a pretty dramatic uplift. We're seeing uplift performance on first year performance of 20%, and we're seeing that on the EOR performance as well, and we're testing it in some of the other zones right now. It does come with an increased cost, but the increase in production more than offsets that cost. It's actually a technique that we've been using in the Eagle Ford for a while. When we first started roll it out into the Eagle Ford, there were many, many different changing variables early on. And so I'm not sure that we can positively quantify what type of uplift we saw there. But it's become kind of a standard operating procedure over much of the Eagle Ford down there. And we simply started to export it slowly but surely over time into the Wolfcamp, and we've seen these results on it in the last 2 years basically. What I would say is industry in general, and again, I think I think we do quite well with this. We collect a lot of data. But industry in general is always moving the business better, forward. There's always technology and innovation. We don't work it in an isolated box. Oftentimes, you've heard us talk about partnering with high-quality rigs and high-quality crews. We value the partnerships with our partners because this is where a lot of the technology and innovation comes from. So I wouldn't bet against the industry, being able to continue to drive forward and increase productivity. You see it with capital efficiency, not just with longer laterals, maybe not as dramatic as a 20% uplift that is unique, but you do continue to see well productivity increase, and this is the way that the industry has done it for decades now.

Exxon made a fairly big splash with their acquisition of Pioneer and a big part of what they suggest is the synergies is the ability for recovery rates to significantly improve. Do you subscribe to that?

Well, in the same way that I just did. When you go back to, again, the Utica in 2012 with different targeting, different completions technology, look at what we just did with our Wolfcamp in the Permian. I think in general, if industry continues to collect data, drill in different basins, hopefully, more of the industry continue to innovate and continue to explore. I wouldn't bet against the industry. As far as any single silver bullet that will do it, those things are usually a little bit difficult to find. But usually, it's a whole series of different incremental gains and different incremental tweaks to the formula that can, over time, start to lead to increased recovery rates. But it's something that we've seen in multiple basins over the last 2 decades almost, of unconventional gas and oil development. And again, I wouldn't bet against the industry because it's something the industry continues to prove out.

I'm embarrassed, I should know the answer to this question, but what proportion of your production is nonoperated?

What production is very little.

So my question is going to be, do you share technology with your nonoperating partners, but it doesn't sound like it's...

Yes, we're not -- we prefer to operate and part of it comes back to the return thresholds that we hold ourselves accountable to. We hold our investment in any reserve cost. So if it's a partner as well, it needs to make some of those internal hurdle rates. Otherwise, oftentimes, we'll try to trade out or come to some sort of an agreement on how to increase each proportionate share underneath what we're drilling on. So I wanted to say that we try to keep things -- maybe the best way to frame it is, it's an old saying that there's not a lot of secrets in the oilfield. I think technologies can stay a little quiet for some time, but ultimately, everybody kind of gets up to the same page. It's the companies that continue to have data, continue to innovate, that typically continue to be kind of out in front on those leading-edge technological gains.

So I'm going to go to mix, international portfolio and then cash returns to kind of close out our session. But I'd like to just go to the audience and see if anybody has any questions they would like to ask. Anyone just raise your hand and see if -- John, right in the middle.

Over on the history of the Utica and how that's sort of worked out and continue to have your exploration program out there. Is it easier to find a double premium opportunity today in the gas play versus more of an oil play?

Yes, that's a good question, John. I think North America has an awful lot of combo plays, if you want to call those as gas. Gas and gas plays, gas, as we all know, is generally easier, quite frankly. And one of the things that helps double premium is pressure, high initial rates, you get your cash recovered quicker. And dominantly, when you start drilling in deep overpressured things, things that are more mature, you're going to find a bigger cut of gas, so either a gas play or a combo play. That's not to say that there aren't a lot of oil plays in the U.S. The thing I'd continue to say is that when you're thinking about organic exploration, there have been a tremendous number of wells drilled across the U.S. There are a tremendous number of logs, lot of seismic data out there. And that's why I said, it wasn't sarcastically that I mentioned earlier, that basically everything in the U.S. right now is bypass pay, right? All these unconventional plays are basically bypass pay at some point. There are annoyances of mud gas shows when we used to drill through them to get to sand and carbonate reservoirs. And now it's just technology that's unlocked that opportunity. It started with unconventional gas because, again, John, gas is easier. These are small port throats. That's what contemplates having a large resource play, so small port throats, small sizes of porosity in there. So gas is easier to move through the reservoir. But ultimately, I'd say there's still a lot of oil that's been produced in the U.S., and I think there is still a long runway for unconventional oil exploration in the U.S.

So I guess jumping on John's question, the question of mix has come up in terms of a 5- and 10-year view with the combo players with Utica, with Dorado and so on. Do you perceive a scenario where your portfolio shifts more towards gas over time? Or what is your internal plan to show you in terms of how your production mix evolves?

Yes. Well, some of our more recent plays, including if we go -- I say recent, but really the Delaware Basin is still a very gassy basin, as you pointed out. We say that it's an oil basin, but quite frankly, oil plays typically used to be 70%, 80% oil -- [indiscernible] quite have that. So yes, I think we'll continue to grow gas and NGLs, which for me, again, I feel very confident in the outlook for gas long-term as I do for oil. And the thing about gas is you've got to be committed and I've said this a couple of times now, you've got to be committed to being a low-cost operator because your margins are small. And ultimately, you can have the best forecast you want to for gas. But at some point, you're going to have to talk about the weather which is terrible to do. So you need to backstop yourself by being a low-cost operator. The nice thing about gas is you can make up for it with volume, right? Because it has a low operating cost. It's typically easy to move throughout the reservoir. And so you can move a lot of gas and you make up for that small margins with the size and scale of it. So for us, over time, I'm not giving guidance. I'm not talking about plans. We still prefer oil. We see oil has a long runway, and the margins are more forgiving. But just the makeup of our portfolio mix, including the Delaware Basin, yes, you would say that the shift is going to ultimately get gassier. That doesn't necessarily mean that we're letting our oil decline. There's no intention of that. We still see a long runway to be able to grow our oil assets.

And on the other hand, that's happening into the LNG expansion you talked about earlier, your LNG strategy is like all E&Ps, it tends to be somewhat nascent at this point. How big would you like your commitment to LNG exports to get as a proportion of the portfolio?

Yes. I think of LNG is -- it's an exposure to another market. So that's a critical piece of it. We do that at the basin level. We do it at the company level. It's an advantage of being in multiple basins again. We see eventually, say, the end of the decade when the U.S. is a major player globally in LNG, that you'll start to see a little bit of squeezing of those prices to be perfectly honest. You'll probably see Henry Hub come up a little bit, TTF will come down a little, JKM will come down a little bit, essentially in a perfect Saturday, those prices will be separated just by freight and liquefication. But what you're going to have are arbitrages that are going to pop up. And it's going to happen when there's a blizzard in Japan or an outage in Europe or something along those lines. Well, you can't chase arbitrages, right? Everybody knows that. You've got to be kind of exposed at it at the time to be able to take advantage of it. I think about a year ago, a year ago, August '22, everybody started drilling gas wells, right? Everybody picked up a gas rig because gas was $6.50 in August, and so you know it's going to be good stuff in the winter of 2023, and what happened? By January or February, gas was headed down to -- what, $1.75 or something like that. So you can't chase those arbitrages. You need to be exposed to these different markets. From that regard, what I'd say is you shouldn't expect us to be 100% committed to LNG or anything like that. We do like the diversity of market. But again, we do foresee Dorado is going to be able to play a big role potentially there. It's right along the Gulf Coast. It's dry gas. We think it's got a very low cost operations to it. And so we're excited, I wouldn't say that we're prepared to discuss or actively looking for anything. But just as we're not actively looking for anything, I should say, we're also always in the market for good deals. When we first came out with our LNG commitments, with Cheniere down at Corpus Christi, we actually started negotiating the first one right around the time we started leasing in Dorado, which was years ago. We came out with an expansion to that agreement. Commensurate was stage 3, basically about a couple of years ago, we started discussing that one. So very, very early on and almost countercyclic, you might say, compared to when a lot of the other E&P companies have started to jump into the fray on some of the LNG deals that you've seen more recently. So we intend to continue to work our marketing strategy, which really begins with control of the asset, right, low-cost development and then diversification in the multiple markets.

I'm conscious we're running out of time, but I wanted to touch very quickly on the international portfolio. Trinidad's going to stable for a long time, cash [indiscernible], obviously, it's been a great asset for you. But periodically, you've looked at other areas, Bakken Lite, now Australia. Can unconventional capability be truly exported?

Yes. The subsurface is there, I think, I really do. The trick is there are a couple of different things for us. And Trinidad's, conventional and so is Australia. But we have tried a couple of unconventional assets in Bakken Lite, as Doug mentioned, in China, in the Sichuan Basin, we had a successful unconventional tight gas asset. And then more recently, we drilled an unconventional what turned out to be tight gas. It was supposed to be a tight oil prospect there in Oman. What we see is the difficulty is, A, finding the surface terms and agreements and environment that are actually competitive and compelling to add to our portfolio. So it's not just the subsurface. The subsurface has to be there. That has to start. But once you cross that hurdle, you've got to move above ground, and you've got to find a willing participant there. And the trick that we run into is 1 or 2 things. The first is, you guys know our company well, we're not a super major. We can't go into a country and stand up a whole new oilfield services sector. That's not us. We're smaller. We're a little more nimble. We specialize in organic exploration and things like that. So that means you need to -- we would be more advantaged to be in a country that actually has an established oilfield services. You heard me say earlier, we like to partner with good companies. The challenge that provides is if there's an established oilfield services, that means that they're established oilfield contracts there. There's already royalty and taxes and things of that nature. And oftentimes, they're set up in a way that promoted conventional production as opposed to unconventional. Unconventional is much more capitally intensive. And so it's much more difficult to make something competitive with our domestic portfolio from a returns perspective if you're trying to deal with international kind of conventional types of terms. On the flip side, if you find a willing participant on the surface there that we'll negotiate a very favorable contract for you, well, more than likely, it's because they don't have conventional production there, and they likely don't have an established oilfield services. So finding an area where all those things kind of come together and fit, that's the real trick on it. But it definitely starts with the unconventional we're not deterred. We continue to look and explore because we have had success in the past. Again, Bakken Lite turned out to be a good asset. Our acreage was tectonically challenged. In the Sichuan Basin, we had a very strong asset there that we exited right around COVID. And then in Oman, we actually tested the prospect. We drilled 2 vertical pilot wells, 2 horizontal wells. We found sand in both of them. Like I said, unfortunately, it was -- it needed to be an oil prospect to be competitive with our portfolio. It will end up going down as a discovered undeveloped kind of gas prospect.

So in the couple of minutes we got left, I'm going to hit cash returns. So maybe we could -- but I'd like to frame it a little differently because you Pearce has come in as Head of IR, tremendous we've known Pearce a long time. David was very protective of your view not to talk about sustaining capital and breakevens. Why did you feel comfortable to bring that up again on the earnings call? Because you kind of offered it, you kind of volunteered it, and all it does for me is reinforce how potentially free cash flow generative your portfolio is, which then begs the question, well, what is the right method of cash returns? So I wonder if you could address why decide to disclose a breakeven, why there's a special dividend makes sense?

Yes. The sustaining CapEx we disclosed at this time in concert with raising the regular dividend. And for us, that is an important piece for our shareholders. We want to -- we've talked about our cash return strategy. It focuses in on the regular dividend. We think that's the most important piece of it because that's a commitment to the shareholders. Hopefully, it's understood that, that's what we see as the going forward capital efficiency of the business. That's what we can support going forward. And we've never cut nor suspended the dividend in over 25 years of paying one. And to give that comfort, that's a question oftentimes we have from our shareholders is how confident are you can support this regular dividend. So that's why we brought it out. We had announced a sustaining dividend I think back in 2020 -- I'm sorry, a sustaining capital program back in 2020 or 2021 kind of under the same circumstances. And that's really why we got comfortable kind of getting there. Now as we've talked about, Doug, it is a little bit difficult for our company since we are in multiple basins. We have multiple product types. We have an ongoing exploration program of pinning down exactly what is a maintenance capital program, which is why we gave a bit of a range. That's how we talk about it internally is what would be a maintenance capital? Is it flat BOE production for 5 years? Is it flat oil production? Is it revenues on a flat price matrix? Are we investing in any infrastructure, any exploration? Or is this like, "Oh, no, the wheels have fallen off." We need to just maintain production of bare bones, which is why we kind of came in into that range of a $4.2 billion to $4.8 billion range. $4.5 billion is probably a good midpoint, but as we talked about on the call, weekend with a 10% raise to the regular dividend, we can cover that regular dividend and a maintenance capital at the higher end of that range at $45 oil. And that, I think, was something important for us to talk about again as we continue to raise the regular dividend.

And you already have the highest yield in the sector.

Something we're proud of, yes.

But you do really like the yield to be lower.

I would like the yield. Hopefully, it's getting a little lower today.

Ezra, thanks so very much indeed for being here.

Thank you, Doug.