EOG Resources, Inc. (NYSE:EOG) Goldman Sachs Global Energy and Clean Technology Conference January 6, 2023 12:40 PM ET
Ezra Yacob – Chairman and Chief Executive Officer
Conference Call Participants
Neil Mehta – Goldman Sachs
Umang Choudhary – Goldman Sachs
All right. We’re really excited here, Umang and myself to welcome Ezra from EOG to this conversation about balancing growth versus free cash flow generation. Ezra, thank you so much for being here today.
Yes, thank you. It’s been a good conference. I had some great meetings. I appreciate being back in person.
Q – Neil Mehta
Yes. It’s nice to see everyone, and a lot to celebrate over the last year in the energy sector and hopefully more to come. As we think about EOG, what do you think is underappreciated in the conversation, in the stock and in the value of the business right now?
Yes, that’s a good question. That hits right at the meat of the matter. I mean, I think what you have with EOG is, we have a very [Technical Difficulty] the rest of the E&P space here. It starts with our multi-basin portfolio. We are — we see a lot of advantages, a lot of leverage to being able to build and work across multi-basin assets base. That base has been created dominantly organically as well. It’s taking information and technology that we have from one basin, applying it to the next. And then as we develop new technologies in the new basin, we extrapolate those back to the previous basin.
Much of that inventory has been discovered and found and based and the investment decisions are all based on our premium pricing deck. That deck is a $40 WTI oil price and a $2.50 natural gas price for the life of the asset. And so, as we add new plays, new exploration areas, new basins, you think about that is that we’re only adding things that are additive to the pre-existing inventory. And for us, it’s not inventory unless it makes at least a 30% and dominantly right now, a 60% direct wellhead after tax rate of return based on that price deck, $40, $2.50 natural gas for the life of the well. I think that’s the first thing that’s underappreciated.
The second thing that’s underappreciated is the fact that we support that by being a low cost operator. And we really do that on two ways. We focus on it by utilizing technology to increase operational efficiencies, so sustainable well cost reductions, that’s just less time on location is essentially what it comes down to. Drilling, keeping a bit on bottom, not having to make trips. The second thing we do is, we strategically look for opportunities to bring different pieces of the value chain in house. Historically, we’ve done that with sand, chemicals, water, recent years we’ve been doing drilling mud and more recently things like drilling motors.
The third piece of differentiation for us is our financial policies, our cash return strategy. We’re still focused predominantly on the regular dividend. We look to increase in a sustainable manner the regular dividend, because we really think looking forward that’s the hallmark of a great company, not just in the E&P space, but across the broad market. That should be telling the investment community what we think the increasing and ongoing capital efficiency of the company is. And we’re proud that we’re able to raise that 10% this year again.
On top of that, we’ve made a commitment to return a minimum of 60% of our free cash flow every year. This year, we’re on track to exceed that. We’re able to return just over $5 billion to the shareholders, inclusive of the regular dividend. All of that is also supported by what I think is industry’s strongest balance sheet. We have a strong cash position, very low debt. And that provides us a lot of counter cyclic opportunities to make investments that otherwise we may have to think twice about.
We’re a safety and environmental leader. We’re utilizing technology to drive down our emissions intensity. We’re using technology to use things like carbon capture and storage pilot project that will be starting up this year. We’ve instituted some new technology called closed loop gas capture to eliminate flaring. And we also just announced and our rolling out iSense, which is some continuous methane monitoring across all of our assets.
And the thing that really is our competitive advantage that really makes us special is our culture. This is ongoing for 30 years now to create a decentralized entrepreneurial, really business minded interdisciplinary group of employees that work and live close into the field where we have our assets. Those are the things I think are really underappreciate and those are the things that really create a very interesting and unique value proposition for the investors.
Thanks, Ezra. Let’s start on the macro. And I know EOG over the last couple of years has really started to build out some organizational capability around forecasting commodity price and scenarios. Talk about how you’re looking at the oil balances in 2023?
Yes, there’s a lot going on, but at the same time there — you can boil it down to kind of a few things. We entered this year looking at the operational capabilities of the U.S. to kind of build a model on U.S. growth. We looked at supply chain constraints that were out there. We looked at rig utilization, frac utilization, things of that nature. And we forecasted that growth would be significantly muted from where it’s historically been and that’s what we see coming up. And we’re kind of looking at that same type of direction going forward into  (ph).
On the global scale, on the real macro though, the things that are moving forward that we’re looking at, and there’s a lot of the stuff that we talked about on the last call, not a whole lot has changed quite yet. But obviously, the Russian sanctions, how are those really going to play out? So we’ve got crude sanctions in place now. In the first part of February, we should have some product sanctions that we think will have a bit of a bigger role. And then obviously, another one on the supply side, we’ve got lower U.S. growth, but ultimately the SPR has been a very, very big driver.
When you look at what the SPR has done, we’re basically at the same level of inventory where we were roughly a year ago. But the SPR has arbitrarily added about 650,000 barrels per day on an annualized average. Now all that really came in the last six months of the year, so basically 1 million barrels a day, and that is finished. There is a small release here, there are a couple more small releases. Predominantly the majority of that is going to be done. And so, on the supply side, we definitely see some tightening.
Now on the demand side, it’s a little more difficult to see. We’ll see what happens with the recession. A year ago, I think many people thought we’re going to be here by now. We’ll see how the recession plays out on demand. What we’ve seen over the last, I would say, four, six quarters is that, dominantly energy demand use has been pretty inelastic with recession fears. But then the second one, the big one is China demand and China recovery. With zero COVID being taken off the table now, I can’t tell you when China recovery is going to come back. I assume it’s going to kind of ebb and flow. But I think it’s safe for all of us to assume that China demand is going to come back.
And so, what you see is, going out throughout this year while the front months are showing some lower pricing due to what we think is the inventory levels, heavily influenced by that SPR, you’re going to get to a spot this year where we’re forecasting pretty tight supply and demand balances.
[indiscernible] How are you thinking about the setup near term, especially after the weather really spoiled the gas party basically? And then how do you balance that versus your organic growth plans for 2023?
Yes, we’re very well positioned on the natural gas side with Dorado. And I’ll get back to that in a minute. But on the macro gas side, yes, gas is always difficult, right? Because you have to work up your oil macro first, so you understand what’s happening with associated gas. And then ultimately, you need to come to what does the weather look like, which is a difficult thing. So as we sit here today, obviously, prices pulled back pretty dramatically in the last month. And a lot of it has to do with two drivers. The first, obviously, it’s been a warm start to winter. That’s the first thing. The second thing is, not unlike the SPR, but you’ve arbitrarily had two Bcf a day kind of taken offline for the last six months with the outages down along the Gulf Coast with [Freeport] (ph). That should come back online. So you’re going to have right off the bat two Bcf a day that comes back online and helps demand.
And then the other thing that I think we all need to keep in mind and we’re watching this, we’re modeling this is, really what presented itself this past year and especially in the summer has been gas to coal switching and what the relationship is there. Not only has the U.S. retired, ultimately a lot of coal fired generation — power generation. But you’ve got an increasing power generation demanding natural gas in light of that also. And this is power generation that renewables can’t keep up with. While you’ve got that going on domestically, abroad you’ve got increased use of coal fired power generation.
And that’s really disrupted or altered is maybe a better word for it, the actual trade routes and trade flows for coal. So now we’ve got a higher coal price. It’s come off a little bit from the summer, but still [Technical Difficulty] exporting a lot of coal, plus you got the ultimate [Technical Difficulty] we sit today with gas basically at about the five year average gas price somewhere at the $3.70, $3.75 range. I’d say we’re constructive on 2023 and then I would say we’re bullish on ‘25 and beyond. And that’s because of the increased demand coming along the Gulf Coast for the increased LNG that everybody’s been well aware of.
For us, how it affects our capital allocation. You know, Dorado is a natural gas play. We discovered, it’s Austin Chalk, upper Eagle Ford and lower Eagle Ford there in South Texas. We’ve been drilling it for a few years now. We’re about 50 wells in that play and we have — what we think is identified over 1,000 locations. We think it’s got the potential to be 20 Tcf ultimately recoverable. If you think about that 20 Tcf number, one way to do the simple math on that is, that would be a Bcf a day produced for 50 years. So it is a world class resource. The finding cost competes with some of the lowest cost gas in the U.S. And obviously with it located in South Texas, the transportation fees are going to be very, very low. It’s going to be better positioned to take advantage of the major demand center in the U.S. which is along the Gulf Coast, not just LNG but also petrochemical.
For us, that’s not — it’s a play that eventually we’ll be able to flex on really quickly, right now it’s so early. We’re honestly still making progress on completions designs. We’re still building out some of the infrastructure, sand, waterline, things of that nature. So for the next couple of years, it’ll be really investing in that play with two kind of bookends on it. The first is, when would you end up overcapitalizing that? Well, for us, that’s simple. It’s the same as any other portfolio or any other asset in our portfolio. You overcapitalize the minute, your returns start to decrease or your finding cost starts to go up. That’s a simple way to look at it. All you need to do at that point is just pull back a little bit, allow that theme I talked about, the culture of our company, allow them to understand what they’re doing, allow them to catch up, give them the tools that they need to either increase that well productivity or drive down the well costs.
Now that’s on the overinvestment side. Now on the underinvestment side, that’s a risk too. Because think about what I just talked about, the culture of our company, it’s continuous learning, its continuous improvement. And so, you need to fund each of these assets to a degree so that they’re continuing to build out infrastructure, learn about the rock, learn about different landing zones, how to complete the wells and ultimately continue to not only technically learn, but also move further down the cost curve due to capturing the economies of scale, which is always an important thing in these unconventional plays.
So given where gas prices are right now and I agree with you that Dorado is very much low on the cost curve. But the long term outlook for gas prices are much more robust. What do you think about pulling back [indiscernible] what gas price would you say. Like, you know what? These assets are much more valuable if I break them on 2025 versus in 2023.
Yes, so the premium strategy of the company. It’s an amazing thing to think about. It makes us somewhat agnostic to the actual gas price, because we’re making our investment decisions based on the $2.50 natural gas price that we run internally. Those Dorado wells, we have line of sight that they’ll be generating double premium returns. Which I know everybody thinks double premium is really funny. That’s just how we talk about it internally. It’s a 60% direct after tax rate of return on, in Dorado’s case, that $2.50 natural gas price.
So the ultimate thing when we think about capitalizing these projects, Umang, it gets back to the fact that what is the right amount of capitalization for it? First, obviously, you need to look at the macro. But like you said, we’re assuming longer term outstanding growth and the market needs the molecules. So then it really does come down to the fact that we want to make sure every single year that asset is continuing to improve. Now it’s just $0.01 for Mcf is improvement on that finding cost. So the many you start to go the other way while you could still be generating upfront really high cash returns, those higher costs are going to stay with you. They’re going to go into the cost base of the company. They’re going to end up raising your breakevens. And we all know that times are good in cyclical businesses, but they don’t always last. Things go the other way.
And at EOG, we’re focused on shareholder value creation through the cycles. We’ve done a lot on focusing on this premium price deck, basically taking pricing control into our own. A lot of people say that our industry are price takers. What we did is, we basically turned that on its head and we said no, we’re going to go ahead and make our own price, we are going to be a price maker and we’re going to make our investment decisions based on this price, because we think this price is not sustainable through the cycle. What that means is, we’ve done as much as we possibly can to decouple ourselves from the inevitable commodity price cycles even though we’re an oil and gas company. That’s what we do.
So in the next 20 minutes, Ezra, let’s spend some time talking about the assets and then spend some time talking about capital returns and capital allocation. Just to start on the asset, one of the things we’ve done with some of the producers is, as the CEOs talk about the walk from ‘22 to ‘23, recognize many of you are going to provide official and fine tune guidance in the couple of weeks. But what kind of bread crumbs can you leave us with as we think about ‘23 off the ‘22 days?
Yes, I think part of it goes back to our story being a little bit different, the fact that we do have multiple assets across multiple basins. And so, when you think about that, part of the way to think about our structure is, where are each of those assets in their lifecycle? So we start with the Utica. The Utica is very early on, so we’re still doing a lot of delineation there. We’ll be doing some spacing tests, things of that nature. So we talked about on the last earnings call, we’ll be drilling roughly 20 wells there is what we anticipate doing for next year. In Dorado and the South Powder River Basin, making fantastic progress there. We don’t have all the infrastructure, not necessarily gas takeaway and things like that, but again, sand, water, things of that nature.
We understand spacing. We’re making — we understand landing zones where we’re tweaking those in combination with the completions designs. Both of those, you can anticipate should be seeing a little bit more activity from what we saw this year. But again, those are at that critical point where you want to make sure that you’re not moving too fast. They’re what we internally refer to as emerging plays, not an exploration opportunity, but they’re emerging, they’re headed towards one of our core assets. Obviously, right now, the Permian is core. The Permian is in the sweet spot. We’ve got our infrastructure. We’ve got over 5,000 vertical feet of productive opportunities across six different play types. We probably have something like 20 different landing zones in there depending on where we’re at geologically.
We’ve got a large asset team out there that lives and works in Midland. They tear apart the data every day. They’re planning each of the wells, not through manufacturing mode, but actually looking at the geology, looking at each drilling unit individually and figuring out what the best spacing and targeting is to kind of find that balance between returns and ultimately NPV. And so that one, the thing about the Permian right now though, when you transition from ‘22 to ‘23 is, things out there are very tight. They’re expensive and they’re tight. And so again, we like the level that we’re working at. We’ll probably — we’ve talked about carrying a pretty consistent activity level across the year.
And part of that again goes back to — pricing is up right now. And so even though well costs are up with the inflationary pressures, you still got expanding margins. Why don’t you lean in a little bit harder? Well, that is taking the last six years’ worth of premium drilling and discipline and throwing it out the window. We want to remain disciplined and move at a pace where even though we’ve offset a lot of the inflationary pressures out there, we haven’t been able to offset it all. And we have been able luckily to increase the productivity gains in some of our wells, which helps to offset the well cost and continue to lower that finding cost and that’s what we really want to stay focused on.
So pretty flat activity level is probably, let’s say, forecast there. And then lastly would be some of our longer — the assets that are a little bit longer in the two, like the Eagle Ford. The Eagle Ford is not really a growth asset anymore. We’ve slowed down there. We’ve put the sales roughly 100 to 125 wells per year. But the amazing thing about the Eagle Ford is, and this is a great example of what happens when these assets kind of go through this life cycle I’m talking about is, it’s not unlike the Boston Consulting Group chart where you end up being at cash cow. In the Eagle Ford, even though we’re drilling less productive rock than we were six, seven, eight, nine, 10 years ago, in the last two years we’ve actually turned in the highest scorecard, the highest rate of return results than we’ve ever had in nearly 15 years of drilling in that asset.
And even though the wells are less productive, the well costs have come down significantly. We’ve learned more about the asset. We’ve been able to put in infrastructure. Things like water reuse, localized sand, things of that nature do a lot to save not only an operating cost but upfront cost.
The last year, if we think about the cross side of the equation, last year if we think about the opportunity set, you talked about super zippers, you talked about moving to longer laterals. There were some secular drivers which could improve the cost structure down. When you think about 2023, what are the things which you’re evaluating in a toolkit which can help cost come down as well?
Yes, this year — last year we did make a big shift into zipper fracs, which saved — yes, super zippers or whatever we need to sign more fracs, whatever they are called. But yes, we made a big shift there and that helped to offset quite a bit. The other thing we did though is, we were able to just actually spend less time on location. Drilled times went down across the board. This year — every year we have incremental gains like that. This year we’re going to lean in on some of the things and they’ll be probably to a little bit smaller of a degree, but they’ll still help offset much of the inflationary pressure that’s out there. Things like drilling motor, our drilling motor program in which originally we took drilling motor kind of QA, QC in house. We’ve taken out a bit step further. And the big thing about drilling motors is making sure especially in these longer laterals, when you start drilling fast, when you start drilling a two mile lateral in say seven days. If the motor dies when you’re in the middle of the lateral and you have to trip out, it’s potentially a 12, 18, 24 hour trip time on a seven day well, that’s a lot of added costs. It’s not just the cost of the motor, it’s actually that time on location.
So motor program is going to pay off to be a big one here for us in the future. And then we’ve got some other things like drilling mud. We continue to optimize not only the mud properties that we have, the chemical properties where we need to use, let’s say, the [indiscernible] of mud and where we can get away with a little bit cheaper of a mud system. But most importantly is, balancing out the right mud weight. Too much mud weight, not only will break down potentially formation and lose that mud, and mud is made out of oil. So I guess expenses, especially when you’re trying to make oil. But the other piece of it is the higher your mud weight, obviously, slower they’re out there drilling. So those are some of the tweaks we’ll have.
Right now, we’re forecasting potentially another 10% increase on the inflationary pressure on the well cost side kind of going ’22 to ’23.
Great. Let’s talk about some of the assets. You unveiled the Utica recently and we talked a little bit about it in Texas a couple weeks ago. And at first, I think the investor reaction was, is this a gas plan? I think you’ve clarified, it’s actually a liquids play. And given Utica was a little choppy before, what gives you confidence that this time is different?
Yes. We’ve been looking at the liquids fairway here in the Utica well for a number of years, kind of passively and monitoring some of the activity, not only going on in the deep part of the — hot part of the gas window, but also as you come up into the condensate, you can get close to the liquids fairway. And what we’ve noticed there is, there’s a lot of upside to be applied on the completions. And it’s a lot of what we’ve learned from mechanical stratigraphy of working recently on plays like the Wood Ford, the continued progress we make in the Eagle Ford and some of the work that we’re doing on the Leonard Shale or the Avalon Shale.
And once you understand kind of the subtleties in these shales and how the GM mechanics work, that introduces landing zones to you and you can combine your completions technology. And we’re talking about things like cluster spacing and stage spacing and diverter and the way you’re pumping your sand and water, these things that have been talked about in the past. And when you apply those, you can really start to get some upside.
We have some proprietary software in-house that we’ve developed. It’s reservoir modeling — that when you put in the geo-mechanical parameters, the rock type, the processing and permeability, how it’s going to break and combine that with some of the completions technologies, you can really start to get a forecast of what you think the well will do. It’s basically a predictive analytics tool. And that’s what we started using in a lot of our exploration plays, but that’s where it really panned out in the Utica.
Now the nice thing about the Utica is, there is enough activity up there that we’ve been watching people drill. We’ve been watching people land their horizontals, we’ve been looking at how they’re completing the wells. And we’ve been able to confirm and prove up this forecasting tool that we have. And that is ultimately what gives us a lot of confidence on where that play is going.
It’s not like the depot Utica. It’s a very benign environment. It is overpressured, but we feel that we’ll be able to drill three-mile laterals as a standard. Many operators are already doing that. Completions designs are right in our Bailey Wick like I described with the shale structure that it sets up.
We have two slightly different geologic environments to the north, it’s a little bit thicker, to the south, it’s a little bit thinner, but you get more robust frac barriers. In the South, we also — over the entirety of the trend, we have about 400,000 acres under lease, it’s about 200,000 acres in both the North and South. And in the South end, we actually have purchased 120,000 acres worth of mineral rights, which also gives a massive uplift, not only to wellhead rate of returns, but really through the cycle kind of full cycle returns.
Going back to your base assets, including the Delaware, EOG historically has had premium levels of productivity. You have seen competitors catch up to you as natural, right, because just the life cycle, how are you seeing the productivity as you compare to your peers into ’23?
Yes, a lot of it kind of depends on where you’re drilling. The first thing to keep in mind about the Delaware Basin is, the difference is from west to east. On the West side, actually, we call that even a combo play, similar to what we were just talking about in the Utica. We’ve got a Wolfcamp and a Wolfcamp Combo play in there. And it comes back down to the ultimate reserves, how much of it is oil versus oil NGLs and natural gas.
And so, when you’re looking at productivity, we need to keep in mind a couple of different things. Where are you actually drilling in the basin geographically? And then what are the specific landing zones that you’re looking at? For us, we still feel very confident on what we’re seeing with our well productivity, our capital efficiency in the base. I think a lot of that — since that is the main driver for us, you can see that evidence last year on our quarterly performance as far as production and CapEx spend is that everything fell right in line.
With regards to the peers, there are a lot of peers out there, and it kind of depends on where you’re at. A lot of the wells that are being drilled now are dominantly being operated by independents with acreage and not necessarily the same areas as our Red Hills acreage or anything like that. And the peers that are closer by to us, you just need to look at the different landing zones, the different spacing, the co-development that’s going on, because each of us has a bit of a different kind of technique on how we exploit the resource.
For us, as I said, our team is focused on every — each and every drilling unit trying to co-develop and we’ve been doing this for years, co-develop those targets that are going to be in geo-mechanical communication with one another. And we do it in such a way between spacing, whether vertically or horizontally such that we can optimize returns and NPV of those drilling units. We don’t want to leave anything on the table by spacing the wells too wide. At the same time, we don’t want to start to erode the returns by spacing those wells way too close.
Yes. Let’s go back to Dorado. It’s a very interesting play. How has the productivity and cost trending to your internal expectations for 2022? And then when you think about Dorado and how it fits into your energy strategy, which is obviously increasing over time, can you maybe expand a little bit on that? And how do you think of your LNG strategy evolving as well?
Yes. Yes, it’s a great question. So Dorado in general, and the reason I say it’s going to command more capital in the coming years is because, the performance on the learning curve has been moving faster, at a faster pace than what we’ve typically seen in a lot of our, let’s call them, again, emerging assets or emerging plays.
Our asset team down there has done a great job reaching out across the other basins and basically borrowing every good idea that they’ve seen out there and implementing it as quickly as possible, which is kudos to them for being interdisciplinary and looking out there and keeping an eye on what else is going on in the company. Well costs have come down. We’ve done a tremendous effort on there, even though — well, I should say operational efficiency is coming down, drill times are coming down significantly, it has been difficult with a limited program down there to be able to offset some of the inflationary pressures.
And then on the well productivity side, they’re fantastic wells. It’s amazing the productivity of these, and dominantly, we started out drilling on the Austin Chalk knowing that we had potential in both the Upper and Lower Eagle Ford. Honestly, I thought it was probably going to be a couple of years before we got into co-development down there. And credit to our team, again, the asset team and the frontline employees. There are some areas where they’re already — they’ve already moved fully into co-development. They’re already drilling Austin Chalk, Upper Eagle Ford and Lower Eagle Ford, like I said, probably at least a year before I really thought that we would be there.
So if we go back again to what we talked about briefly before, we think it’s some of the lowest cost gas, especially to the Gulf Coast with transportation and G&P really across North America. So it’s not just how does it play into our LNG strategy. But really, how does it play into the U.S.’s, North America’s LNG strategy, because it is a significant resource located in a great spot for it.
If you guys recall, we were some of the first movers here in getting some LNG agreements done. We’re currently — we currently have exposure to do140 million a day on an LNG contract, where it’s a gas sales agreement. We sell right there, FOB kind of at the dock. And so we don’t have any risk. We don’t have any exposure to buyers overseas or anything like that. But we are seeing some upside to the pricing. And that’s actually with what we saw over the summer, obviously, it’s actually showing up in our realized pricing, which is fantastic, it’s great to see. And we started negotiating that contract probably about four years ago, honestly, right, when we were kind of early on exploring in Dorado.
Since that time, about two years ago, we actually negotiated an extension and expansion of that contract, and that’s the one that we announced earlier this year. Again, it’s similar. It’s a gas sales agreement, and it takes our total exposure on the LNG side up to 720 million a day. And that’s commensurate when Sage 3 starts up with Cheniere in Corpus. And we’ll have a couple of different pricing contracts on that. We’ll have 300 that’s getting exposed to international pricing. And then — I’m sorry, 420 that gets exposed to international pricing and then 300 that’s getting exposed to the domestic pricing and getting shipped offshore.
So for us, when we look at it, LNG is another way to diversify our exposure on our marketing agreements. And whether it’s at the corporate level or at an asset level, one of our strategies is to be able to sell all of our gas and oil into multiple markets. When you think about us at the asset level, we do all of our in-basin gathering, we usually deliver it to a sales point, and that sales point will be an area where we’ve got two, three, four multiple markets that come in. The reason for that is, we do think that arbitrages are created, and we don’t want to have to try and chase arbitrages. We want to be able to be exposed to the arbitrages when they present themselves, because we think the market is pretty efficient, and they won’t last for very long.
It also allows us to bypass any bottlenecks or downstream interruptions. So part of our strategy is really to have control and diversification, not only diversification regionally or geographically, diversification of product type, but also diversification to the marketing exposures, what we’re selling into. And we consider LNG to be the same type of strategy.
So Ezra, when you roll this up, you’ve walked through a lot of different assets, how should we think about your 2023 production profile for — on an oil basis, gas basis and then or I should say, on a Boed basis?
Yes. So what we talked about on the third quarter call and things haven’t really changed from then. And so on the oil side, activity level is probably pretty consistent. So assuming things don’t dramatically change, which they haven’t in our minds since early November. You can probably expect similar rates of activity and similar rates of oil growth to what we saw in 2022. So kind of that low single-digit type of range.
On the BOE side, obviously, we’ve talked today about a little more allocation to the South Powder, a little more allocation to Dorado. We also have talked about — we didn’t talk about today, but we just got a platform in Trinidad, so we will have increased international drilling and that’s a dry gas play. So a little bit of increased natural gas down there. And so the BOEs that flow out of that will probably be in that double-digit range.
So we’ve gone — this whole session we haven’t talked about return of capital, and we only have two minutes left, but you are in a net cash position. And so talk to us about the way you’re thinking about returning capital to shareholders from these levels.
Yes. So there’s — the first thing, let me say is, being in a net cash position is a strategic advantage, and it’s a great place to be in a cyclical business with what we can see has been — can be very volatile, very quickly. It’s what allowed us to make strategic acquisitions like in the Utica, when we bought the minerals there.
It’s what allows us to be opportunistic and pre-purchase pipe that we’re now installing down in Dorado, things of that nature. So it’s a fantastic place to be. And quite frankly, I think we’re kind of unique because we do have a cash return framework out there. It’s a minimum of 60% of our free cash flow will get returned. Again, that includes — that incorporates and the focus hopefully is still on that regular dividend because that’s an important piece, like I described at the beginning of this, but not only have we returned in excess of 60% of free cash flow this past year, we’ve been able to reinvest in the business, which is still, when you’re reinvesting at high returns, the best way to create shareholder value, and we’ve been able to strengthen the balance sheet over the last year.
Those are the three things that I think we’re in a very unique position to do it. And it’s really because a lot of the things that we talked about today, our focus on being a low-cost operator, our focus on being in multiple basins to allow technology and data drive our improvements. The fact that we invest on a conservative, fiscally conservative, fiscally disciplined price deck, and I think that’s really, again, what separates us from many of our peer companies.
Yes. Very good. Well, great. Ezra, thank you. Thank you for being here in Florida. I wish you a wonderful 2023, and we’ll talk to you in a couple of weeks on the call.
Great. Thank you, guys. Really appreciate everybody, and really appreciate everyone attending.