joining us, and Tim Duncan, the CEO of Talos, is sitting to my right. Tim, thanks for joining us.
Thanks for having me.
So just quickly before we start, maybe a short overview of your business, just to give everybody a flavor for what-
Sure, yep
... you do and where you're positioned.
So Talos Energy is a company that I was able to start 12 years ago using private equity capital. It was the third company that we started. We had built and sold two companies from 2000 to 2012, sold one to Woodside, we sold one to Apache. So Talos was kind of round three, and everything we had done in our careers as founders had been offshore. And if you look at 2012, when we started the company, obviously, a lot of that capital was running to onshore, and our thought was, "If we stay here, there's gonna be a lot less competition, you know, for assets." And how the basin works. So Gulf of Mexico, and I know many, many have studied this, but it's still the second-biggest oil-producing basin in the country. It actually has the biggest geological column.
So think about geographically, it's huge. Geologically, it's huge. So you can have production from five to 30,000 feet, and most of it's aggregated by four owners: BP, Chevron, Shell, and Oxy, and that's 70% of the production. They typically don't want to be the last owners of an asset, and they're not buying each other's PDP, so the flow, the deal flow's different. So our idea was, "Look, let's stay in the Gulf. Let's continue to look for assets that are less strategic for Shell." They were put in place, they spent billions of dollars. Maybe they were trying to develop a couple of 100 million-barrel discovery. At some point over time, if that's less strategic, the second owner can come in and buy that at a fraction, and then look for new opportunities using seismic technology.
So we've built companies being the second owner of assets, buying at a low entry cost, and then drilling opportunities that are 5, 10 miles away from that infrastructure, getting good margins, typically oil weighted. So where we are now, over 100,000 barrels equivalent a day. We've built this thing now for 12 years. You know, the model, that strategy of doing M&A as a means to an ends to lower breakevens on the drilling side has benefited us well. We've never had financial distress. This isn't a story. If you think about being around 12 years and what's happened over the last 12 years in E&P, I think we're one of those companies that have had a consistent way of building this business.
Great. And maybe we'll start with sort of your 2024 and 2025 drilling program, and you talked about your production.
Right.
Maybe talk about what your drilling program is really focused on right now, and how we sort of think about production-
Yeah
... relative to CapEx.
So we got off to a nice hot start to the year, and that's because, you know, again, consistent with the strategy that we just talked about, we had a couple discoveries in 2022 that were right offsetting a transaction we did a couple of years before, which was a Shell facility called Ram Powell. We studied everything going on geologically in the area. We found two deposits within 15 miles. One was called Venice, and one was called Lime Rock, so we kind of named these prospects. We spent 2023 hooking those up. So you're finding these wells that can deliver rates at 8,000-10,000 barrels a day, and you're trying to get them into your production facility within 12-15 months. 20 years ago, that takes 5 years, right?
Mm-hmm.
These are much shortened cycle time if you own the infrastructure. All that was a lot of the capital spend in 2023. As we went into 2024, those two wells are coming online at 19,000 barrels equivalent a day gross, so now they're producing. We announced a transaction in the first quarter that we think has a really interesting asset, and all of that lifted us over the 100,000 barrel equivalent a day mark. Now, there's some timing related to that, and there's a presentation that gets to where we guided the business because of the timing of the close of the transaction. We guided 89,000-95,000 barrels equivalent a day.
If you're trying to do a quick run rate on EBITDA, you know, if you think about our business, our netback margins are typically around $40 a BOE, which is some of the highest netback margins per BOE in the E&P sector. So, so that, that's where production is. You know, we're. We had, I think, a very strong first quarter. It was a production beat, an EBITDA beat. It was a CapEx beat. It was a free cash flow beat. I think the challenge that we're having right now, a little bit in the stock, is some of those holders and some of those private companies we were able to roll up, there's been some lock-ups expiring and things like that. But the operational performance of what we're trying to do right now, I think we're as healthy as we've ever been.
We just refinanced the entire cap stack with the recent transaction. All our maturities got pushed out, so we're in a really good spot.
Okay. And you just 'cause you mentioned the first quarter and the challenge, the second quarter, you have downtime on the,
The HP-I.
HP-I.
Yeah.
What's the rationale behind it, and-
Yeah
... is it on, is it on track?
So, the HP-I is a vessel that a service company, Helix-
Yep, I know Helix.
... is the owner of that.
Yeah.
Sure. So they're the owner of that vessel. They really, their job is they own the ship, and they try to keep it stationed, and this is one of the few dynamically positioned production units in the Gulf of Mexico. So they call those FPSOs globally. We don't need to store the oil. It actually flows up through our subsea infrastructure, up into a buoy, and then it, the oil gets processed, and we operate the oil facility, the handling facility on the ship, and then immediately goes into a sales line in the same buoy, so nothing gets stored. And then, if a hurricane comes, that buoy can actually disconnect. The ship moves away, comes back, and we hook it right back up again.
To keep those thrusters in that ship and to keep it healthy enough that it can constantly reposition itself, every two and a half years it has to go into a dry dock. This was the cycle of that dry dock. We thought it would be a little bit into the first quarter, but it looked like it moved to the second quarter, and a lot of that's just dry dock availability. It was down in Galveston. I can tell you right now, it's left dry dock at, you know, a couple of days ahead of schedule. That's not breaking news, because if you're in Galveston, you'd watch that ship-
Yeah
... sail right the hell out of there. And my dad happened to... Yeah, just a fun story. My dad was renting a place in Galveston over the weekend, and he sends me a photo Sunday morning. He's like: "Isn't that your ship leaving?" I'm like, "Damn right, it's leaving, and it's heading right back to where it's supposed to be going." So, that'll arrive back into the field in the next week or so. It does some testing, and then it hooks the field back up within the guidance that we provided around that dry dock.
Yeah.
And so, that's an important asset. And again, that's an asset that we bought from Chevron, that when we bought it, Helix had put a solution in that ship for those subsea wells. It was expected that field would last maybe another five years. We bought it reflective of an asset that might only have five years, and that was 12 years ago, and it still has five more years. And so we had a big discovery a couple of miles to the south that ultimately brought that asset, that we bought around 10,000 barrels a day, at the time, in 2013. I think it peaked at 40,000 barrels a day. So, you know, not only is it a really cool infrastructure story, it's a really cool subsurface story on how our strategy works.
... do they own the asset, and then you?
We rent that from Helix.
You own the processing, and you own the processing?
That's exactly right.
Okay.
And it's a great relationship we've had with them. That relationship, you know, through that asset, has allowed us to develop other relationships. We entered into a five-year plugging and abandonment JV with the Helix guys as they try to build out that business.
Mm-hmm.
We're a very good partner with those guys. They've been a good partner to us.
Gotcha.
Yeah.
Okay, good. You know, one of the things that, when we think about global oil production, and we think about international, and we think about offshore versus onshore, we think U.S. shale is short cycle, and we sort of think-
Yeah
... deepwater is very long cycle.
Right.
I think you guys sort of think about shorter cycle offshore, in the sense that I think you just mentioned, you can bring stuff on production in 12-18 months.
Right.
How do you think about the investment decisions and sort of your parameters around what type of commodity price environment and sort of the duration of that when you're making investments in new projects?
So, so a couple things. One, I mean, if you think about the Gulf of Mexico, I started my career as a young engineer at Hess, and we were, you know, we were installing infrastructure. That's what you were doing. You were installing a lot more than you were taking out. I mean, that's what the basin was. The basin's evolved since then, and so, you know, I'd say... I would tell you, in the last 20 years of building companies, we now own 30-plus big deepwater facilities. We've installed none of them. Now we're purchasing those. So you have to think about what we're trying to do in two types of planes, if you will. How we do M&A, and that is, how do we get ahold of this infrastructure that we think is important to help develop inventory?
You know, when you own a deepwater infrastructure, you're looking 30 miles from that infrastructure, and then that's where we focus in on the seismic and the seismic technology. How do I sharpen an image around this infrastructure? And that's how we develop the inventory. So you can go get on our slide. We're now the fourth-biggest owner of acreage in the Gulf of Mexico with a startup, you know, 12 years ago. And, and we're the fifth-biggest operator. And a lot of that acreage is centered around that infrastructure. Now, how we do that M&A really is reflective of what's the price deck, what's the strip, what's the bid-ask spread?
We typically are buying inside proveds, so unlike onshore, you know, we're not saying, "Hey, why don't you allocate this much for the, for production and this much for acreage?" It's all inside proveds, so whatever we do outside of that is upside to us. And so once we transact on that, and we own the infrastructure, we are typically planning the business in a $65-$75 environment, but because of that infrastructure, these breakevens can be well under $50. And so if you look at the things we're drilling this year, and you look at Venice, Lime Rock, those have much lower breakevens 'cause I don't have any construction costs other than the subsea development and tie-in cost. I'm not trying to build new facilities. That allows us to get what I would call that middle market prospect.
So to make this basin work, you don't want to just go do M&A, 'cause if all you're doing is M&A, and if all you're doing is simple, proved, undeveloped hub locations, you can become an obligations manager, and that's not what you wanna do. You don't wanna just do exploration, 'cause if you just do exploration, then you might drill something today that doesn't hook up for three or four years, and you could have a different cost of goods and a different revenue-generating environment. We believe in owning the infrastructure and then letting all of the risk reward of the basin, development, exploitation, even exploration, all of that be in your inventory, but utilizing the infrastructure. And so that's so we play across the risk spectrum that allows you to play across the geology of the basin, and that's where you get the benefit.
So we could drill a development well, and it's 1 million barrels, and it flows 2,000 barrels a day, or we could drill a 25 million barrel prospect that comes online at 10,000 barrels a day. The critical part of this is to utilize the infrastructure and really raise your operating margin, lower your breakevens on the CapEx side. So that's how we think about it.
Is there any way to think about whether you can tie into existing production structure or if you need a new production facility, the gap in sort of cost breakevens?
I think, you know, I think you'd have to find something right now that was just really big. So we're gonna drill a prospect called Daenerys, and don't make fun of that. Our geologist was a big Game of Thrones fan. And we let him name the prospect. But it is a legitimate structure, a geological structure at 28,000 feet that you just couldn't illuminate 10-15 years ago. And now, advancements in seismic technology, we're gonna go drill that structure. We put together a partnership fairly easily. There is a facility within 25 miles if you find 50-75 million barrels, which was highly economic. You can just hook up two or three wells and get that going at 25-30,000 barrels a day. We would love for that.
But if it's really as big as it could be, that could be one of those that you say, "Hey, look, we should think about constructing a facility to manage something like 100,000 barrels a day over the long haul." So yes, there are certain size discoveries that you actually would say, "This justifies a new build." But a lot of what we're doing in the market is similar to what we're doing in our Katmai asset that we bought in the QuarterNorth, similar to what we did around Ram Powell recently in Venice, Lime Rock, and that's, I'm bringing on a well, 8,000 to 10,000 to 11,000 barrels a day. It's within 15 miles. I can hook it up in 15-18 months if I use the infrastructure. So why spend 5 years if I can accelerate it into 18 months?
I would tell you, back to your earlier question about onshore, there's no doubt in these onshore plays, whether that's the Eagle Ford, whether that's West Texas, that you're gonna drill a well, and you're gonna complete a well. There's still a log-normal distribution of results. They don't all look the same, but they do hook up fairly easily. The basin, I think, you know, one of the myths right now around the basin is the cycle times are really as long. They are certainly longer, but they're not, you know, 20, 20 years ago, that 7-year, 5-year cycle time. We've done a pretty good job condensing that to 18-24 months for some impactful wells, and that works because our corporate decline isn't as bad as quick, if you will, as so many onshore plays.
We have more of a 20% base decline, some of those onshore plays may be 35%-45% base decline.
... And the difference in cycle times is that it's infrastructure, obviously.
Sure.
But is it also other technol- what else has kind of played into that?
You know, it's the technology, I think, where the technology helps is, you know, we've got more certainty on how these drill these wells. We have better cost control on how we drill these wells. There's better flow assurance on how we think about... You know, look, it used to be, "Hey, if you're gonna flow a certain type of oil, I don't know if you can get it that far." And now, with better subsea insulations on the pipe and better flow assurance in how we think about chemical treatments, better understanding where we put, now we're seeing subsea pumps and some other things and better technologies. We can get more comfortable that more things can happen in a tieback environment, where I'm able to go a little further.
Because once you lose your belief system that I can go that extra five miles, 10 miles, you start to compel yourself to build on site, and now you're, now you're adding more cost, and you're lengthening the time to first oil. So, you know, it's absolutely infrastructure. That's the beginning and the middle of where we shorten cycle times, but it's really more confidence in an ability to do a project that maybe you wouldn't think was a subsea tieback candidate five, seven, 10 years ago because you didn't wanna go that extra-
Yeah
... distance or something like that, that now you're willing to do.
Okay.
You know, so.
And anybody in the audience, anytime, if there's questions, just we'll take them. You mentioned the ability to illuminate the deeper formations. Is that with new collection technology on the seismic front, or is it-
Yeah
... new imaging, or is it processing, or is it kind of a combination of both?
It's all of it. You know, you start with, you know, and this is gonna get a little nerdy on how all this comes together. But you start with, you know, Moore's Law. Computing speed is effectively doubling every couple of years, and so much of seismic is not just how you acquire seismic, so where you have a source, and you're shooting, you know, sound waves into the ground, and then you're trying to figure out how quick they come back, and that creates an image. And so how do you do the algorithms that do the iterations that process that image? And then, after you shoot a survey, four or five years later, you may wanna tighten that image.
So, if I'm shooting a survey over a large portion of the Gulf of Mexico, and Shell does this every three or four years, or BP, they're constantly shooting these surveys. They're doing it with companies like TGS or, or CGG, or some of these companies. Some of these are European-based public companies.
Mm.
Right? So they're shooting these surveys, and they specifically are trying to image all the way down to, say, 30,000 feet. They have to make an assumption of what salt- where salt is and what the velocities of the sediments are across a very big area. Now, let's say I go in and do a transaction, and I'm buying four or five facilities in a much smaller area of a bigger survey. I'm going to tighten that image. I'm going... I, now I have better well control, and I know in my focus area, how to think about the sediment velocities. That's where I reprocess. I'm re-imaging in a smaller subset of a bigger survey to really understand where salt is, where salt isn't, what the formations should look like, and with that crisper image, it unlocks something that I may not be able to see regionally.
If Shell or BP is shooting something regionally, they're probably looking for some big, deep structures, and they don't need to have perfection of some of those velocity ideas regionally. But once you go local, you're looking for those same structures, but you're also looking for that middle market, 20 million barrels, 25 million barrels, that the Shell and BP may have never been looking for in the first place 'cause that's not material to them, but it's material to companies like ours. So, you know, the ability to illuminate, sharpen an image locally on a seismic data set that was shot regionally, that computing speed really helps. And so techniques on the algorithm changes, computing speed, and then just your geologist understanding of sediment velocities changes the imagery around where you just did a transaction.
So it's not a surprise if you go look at the maps, and you see where our infrastructure is. That's where the acreage growth is because that's where the reprocessing projects are, and that's how we've built these businesses. We were doing that in shallow water 15 years ago, but then, when we built Talos, there was so much infrastructure put in deep water in 1999, 2000, 2003, by the Shells and the BPs and the Chevrons and the Exxons of the world, then they become assets that are interesting in 2014 and 2015. And so that's how you see the turnover, and that, that's what the strategy's been.
Okay.
What's interesting about it for us is, again, there's just not a lot of us out there. If we tried... The barrier to go build something in West Texas is pretty low. The barrier to build something in the Eagle Ford - the barrier to start a new company in the offshore, there's not a lot of private equity raised now compared to 10 years ago. You're not gonna put a 10-bank credit facility together offshore now, that you could do 10 years ago. So we're in a really interesting spot for us to be able to both grow our business organically, just using the strategy I told you about, do small things tactically, or continue to think about bigger M&A ideas because, again, I do think the holders of the biggest assets won't be holders of those assets forever.
Got it. Okay. Has the, the, on the multi-client seismic side-
Yeah
... has that become less significant because there's less clients, so is it more contract folks?
No, you always need a multi-client to underwrite those surveys.
Okay.
Someone's gotta take the risk of shooting them, right?
Yeah.
And again, give the basin credit. Once we've figured out how to get below salt, it was like, "Oh, my goodness, there's another 10,000 feet of section below here.
Yes.
We should be exploring it." And so, you know, and I think you could go get on Shell and BP and Chevron's analyst deck right now, and they're gonna tell you the Gulf of Mexico is still a critical asset for them. But again, it's not an asset that they're trying to redevelop. It's not an asset, like in West Texas, they're trying to find an extra bench. It's an asset where they're truly trying to explore and develop, maybe not own, and ultimately, you know, again, P&A later. And so there is a spot for us. Now, here's a fun fact in everything I just told you. I've been doing this 20 years. I've had teams of young geologists, older geologists, just building companies. You know, and talk about just starting companies from scratch.
We've never shot a seismic survey or been the underwriting participant of a multi-client survey. We've only bought stuff that somebody else underwrote. Fast-forward 5 years, now that project, now that asset might be not as critical an asset in the portfolio, and then that's where we transact, and that's where we re-image. And-
Do you re-image or do you just reprocess? Is it, or-
Well, I'm saying... By saying that, I'm saying the same thing, where we reprocess-
But you don't go and reshoot the data.
Yeah.
You just have better computing power-
Right
... to compute what was there.
Right.
That's what I thought.
That's right.
Okay. That's thought.
And it's not that we are-
Yep
... wouldn't participate in a multi-client, there's just, these data sets are so well shot-
Yeah
... typically by someone else, regionally, we just need to tie it up locally. So there's no real need for us to be involved in a brand-new shoot and take the underwriting risk of a brand-new shoot.
Makes sense.
Yep.
We did a dinner last year, and I think someone from your firm was there, and we had-
Was that with the service guys?
Yeah, the deepwater.
Yeah, I was there.
You were there-
With Jeremy, and the guy-
With Jeremy? Yeah.
I had to sit up here with Jeremy-
And Jose
... and he's like, "Yeah, it's gonna be like," and I'm like, "What do you think, Tim?" I'm like, "Oh.
And Jose-
They're dear friends. I mean, I'm glad those guys are having success.
One of the things that came up, and it might have been the folks from Seadrill who said that, but they said-
Yeah
... no, it actually wasn't Seadrill. It might have been you guys, actually, yeah. But we'll never build another deepwater rig.
Oh, it's not me, that was them.
So, and Jeremy didn't like that. But where, where do you think we stand on kind of availability of rigs, pricing of rigs, and kinda how that kinda impacts your-
Yeah
... your business going forward?
I mean, it's an impact. I look, and again, those guys have been through it, and so I'm never too far, you know, never too frustrated. We want the service sector to be healthy. We want them to have better days, and that's why I said that jokingly. It was fun to be on that panel, and it's good when those guys are doing well. Now, when you think about a small company, we started with five folks, and now we're over 100,000 barrels a day. We've built this thing over time. We've seen offshore companies fail in that journey. We've been very fortunate that this strategy's worked for us, but you've seen the failures, and some folks in this room know about those. Now, why do those things happen? In my mind, it's three reasons.
They jumped into a project where they had too much working interest, and that got away from them, and they shouldn't have done it. They didn't hedge, they got too proud around the commodity, and they didn't protect the capital program or protect the balance sheet, and we are, you know, pretty regular way hedgers. Or they took on a rig contract for too long a period of time at too high a rate, and then the commodity moved, and they were stuck with this obligation. So, you know, we get that those prices are higher. We understand why they're higher, we understand some of that inventory is down. Rigs do get regionalized, even though you can take them all over the world. Brazil is a different market than the Gulf of Mexico.
What we can't do, as much as we would like to be able to really normalize our schedule, is we can't just say, "Hey, look, rigs are higher than they've been in the last 8 years. Now is the time for me to take on a 2-year obligation." So we're gonna find different windows, and we're gonna have to be ready. Our team has to be ready to operate and permit and get things going, to where a rig comes available for 120 days, and we just take that at the spot market. You know, maybe in between other companies' jobs, or maybe we find a 9-month, 12-month window. But we really aren't gonna engage in that longer rig contract. If there's more guys like us, then that market normalizes itself a little bit, you know?
And so I think we just have to be disciplined and say, "Look, that may create a little lumpiness." This year, for example, we weren't willing to extend the rig we had last year into a full year, so we dropped that rig. We'll pick one up in the second half of the year. This is gonna be a lower CapEx environment, which is why we're generating so much free cash flow and have a 20% free cash flow yield, you know, this year. Next year, that CapEx program may pick up if we decide to pick up a rig. But we, what you won't see us do is get so nervous about the rig market, that we just feel like we've got to go in there and go grab a multi-year rig contract. That's just... That, to us, that's one of the major risks that-
Okay
... that have bid in offshore independent producers in the past.
One of the things that I've asked a few E&Ps and a lot of service companies over the years is, you know, Wall Street, over the last decade, has sort of hammered E&P companies to be capital disciplined-
Yeah
... careful how much they spend, et cetera. Do your decisions get impacted by Wall Street demands? Like, i.e., would you-
Yeah
... be doing something different if it wasn't for what Wall Street was pushing for?
No, I don't think capital discipline is something... It's an interesting question. I don't think capital discipline is going to be something that we say, "Hey, no, that's a bad idea." You know, we just wanna be drunk and sail it all the time. I think where you can be cautious around that is particularly offshore, you should think about our business in two-year cycles and not quarter-to-quarter cycles, right? And so, you know, I've got multiple projects I wanna bring online, and then I might not have anything for a little while. And so last year was a higher spend year, this year is a less spend year.
If I look at that over two years, that looks like a 67%-70% reinvestment rate, but it could look like 80% last year and 60% this year, and so it just moves in those kind of cycles. I don't think we want to make decisions where we're passing... Again, I'm thinking about this offshore. A lot of times, we have greenfield opportunities. Somebody went looking for 80 million barrels, they found 30 million barrels. My facility's 10 miles away. That's super interesting. Should I take that, or knowing that that might raise my capital program, or do I say, "Well, I don't..." You know, do I worry about re-guides and things like that? And so I do think, you know, being in a quarter-to-quarter, I wanna make sure you're always reinvesting at this rate. I wanna make sure that you don't change guidance here, or guidance there.
So sometimes, you know, where I think managers have to really try to think about the long term. And I'm suggesting we have that today. I think we've been consistent on what we're trying to do this year. But we could run into an opportunity where we say, "Look, that's really, really interesting. That's a really high IRR. That's going to increase the broad net asset value of this business." But it's going to cause, in this near term, a different level of capital spend. And so I think as managers, we can't get so caught up in it that we walk away from an opportunity that's unique to the business, that's unique to the long-term value-add proposition, because we're worried about how that runs through guidance or how it runs through the discipline story.
So no one's gonna be against the idea around discipline, and everybody wants to make sure they show that execution. I think what's unique about offshore, this isn't just add a rig, drop a rig drills, right? That's not what we do. This is big project then big project, then big project. That's what we do. And, and so it's how you stack up big projects in any given year. And so we gotta we gotta communicate our business on different cycle times, so that if we decide to add projects that make sense, it may look lumpy in one year, but then it may smooth out in the following two years.
We just have to talk about our business differently, so that we can have the right level of projects going on at the same time, and still give the market comfort that that's within a disciplined structure.
You talked about the maturities being extended, and I think it was 2025, the-
Mm-hmm
... the high-yield note you did.
Right.
Just, at a high level, how do you think about capital allocation from here, like, as far as-
Well-
... M&A-
Yeah
... organic growth
Right
... what, maybe even on the M&A side, what, what might be happening?
So we did that QuarterNorth deal, and there's about $950 million of cash in that.
Yeah.
And so part of that cash was utilized in not only adding to the high-yield notes, but refinancing those notes. So that got you to the 1.25, two different maturities, lower cost of capital than where we've been before, all that's positive. The rest of that came off the revolver. We should have all of that paid down at the end of the fourth quarter, you know, and maybe sooner than that, and hopefully sooner than that. So, you know, we're accelerating debt repayment. We sold our little CCS business, had a nice return on that with Total. That accelerated paying down the revolver. So we should end the year just with this termed-out debt. That lowers debt leverage to around a 0.8, so I think that's a good, healthy place. And then look, you know, those are trading at 107.
They have, you know, penalty provisions, and so do you go buy expensive, you know, kind of premium debt or, and buy that, or do we think about buybacks and some other ideas? Do we think about accelerating one of these big projects? So I think we're gonna have... Right now, our capital allocation has been really focused on getting that revolver paid down. And, and look, as you see oil pull back a couple bucks, you remind yourself why you're always trying to pay down your revolver, right? I think it's good to have that level of discipline. So we're - that's our focus in the very nearest of terms.
As we get that paid down, look, as we think about hopefully beating our forecast, and now the choices are buying debt at 107, doing buybacks or other shareholder, you know, return ideas, or bringing in another project that's got 40%-50% IRRs, that's a more, you know, bigger menu of capital allocation choices that I think we're gonna have in front of us as the year goes on.
I was speaking with a client who I've known for probably way too long yesterday, and one of the things that came up was OPEC's decision. But as it pertains to you, when you think about your spend, and you think about the commodity price environment, how much do you think about, like, sort of the excess capacity that's in the hands of the cartel, and how much do you think that's actually real excess capacity and not?
You know, it's interesting. I think there's interesting articles written about, is there real excess capacity or not? Look, I do think it's interesting, you know, how OPEC and Saudi Aramco in particular, where their behavior is moderated, and how they think about needing an oil price, particularly even as it... Look, it did a secondary the other day. I mean, you know, it would fight. So, you know, people want to the behavior of how that company's run has changed over the last four or five years. And having predictable commodity price is important for them. I do think, again, if you think about long-term demand and people's views, I always found it interesting when you got that, you remember the old BP energy report, and they would-
Yeah, yeah
... produce a report.
Yeah.
Exxon would have a forecast, and BP would have a forecast, and everybody had a forecast on where oil demand would be in different sectors, call it 2035, call it 2050. The wild part about that was, I think I saw one last year, where the difference between some of those forecasts, and these are all majors that work in all these different countries around the world. They have a sense of demand in all these different jurisdictions, yet when you looked at the spread across Total, BP, Exxon, and all these guys, and then you can look at EIA and all these different groups, the spread was, like, 15 million barrels between, like... How can they be this wide? Someone's missing the actual demand. And I think there's been pretty good articles written.
If we think about people having some level of energy poverty, getting into a better place, is really that demand, 105, 110, 115, 120, should it be greater than that? And if it really ever becomes greater than some of these forecasts that already have a wide variability between them, then how do we think about supply meeting that demand? And so, you know, I'm on the side of typically. And people say, "Well, yeah, you're an oil guy—you are." But I'm on the side of people are constantly trying to better their station in life, and they are absolutely driving the demand, and that governments want GDP income, GDP per, you know, per citizen to go up over time, and that requires more energy demand. So look, I'm long the idea around demand.
Now, the question really is, do we really have the supply to meet it? That's a whole another story. I, I would tell you, there's a lot- Guyana is a great story, Namibia is a great story, everything else is pretty darn mature.
Yeah.
You know, it is, it is certainly a mature resource base around... We're, we're doing all sorts of interesting things all the time, and there's some new basins being opened up all the time, but it is a mature resource base. So mature resource base that we're throwing a ton of technology at, and I think an increasing demand story is pretty constructive for the commodity.
We're over time, but I wanted to get you two quick ones. One is, outside of the Gulf of Mexico, are there places you'd go, or you-
Yeah, look, you know, getting back to this whole global story-
Yeah
... we just talked about, 50% of all the production in the world's offshore, 80% of all the production in the world is conventional rocks. It's not unconventional stuff in West Texas. And so, you know, we are a conventional geology offshore operator. That's fundamentally what we are. We've built that in the Gulf of Mexico. That is where our focus is. But obviously, we've dabbled down in Mexico a little bit, which is a different story for a different day. But geologically, we had a lot of success there. We're trying to manage the above-ground risk. If we think there's something interesting enough geologically that could use kind of our strategy and what we do, and we think the above-ground risk is manageable, we would look at it. It hasn't compelled us yet. Our focus is in the Gulf.
But I do think this strategy can travel. You know, there's a lot of these basins that have that maturity that needs the independence, and so these opportunities and again, it's hard to raise new private capital to go capture these opportunities. And are the majors buying each other's stuff when they're trying to exit? So if those opportunities present themselves, we'll look at it. We've done it in the past. Our focus is in the Gulf, but I think if you look out 3, 5 years from now, that would be a surprise.
Okay, and then just one real quick one. What if there's one thing you worry about the most on a, either a-
Hmm
... a daily-
Yeah
... or a quarterly view.
Yeah.
What's the biggest-
Well, look, I, you know, like, and it's a standard answer, but it's very true. If you, if you sit in my chair, when you wake up, whenever you wake up in the morning, 5:30 A.M., 6:00 A.M., whenever that is, you check your phone to make sure nothing happened the night before. I mean, you just... You know, you think it is not an easy business. It's a hard business. It's a dangerous business. But then, for us, you know, when you're playing offshore, you're playing in someone's federal territory. That's what you're playing in. I, my, all my assets in the Gulf of Mexico are managed by the federal government. You know, if we play down in Mexico, that's managed by that federal government. If we try to play in Brazil or West Africa, they're managed by those federal governments.
So we really do have to manage above-ground risk. We try to manage, you know, what, how energy policy and that impacts us, and so we're focused on it all the time. I think how we run the business, how our guys execute the business, you know, again, it's not, if you will, as predictive as onshore. It's not add a rig, drop a rig, but the big stuff can be really big and really interesting. We have to always kind of keep in mind what's happening on the above ground side.
Great.
So, yep.
Well, thanks. We'll leave it there, but thanks for your time.
All right. Thank you.
Great.
Thanks for having me.