Coterra Energy Inc. (CTRA) Earnings Call Transcript & Summary

All right. You guys have killed the music, that means that the next session is going to start. So our next session is a fireside chat with Coterra Energy. Coterra, as you know, is one of the E&Ps with the highest marks in the industry in terms of operations and the geoscience fronts. Today, our guest speaker, Blake Sirgo, Senior VP of Operations, he's at the sharp end on both of those efforts, so we're going to get into a lot of the operations and geoscience today.

Maybe to kick it off, maybe a little bit more high level. I want to make this point. During the quarter, there were a lot of companies that came out, and they expressed very strong operational improvements throughout the year, but it did not translate into guidance. Where I think Coterra really stands out is in its ability and its willingness to properly translate the improvements that they're seeing in real time into updated guidance that doesn't just sit in higher '24 but translates into their 3-year outlook, so for '25 and '26. So Blake, maybe I can throw it to you, and you can give us a sense of how the company thinks about those operational improvements and how they translate into guide and why you're willing to express the better outlook that you're seeing.

Yes. Sure, Kalei. And thank you for inviting me here today. It's a pleasure to be here. When we provide any guidance, 12-month guidance, I always think of it as we're really giving you a snapshot of a program, a program that's built to be multiyear. And so our operations are really bedrocked around a few really key things: get the best people, get the best equipment and put them in a position to win. And so for us, what does winning mean? Consistent operations, we like our frac crews to run 24/7, 365. We like our rigs to run 24/7, 365. We like to concentrate their activity so our folks can really hone their skills on those assets and get better and better through time. And so while we've had several quarters in a row, and it looks like a lot of beat and raises over and over, it's really just a program that's highly focused and there's continuous improvement all the way. And so that's really our challenge our teams take on every day. They know we have to be better today than we were yesterday. And so they're just constantly looking for any new way to improve our efficiency, and that just builds the cadence through time.

Well, structurally, this year, you're doing something a little bit different in introducing more row developments, where the wells are situated side-by-side. That makes for quicker movement of equipment, more uptime, more utilization. Can you talk about some of the improvements that you're seeing on the rig and the frac side and how they compare to maybe pre-row development?

Sure. Yes. The row development is really just the next evolution of that consistency I was talking about. It really wasn't a novel idea, but we operate in all these big DSUs, these drill spacing units. And our ops teams started to think about if we could really line these up in one big contiguous row, we can crush our mob times. We can maximize wells per pad. We can centralize as much facilities and infrastructure as possible. And we can take all those little bites, and as you add them up, it turns into real savings. And so that's really what's spawned the row development. At the same time, we've been looking at doing simul-frac for a while. We modeled it. We've done a few tests. Frankly, we've been challenged to figure out, is it really going to save on dollar per foot? We knew it would make us faster, but we didn't know if it would make us better. But the row projects really maximized wells per pad, and that's really what you need to make simul-frac work. And so we said if it's ever going to be successful for us, this is where we've got to try it. And I'm really happy to say it's outperformed all our expectations, all the models we had for it. And now that whole program is much more efficient than it was just a year ago.

The first row isn't fully complete yet, but the early learnings are very constructive for that kind of development to the point where you've introduced new rows for the next couple of years. Can you talk about why your confidence is so high in this kind of development to where you can lay out the next 2-year program?

Sure. The confidence comes through execution. You just have to know you can execute this over and over. And it's easy for us to say that in Culberson County because it's our largest asset. We own and control four contiguous townships. We're 50-50 with Chevron. We're the operator. We own the midstream, so we control all the gas. We own the SWD. We own the power grid. We have complete control. And so when you have that level of control, you can do things like drill and complete a 67-well row and have every single barrel flow unconstrained and ready to go. That's not always the case. If you have smaller footprints or you're more reliant on third parties, we might not have that same level of confidence. But in Culberson, we're very confident.

Like how do you size it? How do you size the rows?

Not endless iterations. It's all about return on invested capital. That's what -- it's just economics. That's all that's driving these row developments. There's lots of different things that pull on that. So it could be a takeaway. So we don't get -- we don't have to get too caught up in our D&C dollar per foot if it's also spawning a lot of midstream CapEx to be spent. All that goes into the equation when we're looking at the economics of a row. It's also timing. How long are the rigs and crews going to be tied up on wells per pad, what's the possible delays before production comes on, how does that impact the economics? And then the land situation, can we really commingle as much as we want? Or is there a natural break where, to go further, we're going to have to start getting away from commingling and we'll lose those efficiencies? And so that tends to be where you start drawing lines on the rows.

So Culberson, when I look at it, is one contiguous block. Does that set up for 100% row developments going forward?

Yes, I don't think I could ever quote 100%, but the vast majority of what we have coming in Culberson will be row development. There's always a few DSUs that are still fantastic rock that we want to get to that, for one reason or another, we can't combine with a row. But it's going to be a small percentage.

Does the lease geometry in the Reeves County area also lend itself to this kind of a development?

Parts of it do and we're looking at that now. We haven't been able to put together a true giant row there yet that we think competes for capital, but we're definitely looking at it.

Talk a little bit about the Harkey. So Harkey originally started off as not being in the row development program, then you added three, and now it's up to six. And they are a pretty big chunk of the future rows that you plan to drill. Can you talk about why you have confidence in this zone? What are you seeing so far?

Yes, sure. Our subsurface teams, one of the things they spend the most time on is understanding our frac barriers, so where can we develop one bench and truly come back and develop the bench above or below and have no worries about communication or depletion or anything like that? And historically, the Harkey developments we've done to date, which were in Eddy County, Reeves County and then on the far east side of our Culberson asset, we've seen those really strong frac barriers. And we have thought of them as two different zones. And that's how our latest big row project was set up. It was just an Upper Wolfcamp development with the thought always being we would come back for the Harkey. As we were already underway on the row, we did some co-development tests in the Harkey and the Upper Wolfcamp in Culberson County. And part of this was to we're always trying to gather those datasets and reaffirm those assumptions. And we started to get data that the co-developed wells were outperforming our previous overfill projects in Culberson County. I can't tell you exactly why. I can't give you a pretty reservoir model that says this is why that is, but that's what the data said. And at Coterra, we just go where the data goes. The data said the co-developed result was better, so you saw us pivot. We immediately added Harkey wells to the row where we could. Frankly, everything was going so fast, we could only add so many. And we're already back drilling on the top of the beginning of the row, adding those Harkey wells back in. And so our current thesis go-forward in Culberson is those zones need to be co-developed. That's always subject to change. We'll get a ton of data just off this row. But going forward, right now, the plan will be the future rows, those zones will be co-developed.

When do you anticipate disclosing the results from the next set of co-development Harkey wells? Is that coming in the first quarter of '25?

We should be able to put a pin in Windham Row on the next call. All the wells will be online, dollars will be spent and we can report all the final stats, and I'll be excited to report. The team has just absolutely crushed it.

Are the Harkey locations already accounted for in your inventory stack?

Yes, yes. We consider them part of the -- all the different -- we count all our Bone Spring sticks, the Harkey is part of the bigger Bone Spring package. And all that's included in our inventory.

You talked a little bit about frac, how you guys have embraced simul-frac. The leading edge is now trimul-frac. How do you think about incorporating that frac program into this Windham Row sort of development program? Does it make sense? Or do you think adding something like this to that program would be too disruptive to the program that you've built?

Yes. The short answer is we don't know. We're always looking for new efficiencies. We model these things out. We don't see, on paper, the same step change from simul to trimul like we saw from zipper to simul. That doesn't mean we're right. That's just what it says on paper right now. But it gets back to that full cycle invested dollar. And you've got to think, if we went trimul, now we're accelerating a lot of wells. As I mentioned earlier, we really like consistent programs. So a full year trimul-frac is quite a bit more CapEx than a full year simul-frac. And now we have much larger production wedges to deal with, which is going to spur a lot of infrastructure cost and a lot of midstream costs. And so all that has to go into the equation. You might be saving some on dollar per foot, but if you're giving it away on infrastructure dollars, the project itself doesn't really win. And those are the kind of things we're always iterating on.

And to be clear, I think the motivation for why this question continues to come up is because you're set up to do it, both on the electricity side and on the water side, so it gives you capability. Can you confirm that?

I think logistically, we could pull it off, but that's a lot different than saying we're going to make money doing it.

Fair. Maybe zooming out a little bit and to kind of think about how you guys think about Permian returns, there's sort of this concern that E&P inventory over time will degrade, but there's ways that you can offset that. Can you talk a little bit about how you plan to manage that degradation and how returns may look maybe 5 years out versus how they do today?

Yes, that's a great question. We're always trying to understand our future capital efficiency. If we're doing our job and constantly high-grading our assets and drilling our best of first, the natural assumption is it's going to fall off eventually. And frankly, if you had asked me this question 5 years ago, I would have been saying, "There's no way our capital efficiency could be flat to improving," but yet it has. And the reason it's done that is because of all these operational efficiencies that we've talked about. They really hammer the cost side of the equation. But also as we're expanding into the strat column out of just the Wolfcamp, I think the exuberance over some of these other zones is really starting to grow more than what we thought as we build a bigger and bigger dataset. Our Bone Spring program in New Mexico, which we've been at it a long time, but we're starting to drill some Bone Spring sands in Lea County that we haven't spent near as much time on in the past, and we're really getting surprises to the upside. And you couple that with really long laterals, a really good understanding of our spacing and frac design that's all fed through our ML models, which really kind of drive the bus for us now, and we're starting to find we can recreate some really strong capital efficiency even though we're not in the bread-and-butter Upper Wolfcamp zone.

Maybe you can dive a little bit deeper into the Bone Spring sand. When you think about the early iteration of your '25 program, how much capital do you think will go into that zone and help improve that up? And do you see it being a bigger part of your program in '26-plus kind of era?

Yes, I couldn't quote you a percentage, but I do expect the Bone Spring to be a bigger and bigger piece of our portfolio, especially in New Mexico. New Mexico is just the land of riches for us. I mean, there's just so many benches to prosecute. Sometimes when I look at the wine racks, Windham Row is very horizontal. We have vertical rows going on in New Mexico because there's so many benches to go after. And those things are a whole fun optimization program in and of themselves. And so I think you'll see a lot more Bone Spring results from us.

Are there any sort of well catalysts we should be looking out for in the next couple of quarters as you prosecute that?

No, I think it's steady as she goes.

All right. Maybe moving on to the Marcellus here. So in the Marcellus, obviously, this year, you've toggled down activity in response to weaker pricing. But I would imagine that you guys are closely watching those operations and there's learnings that are continuing. So even though you've drawn down from, let's say, 40 wells this year versus 70 wells next year, it doesn't necessarily mean that to impose some kind of stay-flat program, you've got to get back to that 70-well kind of number. I would imagine it's lower today, given what you've learned. So maybe you can talk about what you've learned and how you think about a stay-flat maintenance program in that basin going forward.

Yes, we don't really have a governor that says, "What would it take to stay flat?" That's not really how we allocate capital. We just -- we put it to its best returns and the growth is an output, not an input. So we're not targeting a maintenance case. But as far as like efficiencies in the Marcellus, we just laid down the crew. And it hurt to do it because we just finished our Dimock project, wrapped that up. And it was one of the best projects we've ever executed in the Marcellus. Whatever you want to look at, cost per foot, drill feet per day, completed feet per day, pumping hours per day, it was records for us across the board. And a lot of that was work that's been done over the past 3 years to really optimize our efficiency in the Marcellus and concentrate activity that really start to bear a lot of fruit before the gas markets kind of took a turn on us. So there's a really high-octane program sitting there ready to go. We just need Mr. Market to work with us a little bit.

And as you think about that market in '25 in that context, do you think you'll run the same program that you ran here in '24? Or do you think dropping a rig, maybe a little bit fewer completions is the right move for '25?

I think all those options are on the table right now. We're waiting to see what pricing does. The Northeast basis is still very challenging. It's very challenging right now. We actually have a production shut-in today because anything exposed to that cash market is really weak. And so we're not comfortable producing into that. But it means we're really not comfortable drilling and completing into that. And so we need to see that come to fruition.

Despite the lower level of activity this year, I think we've all been surprised by the productivity coming out of that basin, especially with respect to your guidance, where the Marcellus is not perhaps declining as much as you would have anticipated. Can you talk about the resilience of that base production?

Yes. The biggest factor by far is line pressure. And I think we underestimated the slowdown in drilling and completion activities and taking the shut-in molecules out of the pipes really affected line pressure and dropped it. And the base wells really liked it and they all responded very well. I mean, the lower Marcellus base wells in Susquehanna are some of the most prolific gas wells ever drilled in the Lower 48. And so it doesn't take much of a pressure differential when they respond. And so that's a lot of what you're seeing, it's just the base production, lower pressure outperforming.

Is that lower pressure sort of midstream environment, is that a new normal? Or is that a function of producers curtailing production? In which case, when it normalizes, would you expect your base to perform differently?

No. Our field is isolated. So we're all in one gathering system. We don't share with any other operators. And so our pressures are our pressures. It begs the question, should we be investing more in lowering pressures over the long term? And we have lots of projects that we're looking at.

Staying on curtailments for a second, you guys talked about 300 million cubic feet being curtailed in the Marcellus. And that was a number that's a point-in-time kind of metric, changes week-by-week. We looked at U.S. Lower 48 production yesterday, and it was around 98 Bs per day, which suggests that guys were curtailing production over the weekend because of really weak cash prices. Can you sort of give us an updated number of where your curtailments are today?

The numbers we gave out, that would be the monthly average rate. That's essentially when we give those numbers, that's what it is. That's the average for the month. So yes, the daily could move up and down compared to that number. But we're making these curtailment decisions 1 month at a time. And so we're already looking very closely at December. We're looking at in-basin pricing and we're making those decisions. Are we going to stay curtailed or are we going to bring something on? And all that is always in flight.

Can you remind us of the important price points we should be watching for you to maybe change your behavior, whether it's reintroducing those curtailed volumes or to accelerate production in the basin? What price points do you need to see?

For shut-in, there's no magic here to this, but we kind of say we just don't want to net less than $1. And so our all-in kind of variable cost is around $0.84, $0.85. So Leidy is usually the index we look at. If Leidy is trading kind of below that $1.80, that's the signal to us that we want to stay shut-in. As far as bringing activity back, we're going to need something north of $3, and we're going to need to see it sustained for a little while.

Maybe to distill that down into a soundbite, would you say that you guys optimize around your cash cost or around some kind of return?

Cash cost for shut-ins, for base production, go-forward capital, yes, full cycle return is all we look at.

Maybe shifting gears here and thinking about the Anadarko, the market has sort of been reading the tea leaves on the Anadarko all year. Sentiment has gone from, "Maybe let's spend a little bit this year, a little bit more next year." But the latest commentary in your deck seems to suggest that you're getting more constructive on the basin. Can you talk a little bit about that evolution and thought process with respect to the Anadarko?

Yes, I think it's maybe not getting more constructive but just having repeated results, good results. What we did with our Anadarko program, if you recall a few years ago, there was a lot of exuberance over the Meramec zone. And we didn't really share in that exuberance. We thought some of the initial estimations, the wells were really overspaced. There wasn't as much resource there as maybe the market thought. And so we kind of took advantage of that opportunity to do a lot of trades to core up our core position around the Woodford, which has been our bread-and-butter zone in the Anadarko forever. And it's a complex space and you've got to really understand the geology. And that's where we cored up our positions. And so we built those positions. And since then, we've been just bringing on one project at a time and making sure we're actually executing on those results that we forecasted. And the team has really built a great track record. I think our program right now is pretty right-sized and it's executing really well.

Is it repeatable?

It's repeatable at the size it is. It is a variable basin. You have to understand the yields, how they change. You have to understand the subsurface. And the program we have sized right now, we think, is very repeatable.

I think you touched on some of those points, but the pushback in the basin is that areal extents maybe not as robust as some other basins. The phase window has changed pretty abruptly. Leasing and getting your AFEs out there for that basin are pretty complicated, given how it's set up. What in that sort of understanding would you push back on, driving to the point where it's a better basin than perhaps people give it credit for?

Yes, I think it's a better basin geologically if you really understand the rocks and you're an experienced operator in the area. It is easy to get tricked into thinking that it's a layer cake and you can just repeat these results across some wide expanse. Compared to the Permian, where the Wolfcamp changes a little bit, but the Wolfcamp is kind of always the Wolfcamp, that's not how it is in the Anadarko. You really have to know almost to a DSU level, "What am I targeting? How is this calibrated? Can I repeat this result?" That's really what we focus on. But if you have knowledge in that area, which we have a wonderful team with a lot of experience, that's how we build those consistency of results.

The way that we kind of interpret that is that even if you're not executing a consistent and repeatable program, you've got pockets of opportunity that deliver great results for a given maybe 12-month kind of program. But a 12-month kind of program doesn't readily bake into forward-looking assumptions very well, so it doesn't provide that much of an equity story. Do you think that's a fair characterization?

Oh, I think it is if you were trying to build a story solely on the Anadarko. I mean, I don't -- I have the pleasure of looking over three different basins and we just look at it as one investment portfolio. So we really don't waste too much time and energy over what basin it's in. If we can put a couple of hundred millions of dollars to work at a really strong return, that's what we're going to do.

Is that kind of the framing for how we should be thinking about '25 or '26?

Well, we're not ready to give out '25. But I would just say we're excited about the results in Anadarko. We think they're repeatable and we have a good program going there.

What kind of option value do you see in the Anadarko? And where I'm going with this is that there's a narrative out there that suggests that the Haynesville, which is the gas basin, will decline over a period of time. Maybe it has a life of, call it, 6 to 12 years, at which point it slips into decline. Therefore, you're looking for another resource to backfill the contracts that it's linked into. Does the Anadarko provide that backfill opportunity? Is that a narrative that you agree with?

Well, yes, I think its proximity to the coast is really nice. Currently, the gas differentials are very strong. That's because the pipes aren't full. And so the basis is really good. Really, what it has going for it, more than anything, is it is a gas basin, but it has a ton of NGLs and great condensate yield. So it's a gas basin, but you get tailwinds from liquids. And that really kind of helps weather the storm. It's not as directly tied to gas price as, say, our Marcellus asset is.

If you had a bigger canvas to play with in the Anadarko, would that result in a more repeatable program?

I don't think so.

Are you at your size?

No, it's always going to be driven by the subsurface. I mean, that's really what matters more than anything, you've got to know the rocks.

And I guess this kind of brings us to a conversation around M&A. Coterra was very active in the early days of this wave of M&A activity. You guys acquired Cabot. Lately, you guys have been linked to various deals in the media. None of those have been substantiated. Just trying to get a sense of what you think about this current wave of M&A. Do you think it's over? Do you think that there's still room to participate? And would you like to?

Well, I don't think M&A in oil and gas will ever be over. It's always going on. But we've been real consistent about this, how we view all these opportunities. We look at a lot of things and we're just trying to -- how do we create a better company, that's really what we're always looking for. Like scale is nice, but being bigger is not what we're after. Can we be better? That's really the lens we're trying to always view these things for, which means does the asset compete for capital within our current portfolio? Is it financially accretive to our shareholders? And then probably the most important one to me is what skills do we as an operator bring to this asset that would make it more valuable than it currently is? All those things have to line up to make a transaction happen. And that's -- it's a tall task, but it doesn't mean we're not always trying to get it done.

But where does growth, oil growth in particular, fit in to Coterra's priorities in terms of creating value for shareholders? You are growing in the Permian Basin. It's not insignificant. It's upwards of 5%. And given your operational improvements, perhaps that number could be greater on a CAGR basis. How do you guys think about that piece? Because it's very contentious. There's investors that like it and investors that don't. So how do you state your position?

It is very contentious. We have lots of discussions about it. We don't solve for growth. I mean, we really -- it starts with our balance sheet. We stress-test the next year's cash flows, the balance sheet. That spits out a capital number that we think we want to live within. And then it's how do we put that money to work at the best possible return across our portfolio? Lately, that output has been oil growth in the Permian is what's driven that. But we're trying to manage a portfolio across dry gas, NGLs and oil. And right now, oil is in favor and the Permian Basin has fantastic economics. So it shouldn't be surprising that, that's where the capital is flowing. We're not going to apologize for the outsized oil growth, but it's not a target. It's not something we set a line in the sand and try to hit.

When thinking about the other commodity in the Permian Basin in natural gas, obviously, this year, Waha pricing has been atrocious. But there will be a period in time when the market is going to ask you to make a return on your gas molecule. When do you think that is? And how would Coterra lean into it?

I think it's happening now as we speak. I mean, you're seeing the Permian, as a whole basin, gas and oil production are starting to diverge. And that's a very big sign of more infrastructure and pipe that's going to be needed to get the gas to market. And so all we're really doing though is now moving that gas to the coast. All these LNG projects are paramount. They need to come online. That gas needs an ultimate home and we're participating in that. We just announced a couple of LNG deals. One of those was 100 million a day tied directly to the Permian. That deal has a direct link. So we get out of the basin, we get on the water, we have a great JKM netback structure. That's one piece of how we're managing the Permian portfolio. We're looking at a whole bunch of different projects. Everything from an additional firm but also in-basin sources, we're looking at those. But then we also have the financial side. And we do layer in some hedges, where we can, to help protect against Waha. But I don't anticipate that problem going away anytime soon.

You mentioned the three new LNG contracts that you announced this quarter. And I know that there is a very limited disclosure you can give us here. But I'd like to understand better how those contracts originated. Given that these are on an existing LNG facility would suggest that somebody gave up their space. So can you talk a little bit about the origin of these contracts?

Yes, I can talk at a high level what strategy we were using. And it's really hats off to our marketing team. They've been at this hard for the past couple of years trying to understand the LNG landscape. And there were a couple of things that as we dug and dug and dug, that became really important to us is, one, we wanted to get a direct netback structure tied to a foreign index. And that was really important to us. We needed a really strong counterparty that, frankly, was already in the game. They already had LNG liquefaction space and they were already moving cargoes. That was really important to us. And so when you start to narrow the field and those are your requirements, the field gets really small. But luckily, Coterra has a really strong credit rating. There's lots of people out there who want to do long-term deals with us. And we're able to find some really good partners that were willing to partner with us and check all those boxes for us.

From a commercial strategy standpoint, is there a proportion of gas you'd like to dedicate to international markets?

No, we haven't set a preferred percentage yet. I kind of view this as our first bite. This is -- these are big deals for us. But we also already have a big deal that goes out of Cove Point that's tied directly to our Marcellus asset. And that doesn't show up as much in our portfolio because it has a NYMEX-type arrangement on it. But it is an LNG deal on the water that has some really unique things on the contract that we love. So that was a big bite, we just took this bite. We're in the market. We're looking all the time.

The Biden pause is expected to come off under this new regime. Perhaps that opens up new opportunities on LNG plants that really haven't reached the end of their development yet, perhaps they start in '27 or '28. Would you be interested in acquiring space on these facilities in addition to what you already have?

Maybe, maybe, if we can get the terms right. That's -- we're really careful not to ever let the tail wag the dog at Coterra. So it's about drilling programs first and marketing second. And so we're really careful about when and where we do these deals, but we have capacity for more.

Maybe shifting gears and thinking about your -- the way that you allocate your capital, the amount that goes back to shareholders. This year, you've been pretty active in the buyback because the stock price has been kind of soft, so you want to lean into that. The stock price still hasn't really improved. Should we still expect you to continue to sweep your excess cash into the buyback? Is that something that you're planning for '25 as well?

Yes, I mean, we haven't put out the strategy for '25. But our pledge of 50%-plus free capital remains intact. You are correct, we've been closer to 100% this year because, unfortunately, we've seen a lot of value in our shares and that's why we've been continuing to buy that. But I wouldn't expect our logic to change around that.

Maybe just touching on the balance sheet here a little bit. Understanding that you guys are in a great position, can you kind of remind us where you want your debt targets to be, how close you are to those, how do you maintain it?

Yes, I mean, in general, we like to be below 1x. I mean, that's the goal and you can pick your price that you want to underwrite that at. But that's not something we worry about at Coterra, and we try to keep it that way.

I think we have a roving microphone around here somewhere. So if anyone in the audience wants to ask a question, please raise your hand and we'll get that to you. Maybe shifting gears here and going back to the Permian Basin and back to the geoscience with respect to the Bone Spring sand in 2025, that's one of the areas you'll be exploring. Is there anything else on the Permian front you'd like to highlight that you're making great strides and improvements into that could be a story for the next year?

I would just say, in general, we've become really reliant on our machine learning team inside Coterra. And that's a homegrown organic team. And that's really what's led to a lot of our predictability in our results is we're now just looking at enormous datasets, not just our data, but all the public data to where we have a machine learning forecast for every single well we go drill. And it's really well calibrated. It's very repeatable. And that's what helps us make these -- when we're comparing the economic opportunities across the Permian, we just really lean into that. And it's made our jobs a little easier and so we're going to keep leaning into it.

As an industry, we're not really picking up rigs or fracs at the moment, so deflation is still a theme as we roll into '25. What are you seeing at the field level?

We're seeing some deflation. We're out for bid right now on a lot of '25. And so we haven't got all the bids back and awarded any work yet. But we're seeing general softness, nothing too outsized. But in general, there is some softness, from what you just said, less activity.

Is it more on the rig side or the frac side?

I don't know. We haven't got frac bids yet, but I have seen some softness in the rigs. There might be some softness in the frac fleets. But in general, if you want a premium crew, high efficiency, there is a floor on that. You can only go so low if you really want to keep your efficiencies intact. Our service providers, they're still dealing with a lot of high cost structures. Labor costs is still very, very high for them and a very big mover. And so safety is paramount to us. Good, safe, consistent operations is really what we're striving for. And so when you draw your line there, there's only so low those guys can go.

One area where companies seem to be flagging but hasn't really materialized into a major issue yet is grid capacity in the Permian.

Is what?

Grid capacity. Is this something that you expect to be more thematic here in '25?

'25, '26, '27, I think it's going to become more thematic. We're a little isolated, like in Culberson and Reeves Counties. We own and control our grids. We have our own substations. Those are from projects we started almost a decade ago. We are more exposed in New Mexico. We're very dependent on co-ops. And those lead times are getting longer and longer and longer as the load requests are really just going through the roof. And so I think you will see it still grow as an issue. You're seeing a lot of operators putting in microgrids and their own generation. And that's -- I think you're going to see a lot more of that.

Are you guys doing any of that?

Not yet, we haven't had to yet. And a lot of that's just because of the legacy positions we've built and the power we have. But as some of those programs continue to grow, I won't be surprised if we have to do some of that.

As an operator in New Mexico, how concerned are you of a recent study that came out that suggested they may pull back on or they may impose drilling restrictions in certain areas of the state? Does that impact you? Are you worried about how this ultimately unfolds?

No, I think it's more noise than anything. I mean, there's always some critics in New Mexico that like to put scary things out there. But the oil and gas business has been in New Mexico for almost 100 years. And depending on what year, 40% to 50% of the state's revenue comes from oil and gas. And so we've always found New Mexico a very constructive place to do work. We work very closely with the regulators and we have really strong relationships.

Given that this isn't a policy that they would impose next year sort of gives you a window to lean into greater activity in the New Mexico area if you wanted to. So does that come into the consideration set when you think about planning your programs for the next couple of years out? Would you lean harder into New Mexico if you knew what's coming down?

No, I mean, we still -- capital really decides -- return on capital decides where we drill. And so that's really what we're chasing more than anything. You always have to be ahead in New Mexico, you just have to. It is a little bit longer permitting and planning process. And so we've been doing that for a long, long time. We have a long history in New Mexico. And so we know how to stay well ahead and make sure we have everything we need to execute.

Well, we've got a minute left here. I'm totally out of questions. It seems like our audience is quite quiet. So I guess with that, I will shut it down here. Blake, it was really nice having you. Thanks for coming out.

Yes. Thank you. Appreciate it.