Our next guest, Chairman, CEO of Coterra Energy, Tom Jorden. Coterra is a relatively newly formed entity post the merger of Cimarex and Cabot Oil & Gas in 2021, and now it boasts high-quality positions in three premier plays in the U.S. Permian, Marcellus, and the Anadarko Basin, with diversification across different commodities. Tom, it's great to see you.
Great to be here.
The last time we chatted, you were still leading a company called Cimarex, and a lot have changed in the last couple of years, so really thank you for being here. I wanna start the conversation certainly with the transformative merger that have happened in the last two years. It's almost been two years since the completion of Cabot. I wanted to ask, is the integration fully complete from a operational, cultural, and organizational perspective? Give us the look back on how the last two years has gone.
Well, I'll say, nothing at Coterra is fully complete, ever. You know, we're a young company, we're a growing company, we're a learning organization, and so we're always evolving. But, from where we came, from the day we closed to what we are today, we've made remarkable progress. The physical integration, the system integration is down to just tweaks at this point. So we're really kind of there as far as one platform across the company. The operational integration's been really a lot of fun to see the various operating units come together, exchange ideas, and exchange best practices.
But, probably nothing's more exciting than the cultural transformation of just bringing a passion for new ideas, a passion for excellence, a passion for open and honest debate, a lack of interest in hierarchy or organizational boundaries, and giving everyone in the organization permission to express their ideas freely and occasionally even passionately. And it's just been terrific. We have a lot of work ahead of us. It's challenging times, but really, really pleased to be where we are. I'm glad to be where I am.
That's great, and I feel like that, that energy and that conversation has always been a trademark-
Mm
... always within your organization. It's good to see that continuing. I guess I'll maybe talk about some of the synergies that you were able to realize already. Were there differences, whether that's organizationally or operationally, that you had to reconcile between the two organizations over that period?
Well, as you know, a lot—we've established a lot of operational synergies. Both companies had excellent operational histories, and we've shared a lot of ideas back and forth. And I'll just give you a particular example. Our Marcellus team has dealt with severe winter weather forever, and in preparation for winter of 2022-2023, we had last fall a lot of collaboration between our Marcellus team and our Permian and Anadarko teams, and had a lot of changes around that collaboration in winterization. So when the Winter Storm Elliott hit, I think it was Elliott, that was twenty... winter of 2022. But, you know, there was a wave of downtime across our industry. It started in the Permian, then that same storm went to the Anadarko and went to the Marcellus.
The earnings for fourth quarter calls were all about production shortfall, weather downtime. Coterra didn't have really any weather downtime to speak of, and that's really a testament to the collaboration that went on and some of the preparation that went on. In fact, no one, no one even noticed the fact that we had no production downtime, so that was, that was terrific. You know, it's really been terrific to bring a spirit of energy across the organization. There's... You know, you asked about differences. I would say the two legacy companies had very different experiences, and as such, developed very different muscles around those experiences. Cabot, being a one-basin company, really developed a tremendous marketing savvy around marketing the natural gas with a portfolio approach.
In fact, I would say that, we've—they've taught us what excellence, excellence looks like, that group has, when it comes to marketing. Cimarex, on the other hand, operated in a variety of operating environments, a lot of water in our production base, a lot of different landing zones, and so we developed kind of a functional chaos in the way we operated because we had ideas floating in rapid fire. I would say if I looked at Coterra today, I'm pleased to say that it's a very uncomfortable place to work. And by that I mean, you know, I think one learns fundamentally in life on anything you care about, whether it's physical fitness or education or relationships, spirituality, anything worth throwing yourself at, ultimately it becomes a choice between progress and comfort.
Across the platform at Coterra, we're choosing progress, and that means we're gonna be uncomfortable and challenge one another, and you know, focus that uncomfortable productive outcomes. You know, don't worry about your job, worry about the competition and how do we get better.
That's, that applies to many things-
Yeah.
to me on just running a company, but that's excellent. I wanna address the, I guess, one of the major pushbacks.
Mm-hmm.
that we always on the perceptions of the inventory that we have it
Mm-hmm.
-that when you Cimarex had low inventory of, Permian and Anadarko-
Mm.
and that wasn't the case with Cabot. But then you get into the Upper Marcellus-
Mm.
and started doing the more delineation, and results were... seems to be better than expected. Could you talk about how you've been addressing that concern and what you have been able to do already on the inventory?
Mm-hmm
That with Cabot?
Yeah, you know, look, inventory is a concern. I think, I think inventory is on the list of everybody's concern. At Coterra, we have a really long-dated, high-quality inventory, but we're concerned. You know, I tell our organization that if we're not replacing our inventory, we're having a going-out-of-business sale. Maybe a 20-year-long sale, but if we're not replacing it, we're having a going-out-of-business sale. And so, you know, we do want a fair amount of energy around inventory always, and that's really an attribute of a learning organization. You know, the inventory in the Marcellus is, you know, we have about four-seven years left of Lower Marcellus drilling, and then we're feathering in Upper Marcellus. And we have, you know, depending on our well spacing, I would say, a decade of inventory there.
You know, no inventory is infinite, and we're very pleased with the delineation we've done in the Upper Marcellus. We're seeing results that I think confirm what we and the former management team had said about the Upper Marcellus. You know, it's gonna be 70%-75% of the productivity of the Lower Marcellus, which is still fantastic. We're very pleased with the development projects we brought online. They're exceeding our expectations. And it's just a great portfolio. You know, whether it's the Marcellus, Anadarko, the Permian, we have a lot of optionality. But deep inventory and optionality does not give an organization permission to be static. And so, you know, it's not what your inventory is, it's what you do with it, what the company does with its capacity.
And so, you know, look, I'll say it again, Coterra is a very young company. To look at Coterra and think that what we are today is what we're going to be, is to miss the story of Coterra.
Right. And, I know there's that energy, the continuous push-
Mm-hmm
has always been there. Before I move into Permian, you talked about feathering in the Upper Marcellus.
Mm-hmm.
Have you given guidance on what's gonna be the mix of lower versus upper on going forward?
Well, we give general guidance, yes. I mean, I would say over the next two or three years, I think you can look for 30%-40% of our program being Upper Marcellus. That will change from year to year. There'll still be some years where the lower is more than that. You know, one of the nice things we're seeing with our program is increasing lateral lengths in the Marcellus, and that leads to greater capital efficiency. Over the next couple of years, we expect lateral lengths to be 2 miles or longer on average, total, and that's a really nice thing. We've made some progress on leasing some stranded assets, and that gives us the flexibility to drill longer laterals. We've actually drilled a couple of lateral, a couple...
Well, a project that's almost 4-mile laterals. So we're really seeing some tremendous just improvements. I don't know that that'll be the standard. I mean, there's a lateral length where the mechanical risk sort of starts to outweigh the economic benefit, but certainly 2-3 miles is well understood. Four, I don't know that we'll make that normal.
Right. Switching gears to the Permian, and I find that this question is particularly suitable for you.
Mm-hmm.
I find that the industry is still making progress on spacing and completion design and cube development, and that is something that we're talking about for a while-
Mm-hmm
... and it's, and that progress is continuing, and it comes with some concerns as well. There's been some hiccup. But I guess from your point of view, is there like how much more room to continuously improve completion design and spacing design in the Permian? Are we at incremental progress at this point, or are we still having breakthrough in what's the best way to develop the assets?
Well, well, it's, it's probably becoming a, a game of... I won't say it's a game of inches, it's probably a game of yards more than the Hail Mary pass. You know, we made, we made tremendous progress over, you know, the period 2013 to 2019, and the, the progress now is, I, I think, incremental, but, but significant. You know, one, one of the big advances that we're seeing at Coterra is the impact of Machine Learning on our program design and execution. Machine Learning is, is really democratized at Coterra. It's a part of every operational meeting on, on, project planning and project execution, and we've got some ideas that, that are, you know, potentially impactful on achieving lower costs without sacrificing well response.
So, you know, I think you're gonna continue to see Coterra and our industry adopt technology in a way that will surprise all of us. You know, we were remarking earlier today that when we first started drilling Wolfcamp wells in the Permian, we were drilling 5,000-foot wells, and we were taking between 45 and 60 days to drill them, and now we're drilling 2-mile wells in under 10 days. So it's, you know, it's been an amazing advancement that none of us saw coming, so I'd be a fool if I made some limiting remark on the future.
I think over the last few calls you made, the machine learning being transformative-
Mm-hmm
And then that stood out because I know how excited you get about technical advancements. Could you peel back a bit more on exactly how does that apply? Is it more on the cost side? Is it more on the well productivity side? Like, how... Are we just at the early stages of figuring out what that actually do to your bottom line?
Am I limited by this clock? Because I can go on and on, but I'll keep it brief. You know, and different companies use different focus areas for machine learning. Probably the most ubiquitous is production optimization. You hear lift optimization. We came at it from a different vantage point in that we started focusing on predicting well performance, and we said, "You know, what if we could truly predict well performance in a way that had fidelity and reliability, and we could calibrate it, and it would have accuracy?" And so we spent. We started in about 2018, 2019, and we had some misfires. You know, we gained a lot of experience on how to implement machine learning in an organization, and we made mistakes, but we adjusted and pivoted.
So today, we have the ability to predict our well performance in a manner that is outperforming our best reservoir engineers. That the well performance that machine learning is predicting is better than what our engineers are doing with all the experience they have. So what that means is, you may have 15 different features that go into a well performance. You have lateral length, you have spacing, you have depth, you have geometry, you have completion design, you have many geologic parameters, and all of those tailored to a particular location allow us to predict that well performance. Well, having your well decomposed into those 15 elements really gives you the opportunity to iterate with different permutations than you actually implemented in the field and optimize.
Think of machine learning as branches of a tree, where you're gonna climb the tree, and every time it branches, you do your best to choose the best branch, but you end up over here in the tree. Machine learning lets you explore all the different branch paths you might have taken with all the random mixing of those parameters and lets you select the most capital-efficient outcome that you could have taken with thousands of different options.
Mm.
So it's really the power of that is tremendous. The power of that in just understanding the impact of parameters on our own design is remarkable. We've now taken it to a point where we've separated the decomposition into spacing, completion, and geology as separate subfeatures. So when we look for analogs, you know, classic reservoir engineering says, "If you want to study a response in an area, you look for nearby wells as a go-by." Well, because machine learning has decomposed geology as a separate, independent feature, we can go find the best analogs, and sometimes the best analogs are 20 miles away in a different geological environment, but they're going to respond similarly in informing you about where you are. It's just, it's really remarkable, but what's most remarkable is the way we've democratized it in our organization.
I mean, it really is marbled throughout our thinking, our reservoir engineers, our production engineers, our completion engineers. They don't make a significant decision without insisting that the machine learning team be at the table, and so that's. We're not pushing it, they're pulling it.
Mm.
That's, that's, I think, a distinction with Coterra's approach over some of our peers, not all. I, I think some people make a mistake when they take Machine Learning, put it in an ivory tower, and then descend it upon the organization. It's, it's really democratized at Coterra.
So there's a manifest in the, like, on all your line items? Like, and, I'm just thinking, is it lower CapEx, better production, or it's really permeating throughout?
Well, you know, I, I'll say to that, we're just warming up. Yeah, our machine learning team is really hungry to be exposed to different problem sets, and they've made a pitch to us to: "Don't bring us in on what you think machine learning can help on. Bring us in, show us the company's top problems, and let us see if we can help.
Mm.
That's the right approach.
Got it. Great. Look forward to hearing more about that.
Yeah.
So on the issue of flexibility, and you also—that's also a word that you like-
Mm.
just flexibility with operations and be able to flex up and down. But how do I jive that with the fact that you are also doing a lot of, I think, bigger pad development?
Mm-hmm
-including, I think, a 51-well project, and just traditionally think that as, like, not as flexible-
Mm
when you're doing these projects. So how do I reconcile the two ideas?
Well, you know, in life, things can be simultaneously contradictory and both true. Yeah, we have a baseline capital. I mean, I will say that it's kind of like our services. We have, you know, if we have 12 rigs running, and six frack crews, maybe we'll say we'll take half of them and put them under a one-year contract, and the other half will float either month-to-month or pad-to-pad. So, you know, there's a baseline foundational commitment to a capital program, and then the flexibility is in the margins, and we try to keep that margin to about half of our services. Well, project architecture and flexibility is similar. These large projects really allow for tremendous cost savings.
You know, for example, the large project that you cited, the 51-well project in the Wolfcamp in Culberson County, that will have seven pads on it. Had we done that individually, it would've been, you know, much more than that.
Mm.
By doing a large project, you get those savings. You get to repeat the same experiment many, many different times in a row, and that your drilling and completion will get really efficient. So you wanna have... You know, large projects are a great idea once you're in manufacturing mode. But we do wanna leave a large part of our capital program for swing decisions. So the way we're looking at 2024 is we'll have on-ramps and off-ramps. We'll have places where we can stop and places where we can start, both in the Marcellus and the Permian and Anadarko. So we'll have a lot of flexibility in 2024 to redirect capital, but that's not in contradiction with those large projects.
Got it. Specifically to the Marcellus, I think you mentioned, threw the number out there of 200, can reduce CapEx by $200 million-
Mm-hmm
And hold Marcellus flat. Where are you seeing the commodity prices are currently, so is that how you're thinking about 2024 right now for gas?
Well, you know, we haven't guided into 2024, but look, if I had to make that call on the near month price, I'd say absolutely, you know? We're waiting and hoping for a cold winter that would be a price resetting natural gas prices. But if natural gas prices were to stay where they are today relative to oil, we would more than likely pivot capital from the Marcellus to the Permian and Anadarko. We think we can do that, and the number we've quoted is $200 million. We think we can do that and hold our Marcellus production roughly flat and not compromise our ability to respond in 2025.
You know, we're always thinking well down the road, but within that formulation, we do have on-ramps in the Marcellus, where if gas prices were to significantly recover, we could add activity, probably on-ramps every quarter, so.
Got it. A bigger picture gas question. Now that you have really three areas that can generate tremendous amount of gas: Marcellus, Permian, so-
Mm-hmm
... and Anadarko Basin. So far in this conference, we heard a lot about the incoming LNG demand and the need for gas. With your assets to it, how you think about where the gas is gonna come from, and how Coterra, should that demand materialize, how are you going to respond? Because, you know, Marcellus is considered to be pipeline constrained, Permian, it's, at some point, it's dependent on infrastructure and then the Anadarko Basin.
Mm-hmm.
Just how you think about how you're positioned for that?
Well, we're, you know, very constructive on gas long term. Certainly, there will be additional LNG opening up here in the next, you know, 18 months, and we're very optimistic about the worldwide demand for that LNG. I know there's a lot of research and discussion going around about the worldwide LNG markets, but, you know, I think we're confident that in the long run, good, sound energy policy will prevail, and that natural gas will be seen as a real tool for climate action. You know, the Northeast, we do sell at Cove Point, between 350 and 400 million a day. It would be wonderful if some additional offtake opened up out of Pennsylvania. Probably not gonna happen in any near-term timeframe.
So, you know, one of the nice things about the Marcellus is we do have a remarkable marketing portfolio. So our weighted average sales price is a combination of fixed price, power pricing, you know, only about a third of it is truly in basin pricing, and half of that is non-New York pricing, which is really a rich market in winter, and that has a material impact on our annual cash flow, so we want to keep that. So, you know, we don't look at Marcellus as being a big source of export gas, quite frankly. Now, that's not true of Anadarko and Permian. You know, the Anadarko Basin is a really great gas market. We have some fantastic assets there.
And then you know, Permian, additional infrastructure is coming online, and that'll be a, you know. The Delaware Basin is gonna be a significant gas basin for a long time. It's, it's generally viewed as an oil basin, and gas is associated gas, but below that oil are some really prolific gas reservoirs. So, so I think there's a lot of gas yet to be brought to the market in the Delaware.
Great. I want to talk about water.
Sure.
It's, I, I think, especially for Delaware and,
Mm-hmm
... your legacy at Culberson, before everyone started talking about water, I think, back in Cimarex states, you guys-
Mm-hmm
... were already thinking about water, and it's a fully closed system, recycling system.
Mm-hmm.
But since then, production has grown, and I imagine water cut have grown as well. Just talk about, like, how you guys are handling that today, and do you see sort of the rest of the industry responding in the same way-
Mm-hmm
... 'cause it's a, it is a big, important topic from an environmental,
Mm-hmm
... perspective, too.
Yes, it's a big topic. Now, you know, we had the luxury of two things. One is we had the luxury of a concentrated asset, where we made the decision years ago to control our own destiny and own and operate our gas gathering and compression, our electrical grid, and also our water disposal. We didn't, at that point in time, intend to own it forever, but we thought, let's own it until we understand the asset better, and that ended up being a very fortuitous decision because it's really to our benefit to own that, you know, long term.
But with water, in particular, we had the advantage of some very creative people, and, you know, I, I think back to an intern that did a project for us on water management in Culberson, and they pitched an $11 million system in Culberson, and we thought, "That's ridiculous." Well, today, we, you know, we built that system. It's, it's a system that takes well, water from the wellhead. It's a buried pipeline system, and then every now and then in the field, the pipe comes out of the ground through risers and goes back in, and we can tap into those risers and redirect that water to frack crews and use that water for stimulation.
There are times when 100% of our water is going into frack crews and many of our water disposal wells are idle because we're reusing 100% of the frack water, which is reused water. You know, I credit a lot of really bright people at Coterra for thinking ahead of the game. You know, another thing that we are way ahead of is seismicity. Our water disposal system was deep disposal, and a few years ago we recognized the threat of seismicity. We have our own private earthquake sensing array out there, first one in the Delaware Basin. And we started pivoting. We made the decision to pivot to shallow production, so we'll be out of the deep entirely this year.
We'll still have those deep wells available to us, but we've pivoted to shallow disposal, to try to minimize seismicity, and it appears to be working.
Is that, well understood by the industry as well? Like, do you see industry responding the same? 'Cause, it's something I think the entire, collectively-
Mm-hmm
... need to address.
Well, it requires a concentration of assets. You know, anytime you're gonna own and operate your own infrastructure, you need to have a concentration of assets. And the problem in the Delaware Basin is, if you look at the landownership, it's like a quilt. Very few assets are concentrated and blocked up in a manner that would support what we've done at Culberson County. In fact, Culberson County is maybe the most concentrated asset in the basin. There, you know, I think there may be one other, but it's really affords a tremendous luxury that we take advantage of.
Great. I've 30 seconds left, but I want to squeeze this in. You guys are decarbonizing natural gas compression.
Mm-hmm.
I think that's a new area that is a big source of emission source, but not really focused on today, but hard to do because of its decentralized. Is it difficult? Is it expensive? Does it save you money? How-
Yes, yes, and maybe. I'll tell you in reverse order. It saves a lot of money when natural gas prices are high. The spark spread, the difference between natural gas-fired power and electrical power you buy commercially. During 2021, 2022, we were making tremendous amounts of money on our electrification effort. An effort, it's something we didn't anticipate. We made the decision to electrify primarily around emissions reduction, but when natural gas prices hit their highs, that ended up being a very fortuitous decision in terms of making money on the power savings. But we also, again, we own and operate our own gas gathering and compression station. We have a lot of compressors. Compression emissions are almost half of our corporate emissions, so electrifying those compressors was a top priority for ours.
It is expensive. You know, we're having to retrofit and build new compressor stations, but you know, it's a small part of our total capital. You know, we're probably spending under $25 million a year at that effort, on average. When we first embarked, I think it was projected to be $94 million over a six-year timeframe. It's gotten a little more expensive than that. We're doing it more aggressively, but it's still fully manageable. You know, we're investing over $1 billion a year in the Permian. We're committed to it, and it's worked out really, really well. So it's a real serious effort of ours.
That's great. Well, thanks for doing that. Well, with that, fortunately, out of time, but-
Yeah
... it's always a treat to, to speak to you. Thank you so much for being here.
Thank you, Mary. Thank you. Bye.