Coterra Energy Inc. — 2024 Q1
Transcript
Each turn shows the speaker, their inferred role, the section, and that turn's net sentiment (×1000).
Good morning. My name is Audra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy Inc.'s First Quarter 2024 Earnings Conference Call. Today's conference is being recorded.
Thank you, Audra. Good morning, and thank you for joining Coterra Energy's First Quarter 2024 Earnings Conference Call. Today's prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations.
Thank you, Dan, and welcome to all of you who are joining us on the call this morning. We're pleased to report that Coterra had an excellent first quarter. Our total equivalent production for the quarter was 686,000 barrels of oil equivalent per day, which was near the high end of our guidance.
Thank you, Tom, and thank you, everyone, for joining us on today's call. This morning, I'll focus on 3 areas: first, I will summarize financial highlights from the first quarter results, then I will provide production and capital guidance for the second quarter, as well as update our full year 2024 guide. Finally, I'll provide highlights for our recent bond offering and the progress we're making on our shareholder return program.
Thanks, Shane. This morning, I will discuss our capital expenditures and provide an operational update. First quarter accrued capital expenditures totaled $450 million, coming in just below the low end of our guidance. Our strong execution in the field continued in Q1, with our oil production coming in at 102,500 barrels of oil per day, above the high end of our guidance.
Thank you, Shane and Blake. We're pleased with our continued execution momentum as we march through 2024. We appreciate your interest in Coterra and look forward to discussing our results and outlook. As always, we like talking about results, more the future promises, and we're always pleased to deliver them.
[Operator Instructions]
Tom and Shane, congrats on the great results. Tom, I want to start off in the Marcellus, and you deferred 12 completed wells for later in the year. The plan still calls for about 29 wells to be put online. Could you maybe talk us through how are -- what are the market conditions? Is there a specific price? Or is there a supply or demand equation that you're looking at to, one, bring on the 12 wells? And 2, how would you think about the rest of the program for the year?
Thank you, Nitin. Well, first, I'm going to say if there's a specific price or a complex formula, nobody has shared that with me yet. But we're looking at our received price. And quite frankly, we sell into indices. Leidy is the one that we typically point to. And when it's -- I would say, when it's sub $1.50, we really look at that and we say, okay, what's the outlook for that? And we do have transportation and LOE that comes off of that. And I wouldn't say there's a particular price. But I'll say this, we do have a very low cost of supply.
Great. Tom, and I appreciate that. I want to shift to the Permian and talk about the Windham Row. Could you maybe talk a little bit about what have you seen, obviously, adding a few wells in the Harkey is a positive. But what are you seeing? And what are some of the lessons learned? And if you can walk us through the 5% to 15% cost reduction that you're seeing, if I think about $1 billion spend in the Permian this year, could we look at something which is 10% less capital spend in the Permian for the same result down the road?
Yes. I'm going to hit the Harkey and let Blake look at the cost reduction. Our general observation in a lot of our Delaware program is that in our assets, our observation has been that whether we exploit these reservoirs 1 layer at a time or not that we don't really see any incremental recovery out of a drilling spacing unit.
Yes. I'll take the cost question. When we talk about Windham Row and simul-frac. The simul-frac is going very well. I mean, right out of the gate, the performance has been strong. We were hoping we would see at least $20 per foot. To date, we've seen about $25. And there's room for that to go even further, but we're early in the game there. We're watching it very close.
We'll go next to Arun Jayaram at JPMorgan.
My first question is on cash return. You returned 90% of free cash flow this quarter. But I wanted to get maybe some broader thoughts on just the overall philosophy given your views on the valuation of the stock. You recently issued $500 million of notes to help refund the payment of the $575 million maturity later this year. How did cash return, Tom, attractiveness of the valuation of the stock play into that decision?
Yes, I'll let Shane handle that one.
Yes, I appreciate the question. I'll take it. Look, we look at a variety of things. We think about the return program and the pace. And look, you've touched on many of them. First and foremost, we look at valuation, and we believe our stock is a compelling valuation.
Great. And Shane, what do you view as the minimum cash you'd like to keep on the balance sheet?
We've gone as low as $600 million over the last, call it, 7, 8 quarters. And -- and again, I think that probably as low as we go. We target $1 billion. We've been as high as $1.4 billion. And I think you'll continue to see us live somewhere in that range. It's a broad range. But I think you'll continue to see us reside within that range.
So it's -- If I could just add some color. We have relaxed a little bit our $1 billion number on cash on the balance sheet. We have plenty of liquidity. Our buyback is really because we see value in our stock, quite frankly, we look at net asset value, and we think our stock is a really prudent buy.
Yes, it's a sleep [ well ] at night balance sheet. My follow-up is just maybe for Blake is your Marcellus well costs are guided down to $950 a foot in the second half versus $1,200 a foot in the first half. Talk to us about that decline? And what's the good go-forward run rate?
The decline is really just driven by the well set that we're bringing on that part of the year. We have some great, really long laterals that are in there and they trend on a lower dollar per foot. Run rate is kind of hard to pin down exactly, one, it depends if you're talking upper Marcellus lower Marcellus. I think it could be anywhere from $1,000 to $1,200 per foot. It's probably going to flow in there. Lateral lengths could drive that a little lower.
We'll move next to Neil Mehta at Goldman Sachs.
Tom, really great quarter. The first question I had was just -- we've seen so much consolidation across the landscape -- the energy landscape. And certainly, you guys did your large deal a couple of years ago, but I just love your perspective on the role of Coterra and future consolidation and where do you see bid and ask and do you see any gaps in the portfolio?
Yes. I'll see that let Shane comment. We're -- the fact that we haven't announced the transaction. As you've heard me say before, shouldn't be misinterpreted that we're not active in the space. We're evaluating a lot of assets. We're looking at how they may fit into our portfolio and really evaluating them against what we think the market demands for those assets.
Yes. I'll just add on a couple of things. I wholeheartedly agree. The team has been executing incredibly well, and we'd love nothing more than to have an opportunity to put more assets and opportunity under their stewardship. And we think it helps in terms of execution in the field. We think it also plays into our strengths of capital allocation.
And the follow-up also on M&A. You have been commodity agnostic. It seems to us and focus more on where you can generate the highest return. Is that the way you think about M&A as well? You're less focused on the product type and more focused on what's the best fit just perspective on Oil versus Gas and consolidation?
Yes. I think our first lens is always financial on everything we do. Now all else being equal, things are never equal. And you get structural changes in the markets, both for Oil and Natural Gas. I would say all else being equal, we'd probably add a little more Oil to our portfolio. But check back with me 6 months from now on that. I mean we really have a history of feedback that if we focus on sound financials, we focus on asset quality, if we focus on the amount of windage we have between our price file and our cost of supply, that's the right focus.
We'll go next to Betty Jiang at Barclays.
I want to ask about the 3-year outlook. You have beaten 2024, and that's flowing into a better 2025 and '26 numbers, which is great to see. With all the efficiency gains that you're talking about, is it fair to think that they would just continue to translate into a better outlook over the entire 3-year period and that you will just be delivering that 5-plus type of growth for maybe seeing to lower CapEx?
Yes, I'll see that and I want Blake to comment. I think sometimes people give us credit for being better modelers than we are. We really do try to come out with outlooks that are aggressive and what we think we can achieve. We do not model in future cost reductions or future efficiencies unless we have line of sight to them. And that's kind of -- I have to kind of apologize for that because we are an innovative organization.
Yes, Betty, I would just say, as I said in my earlier remarks, we still have strong conviction in the outlook that we put out in February. So 5% plus Oil growth, 0% to 5% BOE and Gas growth, all at $1.75 billion to $1.95 billion of annual capital. I think the results that we have delivered in the first quarter only gives us further conviction around that outlook. So we're still excited about it. And believe we'll be able to deliver it.
Blake, do you want to say anything about the future position?
I would just echo what Tom said. We don't bake in any efficiency gains in our 3-year outlook. What we're doing today is what we show. But as Tom said, the expectation here is that we get better every single year. We have a culture of operational excellence. That means what we did yesterday, will not cut it for today.
That's great. And it definitely can see the operational momentum across the board, and that's not an issue at all from a culture perspective. On a -- my follow-up, I want to ask about the Harkey. I think in your slide deck, you mentioned that you will go back to the Harkey on the Windham Row in Phase 2 within the next 12 months.
Yes. This is Blake. I'll take that one. The -- there are cost efficiencies when we come back. The biggest ones our pads are built, our facilities are built. This is why, historically, we like if we can develop benches separately, you can let a bench decline in volume, come right back in at another bench for very little incremental cost. So we will enjoy some of those cost savings when we come back from the Harkey possible codeveloped benefits, that's really what we're interested in learning about.
We'll move next to David Deckelbaum with TD Cowen.
I wanted to ask maybe a little bit of just a cost benefit analysis. You guys have been beating production now steadily largely on what appears to be cycle times and just finding ways to do things faster in the field, which is quite commendable. I think you guys articulated the benefits of cost savings on things like the Windham Row in the 10% range.
Yes, David, this is Blake. I'll take that one. I think it's important to iterate cost is an output of our decision-making. And so while lower cost really helped drive some of our economics, we are focused on total returns of our projects and the highest PVI. And so, if that ends up being a 3-well project in Lea County versus a 54-well project in Culberson County, we go where the PVIs tell us to go. And obviously, continued cost gains really help. Cycle times really help, but it doesn't drive where the rigs go. It really drives us that full economic analysis, and that's what we lean into.
An example of that, I love what Blake said, the cost isn't a first order driver. For now and again, we'll have a project either underway or soon to be underway. And our teams through additional science analysis, we'll propose spending more on completions on a project and drives the cost up. But we always look at the incremental benefit financially and make the best decision we can. We learned -- we all learned early on that you can't save yourself rich. You have to create value.
I appreciate the color on that. Maybe just pivoting to the Marcellus, a similar line of questioning on just how you thought through deferring completion activity versus curtailing existing production and keeping up with the completion kins, if there is sort of the inefficiency of drilling programs and frac crews that gets lost in that process or how you guys approach that sort of thought train?
Sure. This is Blake. I'll take that one. Yes, it absolutely as a trade-off, you're spot on. Our preference is to run a frac crew continuously. We know that's when we get our best efficiencies. But, once again, it's back to that investment case and what are the economics of the project.
I want to give a little different spin on an answer here, David. The Marcellus is a great operating area, and we are very constructive on natural gas prices. But I'm also going to tell you that, as you know, we've reentered a part of the field that hasn't seen drilling over time. And we're very pleased to be doing that. And this just gets to my being a responsible operator and communities we operate.
We'll go to our next question from Scott Gruber at Citigroup.
Tom, long-dated gas because they have been moving higher on all the data center growth excitement, how would you think about capital allocation between Anadarko and the Marcellus, if the forward curve is right, and we're in the $3.50 to $4 range, in late '25, '26? And Oil is still healthy, call it, in the 70s. How would you think about that allocation?
Well, I wouldn't have to thank very hard. I'd look at the incremental economics and we go where the best economics are. We have tremendous gas resources in both basins. The -- and Anadarko has natural gas liquids, which really provides an economic boost. But the Marcellus has amazingly low cost of supply, and we produce pure methane, which we just have to compress and put into an air state line, so -- or a pipeline.
Yes, sure. I mean we're all learning this AI power demand story together, and there's a lot of unknowns, but there's a lot of excitement the power gen that's going to be required is huge. Lots of it looks like it's going to come on the East Coast. That's very proximal to our asset. There's a lot of existing pipes there that we can easily get our gas to those markets. And we're very interested. We're talking to a lot of these folks directly trying to understand their business and their needs, and we will be ready to participate.
It's exciting. We'll wait for a word. And then just turning back to Windham Row. Just curious, you mentioned doing simul-frac on half the wells. What's the limitation there, why not doing on all the wells? Is it comfort with the technique or tag configuration or scheduling the frac crews? Just some color on the limitation there? And if there's any upside to doing it on more than half?
Yes, Scott, it's Blake. I'll take that. That's a great question. And I think it's something that gets missed sometimes in simul-frac is you really have to have an optimal pad with a lot of wellheads on one pad to optimize the cost savings. There is sometimes where you might some frac and save no money because a simul frac crew is just basically 2 frac crews smashed together. So you're paying a lot of money for that crew to be there. The efficiencies come when you have a lot of wells on one pad. And just the layout of these drill spacing units doesn't always give us enough wells per pad to use simul-frac optimally. So it's back to that whole cycle analysis. The goal is not to simul-frac everything. The goal is to make the most economic wells. And so we're only chasing it where it makes sense.
Our next question comes from Neal Dingmann at Truist.
My first question comes for you or Blake, maybe on inventory, specifically. Looking at Slide 5, you had an interesting comment that I think makes a lot of sense, and that's you all suggest that the total fluctuates based on things like well spacing cost, cadence and the like. And I'm just wondering how aggressive or conservative would you consider your estimates versus what you've seen play out in the trends in recent quarters?
Well, I'll just say, we have future landing zones that are not modeled in that inventory. But we want to be very careful with how we talk about inventory. And when I say that, I mean, we want to deliver what we promise. And so we don't throw the kitchen sink in, although our inventory today has zones that we didn't have in our inventory a few years ago. There are still zones to be tested, both shallow and deep. And we're pretty optimistic about our ability to extract maximum value out of an acre of land. But the inventory we published is one that we think we can deliver.
Very good. And then just a second question on capital spend. Specifically, I noticed what I think now what is about 70% of CapEx is directly from Upper Marcellus. Is this a result of just productivity that you highlight on Slide 19 or what's driving the spend in the upper area?
Well, we have some great upper locations in the field. Our Tier 1 uppers really long lateral lengths, competitive economics. And so they're just competing for capital. But also the upper is the future of the assets. So we're -- we like having activity in the upper. We're still learning about it. We're still trying to understand our well spacing and our frac design. And it's important, we continue projects in that zone.
We'll go next to Derrick Whitfield at Stifel.
Tom or Shane, a bit of a build on an earlier question. If gas prices were to continue to underperform throughout 2024. How would you weigh or evaluate the decision between reallocation of CapEx and increased return of capital? I suspect your Anadarko and Permian teams would like more capital.
Yes. You're saying the Marcellus pricing stays kind of in and around where it is like this through the rest of the year?
That is correct.
Yes. Well, look, here's what I'd say is we do build in a lot of flexibility into our capital planning. And a couple of that's really foundational to that and a couple of things. One, some plans to accelerate if market environment changes and things get better and also to decelerate if they deteriorate or, in this case, don't firm up a little bit.
As my follow-up, regarding the deferred turn-in-lines in the Marcellus. How long would you technically be comfortable in deferring the wells before you'd be concerned with compromising the effectiveness or integrity of the completion?
We've looked at that long and hard and we don't see a degradation in shut-in time. There's a history as you go back a decade of fairly significant shut-ins. We don't really have a time clock attached to it. But I -- we're anticipating turning these wells online later in the year. And we're -- our data tells us that those reservoirs will not suffer because of it. And part of that is because we don't produce much water there. And so you don't really have the issues that you might have in the other basins.
We'll go next to Leo Mariani at Roth MKM.
I wanted to just dive in a little bit more to CapEx here. I wanted to kind of get a sense on sort of how the numbers are trending. See second quarter CapEx is going higher, do you expect CapEx to kind of come down a little bit in the second half versus the first half, is kind of second quarter, potentially the peak here and -- when you talk about flexibility in the program, I know you mentioned a couple of times, potentially room for more activity. Is that more just kind of a function of some of the savings you've seen year-to-date?
Leo, thanks for the question. And look, there's a couple of things I would just point to, one, Hana put together a great slide, a new slide in the deck, in the appendix 33 that sort of shows where some of the activity is over the course of the year. And your point that you just made around, does it feel like the second quarter could be a peak capital quarter and then the back half of the year, if you take the residual and divide by 2, that may be a lower number than that.
Okay. I appreciate that. Then I just wanted to follow up a little bit on kind of Upper Marcellus. As you look out the next couple of years, do you see the Upper Marcellus becoming kind of a increasing percentage of your overall Marcellus activity. Is that going to be just kind of driven by somewhat the depletion of the lower Marcellus in the inventory stack here?
Yes, Leo, you nailed it. It's -- the Lower Marcellus has been a wonderful zone, and we know all the remaining sticks, and we plan on drilling them here in the next few years. And the remaining is all the upper. That's the future of the asset. And so as we are chewing through our lower inventory, you'll see more upper come in each year. We're really focused on testing and delineating the upper and just proving it out. But yes, depending on capital spend, the upper will be a bigger and bigger portion of our program.
Okay. No, that's helpful. But it sounds like the message is you think the upper can be very, very competitive with other gas assets as you look at it today?
Yes. I mean there's parts of the field that are super competitive, but I'll just caveat the Lower Marcellus in this asset is some of the absolute best rock in all of the Lower 48. And I don't think it's going to compete with the cream with a crop lower that's been drilled. But there's -- it's still very competitive in our capital allocation.
Yes. And Leo, competitiveness is always a function of well performance, but also price. And that's a nice thing about Coterra where we said is we really do have an asset mix allows us to shift capital and allocate it based on those changes. So competitiveness of assets is not a static thing.
Next, we'll go to Charles Meade at Johnson Rice.
Just one question for me, and it's around the way you guys are going to approach the Marcellus in the back half of the year. I think you -- I heard you mentioned in your prepared comments that your plan has you guys turning some wells on in July. And as I think about recent history up in the Marcellus, a lot of times, we can see a good price bounce in the summer, but then we see another bout of weakness in the fall when the cooling demand goes away.
Yes. I'll just -- I'll answer your question with the analogy. We've said from day 1 that the way we manage our program is not a rifle shot, it's a guided missile. So sitting here and saying we're going to turn wells on in July, that's talking about a rifle shot. We're going to guide that missile every step of the way. We typically don't manage our production up and down with the near-term price file.
And that concludes our Q&A session. I will now turn the conference back over to Tom Jorden for closing remarks.
Yes. I just want to thank everybody. Great set of questions. We are very pleased to present the results we presented last night and look forward to repeating that. And as I said many times on this call, it's our -- talking about results is the conversation we want to have. So thank you all very much for your participation this morning.
And this concludes today's conference call. Again, thank you for your participation. You may now disconnect.