Coterra Energy Inc.

Good morning. My name is Rob and I will be your conference operator today. At this time, I would like to welcome everyone to the Cotera Energy first quarter 2023 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press the star one. Thank you. Dan Guffey, Vice President, Finance Planning Analysis and Investor Relations. You may begin your conference.

Thank you. Good morning and thank you for joining Cotera Energy's first quarter 2023 earnings conference call. Today's prepared remarks will include an overview from Tom Jordan, Chairman, CEO and President, and Scott Schroeder, Executive Vice President and CFO. Also on the call is Blake Sergo, Senior Vice President of Operations. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers, as well as reconciliations to the most directly comparable GAAP financial measures, were provided in our earnings release and update investor presentation, both of which can be found on our website. With that, I'll turn the call over to Tom.

Thank you, Dan, and welcome to all of you who have joined us for our first quarter conference call. Cotera had an excellent first quarter. We delivered on all fronts, production at the high end of our guidance, capital within our targeted front-loaded cadence, and significant progress on our buyback. These results were driven by outstanding asset performance, a recurring trend you should expect from Cotera. Oil production exceeded the high end of our guidance, driven by strong performance in our Permian Wolf Camp and Harkey developments. Our Anadarko projects also continue to deliver above our expectations and set the stage for future activity increases. In particular, part of our production beat was driven by continued outperformance of the Anadarko Miller Trust project, which was brought online last year. The Anadarko is an underappreciated gem. within a strong portfolio. Finally, our Marcellus program outperformed in Q1, as we continue to develop a mix of lower and upper Marcellus targets. As we look ahead, we see continuing volatility in our underlying commodities. As of the close of business yesterday, 12-month NYMEX gas strip had fallen to $2.90 per MCF, The 12-month WTI oil strip stood at $67 per barrel. Two quarters ago, we were looking at a 2023 oil strip of $83 and natural gas strip of $5.30. There are growing fears of a significant recession, which have been exacerbated by the ongoing banking challenges. Fortunately, we at Cotera have some experience with living through volatility and uncertainty. Our formula is simple. Keep our debt low, strive for assets with a low cost of supply, stress test our investments with downside commodity price scenarios, and make capital allocation decisions that optimize returns and preserve flexibility. Service costs appear to have crested and are trending modestly downward. Although we welcome service cost moderation, It does not substitute for our mandate to push forward with operational efficiencies, project architectures that maximize investment returns, and the application of best-in-class technology to leverage our efforts for value creation. We focus on things that are within our control. We are on track with the three-year plan outlined in our Q1 release. In line with our initial plan, we will reduce activity in the Marcellus in the coming weeks and expect to remain at two rigs and one frack crew during the second half of the year. If we were to hold this level of activity flat through 2025, future Marcellus CapEx would decrease significantly and yet hold our northeast production flat, allowing us the option to redirect activity to the Permian and Adarco. Both of these basins have opportunities at the ready that provide great returns. Furthermore, our Marcellus assets retain the flexibility to grow in the future should macro conditions and prices warrant increased investment. Looking forward, we retain maximum optionality to deploy capital to its best use. We also look forward to publishing our 2023 sustainability report later this year. We are making great progress in understanding methane monitoring, including the discrepancies between the various technologies available to the industry. Cotera is working with our vendors to improve the available technology, understand the limitations, and choose the best solution for the problem at hand. With the varying environmental conditions between the Permian and the Dark One Marcellus, We have learned that there is no single scalable solution that can be successfully deployed across our portfolio. Instead, we will rely on multiple technologies to detect, measure, and reduce our methane emissions. Cotera will remain a leading company in innovative design and facility modification to reduce emissions. We also appreciate the collaboration with an outstanding set of competitor companies as we work together to solve this problem. This is an industry-wide challenge, and industry collaboration will be key to finding workable solutions. Our nation and the world depend upon it. With that, I will turn the call over to Scott to walk us through the particulars of a great Q1. Thanks, Tom.

Today, I will discuss our first quarter 23 results, shareholder returns, and updates to guidance. During the first quarter, Cotera reported net income of $677 million. Discretionary cash flow of $1.039 billion, accrued capital expenditures of $569 million, and free cash flow of $556 million. Despite natural gas and oil prices falling 30% and 19% respectively versus 1Q22, discretionary cash flow declined only 16% year over year. This was driven by an increase of the company's oil and NGL production, which caused Cotera's liquids production miss to increase 3% year-over-year to 28%. The company expects greater than 55% of its 2023 revenue to come from oil and NGL sales. Also during the quarter, the company realized a cash hedge gain totaling $100 million versus $172 million loss in Q1-22. First quarter total production volumes averaged 635 MBOE per day, with oil averaging 92.2 MBO per day and natural gas volumes at 2.76 BCF per day. Oil and BOE finished 2.5% and 1.6% above the high end of guidance, respectively, and natural gas hit the high end. The strong performance was driven by a combination of positive well productivity trends and improved cycle times. Turn in lines during the quarter totaled 49 net wells above expectations. The incremental wells came online late in the quarter. First quarter accrued capital expenditures totaled 569, 569 million as I said before, but the cash capital expenditures only $483 million consistent with expectations. Turning to return of capital, we announced a 20 cent per share based dividend and remain one of the highest yielding base dividends in the industry. Management and the board remain committed to responsibly increasing the base dividend on an annual cadence. During the first quarter, Cotero followed through on its return priorities by repurchasing 11 million shares for $268 million. In total, we returned 76% of free cash flow during the quarter. As we communicated in February, it is our intention to pursue strategic buybacks ahead of variable dividends. We have over $1.7 billion remaining on our $2 billion buyback authorization. We are reiterating our annual commitment to return 50% plus of free cash flow to shareholders. Lastly, I will discuss the refinements to our 23 guidance and activity outlook. We reiterated the company's capital estimate of $2.0 to $2.2 billion. While we are seeing clear signs of cost softening, we have yet to realize meaningful savings and therefore have not built any future cost reductions into our forecast. We are increasing our full year oil guidance 1% to 87 to 93 MBO per day, driven by efficient operations and strong well performance in both the Permian and Anadarko basins. The total company well turning lines are unchanged from our original guidance. In the Marcellus, as Todd As Tom has stated in his remarks, we are finishing up a development this month and then plan to drop one of our two frack crews and hold a single crew for the balance of the year. We also plan to drop from three rigs to two rigs this summer as planned earlier this year. In the Anadarko, a late 23 turn in line was pushed into 24. This lowers our Anadarko turn in lines to seven wells down from our prior range of 10 to 15 wells. We now intend to maintain one to two rigs in the basin for the remainder of 23. In the Permian, we expect to continue to run six rigs for the remainder of the year and will pivot between two and three frack crews. Due to improved cycle times, we expect to bring on an additional five wells in the Permian during late 23, offsetting the lower turning lines in Anadarko. Turning to unit cost, the company's guidance remains unchanged at midpoint. but there was some moving pieces, primarily driven by reclassification between cost categories, which occurred after completing our integration into a single accounting system earlier this year. We also reiterated our three-year outlook, which assumes the company achieves a three-year oil CAGR of 5%, BOE and natural gas CAGR of 0% to 5%, which is achievable with capital and activity that is flat to down relative to 23%. In summary, despite commodity headwinds, Cotera's outlook remains strong. Driven by continued strong execution, we are well positioned to meet or exceed our 2023 targets. With that, I will turn it back to the operator for Q&A.

At this time, I would like to remind everyone in order to ask a question, press star, then the number one on your telephone keypad. And your first question comes from the line of Arun Jaram from JP Morgan. Your line is open.

Good morning, Tom. Nice results from your team. I wanted to see if I could delve into your commentary around a potential activity in the Marcellus. You mentioned that your original plan was to go down to two rigs and one frack crew, but you also signaled that you may stay at this level for a certain amount of time given the gas macro. I was wondering if you could give us a sense of do you think you could hold – you know, your Marcellus production relatively flat at, call that 2.1 BCF a day. And what would that mean for CapEx if you did go down to that level? Because I think this year's CapEx guy is around $835 million at the midpoint.

Well, everyone, we, you know, you just kind of repeated what I've said, so I'll try to give a little bit of detail there. We, you know, our What I said is if we were to stay at the two rig and one frack crew, that's not a plan. That's kind of a guide as to what would happen. As we look at the macro right now, we kind of like that and where it positions us. Our Marcellus team has done a really nice job of smoothing out their cadence and getting on to a regular program. So as we look ahead at that level of activity, we think we will – be able to shave off significant capital in the Marcellus and have the opportunity to redeploy that elsewhere. We would hold our production flat or actually slightly grow within that range we've already telegraphed. And it's really a nice place to be right now because strategically what we'd like to do is keep that Marcellus production flattish and be ready to go when the gas macro improves. And that's exactly the position that our really great team in Pittsburgh has put us in. So everything you said is true. I'm not sure what other color we can give. But, you know, one of the things we really like is the flexibility to pivot. And we're maintaining that gas production. We don't want to see it decline. So it will indeed maintain if we were to hold those two rigs in one cracker.

Yeah, Tom, I don't know if you could follow up just one question with how much, you know, lower capex would it be if you went to that program?

With current costs, we think a few out years would probably be a couple hundred million below what we're currently spending.

That's super helpful. The second question for you and Scott, Tom, you have been handily surpassing the 50 plus percent minimum cash return threshold to shareholders. You're at 76% this year. I was wondering if you could get some color on thoughts over the balance of the year. I know that your framework, under your framework, you like to keep around a billion dollars of cash on the balance sheet. You're essentially at that level at the end of March. So any thoughts on the ability to kind of sustain this mid-70s type of cash return over the balance of the year? Because you really don't have much debt due until a little bit into 2024, I believe.

Yeah, this is Scott. Great question. Everything you said is exactly correct. We did reaffirm the 50 plus percent. We're very comfortable with that. That affords us, really, as we shared with our board yesterday, the the ability to be very opportunistic when you go back and look at the report card for the last five quarters, including this first one this year. We have surpassed the 50-plus percent. It is a floor, depending on market conditions and where we want to be and what the commodity strip is doing. It's an investment decision with all three pieces playing into it. Do we want to lean in more on the buyback? Do we want to hold cash for some other strategic opportunity, or do we just want to kind of stay on pat and just rely more on the base dividend? We have all that optionality. I'm sorry to come across as a little coy, but we're very comfortable with that framework, and we're set up tremendously for this year in terms of that optionality.

Arun, if I could just follow up on, I'll say this. Scott and his team have really been masterful in how they've executed our buyback. taking opportunities when the price dips, we're going to continue to be disciplined there. But, you know, the fact that we're reaffirming our 50 plus is, um, not arbitrary. We, we really want to maintain flexibility in our balance sheet. And if we were to have a quarter in the future, when we returned exactly 50, we have nothing to apologize for. We want to be really clear with people that that's our intent. And that we think that there may be alternate uses of cash. It could be, you know, I hope it's a constructive buyback program. But, you know, if we don't think that's the right way to go, we're just not going to embark in an arms race of cash return. We just don't think that's in the best interest of the Cotera owner. And we have great opportunities within our portfolio. And we're fairly constructive on commodity pricing going forward. So we're right where we want to be.

Sounds good. It does give you a lot of flexibility. Thanks a lot, Tom.

And your next question comes from the line of Umang Chowdhury from Goldman Sachs. Your line is open.

Hi, good morning, and thank you for taking my questions. My first question was – hey, good morning. My first question was just wanted to get your thoughts around the macro, both oil and gas. I mean, definitely a lot of concerns around demand for oil and the pace at which we'll cut supply to balance the market for natural gas. And given these concerns, right, as you think through your program, one of the goals has been to maintain consistent activity to maximize efficiency. How do you, what are the levels you can pull, right, to maximize your free cash flow outlook over the next three years?

Well, Amang, that's an excellent question. I think we've described it. The fact that we do have the optionality to liberate some capital out of our Marcellus program and redeploy it to more liquid-rich opportunities would be a pivot to maximize our cash flow in the next few years. We have historically not done a really good job of predicting commodity swings. And as I said in my opening remarks, six months ago, the situation looked entirely different. It's changed. And yet now we're all highly confident that we know what the future looks like. And so having that flexibility really allows us to get up every morning and make good long-term decisions. We don't make those decisions based on the daily spot price. We make those decisions as we see macro trends. Right now, as we look forward, we are, in the long run, highly constructive on gas. Over the next year, we're going to be cautious. That's why we want to maintain our gas production but not go nuts there. So, yeah, we think our program does answer the question you've asked as far as maximizing our cash flow.

Yeah. that makes a lot of sense and then i guess the follow-up on that would be the other way to ensure and manage risk would be around hedging um so any thoughts around uh oil and gas hedging over the next uh for the next one to two years yeah in terms of hedging obviously our we haven't moved away from our our strategy around

organization and all the opportunities we don't have to lean in on hedging the last thing you want to do is lean in on hedging when prices are low if history will show that that always kind of comes back to bite you we are looking at a more calculated more refined way we're in the early stages of that more to come on it but right now we don't feel the need to lean in in either oil or gas to protect the downside we're pretty comfortable with where we're at and show some optimism on both products, or at least particularly on the gas side going out farther. So we'll stand pat right now, but we are open to looking at disconnects farther out of the curve. One dynamic that you may see in place with the team we're working with is maybe we look a little further out than just the 12 months that we've been doing historically. And I think that behooves us to really open our minds to be more open-minded to how we hedge going forward.

Thank you. Thank you for the call.

And your next question comes from the line of Doug Legate from Bank of America. Your line is open.

Hey, good morning, guys. This is actually Kalei on for Doug. So thanks for taking my question. My first question is on inflation. So as the commodity has pulled back a bit, activity seems to be softening. What are you guys seeing on leading-edge pricing at the moment, and how are you guys positioned to respond to it?

Yeah, Clay, this is Blake. I'll take that one. We are seeing the toughening across the whole market. You know, it's been slight, but it's starting to pick up some steam. I'll start with OCTG. You know, we've seen pipe prices roll over. The way we order pipe, that really won't impact us to Q3 or Q4. But we estimate that could impact our program $15 to $20 per foot if we realize all that. On the frac side, we talked about last time how our contracts work for the year. We have quarterly renegotiation points and semiannual renegotiation points on our frac crews. We saw some very slight reductions from Q1 going into Q2, but it was a reduction. And right now we're having the conversations to Q2 to Q3, and they're different conversations than we were having just a quarter ago. So we'll see how those progress. On the rig side, you know, we're really in really good shape. Most of our long-term contracts are actually falling off within Q2. By the end of Q2, only 20% of our rig fleet will be under any type of long-term contract. We're seeing movement there. We are seeing some deflation. We're in discussion with all those folks right now. But we have really long-term service partners, folks we've been through a lot of cycles with, and they're productive discussions. I think everyone understands the market we're in today is not the market we were in a year ago.

I guess to depress a little bit, if you were to renegotiate some of those contracts, is that more of a benefit to the back half of 23's capital budget, or is this more of a 24 consideration?

I would think of it more as it would impact second half 23 and kind of set up a run rate going into 24.

Thank you. I appreciate that. My next question is on the revised oil guidance. You guys raised it by 1,000 barrels per day, and I guess I'm wondering if you can really call it with that much accuracy, or if the intention here is to send a signal. And if it is to send a signal, what are you trying to convey about the performance that you're seeing so far? If it sort of continues at this pace, do you see further upside risk to guidance as we go through the year?

I think it speaks for itself. You know, we're seeing a great performance on these projects. We are optimistic. We try to guide as we see it. But, you know, we don't sandbag. but we're really seeing some surprises to the upside and i think that you know we would we would love to see further surprises to the upside but we really try to call it as we see it but i guess if you raise the guidance is it based on what you saw on 1q continuing

Or is it sort of assuming that you get back to a more normal level? Or what does it say about the expectations for the balance of the year?

Well, it says that we're seeing increasing results that recalibrate our analysis. And as we look at the projects coming forward, we think that's appropriate recalibration. You know, we learn along the way. And we love to learn on the upside. But you know what? Every now and then, you go the other way. Right now, our oil assets are really, really performing well.

Great. I appreciate those comments, Tom. Thank you.

Your next question comes from a line of Michael Cielo from Stevens. Your line is open.

Hi. Good morning, everybody. Tom, you talked about being ready to grow your Marcellus production when the market signals you should. I want to get your view on constraints on pipelines or I guess Blake talked about the rig and crew situation softening, but any potential constraints on getting rigs or crews back when you decide to pivot back to growth mode?

Well, I'll tee it up and turn it over to Blake. We do have some available capacity to grow. It's not unlimited. It's not without boundaries, but over a few-year time period, we've got A lot of availability on that market takeaway. Blake, why don't you?

Yeah, just to echo Tom, we do have options to grow our gas volumes there. There is the pipeline space. It might come with a little higher costs than our current differentials, so that would be something that would have to go into the discussion. As far as rigging fracks, you know, you just got to stay ahead of it. It's not something we could knee-jerk, but we could get to cruising rigs as long as we plan out in time.

Appreciate that. And I wanted to ask on the Upper Marcellus, you've talked about delineation there. When you look at your 529 Upper Marcellus locations that you had in inventory at the end of the year, if the delineation works, I guess, what would be the impact on the number? Are you talking about potentially doubling the inventory or is it a modest increase? I'm just looking for some sense of what delineation could mean for the inventory.

No, that inventory is really with our current acreage footprint. We are back to leasing in Marcellus and filling in that acreage footprint, and our team in Pittsburgh has done a really nice job of that. But that is with our current model of spacing with our current acreage. So that's the number.

Got it. Thank you.

Your next question comes from the line of Neil Digman from Truist Securities. Your line is open.

Mornell, thanks for taking my question. First, it's kind of, I guess, an M&A type question. Specifically, I'm just wondering, could you discuss opportunities to sort of trade and block up your Delaware acreage, specifically in New Mexico, where it looks like, you know, you have a little bit more scattered position there?

Well, New Mexico is a tough area to block up. The ownership is like a quilt work patch. There are some assets on the market that we've looked at, but even at today's prices, assets are marketed at full retail. And we're going to be very cautious on M&A. With our balance sheet and our organizational capacity, We would love to find a transaction that adds value to our owners and increases our opportunity for operations. But, you know, quite frankly, a lot of the assets out there have peaked production. They've really drilled to increase production over the short run and have a rather short inventory behind that. And that doesn't do much for us. Yeah. we've also traded and done a lot of swaps to increase our ability to block up our drilling spacing units and have long laterals so there's a lot of that type of activity that's the benefit of of us and and the operators we trade with but uh you know we look at everything we're very active in that market but uh we're going to be really cautious and preserve value for shareholders yeah like your your strategic nature tom it's always

pay dividends. My second question, maybe just sticking with the Dell, could you give me an idea of sort of, I know you mentioned or you or Scott mentioned six rigs likely to continue active in the Dell this year. Could you remind me kind of what area that'll focus and as a result, really any notable change in the GOR this year versus last?

No, you know, that tends to move around depending on the nature of the program, where we're permitted and You know, this year, looking ahead, we're heavily in Reeves. We're heavy in Culberson. Eddy is a lower share. Lee County is still very active. It's in our deck, you know, our breakdown of where our activity is. But it does tend to ebb and flow. But you're probably going to see, you know, the majority of it on any given year being Reeves or Culberson. Just because of there it's the state of Texas. The timeline between project inception and moving dirt is pretty short, whereas you're getting into Mexico, you have state and federal permit constraints, and it's just not as nimble. But it's going to flow. Very good.

Thank you, Tom.

And again, it is star one to ask a question. Your next question comes from a line of David Dekelbaum from TD Cowan. Your line is open.

Morning, Tom and Scott. Thanks for the time today. I was curious. Good morning. I wanted to ask a bit. I don't know if my eyes are just playing tricks on me, but when I look at presentations, are you including greater activity at this point for the HARKI zones? And you didn't touch on that specifically, I guess, with this presentation, but can you update us on how the HARKI performance is relative to sort of the other programs in Culberson and how you're thinking about that zone? perhaps the more challenged commodity environment today?

Well, we love the Harki. I'll say, you know, the Harki, like so many, is highly variable. It's not a one-size-fits-all. So around the basin, it's going to vary. But in a lot of our position, it's highly and competes very nicely with the Wolf Camp. We've You know, we're very active in the Harki, as you can look at our slide 12. We've got a lot of Harki in our program. I think we'll continue with that. And, you know, it depends on where you are. There's places where it's right on top of the Wolf Camp. There's places where it's a little lower than the Wolf Camp. But it's one of the best landing zones in the basin. I'll say that flat out.

I appreciate the color there. It doesn't sound like necessarily a composition has shifted from quarter to quarter per se, though.

No, no.

Okay. Shifting just to Marcellus briefly, just to revisit lateral length progression over the next several years, you know, the upper obviously has a greater weight, I think, and I think you all said in the 23 program versus what you expect to do in 24, 25. It's Should we expect that future upper wells that are in the program in 24-25 are still in that, call it, 11,500-foot range? How do you think about the average lateral length for the upper versus the lower in the next few years?

Well, the average lateral length for the upper is going to be on the longer end of that. The upper is fairly wide open, so I think you're looking at average lateral lengths that are going to be 10,000 to 15,000 feet. probably closer to the lower end of that, depending on what our units look like. So a lot of the average lateral length in the Marcellus program is really a combination or a function of the upper versus lower mix. As we fill out the lower, we're going to have shorter lateral lengths because we're filling in islands that are undeveloped.

Hopefully that answers your question. Yeah, I appreciate that. Thanks, Tom.

And there are no further questions at this time. Mr. Tom Jordan, I will now turn the call back over to you for some final closing remarks.

Thank you all for joining us. It's nice to generate and discuss great results. We've always been a team that likes to talk about results more than promises. I look forward to continuing to talk about results as time marches on. Thank you very much.

This concludes today's conference call. Thank you for your participation. You may now disconnect. Thank you.