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 Coterra Energy First Quarter 2023 Earnings Conference Call. 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 Coterra Energy's First Quarter 2023 Earnings Conference Call. Today's prepared remarks will include an overview from Tom Jorden, Chairman, CEO, and President; and Scott Schroeder, Executive Vice President and CFO. Also on the call is Blake Sirgo, 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 updated 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. Coterra 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 Coterra. Oil production exceeded the high end of our guidance, driven by strong performance in our Permian, Wolfcamp, and Harkey developments. Our Anadarko projects also continued 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, the 12-month NYMEX gas strip had fallen to $2.90 per Mcf. The 12-month WTI oil stood at $67 per barrel. Two quarters ago, we were looking at a 2023 oil strip of $83 and a 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 Coterra 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 frac 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 Anadarko. Both of these basins have opportunities at the ready that provide great returns. Furthermore, our Marcellus assets retained the flexibility to grow in the future should macro conditions and prices warrant increased investment. Looking forward, we retain maximum optionality to employ capital to its best use. We also look forward to publishing our 2023 sustainability report later this year. We're making great progress in understanding methane monitoring, including the discrepancies between the various technologies available to the industry. Coterra 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, Anadarko, and 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. Coterra 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. 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, Coterra 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 1Q '22, discretionary cash flow declined only 16% year-over-year. This was driven by an increase in the company's oil and NGL production, which caused Coterra's liquids production mix 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 a $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. First quarter accrued capital expenditures totaled $569 million, as I said before, but the cash capital expenditures were only $483 million, consistent with expectations. Turning to return of capital. We announced a $0.20 per share base 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, Coterra followed through on its return priorities by repurchasing 11 million shares or $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 billion 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 by 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 turn-in lines are unchanged from our original guidance. In the Marcellus, as Tom has stated in his remarks, we are finishing up a development this month and then plan to drop one of our two frac 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 turning 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 frac crews. Due to improved cycle times, we expect to bring on an additional five wells in the Permian during late '23, offsetting the lower turn-in lines in Anadarko. Turning to unit cost. The company's guidance remains unchanged at the midpoint but there were 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 reiterate 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, Coterra'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.

And your first question comes from the line of Arun Jayaram from JPMorgan. Your line is open.

Good morning, Tom. Nice results from your team. I wanted to see if I could delve into your commentary around the potential activity in the Marcellus. You mentioned that your original plan was to go down to two rigs and one frac crew, but you also signaled that you may stay at this level for a certain amount of time, given the macro. I was wondering if you could give us a sense of whether you think you could hold your Marcellus production relatively flat at, call it, 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 guides around $835 million at the midpoint?

Well, Arun, you just kind of repeated what I've said. So I'll try to give a little bit of detail there. What I said is if we were to stay at the two rigs and one frac 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 onto 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 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 and one frac crew.

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

As we assess current costs, we anticipate that over the next few years, expenses in the Marcellus may be a couple hundred million less than what we are currently spending.

That's super helpful. The second question perhaps 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 give some color on thoughts over the balance of the year. And I know that under your framework, you like to keep around $1 billion of cash on the balance sheet. You're essentially at that level at the end of March. So any thoughts on the ability to sustain this, call it 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?

Yes, this is Scott. That's a great question. Everything you mentioned is absolutely right. We have reaffirmed the goal of maintaining over 50 percent, and we are quite comfortable with that. This puts us in a strong position, as we discussed with our Board yesterday, allowing us to be very flexible. Looking back at the performance over the last five quarters, including the first quarter of this year, we have consistently exceeded that 50 percent mark. It's a baseline that adapts based on market conditions, our goals, and commodity pricing. We will make investment decisions considering all aspects. Do we want to increase our buyback efforts? Should we hold cash for a strategic opportunity? Or do we prefer to stay on our current path and focus more on the base dividend? We have many options. I apologize if I seem a bit cautious, but we are very comfortable with our strategy and well-prepared for this year regarding those choices.

Arun, to follow up, Scott and his team have effectively managed our buyback, seizing opportunities when prices dip. We will remain disciplined in this area. Reaffirming our 50-plus is not arbitrary; we aim to maintain flexibility in our balance sheet. If we were to return exactly 50% in a future quarter, we wouldn't owe anyone an apology. We want to clearly communicate that this is our intent, and we believe there might be alternative uses for cash. While I hope for a constructive buyback program, we will not engage in a cash return competition if we don’t see it as the best option. We believe this approach serves the interests of Coterra owners well, and we have significant opportunities in our portfolio, remaining optimistic about commodity pricing moving forward. We are in a good position.

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

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

Hi, good morning. Thank you for taking my questions. My first question is about your thoughts on the macro environment, particularly regarding oil and gas. There are definitely concerns about oil demand and how it will impact supply and balance in the natural gas market. Considering these issues, as you develop your plans, one of your objectives has been to maintain steady activity to enhance efficiency. What strategies do you have to maximize your free cash flow outlook over the next three years?

Well, Umang, that's an excellent question. I think we've described it as the fact that we do have the optionality to liberate some capital out of our Marcellus program and redeploy it to more liquids-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 business. 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 we think our program does answer the question you've asked as far as maximizing our cash flow.

Yes, that makes a lot of sense. I would like to follow up by discussing risk management, particularly in relation to hedging. Do you have any thoughts on oil and gas hedging for the next one or two years?

Yes. In terms of hedging, we have not strayed from our strategy regarding organization and opportunities. We don't feel the need to emphasize hedging, especially when prices are low, as history shows that can lead to negative consequences. We are considering a more calculated and refined approach, although we are still in the early stages. Currently, we are comfortable with our position and maintain a positive outlook, particularly for gas, over a longer term. We will continue on our current path but are open to exploring opportunities further along the curve. One dynamic we might consider is looking beyond the 12 months we have historically focused on, and we recognize the importance of being more open-minded about our hedging strategies moving forward.

Thank you. Thank you for the color.

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

Hey, good morning guys. This is actually Kalei on for Doug. 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?

Yes. Kalei, this is Blake. I'll take that one. We are seeing the softening across the whole market. It's been slight, but it's starting to pick up some steam. I'll start with OCT. We've seen pipe prices roll over. The way we order pipe that really won't impact us until 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 on 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, 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 discussions 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 their 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 press 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 the second half of '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 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? Is it sort of continues at this pace, do you see further upside risk to guidance as we go through the year?

Kalei, I believe this speaks for itself. We're witnessing strong performance on these projects, and we feel optimistic. We aim to provide guidance based on our observations without holding back, and we are genuinely experiencing some pleasant surprises. We would certainly welcome more positive surprises, but we always strive to communicate our insights honestly.

I guess if you raised the guidance, is it based on what you saw in Q1 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. 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. But right now, our oil assets are really, really performing well.

I appreciate those comments, Tom. Thank you.

Your next question comes from the line of Michael Scialla from Stephens. 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 tell you that 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 years time period, we've got a lot of availability on that market takeaway. Blake, why don’t you...

Yes, 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 cost than our current differentials. So that would be something that would have to go into the discussion. As far as rig and fracs, you just got to stay ahead of it. It's not something we could knee-jerk, but we could get the crews and rigs as long as we play out in time.

Appreciate that. And I wanted to ask on the Upper Marcellus. We've talked about delineations 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 tied to our current acreage footprint. We are back to leasing in the Marcellus and expanding that acreage footprint. Our team in Pittsburgh has done a great job with that. However, this is based on our current spacing model and our existing acreage. So that's the number.

Your next question comes from the line of Neal Dingmann from Truist Securities. Your line is open.

Good morning, all. Thanks for taking my question. First is on, 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 have a little bit more scattered position there?

Well, New Mexico is a tough fair walk 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. 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 rather short inventory behind that. And that doesn't do much for us. 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 us and the operators we trade with. But we look at everything. We're very active in that market, but we're going to be really cautious and preserve value for our shareholders.

Yes. Tom, your strategic approach has always been beneficial. For my second question, focusing on Del, could you provide some details about the six rigs you mentioned that are likely to remain active on Del this year? Additionally, can you remind me of the specific area of focus for those rigs and whether there will be any significant changes in the GOR this year compared to last year?

No. That tends to move around depending on the nature of the program, where we're permitted. This year, looking ahead, we're heavily in reach. We're heavy in Culberson. Eddie is a lower share. Lake County is still very active. It's in our deck, our breakdown of where our activity is. But it does tend to ebb and flow. But you're probably going to see the majority of it on any given year and being ready for refurbishment, just because of there's say of Texas, the time line between project inception and moving dirt is pretty short, whereas you get into Mexico, you have state and federal permit constraints, and it's just not as nimble, but it's going to ebb and flow.

Very good. Thank you, Tom.

Your next question comes from David Deckelbaum from TD Cowen. Your line is open.

Good morning, Tom and Scott. Thank you for your time today. I wanted to ask if you are seeing increased activity in the Harkey zones compared to previous periods. I noticed that this wasn't specifically covered in the presentation, but could you provide an update on how Harkey's performance compares to the other programs in Culberson? Additionally, how are you approaching that zone considering the current challenging commodity environment?

Well, we love the Harkey. I'll say the Harkey, like many, is highly variable. It's not a one-size-fits-all situation. So around the basin, it's going to vary. But in a lot of our position, it's highly competitive with Wolfcamp. We've been very active in the Harkey as you can look at our Slide 12. We've got a lot of Harkey in our program. I think we'll continue with that. And it depends on where you are. There are places where it's right on top of the Wolfcamp. There are places where it's a little lower than the Wolfcamp, 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 the Marcellus briefly, just to revisit lateral length progression over the next several years. 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. 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? Or 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 in 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, they're 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 of 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. Yes, hopefully, that answers your question.

Yes, appreciate that. Thanks, Tom.

And there are no further questions at this time. Mr. Tom Jorden. 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, and 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.