Coterra Energy Inc.

Thank you for standing by. At this time, I would like to welcome everyone to the Cotera Energy third quarter 2022 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 star one. Thank you. Dan Guffey, Vice President, Finance, Planning and Analysis and Investor Relations. You may begin your conference.

Thanks, Cheryl, and good morning. Thank you for joining Cotera Energy's third quarter 2022 earnings conference call. Today's prepared remarks will include an overview from Tom Jordan, CEO and President, and Scott Schroeder, Executive Vice President and CFO. Also on the call, we have Blake Sergo and Todd Raymer. 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 thank you all for joining us today for our third quarter 2022 recap. At third quarter end, Cotera completed our first full year as a new company. We've made remarkable progress and have established a consistent operating rhythm, a spirit of collaboration and teamwork, a commitment to excellence, and a common economic language throughout the company. We've developed new methodologies, learned from one another, and are building a culture of technical excellence, capital discipline, transparency, and open and productive debate. We are deeply proud of the organization and the progress we've made. It all starts in the field. 100% of our assets are in the field, and the top-notch field staff is foundational to an excellent operating company. I want to give a shout-out and a big thank you to our field personnel. whose perseverance in hostile environments inspires us all. During the past week, I've visited Cotera field offices in Susquehanna, Pennsylvania, Carlsbad, New Mexico, and Oklahoma. It is impossible to spend time in these offices without coming home fired up by the commitment that our field team has to the company and to one another. Their passion for excellence, safety, and environmental stewardship reflects the heartbeat of Cotera. We had a great third quarter. As we announced last night, we reported total production on a BOE basis that was above the high end of our guidance. More importantly, we had excellent economic returns in all three operating basins. Our Permian, Marcellus, and Anadarko business units all posted outstanding economic returns in spite of inflationary headwinds. We reported earnings of $1.51 per share, We declared a fixed plus variable dividend of 68 cents per share, which was an increase over the second quarter. We continued to execute on our buyback with approximately 60% of the authorization now complete, and we retired $874 million of long-term debt. All in, we returned a total of $1 per share during the third quarter in the form of dividends and share repurchases. We have now executed in our return promises for a full year and look forward to making this behavior routine. We are hard at work planning our 2023 capital program. All three of our business units have fielded options that allow us to continue to generate top tier returns while maintaining flexibility. Although we will not be announcing specifics of our 2023 capital program until our fourth quarter update, We are working on plans that preserve the flexibility to accelerate or decelerate as conditions warrant. We will accomplish this with a mix of rigs and frack crews under both long-term contracts and short-term agreements. Although we're optimistic about 2023 and beyond, we're not good at predicting commodity prices or inflation, and we will be prepared to adapt to changing conditions up or down. As I have said, flexibility is the coin of the realm in the commodity business. A few words about inflation. We currently project total well costs in 2023 increasing 10 to 20 percent on the dollar per foot basis year over year. Individual line items, which include rig rates, frack crews, sand, tubulars, fuel and labor, may exceed these ranges, but our projected total well costs are a function of our particular timing and particular efficiencies. Although we will continue to fight inflation with efficiencies, longer laterals, and optimal pad designs, we do not have a silver bullet here. We are market takers. The good news is that once we arrive at a total capital number for 2023, We have the asset quality to generate excellent returns in spite of these inflationary headwinds. You will also note that we disclosed some recent flowback data from a nine-well Marcellus development, seven upper Marcellus wells and two lower Marcellus wells. This project also contains three fully-bound infill wells drilled at an 800-foot well spacing. allowing us the opportunity to study well-to-well interference. We also studied communication between the upper and the lower Marcellus. There were 11 existing lower Marcellus wells underlying this project and offsetting the new upper Marcellus wells. Those wells have cumed a total of 127 BCF, coming online between 2012 and 2019. So that was pre-existing production in the lower Marcellus under these new upper Marcellus wells. We're pleased to announce that we see little to no communication between the upper and lower Marcellus wells, confirming our thesis that the Purcell limestone that separates them serves as an effective frac barrier. This will be very important to our future development of the upper Marcellus. Plus, Owing to the lower dollar per foot cost of the Upper Marcellus wells, the economic returns of the Lower and Upper Marcellus are comparable at a flat $4.25 NYMEX gas price. We will continue to delineate the Upper Marcellus and seek to enhance further capital efficiencies by optimizing spacing and completion parameters. We are very encouraged with the economic learnings from this important test. Finally, Let me comment on the Marcellus Reserve revision that we discussed in our release. This was a culmination of bringing the teams together from both legacy companies, establishing technical consistency, and applying learnings from across Coterra's three basins. These expected revisions are spread over the 50-year life of producing wells. For new wells, the difference between our revised forecast parameters and the original forecast parameters have minor differences within the first five years of production when 80% of the net present value of a new well is captured. Furthermore, these expected revisions will have no material impact on our near-term cash flow, capital allocation, or ability to deliver on the return of capital promises that we have made. I also want to highlight that last night we released our first Cotera sustainability report which can be found on our website. We hope that you will find it to be readable, crisp, and factual. It reflects our commitment to be the very best and to communicate with authenticity and integrity. With that, I will turn the call over to Scott, who will recap a great quarter.

Thanks, Tom. Today I will briefly touch on third quarter 22 results, shareholder returns, and then finish with updated guidance. During the quarter, Cotera generated discretionary cash flow of $1.5 billion, which was up 2% quarter over quarter, driven by strong operational execution and robust natural gas prices. Accrued third quarter capital expenditures totaled $456 million, down 3% sequentially. Cotera's free cash flow totaled $1.1 billion for the quarter, which included cash hedge losses totaling $259 million. The third quarter 2022 total production volumes averaged 641 MBOE per day, with natural gas volumes averaging 2.81 BCF per day. BOE and natural gas production were above the high end of guidance. Oil volumes averaged 87.9 MBOE. per day above the midpoint of expectations. The strong third quarter 22 volume performance was driven by a combination of accelerated cycle times, positive well productivity, and the result of being in ethane recovery for the majority of the quarter. Third quarter turn in lines totaled 46 net wells in line with expectations. During the third quarter, the company retired a total of $830 million of long-term notes which is a combination of the previously announced 124 million of private notes and 706 million of 2024 public notes. After the quarter closed, the company retired the remaining portion of the 24 notes, which totaled an incremental $44 million. The company exited the quarter with $778 million of cash, a net debt to trailing 12-month EBITDAX leverage ratio of 0.2 times and liquidity standing at $2.3 billion. We've been clear about our desire to reduce absolute debt levels, and the third quarter actions achieved our targeted level. Turning to return of capital. October 1, 2022, as Tom said, was the one-year anniversary of Cotera. If you recall on the merger date, we guided that Cotera had the potential to generate $4.7 billion in cumulative free cash flow the period of 2022 through 2024 at mid-cycle prices. Driven by strong operational performance and higher commodity prices, Coterra is expected to generate close to $4 billion in free cash flow in 2022 alone. Since our formation and including yesterday's announced dividends, the company will have returned $4.3 billion to shareholders, or 18% of our current market cap in its first 14 months. This includes $2.6 billion in cash dividends made up of $583 million in base dividends, $407 million in special dividend upon the transaction being closed, and $1.7 billion in variable dividends. Also included in that number is $740 million in share repurchases and $874 million in debt repayment. We will continue to follow through on our commitment to a disciplined capital allocation and return strategy. For the most recent quarter, we announced shareholder returns totaling 74% of the third quarter 22 free cash flow or 44% of cash flow from operations. The return of capital is being delivered through three methods. First, we maintained our $0.15 per share common dividend, which remains one of the largest base dividend yields in the industry. Second, we announced a variable dividend of $0.53 per share, combined with our base plus variable dividends that total $0.68 per share, up from $0.65 per share paid in the second quarter. Our total cash dividend is equal to 50% of free cash flow, as is our continuing commitment. Third, during the third quarter, we repurchased $253 million of common stock, or 9.3 million shares, at an average price of 27.03. The buyback amounted to 32 cents per share, or 24% of our free cash flow. Just over seven months since announcing our $1.2 billion buyback authorization, we have repurchased 28 million shares for $740 million, utilizing 59% of our authorization. We previously discussed our intention to execute the full authorization within a year and remain on track. Lastly, I will discuss guidance. We modestly increased our full year 2022 BOE and natural gas production guidance while maintaining capital and unit cost guidance. Our annual production guidance is up 1% to 625 to 640 BOE per day and 2.78 to 2.85 BCF per day respectively. We have no change to our 2022 turn in line guidance and expect total company turn in lines to be near the midpoint of guidance. Our fourth quarter total production guidance is 615 to 635 MBOE per day with natural gas and oil volume guidance set at 2.73 to 278 BCF per day and 86 to 89 MBO per day respectively. On the 22 capital, we are maintaining our guidance range but expect to be at the high end driven by ongoing inflation. While we are continuing to see inflationary pressures relating to operating costs, we are maintaining unit cost guidance for LOE, GP&T, G&A, taxes other than income, and deferred tax ratio. One note, the deferred tax ratio during the third quarter of 8% was below the expected run rate due to a favorable tax law change in Pennsylvania that was enacted during the quarter. The Pennsylvania corporate income tax rate was lowered for all future years, reducing Cotera's future tax liability. This reversal was recognized as a deferred tax gain on the quarter, which caused a one-time adjustment and drove the deferred tax ratio below our annual guidance. As it relates to the reserve news and its impact, the third quarter results reflect the increased DNA required after the adjustment This will carry through into the fourth quarter, and even with the adjustments, our full-year DD&A guidance remains unchanged. In summary, Cotera continues to deliver on all fronts with strong operational execution and disciplined capital allocation. As always, maintaining one of the best balance sheets in the industry remains foundational to our future success. With that, we'll turn it back over to the operator for Q&A.

To ask a question, please press star 1. Please limit yourself to one question and one follow-up. Your first question is from Janine Y. of Barclays. Please go ahead. Your line is open. Hi. Good morning, everyone.

Thanks for taking our questions.

Hi, Janine.

Hi. Good morning, Tom. Our first question is on capital allocation. And I guess with the upper Marcellus now looking like it's comparing more favorably to the lower than maybe what perhaps some may have appreciated, And the Permian looks like it's firing on all cylinders. There seems to be a lot of optionality for capital allocation next year. Do you have any further commentary on what that allocation could look like between the upper and lower going forward? And also perhaps any commentary on what it could look like between your three basins next year?

Well, thank you for that question, Janine. You know, we don't have any specifics. I will say your observation is spot on. We're very pleased by the upper and we're also pleased by the economics of the upper. You know, as we look at the Marcellus, you know, there are a lot of factors that come into play. One is, you know, we are kind of finishing out that lower and our choices of pads is also a function of our system line pressure where we have compression capability. I think you'll see us have a sizable mix of upper in our portfolio going forward. Sizable is somewhere 30% to 40%, but we're still working on that. We would like to continue to delineate, but thus far, we're pretty encouraged, as you can see. You also rightly noted our Permian is firing on all cylinders. So right now, we have a lot of options in front of us for 2023. We've got some outstanding economic returns. We'll look forward to continuing to work it, but we don't really have anything definitive to say this morning on how we're going to allocate capital.

Okay, great. You knew we had to try. Thank you. Our second question, maybe moving to the reserves. On the approved reserves update, the Permian Anadarka reserves are expected to increase by about 10% year-over-year, and the Marcellus is expected to decrease about by a third. On the Marcellus, the deal closed a little over a year ago. Is this change really just a matter of having maybe more time under your belt to study the asset, and that's what's driving the updated view on the type curves, or is it something more related to, like, your change in philosophy or your price deck assumption? And any additional color would be great on where you're seeing the most impact along the performance curve. And we heard your prepared remarks that 80% of the NPV value is within the first five years. But a lot of questions in there, but, you know, just an important topic. Thank you.

Yeah, no, thank you for that, Janine. You know, when you bring two teams together, there's lots of differences. There's differences in operating techniques, differences in safety philosophy. There are differences in incentive systems. There's differences in technical analysis. So, you know, we really set to work October 1, 2021, of just reconciling a lot of these differences. And, you know, we brought some new techniques and technologies. We learned from one another. But I will say, you know, one of the things you've heard me talk about in the past is this annual look back we do. And it really wasn't until the third quarter that we were able to look at the kind of the systemic issue of the reserves in a light that was, I think, new to many of our colleagues that had worked the Marcellus for a long time. And it really was third quarter when we said, okay, this is worth digging into. And we had all the experts in the room. But I really want to say, and hopefully this came out from our remarks, we really see this as having little to modest financial impact. In fact, we're saying it's not a material event. There's certainly no impairment involved with it, and the DDNA is extremely modest. We also don't see it really impacting our cash flow significantly over, you know, the next three to five years. Now, you may say, well, how do you say that? Well, you know, you cannot take reserve forecasts and just immediately translate it into a cash flow forecast. And the reason is that field in Susquehanna County is very complex. You have line pressure issues, you have parent-child effects, you have occasional shut-ins that you have to deal with. So what happens is our team in Pittsburgh takes the projects they're going to drill and they take it into a system-wide model and see what it's going to generate in terms of a production forecast And although that starts with a base reserve forecast, you do look at all the various things that are going to impact that. Those reserves are going to be produced over a 50-year time frame. But over a 3-, 5-, 10-year time frame, the actual production, actual cash flow is going to be based on particulars of the field hydraulics and field situations. So for many, many years, and certainly for Coterra's history, our cash flow forecasts have come from that field-level analysis and the actual operating conditions on the ground. And so we don't see this as having a material impact to our cash flow forecasts over the next three to five years. Now, you know, in fairness to your question, over that 50-year life, that gap is going to be closed. But that differential is decades out in the future in the well life. So this is not a significant impact on our cash flow as we go forward. Certainly won't impact our capital allocation. But we did the analysis in the third quarter. And we felt like, OK, we saw it. At least we could define ranges with certain confidence. And we thought it was our responsibility to communicate it. And that's why we came out this morning.

We appreciate all the details. Thank you, Tom. Your next question is from Umang Taberi of Goldman Sachs. Please go ahead. Your line is open.

Hi, good morning, and thank you for taking my questions. I wanted to circle back on the activity point which you mentioned. I know I understand it's early days, but I wanted to get your thoughts on the Permian and the gas basis risks next year and how you're thinking about managing that risk and if that would bias the activity towards earlier areas in the Permian Basin.

Well, that's a great question. And I'll invite Blake Sergo here to join me in the answer. One of the things, we look at this very carefully. Now, obviously, in the Permian Basin, oil is our dominant revenue. And in fact, part of the problem in the Permian Basin is gas is kind of a byproduct. And oil is such a dominant part of the revenue that it's associated gas. But the drilling decisions are really driven by that oil. We've taken great pains over the years, and our marketing group, and Blake can comment on this, has been very effective in giving us a sureness of flow. Waha pricing is a very small exposure to our overall corporate price structure, but the critical issue is we feel very confident saying that we have sureness of flow, and regardless of that basis, We think our wells will flow and we'll be able to capture that oil revenue, which is really foundational to the investment decision. But, Blake, I'll let you comment on that.

Yeah, thanks, Tom. I think we all saw Waha go negative late last week, which, of course, we don't like seeing any of the commodities we work so hard to produce go negative. But October still finished above $3 for the month. Historically, that's really strong for Waha. But it's not a surprise. Waha is really tight. Capacity is going to be tight until the end of 23 when the expansion projects come online. So anytime there's major planned maintenance events like this, we're going to see these fluctuations. Tom just alluded to it. Well, Waha price gas is 60% of our Permian gas portfolio. It's only 6% of our Cotera gas portfolio. We have layered in some Waha hedges going into 23 to help minimize that volatility in cash flow. But really all we're focused on is flow assurance, as Tom said. All our Waha price sales are firm with great counterparties. That was on display last week. We had absolutely no interruption to flow. So while we expect some blips along the way throughout 23, we view it as minimal impact to cash flow and we have the flow assurance we need.

Great. Thank you. And my next question was on inflation expectations for next year. I know it's early days. You talked about 10 to 20 percent increase potentially in 2023. Are you seeing any regional differences between Permian and Appalachia? And especially in the Permian, because I believe last quarter you had talked about cost increasing by 30% to 35% over 2021, in 2022.

Yeah, sure. This is Blake. I'll comment on that. We see inflation widely in every basin in all the same categories. We just went through this process contracting a lot of our services for 23. I'd say in general, the Marcellus is a little higher. That's not unique to just this moment in time. Everything in the Marcellus is winterized, so it commands a little higher price. And it's just a smaller swimming pool than the Permian, so there's a little less competition for services, and that comes out in more inflation. When we look ahead to 23, right now we're saying 10% to 20% is what we're seeing. And that's based on the most recent contracts we're entering into. We do have some cost categories, though, that are beyond that range. The reason we're not projecting beyond that is there's a lot of things that go into our $23 per foot. So lateral length, timing, 22 contracts extending into 23, our efficiencies, all those things come into play. Right now, we're modeling closer to the lower end of that range, but if inflation runs through 23 like it did in 22, we can easily see the high end of that range.

Until then, we'll focus on what we can control. Makes sense.

Your next question is from Arun Jararam of JP Morgan. Please go ahead. Your line is open.

Yeah, good morning. Tom, I was wondering if I could maybe ask the question on the reserve write-down, maybe a different way. If you did the PV-10 standardized measure kind of at a flat deck, is there any way you could give us a sense of what the impact would be? Because it sounds like a lot of the impact is in the later portion of the production life of the wells. So I just wanted to give a sense. Maybe you could haircut it like that.

You know, Arun, what I can tell you is in something like this, the value impact is significantly less than the volume impact. I think that's probably clear to everybody. But, you know, I just want to say, although we've come out and we've really tried to give ranges that we think are going to be, you know, we think they're realistic, this is really a fourth quarter process. And we want to finish our reserves. We've got an auditor that we'd like to get through a reserve audit. We have a lot of remaining work to finish that out. And if I could indulge you to hold that question until we're finished in the fourth quarter, I think we can be pretty forthcoming. But we think the ranges we've given are realistic. And we're kind of coming out a quarter early on reserve talk.

Understood. Understood. Tom, you mentioned that the cash flow impact would be minimal. Could you give us a sense of what kind of impact you sense on your production outlook in view of sustaining capital requirements in the Marcellus? Does this have any impact as you think about 23, 24 production?

I don't think that this has any impact on it. Now, I will say, you know, it depends whether you're talking about the upper or lower. I mean, as we're finishing out the lower, as we've talked in the past, we're dealing with situations where we may have shorter lateral lengths. You know, we have up space, but, you know, we are infilling islands of undrilled, so we have some constraints. And that will inevitably probably lead to a slight decrease in capital efficiency over what we're all used to. But that's just kind of the nature of the beast. We think it's most prudent within the field because of our infrastructure requirements to go ahead and, you know, as we continue to poke around in the upper, we're going to finish out that lower. But, you know, we don't see the issue on reserves having any material effect on that issue at all.

All right, great. Thanks a lot.

Your next question is from Neil Dingman of Truist Securities. Please go ahead. Your line is open.

Morning, Al. Can you hear me fine?

Line clear, Neil. All right. My first question is just on the Marcella specifically. I love some of the upper Marcellus news that you have put out and some of those results. I'm just wondering, going forward, two questions around that. One, how active would you be able to co-develop in those areas between the upper and lower? And then right now, the opportunity where you've had some of those stellar lower Marcellus wells, is there opportunities to go back and go after some upper?

Well, our team is looking at that right now. You know, we've challenged them, you know, I may contradict my answer to the last question. You know, we're filling out the lower, but we've challenged them to really look at that infrastructure and let's just try to break the mold and do it in the most profitable way. So, you know, always we like to rank our opportunities and do the best first and work our way down the ladder there on economic value So it's a complex function of infrastructure, compression availability. And we're going to try to be active on our best opportunities. But I appreciate your comments. We really are quite pleased with what we're seeing out of the upper. And we're going to try to fit as much of that in as we can. But, yeah, you just have to kind of wait until we announce our 2023 program. We've got some really bright people working on the best economic model they can field.

No, love to hear it. Thanks, Tom. And then just secondly, on inventory, Tom, do you find yourself now with this upper Marcellus success and with that and obviously with the Dell and MidCon feeling that you have more than ample acreage or just everybody sort of asked the M&A question. I guess my way to tackle that is how – actively are you looking at sort of the plays and assets being thrown out there, or are you pretty content given the size now of inventory you have after this upper Marcellus success?

Boy, Neil, I'm an explorationist at heart. Words like ample acreage and content just don't sit well with me. Look, we've got a very deep inventory in all of our basins. In fact, I was reviewing that in some detail this morning. We're very pleased with our inventory. But, you know, we're also pretty high on Cotera's ability to be an outstanding operator. And I mentioned our field staff. I mentioned our outstanding scientists throughout this organization. If we had the opportunity to acquire more assets at an entry price that added value for the Cotera shareholder, we would do it. We'd look at everything. We are highly curious as an organization. And, you know, but we're just not going to try to play financial games with that. It's going to have to be something that adds real sustainable value over cycles. And, you know, it's my hope and intent that we're going to find something. Let me just finish by saying it's not a goal. It's an ongoing goal. kind of wish. We don't lay down markers on an annual basis and say, let's go buy something. I mean, that's kind of a dangerous way to manage. We want to be opportunistic. I agree, and thanks for the details.

Your next question is from Derek Whitefield at Stifel. Please go ahead. Your line is open.

Good morning, all, and thanks for taking my questions.

Hi, Derek.

Tom, I wanted to lead with the question on your broader outlook. While acknowledging you're not offering formal 2023 guidance today, could I ask you to comment on your high-level takeaways from the CapEx proposals you've received from your three business units and how these proposals compare versus past years?

Well, inflation is having an impact. I will say 2021, the economics were lights out, good as it gets. Certainly, we've seen a little softening in commodity prices as we look into 2023, and we've seen inflation. But you kind of have to put things in context. As we look at the plans that have been laid in front of us in 2023, the economics on any normalized, decade-long historical look are really, really strong. We have a lot of things to do. We've asked each one of our business units to kind of give us a small, medium, and large. We're small as maintenance, and then we look at various options so that we can mix and match and form the best capital program we can. We talked earlier about 2022 being largely underway when we form Cotera. That's not the case with 2023, so we truly do have options to construct the best program possible. You heard me say in my opening remarks, we have services under contract that gives us flexibility. Because as we look at 23, boy, if anybody in this call can tell us what 23 can look like, we'll get you to the front of the line here. We've got commodity price uncertainty. We also have inflation uncertainty. We have world economic outlook that's uncertain and global demand. You know, I'm not being trite when I say flexibility is the coin of the realm. We will enter 23 with services under our control that would allow us to accelerate or decelerate, and we'll have flexibility. Really, we're working this hard. One thing I can promise you is that 2023 will be a very profitable program, or we won't make the investments. And right now, as we model it, We're going to have a lot of options within a very wide band of potential capital, you know, total capital and where we allocate it. You know, just look forward to coming out with some detail once we really make these commitments to our business units.

As my follow-up, regarding your comments on the hierarchy moving into development mode, it's clear that you're comfortable with the subsurface and well-designed. Having said that, could you speak to how the integral competes for capital versus the upper Wolf Camp 8?

Well, it kind of depends where you are in the basin. The Harkey is excellent compared to the Wolf Camp. I mean, they're neck and neck. Of course, the Wolf Camp is... I mean, look, there's a lot of variability in Delaware Basin, so it's kind of hard to average, but... If you had to choose between really great Wolf Camp A or Harkey, it'd be like asking which one of your kids you like best. It's a really tough choice.

It's great, Keller. Thanks for your time.

Your next question is from David Duckelbaum of Cowan. Please go ahead. Your line is open.

Thanks for taking my questions, Tom. Hi, David. Hi there. I wanted to ask maybe a point of clarification on the Marcellus, and I'm sorry you're getting a lot of questions on this today. But I guess as it relates to when you first looked at the assets during the M&A process or during the merger process, if you compare it to today, was a lot of the write-downs more on the parent or child wealth size? Is this more of a... an indication that the parent wells are being more impacted as you do more infield activity drilling? Or is there just multiple variables that wouldn't necessarily describe the majority of the move?

Well, you know, when you look at the Marcellus program, obviously, like any shale basin, it, over time, gravitated to a higher percentage of child infill wells. So, you know, if you look at just the complex, the makeup of the drilling programs over the last few years, you know, for the last number of years we've been drilling a majority of infill wells. So, you know, to your question, I mean, a lot of it is, of course, driven by the behavior of infill wells. You know, we're doing a lot. We're looking at changing our spacing, as we've talked about in the past. We're also, you know, we had a really good technical meeting in Pittsburgh a couple weeks ago, and they're doing some great work revisiting our completions. And we think we may have some optimization by rethinking that. But, you know, I mean, it's driven by well performance, and well performance is mostly in-fill wells because that's been the complexion of our program.

I appreciate that. Thanks, Tom. Maybe if I could just ask a quick follow-up on, there was a mention obviously in your prepared remarks in the presentation about looking at long-term service contracts, but then obviously also maintaining flexibility on the view that perhaps that market might soften next year. Are you in the midst now of signing long-term agreements? And I guess when you think about a long-term agreement for a base level of activity, how long is the duration of those contracts? What would be the benefit of doing that? Is there a fear that you won't have the availability of quality crews going forward in a tight market, or is it really price-driven protection?

Yeah, David, this is Blake. I'll take that one. You nailed it. Priority number one is securing premium rigs and crews. We have to have those to execute our capital programs, and the market is requiring a lot of long-term contracts to get that done right now. So, That's what's forcing that decision. Second, of course, is price. As Tom mentioned, who knows what 23 is going to do. So price is a little tough to get our arms around. But what we do is we leverage our longer term commitments in blocking up a whole bunch of work. And we use that to leverage flexibility on additional work so that if we pick up or drop crews, we know they're available to us and some surety of price around what that will be. It's just a combination of managing that portfolio.

Sorry, just to clarify, are the terms longer than we would normally expect with a term contract? Are these multi-year agreements, or are these typically for 12 months?

No, typically 12 months. Thank you, guys. Or less.

Your next question is from Doug Leggett of Bank of America. Please go ahead. Your line is open.

Thank you. Good morning, everybody. Tom, thanks for taking my questions. Tom, I apologize for going back to the upper or lower more cells, but I wanted to ask a couple of technical issues to try and maybe connect the dots a little bit here. So you talked about the Purcell being an effective track barrier, but I think we're aware that there's some pinching out across the acreage, and I assume that the wells you tested were probably in the thickest part of the barrier, if you want to call it that. So can you walk us through how you see the risking across the acreage and how it might inform your view of inventory depth today versus at the time of the acquisition?

Yeah, Doug, as we map to Purcell, it is, we think, reasonably thick over almost all of our asset. You know, we're talking, you know, 40, 50 feet generally. So we don't see an area in our asset where we would have heightened concern about the Purcell not being a frac barrier. Now, if you zoom out and you look at the region outside of our asset, that statement's going to change. The Purcell does thin, and there are areas around us where the upper and lower Marcellus behave as one continuous petroleum system. We don't think that's going to be the case on our asset. Now, you know, Doug, you know us well. I want to be very careful with how I answer that question. With our best technology right now, and we've got a fair number of tests where we've put tracers and looked at communication across that Purcell barrier, with our best information now, we have a high degree of confidence that that statement is true. And as we look at the area, we think it's going to be repeatable across the area. But that is one thing that we will be testing as we look at additional effort on our cell as well. I always want to be careful of getting ahead of ourselves on what we believe against what we know. I mean, based on all of our technical experience, we believe that per cell is going to be a crack barrier. And all of our experiments today have confirmed that. But we will update you. We feel very confident today in saying that the Upper Marcellus will be an independent petroleum system from the lower and will be developed without significant air fairness.

That's very clear, Tom. I appreciate that. I might be trying to peel the onion back in too much detail here, but my follow-up is also related to that. I'm just wondering if you could share what you've observed through your testing as it relates to how the pressure gradient has evolved across the upper marcellus you know your point about you know lack of communication between the two zones have you seen any shift as you started to you know any any evidence for example as chesapeake pointed out that um you know co-development might be the right way forward because there is some communication are you saying that no you don't believe that to be the case now you know

Different areas are going to behave differently. And I don't want to comment on another operator, but that comment doesn't surprise me. We see our area as somewhat unique in that per cell and the thickness across our area. We think co-development would not be the right approach. And in fact, we also think that the fact that we have that barrier really allows us to take more efficient use of our infrastructure. because we have compression and field hydraulics. And if we were required to co-develop, that would be a much more challenging, complex problem. So the fact that we've got that Purcell Fract Barrier is really, I think, an important part of our economic development. So we just think we're in a different area, Doug.

Well, thanks, Tom. And we'll see you in a couple of weeks. Appreciate you taking my questions.

Your next question is from Joe Chang of Scotiabank. Please go ahead. Your line is open.

Hi, that's Paul Chang. Tom, I want to go back into the M&A question. Can you give us some criteria or financial metrics that you would be looking at? And also that in an ideal world, what are geographic regions or that oil or that gas that you would be focused on that you don't really have? any of those specific targets?

Well, yeah, thanks, Paul. When it comes to M&A, first and foremost, we would like to find some things that compete for capital in a reasonable timeframe. And you wake up every morning and rethink every problem, at least in a changing world. If you don't, you're making a mistake. It's kind of tough for us to just say flat out, we will not consider anything if it doesn't have the kind of returns that are currently in our inventory. Because if that's our criteria, we're done. There's very little out there that competes with our inventory. So we want to think decades in the future and find assets that we think are more valuable in our hands than the current owner, which is another way of saying that we think we might be able to buy it right and create value through that. And that's a really, really high bar. So we remain opportunistic, but we're fortunately, because of the depth of our inventory, under no pressure here. As far as your second part of the question to geography, we're a multi-basin company. We're a multi-commodity company. We know how to play and how to manage a company that's geographically spread out. In fact, we think it's one of the strengths of Cotera, and we think over time the marketplace will see how that strength produces more consistent results over time. But there are some things that we want to be careful of. There are some operating environments that are more difficult. There are some areas that are more politically difficult. And so we would be selective in terms of what new areas we would look at. But we know how to manage multi-basin company, and that wouldn't deter us if it checked all the boxes. But that said, I want to just finish with a statement I made. Because of the depth and quality of our inventory, we have the luxury of really forcing ourselves to have a high bar and make sure that anything we look at is in the best interest of the owners.

Hey, Tom, do you have a preference between oil or gas or it doesn't really matter? And also that from an organization capability limit, since you are still in the process of integrating, do you think that you're ready, you're done enough on the integration that you can take on a substantially new asset or that it may take another six to nine months before you reach that comfort state?

Well, these are a lot of hypotheticals here because the M&A question is always one that it's an optionality. It's not necessarily something that we have specifics to talk about. But the integration is going very, very well. Our teams, as I said in my opening remarks, are really coming together. And the fun thing from my standpoint is that there's really an organic cooperation that's leveraging the great ideas and experience of all of our organization as they get to know one another. And there's a lot of power in that. Good ideas are not regionally constrained when you have a lot of cross-company collaboration. What was the first part? Do you have a preference?

Oil versus gas.

Our preference is generating profits and profitable investments. And we do like a commodity mix just because of the swing in the commodity. That was part of the thesis in forming Coterra. You know, we're roughly balanced between liquids and natural gas on a revenue standpoint. We would consider any asset, any commodity mix, if we thought it made Cotera a stronger company. So we're not in the interest of picking commodities. We're in the interest of picking profitability.

A final question on the thought code. I think that you guys have been evaluating the asset. And at this point, is there anything you can share that what you think will be the future for that asset? And whether you will start increasing your activity level for next year or it's going to take some more time? Thank you.

Well, yeah, we're not prepared to talk about 23 Capital on this call in any great detail. I will share, you know, we've got a couple of projects flowing back in the Andorra right now. and we're watching them with great interest. Look forward to updating you on them. Although we're very encouraged by what we see, we've been around this business long enough to know, particularly on projects that have infill potential. You want to watch things over some months before you call it, but we're flowing a couple of projects back that look pretty interesting to us. Thank you.

Your next question is from Noel Parks of Toohey Brothers. Please go ahead. Your line is open.

Morning.

Morning, Noel. I realize it's a little early in the process, but as you head in and given what you've told us about looking at reserves in the south, can you comment a bit on operating cost assumptions and how... I guess just what you're thinking of long-term. I don't know if any of us expected we would see such a sharp increase in tightness in the service environment. So you could just comment on the cost component as you look ahead.

Yeah. In the fourth quarter, as we finish out our normal reserve process, we'll be updating lease operating expenses, or LOE, we do expect LOE to increase, but there's not a one-for-one connection between LOE and reserves. And that's particularly true in the Marcellus. I mean, those operating costs are so low that we've got a 50-year reserve life, and you really find that pricing and LOE doesn't really have much of an impact. And that's not true elsewhere. So as part of our fourth quarter process, and we do, as I said earlier, want to We want to dot the I's, cross the T's. And although we've talked about a range, we have some work to do. One of that is around LOE, one of the items. But we don't see that as a, certainly not an item that will have meaningful impact on Marcellus reserves. And I mean, we'll have to do the process, but I don't anticipate updating LOE having much of an impact on our end of year. Great.

Thanks for the clarification. And turning to the Anadarko for a minute, just in general terms, it is interesting that even among some of the basins that are maturing further along in their development than the Permian, for instance, we've seen a fair amount of M&A and consolidation activity this year. And I'm just wondering if not so much in the Anadarko, Just wondering if you think that still lies ahead or whether a piece of that is just as an industry, you know, the capital and sort of the technological advances aren't necessarily being manifested in that play the way they are, you know, more aggressively in others.

You're talking specifically to Dan Darko? Yes. Yeah. Well, you know, one of the interesting things in our business is you do have single-basin players. And so often technology, even though you think, well, it's known by all, technological adoptions and innovations sometimes don't spread like wildfire from basin to basin. So you can occasionally have disconnects. And, you know, if we had more time, I could offer a lot of examples of that that I've seen in my career. You know, my experience and observation is there's some pretty smart players in the Andarco. A lot of these private equity companies are fairly innovative. A lot of these teams came out of larger shops and certainly were schooled in understanding the full range of available technologies. So I don't know if I would share the opinion that the Anadarko is behind on technology. I'd love to take that offline, but I just don't see it that way. Great. Thanks a lot.

There are no further questions at this time. I will now turn the call over to Tom Jordan for closing remarks.

Well, listen, I want to thank everybody for your great questions. We delved into some good issues and really do look forward to continuing to generate the type of outstanding results we did in the third quarter. We're very confident that Cotera is lined up to continue to have a landscape of opportunities Just outstanding returns, good capital returns, great discipline, and also look forward to discussing our 2023 capital program next time we convene. So thank you all very much.

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