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Thank you for standing by. At this time, I would like to welcome everyone to the Coterra Energy Third Quarter 2022 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] 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 Coterra Energy’s third quarter 2022 earnings conference call. Today’s prepared remarks will include an overview from Tom Jorden, CEO and President; and Scott Schroeder, Executive Vice President and CFO. Also on the call, we have Blake Sirgo and Todd Roemer. 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, Coterra 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, our commitment to excellence and a common economic language throughout the company. We’ve developed new methodologies, learn 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 visited Coterra 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 Coterra. 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 $0.68 per share, which was an increase over the second quarter. We continue 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 on 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 frac 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% on a dollar per foot basis year-over-year. Individual line items, which include rig rates, frac crews, sand, tubulars, fuel and labor may exceed these ranges, but our predicted 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 3 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 tuned 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 were 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 Coterra 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 2022 results, shareholder returns and then finish with updated guidance. During the quarter, Coterra 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. Coterra’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 MBO per day above the midpoint of expectations. The strong third quarter 2022 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 0.2x 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 Coterra. If you recall on the merger date, we guided that Coterra had the potential to generate $4.7 billion in cumulative free cash flow for 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 2022 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 totaled $0.68 per share, up from $0.65 per share paid in the second quarter. And 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 $0.32 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 2.78 Bcf per day and 86 to 89 MBO per day, respectively. On the 2022 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 cost, 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 lower for all future years, reducing Coterra’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 DD&A 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, Coterra 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.

[Operator Instructions] Your first question is from Jeanine Wai of Barclays. Please go ahead. Your line is open.

Hi, good morning everyone. Thanks for taking our questions.

Hi, Jeanine.

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, Jeanine. 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. As we look at the Marcellus, there are a lot of factors that come into play. One is 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 we’re – 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 proved reserves update, the Permian Anadarko 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. Has this changed 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 just an important topic. Thank you.

Yes. No. Thank you for that, Jeanine. 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 we really set to work October 1, 2021, of just reconciling a lot of these differences. And we brought some new techniques and technologies. We learned from one another. But I will say, 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 have 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 is certainly no impairment involved with it, and the DD&A is extremely modest. We also don’t see it really impacting our cash flow significantly over the next there years to five years. And now you may say, well, how do you say that? Well, you cannot take reserve forecast 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 that – 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 situation. 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 forecast over the next there years to five years. Now 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, okay, 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 Choudhary 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 its early days, but I wanted to get your thoughts on the Permian and the gas basis risk next year? And how are you thinking about managing that risk and if that would bias activity towards oilier areas in the Permian Basin?

Well, that’s a great question, and I’ll invite Blake Sirgo 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 assuredness 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 assuredness 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.

Yes. 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 2023 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 priced gas is 60% of our Permian gas portfolio, it’s only 6% of our Coterra gas portfolio, we have layered in some Waha hedges going into 2023 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 over Bcf a day offline in the Permian, and we had absolutely no interruption to flow. So while we expect some blips along the way throughout 2023, it’s – 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% increase potentially in 2023. Are you seeing any regional differences between Permian and Appalachia, and especially in the Perm because I believe last quarter, you had talked about cost increasing by 30% to 35% over 2021 and 2022?

Yes, 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 2023. And I’d say, in general, the Marcellus is a little higher that’s not unique to just this moment in time. The – everything in the Marcellus is winterized, so it commands a little higher price and it’s just a smaller swimming pool in the Permian. So there’s a little less competition for services and that comes out in more inflation. When we look ahead to 2023, 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, 2022 contracts extending into 2023, our efficiencies, all those things come into play. So right now, we’re modeling closer to the lower end of that range. But if inflation runs through 2023 like it did in 2022, we could 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 Jayaram of JPMorgan. Please go ahead. Your line is open.

Yes. 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 can give us a sense of what the impact could be? Because it sounds like a lot of the impacts is in the later portion of the production life of the well. So I just wanted to give a sense of maybe you could haircut it like that.

Arun is 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 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 – we’re going to – 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 their 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 of 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 do you sense on your production outlook in view of sustaining capital requirements in the Marcellus? Does this have any impact as you think about 2023 or 2024 production?

I don’t think that this has any impact on it. Now I will say 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. We have up; space, but 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 as we continue to poke around in the upper, we’re going to finish out that lower. But we don’t see the issue on reserves having any material effect on that issue at all.

Great. Thanks a lot.

Your next question is from Neal Dingmann of Truist Securities. Please go ahead. Your line is open.

Good morning. Can you hear me, Tom?

Loud and clear, Neal.

All right. My first question, just on the Marcellus specifically, I love some of the Upper Marcellus news that you have put out in some of those results. I’m just wondering, going forward, two questions around that. One, how active would you be able to codevelop 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. We’ve challenged them. I may contradict my answer to the last question. We’re filling out the lower, but we’ve challenged them to really look at that infrastructure and let’s just try to break them old and do it in the most profitable way. So 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 really – 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 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, I’d love to hear it. And then just secondly, on inventory, Tom, do you find yourself now with this Upper Marcellus success with that and obviously with the Dell and Mid-Con feeling that you have more than ample acreage? Or I’m 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 the separate Marcellus success?

Neal, the alignment exploration is the heart. Words like ample acreage and content just don’t sit well with it. Look, we’ve got a very deep inventory in all of our basins. We’re – in fact, I was reviewing that in some detail this morning. We’re very pleased with our inventory. But we’re also pretty high on Coterra’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 add value for the Coterra shareholder, we would do it. We look at everything. We are highly curious as an organization – and 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 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 kind of with – 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.

Agree. And thanks for the details.

Your next question is from Derrick Whitfield at Stifel. Please go ahead. Your line is open.

Good morning. And thanks for taking my question.

Hi, Derrick.

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, we are – inflation is having an impact. I will say, 2021, the economics were lights out as 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 and so that we can mix and match and form the best capital program we can. Yes, we talked earlier about 2022 being largely underway when we form Coterra, that’s not the case with 2023. So we truly do have options to construct the best program possible. We’ve – you heard me say in my opening remarks, we have services under contract that gives us flexibility. Because as we look at 2023, boy, if anybody on this call can tell us what 2023 can look like, we’ll get you at 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. So I’m not being tried when I say flexibility is going in the realm. We will enter 2023 with services under our control that would allow us to accelerate or decelerate, and we’ll have flexibility. Really, we’re working this hard. We – 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 – total capital and where we allocate it. I 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 Harkey moving into development mode, it’s clear that you’re comfortable with the surface all design. Having said that, could you speak to how the interval competes for capital versus the Upper Wolfcamp A?

Well, it kind of depends where you are in the basin. The Harkey is excellent compared to the Wolfcamp. I mean, they’re neck and neck. Of course, the Wolfcamp 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 Wolfcamp A or Harkey, it’d be like asking which one of your kids, you like best. It’s a really tough choice.

That’s great color. Thanks for your time.

Your next question is from David Deckelbaum of Cowen. Please go ahead. Your line is open.

Thanks for taking my questions, Tom.

Hey, David.

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 well size. Is this more of a – an indication that the parent wells are being more impacted as you do more in field activity drilling? Or is there just multiple variables that wouldn’t necessarily describe the majority of the move?

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

Appreciate that. Thanks, Tom. Maybe if I could just ask a quick follow-up on – there was a mention obviously in your prepared remarks and the presentation about looking at long-term service contracts, but then obviously also maintaining flexibility on a view that perhaps that market might soften next year, I guess have you – are you in the midst now of signing long-term agreements? And I guess when you think about the long-term agreement for a base level of activity, how long is the duration of those contracts? And I guess, 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 the tight market? Or is it really price-driven protection?

Yes. 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 markets 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 2023 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 and 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. So – it’s just a combination of managing that portfolio.

And sorry, just to clarify, are the terms longer than we would normally expect with a term contract? Are these multiyear agreements? Or is this typically for 12 months?

No, typically 12 months or less.

Thank you guys.

Your next question is from Doug Leggate 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 Lower Marcellus, 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 Pearsall be an effective frac 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 what it – how it might inform your view of inventory depth today versus at the time of the acquisition.

Yes, Doug, we – as we map the Pearsall, it is, we think, reasonably thick over almost all of our assets we’re talking 40, 50 feet generally. So we don’t see an area in our asset where we would have heightened concern about the Pearsall not being a frac barrier. Now if you zoom out and you look at the region outside of our asset, that statement is going to change. The Pearsall does then, 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. 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 Pearsall 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 Upper Marcellus wells. I always want to be careful of getting ahead of ourselves what we believe against what we know. I mean, based on all our technical experience, we believe that Pearsall is going to be frac 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 interference.

That’s very clear, Tom. I appreciate that. And I might be trying to peel the onion back to – 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? Your point about lack of communication between the two zones, have you seen any shift as you started to any evidence, for example, as Chesapeake pointed out, that co-development might be the right way forward because there is some communication are you saying that now you don’t believe that be the case?

Now 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 is somewhat unique in that Pearsall and the thickness across our area. We think codevelopment 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 codevelop, that would be a much more challenging complex problem. So the fact that we’ve got that Pearsall frac 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. I appreciate you taking my questions.

Your next question is from Paul Cheng of Scotiabank. Please go ahead. Your line is open.

Hi. That’s Paul Cheng. 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 the [indiscernible] what our geographic region or that or that gas as that you will be focused on that you don’t really have any of those specific target?

Well, yes, thank you, Paul. The – yes, when it comes to M&A, first and foremost, we would like to find some things that compete for capital in a reasonable time frame. 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 thank 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 I – 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. So 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 Coterra 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 out the boxes. But that said, I want to just finish with the 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.

Tom, do you have a preference between oil or gas or it doesn’t really matter? And also that from an organization capability moment since you are still in the process of integrating, do you think that you already done enough on the integration that you can take on a substantially new assets or that you may take another six to nine months before which that comfort stay?

Well, I mean, 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. And what was the first question?

Do you have a preference between oil or 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. 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 Coterra stronger company. So we’re not in the interest of picking commodities. We’re in the interest of picking profitability.

A final question on Anadarko, 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 Coterra asset? And whether you will start increasing your activity level for next year? Or is it going to take some more time? Thank you.

Well, yes, we haven’t – we’re not prepared to talk about 2023 capital on this call in any great detail. I will share – we’ve got a couple of projects flowing back in the Anadarko right now. And we’re watching them with great interest. Look forward to updating you on them. It’s – 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 Tuohy Brothers. Please go ahead. Your line is open.

Good morning.

Good morning, Noel.

I realize it’s early in the process, but as you head into and given what you’ve told us about looking at reserves and selling. Can you comment a bit on operating cost assumptions and how those – 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 the tightness in the service environment. So just comment on the cost component as you look ahead.

Yes, we’re – 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 run 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 dot the eyes cross the Ts. 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 the year. .

Great. Thanks for the clarification. And turning into 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 in 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, the capital and sort of the technological advances aren’t necessarily being manifest in that play the way they are more aggressively than others?

You’re talking specifically to Anadarko?

Yes.

Yes. Well, 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 innovation sometimes don’t spread like wildfire from basin to basin. So you can occasionally have disconnection. And if we had more time, I could offer a lot of examples of that, that I’ve seen in my career. My experience and observation is there’s some pretty smart players in the Anadarko. A lot of these private equity companies are fairly innovative. A lot of these teams came out of larger shops and Certainly, we’re 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. Yes, I’d love to take that off-line, 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’ve 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 Coterra is lined up to continue to have a landscape of 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.