Daniel Guffey:

Thank you, Audra. Good morning, and thank you for joining Coterra Energy's First Quarter 2024 Earnings Conference Call. Today's prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations.

Blake Sirgo:

Thanks, Shane. This morning, I will discuss our capital expenditures and provide an operational update. First quarter accrued capital expenditures totaled $450 million, coming in just below the low end of our guidance. Our strong execution in the field continued in Q1, with our oil production coming in at 102,500 barrels of oil per day, above the high end of our guidance.

Thomas Jorden:

Thank you, Shane and Blake. We're pleased with our continued execution momentum as we march through 2024. We appreciate your interest in Coterra and look forward to discussing our results and outlook. As always, we like talking about results, more the future promises, and we're always pleased to deliver them.

Operator:

[Operator Instructions]

Nitin Kumar:

Tom and Shane, congrats on the great results. Tom, I want to start off in the Marcellus, and you deferred 12 completed wells for later in the year. The plan still calls for about 29 wells to be put online. Could you maybe talk us through how are -- what are the market conditions? Is there a specific price? Or is there a supply or demand equation that you're looking at to, one, bring on the 12 wells? And 2, how would you think about the rest of the program for the year?

Thomas Jorden:

Yes. I'm going to hit the Harkey and let Blake look at the cost reduction. Our general observation in a lot of our Delaware program is that in our assets, our observation has been that whether we exploit these reservoirs 1 layer at a time or not that we don't really see any incremental recovery out of a drilling spacing unit.

Arun Jayaram:

My first question is on cash return. You returned 90% of free cash flow this quarter. But I wanted to get maybe some broader thoughts on just the overall philosophy given your views on the valuation of the stock. You recently issued $500 million of notes to help refund the payment of the $575 million maturity later this year. How did cash return, Tom, attractiveness of the valuation of the stock play into that decision?

Thomas Jorden:

Yes, I'll let Shane handle that one.

Shannon Young:

We've gone as low as $600 million over the last, call it, 7, 8 quarters. And -- and again, I think that probably as low as we go. We target $1 billion. We've been as high as $1.4 billion. And I think you'll continue to see us live somewhere in that range. It's a broad range. But I think you'll continue to see us reside within that range.

Blake Sirgo:

The decline is really just driven by the well set that we're bringing on that part of the year. We have some great, really long laterals that are in there and they trend on a lower dollar per foot. Run rate is kind of hard to pin down exactly, one, it depends if you're talking upper Marcellus lower Marcellus. I think it could be anywhere from $1,000 to $1,200 per foot. It's probably going to flow in there. Lateral lengths could drive that a little lower.

Neil Mehta:

Tom, really great quarter. The first question I had was just -- we've seen so much consolidation across the landscape -- the energy landscape. And certainly, you guys did your large deal a couple of years ago, but I just love your perspective on the role of Coterra and future consolidation and where do you see bid and ask and do you see any gaps in the portfolio?

Shannon Young:

Yes. I'll just add on a couple of things. I wholeheartedly agree. The team has been executing incredibly well, and we'd love nothing more than to have an opportunity to put more assets and opportunity under their stewardship. And we think it helps in terms of execution in the field. We think it also plays into our strengths of capital allocation.

Neil Mehta:

And the follow-up also on M&A. You have been commodity agnostic. It seems to us and focus more on where you can generate the highest return. Is that the way you think about M&A as well? You're less focused on the product type and more focused on what's the best fit just perspective on Oil versus Gas and consolidation?

Wei Jiang:

I want to ask about the 3-year outlook. You have beaten 2024, and that's flowing into a better 2025 and '26 numbers, which is great to see. With all the efficiency gains that you're talking about, is it fair to think that they would just continue to translate into a better outlook over the entire 3-year period and that you will just be delivering that 5-plus type of growth for maybe seeing to lower CapEx?

Shannon Young:

Yes, Betty, I would just say, as I said in my earlier remarks, we still have strong conviction in the outlook that we put out in February. So 5% plus Oil growth, 0% to 5% BOE and Gas growth, all at $1.75 billion to $1.95 billion of annual capital. I think the results that we have delivered in the first quarter only gives us further conviction around that outlook. So we're still excited about it. And believe we'll be able to deliver it.

Blake Sirgo:

I would just echo what Tom said. We don't bake in any efficiency gains in our 3-year outlook. What we're doing today is what we show. But as Tom said, the expectation here is that we get better every single year. We have a culture of operational excellence. That means what we did yesterday, will not cut it for today.

David Deckelbaum:

I wanted to ask maybe a little bit of just a cost benefit analysis. You guys have been beating production now steadily largely on what appears to be cycle times and just finding ways to do things faster in the field, which is quite commendable. I think you guys articulated the benefits of cost savings on things like the Windham Row in the 10% range.

Blake Sirgo:

Yes, David, this is Blake. I'll take that one. I think it's important to iterate cost is an output of our decision-making. And so while lower cost really helped drive some of our economics, we are focused on total returns of our projects and the highest PVI. And so, if that ends up being a 3-well project in Lea County versus a 54-well project in Culberson County, we go where the PVIs tell us to go. And obviously, continued cost gains really help. Cycle times really help, but it doesn't drive where the rigs go. It really drives us that full economic analysis, and that's what we lean into.

David Deckelbaum:

I appreciate the color on that. Maybe just pivoting to the Marcellus, a similar line of questioning on just how you thought through deferring completion activity versus curtailing existing production and keeping up with the completion kins, if there is sort of the inefficiency of drilling programs and frac crews that gets lost in that process or how you guys approach that sort of thought train?

Scott Gruber:

Tom, long-dated gas because they have been moving higher on all the data center growth excitement, how would you think about capital allocation between Anadarko and the Marcellus, if the forward curve is right, and we're in the $3.50 to $4 range, in late '25, '26? And Oil is still healthy, call it, in the 70s. How would you think about that allocation?

Blake Sirgo:

Yes, sure. I mean we're all learning this AI power demand story together, and there's a lot of unknowns, but there's a lot of excitement the power gen that's going to be required is huge. Lots of it looks like it's going to come on the East Coast. That's very proximal to our asset. There's a lot of existing pipes there that we can easily get our gas to those markets. And we're very interested. We're talking to a lot of these folks directly trying to understand their business and their needs, and we will be ready to participate.

Blake Sirgo:

Yes, Scott, it's Blake. I'll take that. That's a great question. And I think it's something that gets missed sometimes in simul-frac is you really have to have an optimal pad with a lot of wellheads on one pad to optimize the cost savings. There is sometimes where you might some frac and save no money because a simul frac crew is just basically 2 frac crews smashed together. So you're paying a lot of money for that crew to be there. The efficiencies come when you have a lot of wells on one pad. And just the layout of these drill spacing units doesn't always give us enough wells per pad to use simul-frac optimally. So it's back to that whole cycle analysis. The goal is not to simul-frac everything. The goal is to make the most economic wells. And so we're only chasing it where it makes sense.

Neal Dingmann:

My first question comes for you or Blake, maybe on inventory, specifically. Looking at Slide 5, you had an interesting comment that I think makes a lot of sense, and that's you all suggest that the total fluctuates based on things like well spacing cost, cadence and the like. And I'm just wondering how aggressive or conservative would you consider your estimates versus what you've seen play out in the trends in recent quarters?

Neal Dingmann:

Very good. And then just a second question on capital spend. Specifically, I noticed what I think now what is about 70% of CapEx is directly from Upper Marcellus. Is this a result of just productivity that you highlight on Slide 19 or what's driving the spend in the upper area?

Operator:

We'll go next to Derrick Whitfield at Stifel.

Thomas Jorden:

Yes. You're saying the Marcellus pricing stays kind of in and around where it is like this through the rest of the year?

Thomas Jorden:

Yes. Well, look, here's what I'd say is we do build in a lot of flexibility into our capital planning. And a couple of that's really foundational to that and a couple of things. One, some plans to accelerate if market environment changes and things get better and also to decelerate if they deteriorate or, in this case, don't firm up a little bit.

Derrick Whitfield:

As my follow-up, regarding the deferred turn-in-lines in the Marcellus. How long would you technically be comfortable in deferring the wells before you'd be concerned with compromising the effectiveness or integrity of the completion?

Operator:

We'll go next to Leo Mariani at Roth MKM.

Shannon Young:

Leo, thanks for the question. And look, there's a couple of things I would just point to, one, Hana put together a great slide, a new slide in the deck, in the appendix 33 that sort of shows where some of the activity is over the course of the year. And your point that you just made around, does it feel like the second quarter could be a peak capital quarter and then the back half of the year, if you take the residual and divide by 2, that may be a lower number than that.

Leo Mariani:

Okay. I appreciate that. Then I just wanted to follow up a little bit on kind of Upper Marcellus. As you look out the next couple of years, do you see the Upper Marcellus becoming kind of a increasing percentage of your overall Marcellus activity. Is that going to be just kind of driven by somewhat the depletion of the lower Marcellus in the inventory stack here?

Leo Mariani:

Okay. No, that's helpful. But it sounds like the message is you think the upper can be very, very competitive with other gas assets as you look at it today?

Thomas Jorden:

Yes. And Leo, competitiveness is always a function of well performance, but also price. And that's a nice thing about Coterra where we said is we really do have an asset mix allows us to shift capital and allocate it based on those changes. So competitiveness of assets is not a static thing.

Charles Meade:

Just one question for me, and it's around the way you guys are going to approach the Marcellus in the back half of the year. I think you -- I heard you mentioned in your prepared comments that your plan has you guys turning some wells on in July. And as I think about recent history up in the Marcellus, a lot of times, we can see a good price bounce in the summer, but then we see another bout of weakness in the fall when the cooling demand goes away.

Thomas Jorden:

Yes. I'll just -- I'll answer your question with the analogy. We've said from day 1 that the way we manage our program is not a rifle shot, it's a guided missile. So sitting here and saying we're going to turn wells on in July, that's talking about a rifle shot. We're going to guide that missile every step of the way. We typically don't manage our production up and down with the near-term price file.

Thomas Jorden:

Yes. I just want to thank everybody. Great set of questions. We are very pleased to present the results we presented last night and look forward to repeating that. And as I said many times on this call, it's our -- talking about results is the conversation we want to have. So thank you all very much for your participation this morning.

Dan Guffey:

Thank you, Operator. Good morning. And thank you for joining Coterra Energy’s fourth quarter and full year 2023 earnings and 2024 outlook conference call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations. 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 reconciliation for 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.

Shane Young:

Thank you, Tom, and thank you everyone for joining us on today’s call. This morning, I’ll focus on four areas. First, I’ll discuss highlights from our fourth quarter and full year 2023 results. Then, I’ll provide production and capital guidance for the first quarter and full year 2024. Next, I will provide a new and updated three-year production and capital outlook for 2024 through 2026. Finally, I’ll discuss our shareholder return program and our debt maturity later this year. Turning to our strong performance during the fourth quarter. Fourth quarter total production averaged 697 MBoe per day, with oil averaging 104.7 MBoe per day and natural gas averaging 2.97 Bcf per day. All production streams came in above the high end of guidance driven by well performance and acceleration of till timing during the quarter. Specifically, turn-in lines during the quarter totaled 40 net wells, including 28 in the Permian, near the high end of guidance, and 12 in the Marcellus, slightly above the midpoint of guidance. During the fourth quarter, pre-hedge revenues were approximately $1.5 billion, of which 61% were generated by oil and NGL sales. In the quarter, we reported net income of $416 million or $0.55 per share and adjusted net income of $387 million or $0.52 per share. Total cash costs during the quarter, including LOE, workover, transportation, production taxes and G&A totaled $8.41 per Boe, near the midpoint of our annual guidance range of $7.30 per Boe to $9.40 per Boe. Cash hedge gains during the quarter totaled $46 million. Incurred capital expenditures in the fourth quarter totaled $457 million, just below the low end of our guidance range. Discretionary cash flow was $881 million and free cash flow was $413 million, after cash capital expenditures of $468 million. For the full year 2023, Coterra produced outstanding results. Total equivalent production exceeded the high end of our initial February guidance, coming in at 667 MBoe per day. This outperformance was driven by a combination of better-than-expected well timing and beats unexpected well productivity. Oil production for the year was 96.2 MBoe per day, exceeding the high end of initial guidance by over 4%. Capital costs were right at the midpoint of our guidance range, coming in at $2.1 billion as a result of relentless focus on capital by our teams in each of our business units. Cash operating costs per unit totaled $8.37 per Boe for the year, slightly below our initial guidance midpoint. Looking ahead to 2024. During the first quarter of 2024, we expect total production to average between 660 MBoe per day and 690 MBoe per day. Oil to be between 95 MBoe per day and 99 MBoe per day, and natural gas to be between 2.85 Bcf per day and 2.95 Bcf per day. We anticipate first quarter oil production to have the lowest average for any quarter during 2024, primarily as a result of tilt timing that pulled some volume forward and into the fourth quarter of 2023. Regarding investment, we expect incurred capital in the first quarter to be between $460 million and $540 million. For the full year 2024, we expect incurred capital to be between $1.75 billion and $1.95 billion, or 12% lower at the midpoint than our 2023 capital spend. Our 2024 program will modestly increase capital allocation to the liquids-rich Permian and Anadarko Basins, and significantly decrease capital by more than 50% in the Marcellus. We expect total production for the year to average between 635 MBoe per day and 675 MBoe per day, and oil to be between 99 MBoe per day and 105 MBoe per day or 6% higher at the midpoint than oil was in 2023. Natural gas is expected to be between 2.65 Bcf per day and 2.8 Bcf per day, approximately 5.5% lower at the midpoint than gas production was in 2023. It is important to note that we have incorporated efficiency gains achieved in 2023 into our 2024 guidance. Reflecting on our new three-year outlook. As we did this time last year, yesterday we announced our new three-year outlook for 2024 through 2026. We believe this is a robust, capital-efficient plan that delivers consistent, profitable growth for our shareholders. We anticipate that our project inventory can deliver 5%-plus oil volume growth over this period, with zero percent to 5% Boe growth by investing between $1.75 billion and $1.95 billion of capital per year. This reflects increased capital efficiency and is designed to afford Coterra the flexibility to reallocate capital between our business units as market conditions change. This outlook incorporates an appropriate level of reinvestment and delivers meaningful free cash flow to underpin shareholder returns. Moving on to shareholder returns. Last night, we announced a $0.21 per share base dividend for the fourth quarter, increasing our annual base dividend by 5% to $0.84 per share. This remains one of the highest yielding base dividends in the industry at well over 3%. Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. During 2023, despite relatively lower commodity prices and cash flow, Coterra continued to execute on its shareholder return program by repurchasing 17 million shares for $418 million at an average price of approximately $25 per share. In total, we returned 77% of free cash flow during the year or just over $1 billion. We remain committed to our strategy of returning 50% or more of our annual free cash flow to shareholders through a combination of a healthy base dividend and our share repurchase program. On to our 2024 notes. We have continued to monitor and analyze opportunities regarding our $575 million maturity coming this September. With low leverage at 0.3 times, we believe we have strong access to the active refinancing markets. At the same time, we had approximately $2.5 billion of liquidity between cash and our undrawn credit facility at year-end, affording us many options with regard to our 2024 maturity. In summary, Coterra’s team delivered another quarter of high-quality results, both operationally and financially. We are poised for a strong first quarter of 2024, which we believe will set a solid foundation for the full year 2024 and beyond. With that, I will hand the call over to Blake to provide additional color and detail on our operations. Blake?

Tom Jorden:

Thank you, Shane and Blake. We are pleased with our continued execution in 2023 and expect to deliver on our goals outlined in our 2024 plans. We appreciate your interest in Coterra and look forward to discussing our results and outlook. We’ll now be open for questions.

Nitin Kumar:

Thanks. Good morning, Tom, Shane, and Blake. Thanks for taking my question. Congrats on a strong year that really showcases the idea that was behind Coterra. I guess I want to start at just the capital allocation. You’re cutting activity in the Marcellus in response to gas prices, but a lot of people think of the Anadarko Basin as a gas basin and you’re allocating some incremental capital there. Could you walk us through kind of the thought process there?

Nitin Kumar:

Great. Thanks for the color. And then, Tom, industry consolidation continues at a pretty frantic pace. As you look around the lease lines, you have new neighbors or maybe the same neighbor around you. Your thoughts on scale M&A for Coterra from here on out. You certainly have a plethora of organic opportunities, but I’d love to hear your thoughts on M&A going forward?

Operator:

Your next question will come from the line of Arun Jayaram with JPMorgan. Please go ahead.

Blake Sirgo:

Yeah. Arun, this is Blake. I’ll take that. That’s really why we kind of give that range on that slide. As we’ve talked about in the past, our Permian program is really a rotation throughout our assets and that’s driven by a lot of different things. The mix can vary somewhat year-to-year, but over a multiyear timeframe, it’s pretty consistent. And so I just say we expect 2024 to fall well within that band to deliver another good year on productivity.

Blake Sirgo:

I would say very similar. There’s definitely some room for upside there with some of the allocations, but I’d expect another strong year.

Unidentified Analyst:

Hey. Good morning, guys. This is actually Kali [ph] for Doug. So thank you very much for taking my question. The first thing I want to hit is the Marcellus, where you’re adapting activity in response to price. Sorry, so I guess I’m trying to understand the scenario analysis. Is the Marcellus free cash flow break even on 24 strip? And assuming basis is static, at what hub price does activity begin to shift higher?

Unidentified Analyst:

I appreciate that, Tom. My follow up is on the Anadarko. I think to remember that the geology there being quite complex. So I’m wondering if you can expand on what the team accomplished last year to give you more confidence to re-engage in the capital program?

Operator:

Your next question comes from the line of David Deckelbaum with TD Cowen. Please go ahead.

Tom Jorden:

Our thoughts really haven’t changed. As we were -- I would just repeat what we’ve said in the past. We’ve talked about a reduced inventory in the lower Marcellus. I think, if we were heavy on the lower Marcellus, we’d probably be talking about a three-year to five-year inventory at this point, three-year to six-year maybe, depending on our level of activity. Our inventory is longer than that now as we’ve lowered our investment. But it’s really a function of what’s available to us and that’s the function of our gathering system where we think we have additional capacity. But there’s also an area of this field that’s opened up to us that we’re out exploiting and we’re really glad to be there and getting after some of the really, really productive rock. So, we’ll be drilling in the lower Marcellus for a long, long time. So when we quote inventory numbers, it’s really strongly overprint by which formation we’re drilling in. But the lower is going to be a significant part of our program for a number of years.

Blake Sirgo:

Yeah, David. This is Blake. I’ll take that one. Right now we really expect to do a row project almost every single year. And I know that it’s kind of scary to talk about a 51-well development, but I think it’s important to remember these are six distinct drill spacing units that we have chosen to develop in a row to maximize efficiency. These units are our standard Culberson 2-mile Upper Wolfcamp units with designs from seven to 10 wells per section. This is just really our bread and butter. I mean, we’ve developed many of these over the years. We’re just stringing them together. Our ops teams work really hard to kind of war game these projects and these rows to think of all the execution risks that could go on. That’s why we picked up our eighth rig sooner, to get a good duct build in front of the frac crew. These projects have large multi-well pads. That means if we have any well trouble, our frac crew can pivot while we deal with the well trouble. Our simul-frac part of this project, we’ve modeled really conservative completion timing and that’s because, it’s our first application of this in Culberson, but we don’t really expect our electric crew to operate any less efficient than it has in the past. We worked through a lot of sand and water logistics to make sure everything has abundant sourcing. We own and operate our SWD system out there. That means we have plenty of water on demand at all times. It allows us to keep it in the pipe, so we’re not building any produced water pits with this project. This is just part of our operation now and I’d expect many more row developments for years to come.

Neal Dingmann:

Good morning, guys. Thanks for the time. My first question is just on the flat span and the zero percent to 5% Boe CAGR. I’m just wondering, did these assumptions include, I’m just wondering, do you assume with those on a go forward years, has that ensued well productivity, improved well productivity, lower well cost, or maybe just help me on what’s involved in those assumptions?

Neal Dingmann:

Great point, Tom. And maybe just a second along that same line, I’m just wondering, look at the slide that talks about the gas production. I’m just wondering, is it fair to say that, you maybe have seen peak production or is it just what you’re forecasting that are just a basis of what’s going on with prices and that’s going to be an ultimate driver?

Operator:

Our next question will come from the line of Michael Scialla with Stephens. Please go ahead.

Shane Young:

Hey, Mike. Shane here. I’ll take those two questions. Look, on the buyback, we remained active in the market during the quarter, but we were a little bit cautious. We were trying to kind of get a gauge whether winter and weather would materialize, and I think, as it didn’t, we decided to carry some of that cash over into year end. That’s why you saw the cash balance build up to around a $1 billion, which really puts us in good shape in what looks like it could be a soft gas market in 2024 to be a bit more aggressive on the buyback. So, yeah, there was a little bit of a timing element to that, I would say. On the base dividend, listen, in addition to the commitment to deliver 50% plus of our free cash flow to shareholders on an annual basis, we also remain committed to increasing the annual dividend responsibly on an annual cadence. 5% feels like a pretty good lift, but not overly excessive. So we’re happy with the 5% bump, and we get into next year, we’ll evaluate it again. If it makes sense to do it, we would expect to continue to do it on an annual cadence.

Scott Gruber:

Yes. Good morning. Through your row development program, you’ve been able to push down your Delaware cost to several $1,100 a foot. As you’re reengaging in Anadarko, do you think you’ll be able to work down the cost structure into play? Are you thinking about pad size or rectifying operations or any other actions that you may need before you push down that $1,300 figure?

Scott Gruber:

Got it. And you guys have stuck with an estimate of about 5% deflation in service costs and material costs. But we’re now seeing several operators obviously take actions to reduce activity in the Marcellus. Do you think you’ll be able to see additional service cost savings on top of that 5%, especially in the Marcellus on your remaining activity?

Tom Jorden:

But I don’t want that point to be lost. One of the reasons we have such flexibility in our capital allocation is because we’ve worked really hard over the last couple of years to have a great set of vendor partners and a very light amount of long-term commitments. So we really do have a lot of flexibility in both our drilling and completion services to pivot from one basin to another.

Kevin MacCurdy:

Good morning. First, I want to say we appreciate the three-year outlook. I think you’re one of the few companies in your peer group with the confidence in your inventory to provide a detailed multiyear outlook. My first question is on that outlook. Are you assuming a similar capital allocation in 2025 and 2026 as in 2024? And under that scenario, when and at what levels does the Marcellus start to flatten out?

Kevin MacCurdy:

Okay. And under that three-year scenario, what happens if we have a bullish gas market in 2025 and 2026? Do you reallocate capital from the Permian and the Anadarko back to the Marcellus or do you increase your overall CapEx? I know you spoke about a contingency plan in 2024, but just thinking about how you would think about that over the long-term?

Kevin MacCurdy:

Great. Thanks for the detail.

Ati Modak:

Hi. Good morning, team. Just curious how you view the macro setup for the gas markets here. What’s the risk of surprise in associated gas from the Permian and how do we work our way through that? Are you seeing sufficient signs of supply rationalization to suggest that we’re in a better environment for 2025?

Ati Modak:

Great. And then you talked about this a little bit, but maybe I can approach this in a different way. Your three-year outlook on growth is on relatively stable annual CapEx. Curious what factors you’ve baked into that growth outlook in terms of the incremental efficiency gains. What should we expect to hear from you on that front over this time period?

Operator:

Our final question will come from the line of Charles Meade with Johnson Rice. Please go ahead.

Tom Jorden:

Good morning.

Tom Jorden:

Well, one of the things that we see is we will finish the year with four pads waiting to be completed. So, a lot of what we’re doing in 2024 is setting up 2025. So, it’s not always showing up in the first year CapEx. With projects that have cycle times like ours and like everybody else’s, you really have to have a multiyear outlook on any plan. So a lot of that is a benefit of what we did last year that’s currently being completed and what happens next year is a function of what we do this year. So the annual snapshot on capital versus production is interesting, but fairly incomplete.

Tom Jorden:

Well, we have lots of price assumptions. I would say we have strip. We run a 55-275. We run a 75-250. I mean, we have -- we run 75-375 [ph]. I’m looking at our models now. I mean, we have a smorgasbord of price files that really set our kind of define the fairway of our economic analysis. But I would say this is probably based on the strip as a foundational forecast and then we run permutations from there.

Tom Jorden:

Well, thank you very much for joining us. We look forward to continuing to deliver. As I hope you’ve learned from Coterra, we really appreciate your interest and love talking about results and intend to deliver them. So thank you so much.

Dan Guffey:

Thank you, operator. Good morning and thank you for joining Coterra Energy’s third quarter 2023 earnings conference call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations. 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 prepared 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.

Shane Young:

Thank you, Tom and thank you everyone for joining us on our call today. This morning, I will focus on 3 areas

Tom Jorden:

Thank you, Shane and Blake. Momentum at Coterra continues to build. We’re generating consistent, profitable growth. The company remains well positioned to deliver on its stated goals. We appreciate your interest in Coterra and look forward to further discussing our results during question-and-answer.

Nitin Kumar:

Hey, good morning Tom and team. Congratulations on a great quarter. Tom, I want to start with cash returns. As much as your oil performance has been impressive, as Shane mentioned, you are on track to return 80% of free cash flow this year. Some of your peers have increased the commitment or the percentage that they promised to give back. You are still at 50%. Just, if you could share some thoughts on how you are thinking about the cash return framework and could we see it evolve in 2024?

Shane Young:

Yes. Thanks, Tom. I think Tom laid it out really, really well, Nitin. But I would just emphasize that for the third quarter, we returned 84% of our free cash flow. For the year-to-date, we’re well above that, over 90% of our free cash flow. And that 80% figure that I talked about earlier, that’s a number that sort of takes into account buybacks to date, plus dividends, including an assumed hold of the dividend in the fourth quarter and doesn’t assume any incremental repurchases. So that number could well go up higher by the time we get to the year end. If you look at the track record in the history, if you go back to the first quarter of 2022, till to date, you’ll see we’ve been anywhere from 70% to in excess of 100% of our shareholder returns as a percentage of free cash flow, really averaging a bit over 80% over that time window. So I go back to what Tom says, looking at what we do, and judge us by those actions, but we are fully committed to returning capital in a good quantum to our shareholders.

Tom Jorden:

Well, Nitin, thank you for that question. Our strategy is simple. It’s consistent profitable growth. We want to generate financial returns through the cycles. We don’t want to be beholden to a particular commodity or a particular geography. We believe in operational excellence and think that being good at the business as a strong underpinning of any kind of financial runway. We don’t have a problem to solve. I think the combination of Cimarex and Cabot built one of the most resilient companies in our space. And hopefully, we are in the process of proving that to our viewers. But as we look at the landscape, we would view M&A solely as an opportunity but not a necessity. We don’t have a strategic goal around any kind of M&A, quite frankly, we’re cautious. We’re cautious because when you invest through the drill bit, you can do that incrementally and you can pivot and in just as conditions change. M&A involves large episodic movements that can often catch you countercyclically. So we’re opportunistic. We’re never going to say never to anything. We look at it all. But we’re going to be disciplined. Shane, you have any thoughts on that?

Tom Jorden:

Yes. Shane said it right. It’s about getting better. And I’m particularly proud of the way this organization is performing, and very confident in saying we intend to make a routine. We would not put that at risk with something that interrupts our momentum, period.

Operator:

Your next question comes from the line of Umang with Goldman Sachs. Umang, your line is open.

Blake Sirgo:

Yes. Umang, this is Blake. I’m happy to take that one. As we’ve talked about, the Windham Row, is really our largest row project to date. It’s just taking all of our operational efficiencies and putting them in one place. So in several DSUs lined up together, it’s not what you would consider one giant cube development, if we’re prosecuting the Upper Wolfcamp across one big section and one big row. And by doing that, we can concentrate our rigs, our frac crews, we can co-mingle our facilities, and we can drop our infrastructure costs. So all that adds up to some pretty big cost gains. The decision to add the rig a little bit early was frankly just to get ahead of getting the wells ready. We’ve decided to simul-frac that row. And so simul-frac moves very quickly. You got to have all the wells ready and we just wanted to make sure we had plenty of buffer there. So that’s really the main driver.

Umang Choudhary:

I see. That’s really helpful color. I guess moving to your 3-year outlook, and we will wait for a fulsome update next year. But I wanted to get your high-level thoughts, I mean, this year, you have shown strong performance. Oil growth is 9% year-over-year close to 9% year-over-year. And then on Slide #14, you highlighted continued expectations for strong productivity in the Delaware going forward. How should we think about the evolution for the company over the next 3, 4 years? Any high-level thoughts you can provide there?

Umang Choudhary:

That’s great answer. Thank you.

Arun Jayaram:

Yes. Good morning. I was wondering if you could – really appreciate the Slide 17, on the Windham Row, but I was wondering if you could give a sense of what you’re doing to de-risk some of the project timing and development of that large row development. In particular, I wanted to see if you could give us some insights on some of the learning from the Mint Julep project that you did this year, which maybe helps to de-risk this larger project?

Arun Jayaram:

And Blake, just as a quick follow-up, how many wells would you expect if timing goes as planned to come online next year because I think you just started drilling the row in the third quarter?

Arun Jayaram:

Okay. And then my second question, Tom, where do you stand in terms of the $200 million of capital that could be reallocated from the Marcellus to your other two assets? And maybe just a quick update on how Demic Township, how that could impact or influence that decision?

Arun Jayaram:

Great. Thanks a lot, Tom.

Doug Leggate:

Thank you. Good morning, everyone. Thanks for hop me on. Guys, I wonder if I could ask about the Anadarko, where it sits in your thoughts on relative capital allocation for 2024. And I guess my question is around – the guidance suggested no tills in 3Q, and yet, we obviously saw the activity there. So I’m just curious if your thoughts on the competitiveness of the Anadarko has stepped up a bit going into next year?

Doug Leggate:

I guess as my follow-on is kind of related, Tom. Thanks for the answer. So if I think about the indications on where costs are headed, capital costs are headed and all the moving parts in there, not just from yourselves but from your peers. And then I also stick with the mantra that your capital program is really driven by efficiency and not by growth. I look to 2024, and I have to consider whether your CapEx guidance either is low end of your current range or maybe have some downside risk, and I’m trying to understand, would you rather take those efficiencies and redeploy the capital and keep the capital the same? Or are you trending lower in your spending going into ‘24? Any early guidance will be appreciated.

Doug Leggate:

Appreciate the answers. Thanks so much.

Scott Gruber:

Yes. Thank you and good morning. So I want to touch on the strategy with the row development. It does differ a bit from peers, in that you’re generally focused on single zone development and not developing multiple benches. Can you just provide some more detail on what differs from a geologic perspective on the eastern side of the acreage? You mentioned on the Eastern side, co-development, is it necessary? Do you just see far less communication on the eastern side? What is the strategy, mainly a call on, really being able to leverage prior surface spending when you do develop these Tier 2 zones down the road, to offset the lower productivity. Just some more color on the strategy.

Blake Sirgo:

Yes, I’ll just add to that, the row development does lay the groundwork for all future benches that we might develop. The infrastructure is in place. The tank batteries are in place. Our team has already modeled all those zones and how they can come on later and it will just drive down the dollar per foot on future projects. But as Tom said, that’s an outcome. That’s not the driver of why we’re developing and the way we are.

Blake Sirgo:

No, I’d be nervous to quote a percentage on that one because it’s not in the immediate drill schedule, but it’s significant. It will move the needle.

Blake Sirgo:

Thank you.

David Deckelbaum:

Thanks, Tom and team. Appreciate you guys taking my questions this morning.

David Deckelbaum:

Just curious, you all have demonstrated some pretty impressive well productivity gains, certainly over your base cases. I’m curious, as we progress into the back half or the end of ‘23 into ‘24, ‘25. How would you contextualize midstream constraints? I know, obviously, you have large-scale developments like Windham Row coming online. But we’ve heard by and large from many of the peers in the area, that midstream is creating a pretty big overhang around some near-term productivity. Could you contextualize, I guess, what you’re seeing and how you feel about the midstream setup going into ‘24 and ‘25 relative to your productivity?

David Deckelbaum:

Appreciate that. And then maybe just – so I better understand the comments around the Marcellus spend this next year. It seems like it’s being phrased as though it’s an option to spend $200 million less, but I guess, is that the correct way to think about it? Or is there really a $100 million plus of efficiency gains in there or just program changes just from designing better plans into next year?

David Deckelbaum:

Thank you, Tom.

Josh Silverstein:

Hi. Thanks. Good morning guys. Just sticking with the Marcellus, the realizations have been pretty strong this year, and even better than the corporate realizations. I know some of this is from the NYMEX and fixed price contracts that you guys have. You outlined what you have for the rest of the year. Can you just provide us a little bit of insight as to what you guys have next year? And any thoughts on kind of what you can do for locking in strong basis relative to what the forward curve may be? Thanks.

Shane Young:

And I would just say, even though the second quarter and third quarter, that realization is a little lower, if you look year-to-date, that’s right about where we are tracking year-to-date.

Tom Jorden:

Yes. I will jump on to Josh for a second here. So look, on the cash balance, again, if you look back over the last, let’s call it, 1.5 years or seven quarters, it’s sort of been between call it, maybe a little over $600 million, a little below $1.5 billion. So, we sort of gravitated around that $1 billion balance. I think we do want to be able to be countercyclical with regards to shareholder returns. So, if we are in a period like the second quarter, where free cash flow is a little bit tighter, we can certainly go beyond with that, in some cases, well beyond that in order to continue to support if we think there is intrinsic value in doing that with the share repurchase program. So, we certainly have that ability going forward. The other thing I would just touch on quickly is next fall’s maturity, the 2024. And just to highlight, no decisions have been made on that. And so I think you sort of indicated that we would likely repurchase that or pay that off for cash. And that’s certainly one of the options, and we think we have a lot of different options. But I will just sort of temper that a bit and say no final decision has been made on that maturity.

Operator:

The next question comes from the line of Derrick Whitfield with Stifel. Derrick, your line is open.

Tom Jorden:

Yes, I will start that and Blake may want to comment. We followed that topic carefully. There are a couple of companies kind of talking about that. And I wish I could tell you that we had some back laboratory where we have our own version of it, but we don’t. We are watching very carefully. We certainly hope it’s true. But we don’t see evidence that it’s been field tested yet in any meaningful way. So Blake, do you want to comment?

Derrick Whitfield:

Great. And as my follow-up, referencing Slide 17, I want to take it with really a different angle with my question. As you think about the go/no-go decision on co-development of Harkey and the Western spacing units of the Windham Row, what’s the downside of co-development from an upstream perspective if well level returns are largely consistent?

Derrick Whitfield:

Great color. Thanks for your time.

Neal Dingmann:

Good morning and thanks for the time. Tom, my question, if I got asked on the capital allocation a little differently, you all previously had well above what I would call in prior, call it, a year or 2 years ago, what I always would deem is definitely well above-average production growth and what I would probably call then probably average shareholder return. And then obviously, here in the recent quarters, you have kind of reversed that where you now have well-above shareholder return, what I would call probably the average production growth. I am just wondering Tom, for you, again, is there a scenario where you would revert more back to that prior scenario?

Neal Dingmann:

Yes, sir, and more back to the – instead of a 90% payout on the shareholder return, maybe back to, I don’t even know 50%, 60% or something?

Shane Young:

No, I would agree with it. I mean I would only say, Neal, again, we have a lot of peers today that are probably more focused on just maintaining and keeping things flat. And so I think in that regard, Coterra is differentiated and that we can still generate consistent profitable growth in the current price environment that we sit in.

Blake Sirgo:

Yes. For the total program, we are still estimating about 5% deflation going into ‘24. That’s based on what we know today, these simul-frac savings would be in addition to that. But that’s just for this one project, and we have a big portfolio, so it’s gone across the board savings. We are in the middle of negotiating our rig and frac contracts for ‘24 right now, and look forward to updating that when we put our plan out in February.

Operator:

The next question comes from the line of Matt Portillo with TPH. Your line is open, Matt.

Tom Jorden:

Well, look, what I would love to see is long-term LNG contract guarantees saw uplift in price, we would be willing to get after it. So, I am looking at Blake, getting him working on that. We do have an amazing asset in the Anadarko Basin. It’s ready to go. I mean we when we look at the Permian, the Marcellus, Anadarko, Coterra is very well positioned for exactly what was designed when we formed it. We can react to liquids prices or natural gas prices with a healthy inventory. When I say healthy, I mean a deep and robust inventory, and really, more and more people are seeing that in our asset base. But we would have that option. I mean that’s, Blake, do you want to comment on that?

Matt Portillo:

Perfect. And maybe just a follow-up on gas specifically. Tom, just curious how you all are feeling about the hedge book heading into 2024. It still seems like it might be a bit of a transition year with some challenges on the inventory carryout from ‘23. And so just wanted to see how you all are thinking about your hedge profile for next year and then maybe longer term philosophy around hedging for natural gas.

Shane Young:

Yes, sure. So look, over the course of the last quarter, we did add some hedges to the book. And again, I think historically, we have been pretty consistent in messaging, we want to be somewhere between 20%, 25% to upwards of 50% hedged, any sort of forward 12 months, 18 months window. And so we try to get back into that posture. I think as you look today, we are positioned that way, plus or minus, around 25% to 30%, on the gas side, if you include the physical hedges and the financial hedges in concert. And we think that’s a good place to be, but we will continue to monitor it as we go. You will also find that if you just look at the shape of that hedge book, it is probably a little bit front half of the year weighted, a little less second half, not to the extreme, but there is a little bit of a slope to that profile.

Operator:

Your next question comes from the line of Roger Read with Wells Fargo. Mr. Read, your line is open.

Tom Jorden:

Well, one of the things we have done, Roger, over the last few years, has really spent a tremendous amount of time studying the optimum development scheme for a drilling spacing unit. We have a little different spacing assumption than others. And I think we are – as we apply that throughout our portfolio, we are seeing ongoing benefits from it. We think that with fewer wells, we can extract the same amount of resource. Our machine learning team has been instrumental to Coterra in that understanding. And they continue to drive a lot of our thinking. It’s been a remarkable piece of technology to adopt internally, and it’s had direct benefits in our capital efficiency.

Tom Jorden:

Yes, you were breaking up there, but I believe your question is with wider spacing, how does that impact the duration of our resource. We have modeled that into everything you see in our deck, that’s modeled in. And we don’t count number six on the map, quite frankly. Although everybody loves a high number there, we look at – I mean if we can drill fewer wells and get better financial returns and not leave stranded resource, that is the holy grail. And we think we are never there. Well, we are moving in that direction in a very positive way, and that’s part of what’s underwritten our results this quarter.

Operator:

Your next question comes from the line of Leo Mariani with ROTH. Leo, your line is open.

Tom Jorden:

Well, I will tell you, if that was pretty big, there are a lot of people down in the hallway that have scars from us finding over that. But I will let Blake answer the question.

Leo Mariani:

Okay. And so I just wanted to get a sense, I mean is that going to give you guys a little bit more Permian activity then just on average, it sounds like you are going to be running a little bit more equipment next year?

Leo Mariani:

Okay. Understood. And then I guess, Tom, you talked about this a couple of times, but you got the multiyear guide, you are going to update that early next year, and it just sounds like clearly, you have outpaced expectations in 2023. It just seems like if we continue to see strong well results out of Coterra, you have got this guide of oil, of kind of 5% plus. If trends continue, it seems like it could be a little bit more than the plus as opposed to the 5%, as we roll into next year?

Leo Mariani:

Okay. Thanks.

Charles Meade:

Good morning Tom to you and your team there and thanks for going over the remarks [ph] here. This perhaps dovetails with that last question on your outlook for ‘24. But I want to start specifically with your 4Q oil guide, which was stronger than many of us from the outside looking in, we are expecting. So, perhaps this also fits with your earlier comments about volumes or volume growth is really an output, not a driver, we look at your sequential quarters over the course of trying to, we can see that, and that the oil rate has ticked up and it’s ticked back down, and you are going to have a big pickup for Q4. So, my question to bring it to a point is, how would you encourage us to look at this 4Q, your 4Q volumes? Is this one of the – a big uptick that’s likely to mean revert, or is this more along the lines of a new baseline that you that you guys are looking at that you are going to build on?

Charles Meade:

And I guess maybe just for my follow-up, can you elaborate on what seesaw is?

Operator:

Ladies and gentlemen, there will be no more further questions at this time. I would like to turn the call back over to Tom Jorden for closing remarks.

Operator:

Ladies and gentlemen that concludes today’s call. You may now disconnect. Have a great day.

Daniel Guffey:

Thank you, Cheryl, and good morning, and thank you for joining Coterra Energy's Second Quarter 2023 Earnings Conference Call. Today's prepared remarks will include an overview from Tom Jorden, CEO and President; and Shane Young, Executive Vice President and CFO. Also on the call are Blake Sirgo, Senior Vice President of Operations; and Scott Schroeder. 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.

Shannon Young:

Thank you, Tom. It is a pleasure to be on today's call. This morning, I will discuss our second quarter 2023 results, provide details on our shareholder return program, and update our activity outlook and guidance for the third quarter and for the full year. During the second quarter, total production volumes averaged 665 MBoe per day. Natural gas volumes grew to 2.9 Bcf per day and oil averaged 95.8 Mbo per day, which is a new high watermark for Coterra. In fact, all 3 production streams came in well above the high end of guidance. Our operations teams in all 3 regions executed nicely, which drove BOE production up 5% sequentially. The strong performance was driven primarily by positive well productivity and improved operational efficiencies. Turn-in lines during the quarter totaled 39 net wells, within our guidance of 36 to 45 wells. Production growth during the period was more than offset by commodity price declines, which were down 30% quarter-over-quarter on a BOE basis, driving net income and cash flow lower relative to the first quarter. Coterra reported net income of $209 million and discretionary cash flow of $705 million during the quarter. These results are inclusive of realized cash hedge gains of $84 million. Second quarter accrued capital expenditures totaled $537 million, within our guidance of $510 million to $570 million, and free cash flow was $113 million after cash capital expenditures, which totaled $592 million. Based on strip prices, cash flow and free cash flow are projected to increase during the back half of 2023, and the company expects greater than 55% of its 2023 revenue to come from oil and NGL sales. Turning to return of capital. Yesterday, we announced a $0.20 per share base dividend for the second quarter. Our annual base dividend of $0.80 per share remains 1 of the highest yielding base dividends in the industry at nearly 3% based on recent trading levels. Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. During the second quarter, despite relatively lower commodity prices and cash flow, Coterra continued to execute its return program by repurchasing 2.4 million shares for $57 million at an average price of $23.55 per share. In total, we returned 184% of free cash flow during the quarter. The company's large cash balance afforded us the luxury to return capital in excess of our quarterly free cash flow and continue to buy our shares countercyclically at attractive prices. Based on results year-to-date, Coterra's returned $628 million to shareholders or 94% of free cash flow via our base dividend and share repurchases. We are reiterating our annual commitment to return 50% plus of free cash flow to shareholders. When taking into account recent strip prices, buyback activity completed to date and our base dividend, we expect to return well in excess of 50% of 2023 free cash flow. Lastly, I'll discuss refinements to our 2023 guidance and activity outlook. First on capital. We are reiterating some of the company's 2023 accrued capital estimate of $2 billion to $2.2 billion. While we are currently trending 1% to 2% above the midpoint of our guidance range, we are seeing clear signs of future cost softening on big ticket items such as rigs, steel and frac crews. Other cost categories, including labor and surface rentals have been more sticky and flat to modestly up. Based on leading-edge service costs, coupled with the timing of our contract repricing, our best estimate based on information we have today is that we will see a 2024 dollar per foot decrease of approximately 5% as compared to 2023. We retain a substantial amount of flexibility for our 2024 capital program in all 3 basins and plan on detailing our program early next year as per our customary annual guidance release. On to production guidance. We are increasing our full year oil guidance by 3% at the midpoint to 91 to 94 Mbo per day, driven primarily by strong well performance in both the Permian and Anadarko basins. We are increasing our natural gas and BOE guidance 2% at the midpoint on the back of solid well performance in the Marcellus. For the third quarter, we estimate production will average 640 MBoe per day, natural gas to average 2.8 Bcf per day and oil to average 89.5 Mbo per day. The sequential production decline is solely related to timing and was previously forecasted internally. As implied by our full year guidance, we expect to see a return to growth in the fourth quarter. In our investor presentation, we reiterated our 3-year outlook, which assumes the company achieves a 3-year oil CAGR of 5%. BOE and natural gas CAGR of 0% to 5% and with capital and activity that is flat to down relative to 2023 levels. One update in our presentation was a change in our oil CAGR outlook. We now expect our 3-year CAGR to be greater than 5%. This change is primarily driven by the observed strong well performance in 2023 to date. We have yet to finalize 2024 capital investment allocation by region and retain significant optionality. We will continue to allocate capital to its most productive use. Based on recent strip and our outlook, our 2023 discretionary cash flow guidance is $3.35 billion, down from $3.6 billion in May. The decrease in cash flow is driven primarily by lower natural gas and NGL realizations. The 2023 free cash flow is now estimated to be $1.24 billion, down from $1.58 billion, which is due to lower discretionary cash flow and higher projected cash CapEx, which includes the cash impact of forecasted changes in AP at year-end. Turning to a few business unit updates. The Marcellus delivered strong well performance during the quarter. Production increased 9% sequentially, driving total company natural gas volumes 2% above the high end of guidance. As previously communicated, we recently dropped Marcellus activity to 2 rigs and 1 crew. If this level of activity holds in 2024 and 2025, Marcellus capital could decline by at least $200 million per year while holding production relatively flat. In the Anadarko, our last 2 projects, which both came online in the second half of 2022, continue to outperform. We are currently fracking the 7-well Evans development, which is expected to come online during the fourth quarter. We are running 1 rig in the region during the back half of the year, which will provide nice momentum heading into 2024. In the Permian, we are currently running 6 rigs and 3 frac crews, 1 of which will be utilized as a spot crew. Permian turn-in lines are trending to the high end of our annual guide, largely due to operational efficiencies, including improving drilling and frac feet per day. The incremental wells are expected to come online late in the fourth quarter and contribute minimally to 2023 annual volumes. Lastly, I'll touch on unit costs. Cash costs, including LOE, workover, transportation, production taxes and G&A totaled $8.27 per BOE during the second quarter, down for approximately $8.90 in the first quarter. This was well within our annual range of $7.30 to $9.40 per BOE. One note on deferred tax guidance. After utilizing the bulk of our NOLs in the high commodity price environment during 2022, we expect deferred taxes to range between 10% and 20% of income tax expense in 2023. In summary, despite commodity headwinds during the quarter, momentum for Coterra continues. This is supported by strong operational execution, which led to production beats for the quarter and the need to raise our annual production guidance range. The company remains well positioned to meet or exceed our 2023 as well as our 2023 to 2025 targets. Finally, I would also like to congratulate Scott Schroeder for all his successes over his 28-year career at Cabot and Coterra. He has been instrumental to creating a bright future at Coterra that we enjoy today. I'd like to personally thank him for all his efforts and the support he has provided me over the past month. With that, I'll turn the call back to the operator for Q&A.

Nitin Kumar:

First of all, congratulations, Scott, on your retirement, and congrats Shane on the new role. I want to start by unpacking -- sorry, congrats. I want to start by unpacking the guide for third quarter a little bit. In your prepared remarks, you emphasized that the beat in the second quarter came from improved productivity, but you're looking for about 7% decline in oil. Could you just walk us through maybe the cadence of completions for the rest of the year? And just kind of what leads to this guide?

Nitin Kumar:

Got it. I guess, as my follow-up, I want to touch a little bit about the cash return. We saw you against a tough commodity tape dip into the cash balance a bit and return. I think it was 185% of free cash flow. Could you talk a little bit about how do you see -- you have, I think, $840 million at the end of the quarter. How do you balance between maintaining some cash, being countercyclical in your buybacks? And how you're looking at it sort of longer term?

Operator:

Your next question is from Arun Jayaram of JPMorgan Chase.

Thomas Jorden:

Yes, Arun, it's well productivity is driving that change fairly and simply. And no, there's no assumption of reallocation in that 3-year plan.

Thomas Jorden:

No, I would not say.

Thomas Jorden:

That's correct. Thanks, Arun.

Umang Choudhary:

And also congratulations, Scott, for your retirement. We will miss you. And, Shane, congratulations, look forward to working with you. Let me start with the cost deflation point. I appreciate all the details, which you provide on Slide 12. You mentioned that some of your contracts are staggered, so you might not realize the full benefit in 2024. Can you remind us the percentage of your overall CapEx, which will be exposed to those cost savings? And then to be sure, this is not incorporated in your 3-year outlook?

Umang Choudhary:

Got you. That makes sense. And then I just wanted to go back to the 3-year outlook. I'm trying to understand your earlier comments about maintaining a consistent operational program and some of the recent efficiency gains, which you have realized. What does it mean for your activity plans? Would it mean that you will drill more wells, complete more wells, more productive wells? And how does that change your thoughts around long-term capital spending?

Operator:

Your next question is from Doug Leggate of Bank of America.

Thomas Jorden:

We -- if there's some overprint of it, we're not aware of. I think it's -- yes, it may be a function of some of our spacing and getting spacing right, so that we're not seeing GOR increases rapidly on some of our developments. But overall, we see a fairly consistent analysis of our assets. Blake, do you want to comment on that?

Doug Leggate:

Okay. I just wondered if there was something different about what you guys are doing, but thank you for that. My follow-up is really a clarification question on the earlier comments about spending. Shane, you touched on the Marcellus and your activity level obviously dropped earlier this year. So understanding everything Tom said about accepting the growth as an output. It sounds like you're signaling that for the current level of activity, you're -- your CapEx could reasonably be in the $ 1.9 billion, maybe even lower range. Am I reading that wrong? Or can you just elaborate a little bit on what you were trying to signal there?

Doug Leggate:

And that holds you flat in the Marcellus?

Operator:

Your next question is from Michael Scala of Stephens.

Thomas Jorden:

Mike, we've got a wide range of investors, as you can imagine. We have different voices. Quite frankly, we have some investors that tell us that if anybody is earning the right to grow, it's this team. We have other investors that are -- feel differently. We always enjoy conversations with our investors in getting feedback, and we'll certainly be doing that on the heels of this call. But I think the investors that I think resonate with our story are looking for consistency, and they're not buying Coterra to just ride a wave up or down. They want to see some progress. And that's what we're here to do.

Thomas Jorden:

Yes. I'll start it out, and I'll let Blake take it home. But this is exactly what our Shale era is needing. We can take advantage of infrastructure. We can take advantage of operational efficiencies. We can take advantage of certainly our electrification, and we can take advantage of minimizing any kind of parent-child interference. We can stage the wells coming online in the way that manage this reservoir. It's just really everything that the last decade has led up to in terms of taking advantage of our own technical innovations. Blake, do you want to say anything?

Thomas Jorden:

I'll also add, we'll be bringing those wells online as we go. It's not a situation where we wait to bring 51 wells online when the last one is completed. We staged them online continuously as we're continuing to drill and complete.

Neal Dingmann:

Scott, thanks for everything. It's been great working with you. My question first is on OFS cost, specifically. Could you guys just talk maybe, we hear a lot about cost deflation, OTCG and all those things. But I'm just wondering, Tom, maybe more or less how you all think about spot versus long-term contracts? I know you've in the past had some opinions. How you think about the 2? And is there a big pricing difference between the 2 today?

Blake Sirgo:

I think you nailed it. It's all about the value proposition. Not a year ago, we were signing contracts to hopefully keep inflation from rising. Today, we're looking at contracts where we can see deflation if we entered into longer-term deals. And so we just have to balance those things, because they can reduce our flexibility, and that's what we are on the downside cases.

Thomas Jorden:

Well, it's in Culberson County. It's in sort of the South Central Culberson County on the Eastern side. We call it the [indiscernible] row named after landowners out there, but it's in a great area. It's well defined. We've got a lot of calibration, good reservoir, good pressure, good oil. I mean it's ready to roll.

Derrick Whitfield:

Congrats to both Scott and Shane as well. Tom, with regard to your Q2 production beat, you noted better-than-expected well performance in cycle times in your prepared remarks. Given the degree of your oil beat and the amount of times you've referenced well productivity in this call, could you speak to the new designs or landing zones tested more specifically, which contributed to better-than-expected well productivity?

Blake Sirgo:

Yes. I would -- well spacing and frac design are a never-ending topic at Coterra. We debate them constantly, and we're -- we don't ever settle that the current design is the best. So you're seeing that across the portfolio this year.

Thomas Jorden:

I don't think it will impact the relative allocation. We have a lot of projects lined up that it will impact. I mean as we look out the next 3 years, I don't -- I think it will help us to optimize based on what we learn. We're continuously trying to optimize, but I don't think it would necessarily change our capital allocation.

Roger Read:

Going to come back and hit some of the same, let's call it, capital efficiency, productivity questions that have been asked. But if you step back and look across, and you do have different collection of assets in some of the other companies in terms of being a pure play, you're looking at your productivity and efficiency, not so much where the gains have been, but where do you see the greatest opportunity going forward? Should we be focused on the Permian? Or is it continuing to be the Marcellus here?

Blake Sirgo:

Yes. Just saying the Marcellus, our team has done a fantastic job focusing on lateral length. Over 50% of our program this year exceeds 10,000 feet. We actually have a couple of wells with total measured depth in excess of 25,000 feet. So pretty light sale performance that's really helping drive down our cost per foot. In the Permian, it's all about these wells per project, these bigger developments that take advantage of project size. Our average wells per project is up about 23% just over the last 2 years. We expect that to continue.

Blake Sirgo:

Right. Our drilling and completion fee per day are up also. I mean our crews are hitting records on pumping hours per month. Our drilling fee per day is up 14% this year. But that's what we expect. That's what we do every year.

Blake Sirgo:

Yes. I think that's why we gave Slide 12 to kind of give some color on deflation. When we built the budget, we were taking all the best information we had at the time and if that deflation had rolled through the entire cost structure, we feel very confident we'd be at the low end of the range, but it just hasn't materialized. We're seeing it on a few leading items, but not through the whole cost structure. So when we give the 5% going into '24, all that assumes is the gains we've got so far this year continue with nothing else.

Blake Sirgo:

Yes. I don't have that exact call out. I can tell you, it's not pretty much baked in dollar services.

Kevin MacCurdy:

A question about the trajectory of OpEx this year. The first 2 quarters were at the higher end of guidance, and you didn't change your full year guidance. So that suggests the second half of the year would need to be at the lower end of the range. Kind of what are you seeing out there that gives you comfort on the second half OpEx, especially given the lower volumes outlook?

Shannon Young:

Yes. I would say sort of on cash costs sort of as we highlighted for the quarter. In addition to LOE overall, we're down from $8.90 a BOE last quarter down to $8.27 BOE this quarter. So I think we feel like we're trending in the right area.

Thomas Jorden:

Well, based on our experience with long laterals. I mean, long lateral performance is something that we're all still learning. As we went from 1-mile to 2-mile horizontal wells, we had to learn what the uplift from 1 to 2 is. It's depending on the reservoir, depending on the spacing, depending on the nature of the flow back. And although we have some experience with 3-mile laterals, we don't have broad experience in any 1 area. We've got a 3-mile project in several different areas, this one was in Reeves County, where the operating environment is so different. And just quite frankly, the well surprised the upside. I mean I wish I had some grand conclusion, but it just -- they flowed back a little stronger and with a little more uplift over a 2-mile than we had forecasted.

Leo Mariani:

I just wanted to stick with some of the line of questioning here on well productivity. You mean I think that the one that kind of stood out to me was the Marcellus in the second quarter. So material increase on the production 9%. Typically, I guess, I kind of think of the Marcellus as being sort of an older, more mature play, where there's probably not a tremendous amount of sort of tweaks and improvements that can sort of be had here. But it certainly looks like maybe that wasn't the case here in the second quarter. And it didn't seem like there were some outsized number of wells that came online, just seems like some outsized production growth. So can you maybe give us a little bit more color around why the Marcellus was particularly strong in the second quarter?

Leo Mariani:

Okay. That's helpful. And just kind of turning to CapEx. You guys said you're probably going to end up being a couple of percent over the midpoint here in '23. As I kind of looked at the sort of accrual numbers, and maybe you're looking at the cash numbers as you're kind of getting to that, so maybe you could kind of let us know if that's kind of accrual versus cash. But I think in either case, it implies a pretty healthy downturn in fourth quarter CapEx, something maybe closer to the low 500s. So I just want to make sure I'm reading that right on the capital into 4Q. And are you guys kind of looking at sort of accrual or cash when you're talking about kind of where you think you're going to end up here in '23?

Operator:

Your next question is from Paul Cheng of Scotiabank.

Thomas Jorden:

Thank you for those questions. We don't have a tally of our 3-mile inventory. I will say it's going to be a small part of our program generally. A lot of our lands are already developed or parsed out for 2-mile wells. And so 3 miles are going to be the exception. Go forward, I think you might see a project or 2. Marcellus probably will have the most 3-mile wells of our program just because that Upper Marcellus is wide open, and we'll be taking advantage of that fully. But Permian is going to be a rare instance. And then as far as your question on the larger project size and the loss of the ability to cycle learnings, if I understand your question properly, that's -- that is a 2-edge sword. It also will give us the opportunity to test a lot of things, because with a 51-well program you have a lot of opportunity for control and test. One of the things that is [indiscernible] in our space is if you have an individual small project and you march off and change some parameters, you don't always have that control experiment to compare it to. So the 51-well project will have the opportunity to have several subtests within that to have good offset control and really normalize out some of the geologic and other attributes that can cloud your conclusions. So it's a good question. We think that we're ready for a project of this size, and we do really look forward to delivering outstanding results with it.

Noel Parks:

I wondered if you could talk a bit about your thoughts on sort of the risk reward of infrastructure investment going forward from here? And I'm thinking in particular about this low we're in with gas prices, oil strengthening and that makes me think, of course, about the Permian and associated gas. And I thought there's somewhat mixed signals about how that might fare with the LNG uplift on the horizon. And so just between Marcellus addition and of course being in the Permian, just your thoughts on maybe what infrastructure priorities might look like heading into LNG?

Noel Parks:

Okay. Okay. Fair enough. And I wonder, as far as what you're seeing in terms of some cost softening on the horizon, just wondering, are you seeing significant divergence sort of in vendor behavior from basin to basin? Are any of your basins are vendors looking sort of more anxious and more proactive about sort of working on price with you? Or is it fairly uniform?

Operator:

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

Scott Schroeder :

Thank you, Tom. And thank you, everyone. It's been a tremendous ride. I'm extremely proud of what we put together here. Coterra is a great company and all of you and all the investors are in great hands. It's a unique organization. It was something that people didn't see coming, but I think 2 years into this, everybody is very happy internally, and I hope externally that it all came together. I've been tremendously blessed, and I thank all of you for your support and trust over the years and rest assured that you're in great hands with Shane and the entire Coterra team as you go forward. Again, thank you for everything.

Dan Guffey:

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

Scott Schroeder:

Thanks, Tom. Today, I will discuss our first quarter '23 results, shareholder returns and updates to guidance. During the first quarter, Coterra reported net income of $677 million, discretionary cash flow of $1.039 billion, accrued capital expenditures of $569 million and free cash flow of $556 million. Despite natural gas and oil prices falling 30% and 19%, respectively, versus 1Q '22, discretionary cash flow declined only 16% year-over-year. This was driven by an increase of the company's oil and NGL production, which caused Coterra's liquids production miss to increase 3% year-over-year to 28%. The company expects greater than 55% of its 2023 revenue to come from oil and NGL sales. Also during the quarter, the company realized a cash hedge gain totaling $100 million versus $172 million loss in Q1 '22. First quarter total production volumes averaged 635 MBoe per day, with oil averaging 92.2 Mbo per day and natural gas volumes at 2.76 Bcf per day. Oil and BOE finished 2.5% and 1.6% above the high end of guidance, respectively, and natural gas hit the high end. The strong performance was driven by a combination of positive well productivity trends and improved cycle times. Turn-in lines during the quarter totaled 49 net wells above expectations. The incremental wells came online late in the quarter. First quarter accrued capital expenditures totaled $569 million, as I said before, but the cash capital expenditures only $483 million, consistent with expectations. Turning to return of capital. We announced a $0.20 per share base dividend and remain one of the highest-yielding base dividends in the industry. Management and the Board remain committed to responsibly increasing the base dividend on an annual cadence. During the first quarter, Coterra followed through on its return priorities by repurchasing 11 million shares or $268 million. In total, we returned 76% of free cash flow during the quarter. As we communicated in February, it is our intention to pursue strategic buybacks ahead of variable dividends. We have over $1.7 billion remaining on our $2 billion buyback authorization. We are reiterating our annual commitment to return 50% plus of free cash flow to shareholders. Lastly, I will discuss the refinements to our '23 guidance and activity outlook. We reiterated the company's capital estimate of $2.0 billion to $2.2 billion. While we are seeing clear signs of cost softening, we have yet to realize meaningful savings and therefore, have not built any future cost reductions into our forecast. We are increasing our full year oil guidance 1% to 87 to 93 Mbo per day, driven by efficient operations and strong well performance in both the Permian and Anadarko basins. The total company well turn-in lines are unchanged from our original guidance. In the Marcellus, as Tom has stated in his remarks, we are finishing up a development this month and then plan to drop one of our two frac crews and hold a single crew for the balance of the year. We also plan to drop from three rigs to two rigs this summer as planned earlier this year. In the Anadarko, a late '23 turn-in line was pushed into '24. This lowers our Anadarko turning lines to seven wells, down from our prior range of 10 to 15 wells. We now intend to maintain one to two rigs in the basin for the remainder of '23. In the Permian, we expect to continue to run six rigs for the remainder of the year and will pivot between 2 and 3 frac crews. Due to improved cycle times, we expect to bring on an additional five wells in the Permian during late '23, offsetting the lower turn-in lines in Anadarko. Turning to unit cost. The company's guidance remains unchanged at midpoint but there was some moving pieces primarily driven by reclassification between cost categories, which occurred after completing our integration into a single accounting system earlier this year. We also reiterate our 3-year outlook, which assumes the company achieves a 3-year oil CAGR of 5%, BOE and natural gas CAGR of 0% to 5%, which is achievable with capital and activity that is flat to down relative to '23. In summary, despite commodity headwinds, Coterra's outlook remains strong. Driven by continued strong execution, we are well positioned to meet or exceed our 2023 targets. With that, I will turn it back to the operator for Q&A.

Arun Jayaram:

Good morning, Tom. Nice results from your team. I wanted to see if I could delve into your commentary around the potential activity in the Marcellus. You mentioned that your original plan was to go down to 2 rigs and 1 frac crew, but you also signaled that you may stay at this level for a certain amount of time, given -- macro. I was wondering if you could give us a sense of do you think you could hold your Marcellus production relatively flat at, call it, that 2.1 Bcf a day? And what would that mean for CapEx if you did go down to that level because I think this year's CapEx guides around $835 million at the midpoint?

Arun Jayaram:

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

Arun Jayaram:

That's super helpful. The second question perhaps for you and Scott. Tom, you have been handily surpassing the 50-plus percent minimum cash return threshold to shareholders. You're at 76% this year. I was wondering if you could get some color on thoughts over the balance of the year. And I know that your framework -- under your framework, you like to keep around $1 billion of cash on the balance sheet. You're essentially at that level at the end of March. So any thoughts on the ability to kind of sustain this, call it, mid-70s type of cash return over the balance of the year because you really don't have much debt due until a little bit into 2024, I believe?

Tom Jorden:

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

Operator:

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

Tom Jorden:

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

Scott Schroeder:

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

Operator:

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

Blake Sirgo:

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

Blake Sirgo:

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

Tom Jorden:

Kalei, this is -- I think it speaks for itself. We're seeing great performance on these projects. We are optimistic. We try to guide as we see it. But we don't sandbag but we're really seeing some surprises to the upside. And I think that we would love to see further surprises to the upside, but we really try to call it as we see it.

Tom Jorden:

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

Operator:

Your next question comes from the line of Michael Scialla from Stephens. Your line is open.

Tom Jorden:

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

Michael Scialla:

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

Michael Scialla:

Got it. Thank you.

Neal Dingmann:

Good morning, all. Thanks for taking my question. First is on, I guess, an M&A-type question specifically. I'm just wondering could you discuss opportunities to sort of trade and block up your Delaware acreage specifically in New Mexico, where it looks like you have a little bit more scattered position there?

Neal Dingmann:

Yes. Like your strategic nature, Tom, it's always paid dividends. My second question, maybe just sticking with Del. Could you give me an idea of sort of -- I know you mentioned or you or Scott mentioned six rigs likely to continue active on the Del this year. Could you remind me kind of what area that will focus? And as a result, really any notable change in the GOR this year versus last?

Neal Dingmann:

Very good. Thank you, Tom.

David Deckelbaum:

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

David Deckelbaum:

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

David Deckelbaum:

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

David Deckelbaum:

Yes, appreciate that. Thanks, Tom.

Tom Jorden:

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

Dan Guffey:

Thank you, and good morning. Thank you for joining Coterra Energy’s fourth quarter 2022 earnings conference call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; and Scott Schroeder, Executive Vice President and CFO. Also on the call, 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 Web site. With that, I’ll turn the call over to Tom.

Scott Schroeder:

Thanks, Tom. Today, I will discuss our fourth quarter and full year 2022 results, shareholder return strategy, and then finish with our '23 outlook. During the fourth quarter, Coterra reported net income of $1 billion, discretionary cash flow of $1.4 billion, accrued capital expenditures of $483 million and free cash flow of $892 million. Fourth quarter total production volumes averaged 632 MBoe per day, with natural gas volumes averaging 2.78 Bcf per day and oil at 90.7 MBO per day. Oil finished 2% above the high end of guidance and natural gas hit the high end. The strong fourth quarter volume performance was driven by a combination of positive well productivity trends and improved cycle times. Fourth quarter turn-in-lines totaled 46 net wells, in line with expectations. During the quarter, we returned 107% of free cash flow, which included $0.57 per share in cash dividend and $0.65 per share in the form of share repurchases. Share repurchases totaled $510 million in the quarter, marking the completion of our $1.25 billion program first announced in the first quarter of 2022. For the full year 2022, total production came in at the high end of guidance relative to our February '22 guidance. Oil came in 2% above the high end and natural gas came in 2% above the midpoint. Net wells online during the year were 3% below our original guidance. Accrued capital expenditures, which were 16% above original guidance, totaled $1.74 billion and were driven by significant service cost inflation. During 2022, the company returned 85% of its free cash flow, 50% in the form of base and variable dividends and 35% in the form of share repurchases. In total, the company returned $3.2 billion to shareholders, or 18% of its recent market capitalization. After paying off 874 million on long-term notes during the year, Coterra finished the year with $673 million of cash and a net leverage ratio of 0.2x. The company has four manageable tranches of debt left with maturities ranging from 2024 to 2029. Turning to return of capital. As many of you read in our release and we have alluded to already, we have multiple updates on the capital return front. First, we increased our annual base dividend 33% to $0.80 per share. This reinforces the confidence management has in our business and our ability to perform across the cycles. It also reinforces our commitment to providing consistent and meaningful annual dividend increases to our owners. Next, after completing our $1.25 billion share repurchase authorization in '22, we announced a new $2 billion share repurchase program. Using current commodity prices, this authorization will not be fully executed in a single year, but the $2 billion is our commitment to the repurchase program and returning value to our shareholders. Lastly, we updated our return on capital priorities. We are reiterating our commitment to returning 50% plus of free cash flow to shareholders. However, we are prioritizing share repurchases ahead of variable dividends. Due to market conditions and the value proposition we see in our business, we believe buybacks are the best vehicle to return value to shareholders. Expect Coterra to pay its base dividends, pursue strategic buybacks and supplement with variable dividends, if needed, to hit our minimum threshold. Lastly, I will discuss the 2023 outlook. The company's 2023 capital is estimated to be $2.0 billion to $2.2 billion. This estimate includes approximately 10% cost inflation over the calendar year 2022 capital expenditures. Total full year '23 production on an equivalent unit of production basis is expected to be relatively flat to slightly down. Oil is expected to grow 2% and natural gas volumes are expected to modestly decline 1% year-over-year. Rolling activity in 2023 is expected to be relatively consistent with five to six rigs in the Permian, two to three rigs in the Marcellus and two projects in the Anadarko. Frac activity will be up 31% year-over-year due to project and DUC timing. The company average lateral life is expected to increase approximately 10% year-over-year primarily due to longer laterals in our upper Marcellus program. Since last summer, 2023 natural gas prices have fallen from a $6 annual average to a recent strip of $3. However, front month prices are near $2.16 and this is yet to be seen if the forward curve will hold. At the same time, service costs have not softened or adjusted. This dynamic has led Coterra to pursue a production maintenance plan in 2023 with anticipation of modest growth in our three-year plan. The company has an industry leading balance sheet and low breakevens to maintain consistent activity through the cycle. To put this in context, the company's corporate breakeven, which we define as free cash flow after paying the base dividend, sits at $45 WTI and $2.25 Henry Hub. The capital split in 2023 is expected to be 49% in the Permian, 44% in the Marcellus with the remainder going to the Anadarko. On the heels of positive results in the upper Marcellus in 2022, we are allocating 40% to 50% of our 2023 Marcellus program dollars to further delineate the upper interval. This is above the 30% to 40% range we discussed as a preliminary target in late '22. This range is likely to be the higher end of the range for the upper Marcellus versus the lower Marcellus split over the three-year period we laid out. Infrastructure timing, pipeline availability, and economics were all factors in increasing our allocation to the upper in 2023. Cost guidance for 2023 assumes that dollar per BOE unit costs are flat to down across the board largely driven by lower commodity prices outlook. Lastly, the future of Coterra is bright. Based on the current service cost environment, we estimate that if a company invests 2.0 billion to 2.1 billion per year over the next three years, it will generate a compound annual growth rate of 0% to 5% for both Boe and natural gas and closer to 5% for oil. At current strip, this would generate accumulative free cash flow of approximately $7 billion or 35% of the current market cap. In summary, our first full year at Coterra was stellar. We met our plan production, expenses and far exceeded revenues due to a small hedge book and robust pricing. For '23, the price dynamic is different but the engine of success is the same, focus on operational execution of our high quality inventory to generate strong returns and outsize shareholder returns. With that, I'll turn it back to the operator for Q&A.

Nitin Kumar:

Good morning, Tom and team and thanks for taking our questions. Tom, I'd like to maybe unpack a little bit of your commentary around the 2023 capital budget. You said about 10% of that is really targeted towards growth with some off ramps. So should we expect if you were to be in a maintenance mode, is your capital about 1.9 billion or 1.8 billion? And how does that trend over time, particularly over the three-year period?

Blake Sirgo:

Yes. Thanks, Nitin. Our '23 budget number represents the three-year growth plan we've laid out, not a maintenance plan. If you look at Slide 6, you'll see we plan to spend 2 to 2.1 per year over the next three years. What that does for us is provide 0% to 5% Boe and gas growth on average annually and oil growth at 5% on average annually. That's something we're choosing to do, because we have a deep inventory of high return projects. But if we chose not to grow and go into maintenance mode, that would drop to 1.8 billion to 1.9 billion per year over that same three-year period at our current cost structure.

Scott Schroeder:

Actually, Nitin, I’ll give that to Blake. He’s over our marketing group now.

Nitin Kumar:

Great. Thanks, guys.

Umang Choudhary:

Hi. Good morning. And thank you for taking my questions. I wanted to start off with your free cash flow allocation priorities. Would love your thoughts around allocation between share repurchase, your target of building $1 billion on cash on the balance sheet, and any thoughts around M&A?

Umang Choudhary:

That's very helpful. Thank you. And then maybe to follow up on Nitin’s questions on flexibility of your capital program to changing macro conditions, what kind of flex do you have in your program over the next three years? And then any color you can provide on the recent cost trends will be helpful. Thank you.

Blake Sirgo:

Yes. And on the cost trends, the 10% we're showing for '23 is really a reflection of those contracts we entered into in late '22. It sure feels like the market is starting to soften. There's less talk about price increases, or talk about costs holding flat. And if activity starts to drop across the lower 48, we'll be looking to claw some of those costs back.

Operator:

Your next question is from Arun Jayaram of JPMorgan. Please go ahead. Your line is open.

Tom Jorden:

Yes, Arun, I don't have the actual well count in front of me, but it's fairly flat level of activity is what we're projecting. So I think you could really see a level set in terms of the '23 activity going forward. But just an editorial comment, Arun. If there's one thing that many of us have learned is that in this shale era, this stop-start around commodity prices is really damaging to your cost control, the operational cadence. And quite frankly, I think as an industry, we've typically kind of gotten that exactly wrong in terms of when we invest and what we can track. So the nice thing about Coterra is because our assets have such robustness at low commodity prices, we can maintain more of a regular operational cadence. And that's what we're going to do. And that's a strategic pivot for us. It's why we put Coterra together. Now whether that operational cadence has our current rig count or a rig count less or a rig higher, we're going to try to maintain a steady cadence and not wake up every day with our hair on fire when we read the paper. We can afford to prosecute this business the way this business needs to be prosecuted.

Tom Jorden:

We do not see a change in our Delaware productivity. One of the big differences as I said in my opening remarks is in 2022 we just drilled a couple of absolutely lights-out outstanding projects. And I'm talking about projects with over 10 wells that average 1,000s of barrels a day. So those are you -- we don’t have tons of those and we drilled a couple of them in '22 and that was part of that productivity in '22. But specifically to your question about well to well interference, when it comes to the Wolfcamp and Harkey, we generally see that as one petroleum system. And there will be some degree of pressure communication between the Wolfcamp and Harkey, depending on where you are in the basin. But we do not see that as a factor that degrades overall well productivity. We typically stage that development within reasonable proximity of time. But our thinking on that matter is that having the two landing zones does not interrupt or impede your overall recovery out of that drilling spacing unit. So we don't see that as a significant issue for the Wolfcamp, Harkey. And I think the big answer to your big question is, over that three-year landscape, we don't see significant change in our Delaware productivity.

Operator:

Your next question is from Jeanine Wai of Barclays. Please go ahead. Your line is open.

Tom Jorden:

Hi, Jeanine.

Tom Jorden:

Well, look, mid cycle is kind of in the beholder. Everybody says the word mid cycle. And we’d rather you didn't ask us what the number was. But you do and we'll answer it. Our current mid cycle is our walking around numbers, 275 natural gas and our assets are really, really robust 275 natural gas. But as we said, Jeanine, we have the ability to move it around. The nice thing about having both a deep oil and natural gas inventory is although we produce a lot of natural gas in the Delaware basin, it's kind of a byproduct. So it's not really a function of a gas price. But right now, our returns are pretty good across our portfolio.

Tom Jorden:

Well, we are kind of in a shoulder period natural gas right now, outlook on natural gas. In 2024, we'll have LNG export come online. And so we are kind of in a wait and see mode on natural gas. We're long term very bullish because of the world's need for natural gas, and particularly the world's need for U.S. LNG exports. We're optimistic that that's becoming more and more apparent to more and more policymakers. And we remain ready to accelerate our natural gas assets. We're in the mid 40s on upper Marcellus this year on a total footage. And we've talked openly that the upper Marcellus doesn't have the productivity per foot of the lower Marcellus. That's something that's a fact of our assets; still outstanding, still very good and we're going to continue to develop it as we go.

Operator:

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

Tom Jorden:

When you say commodity benchmarks --

Tom Jorden:

Yes, I've got that in front of me, Doug. We have quite a bit of robustness in our inventory. And we typically run our inventory at multiple price files. I'm looking at a permutation in front of me that's run at $60 oil and $3 gas long term, and $85 oil and $4.25 gas long term. Now I will say when we go to $3 or less, we do assume some reduction in capital. And currently, we say, all right, if we're going to say $60 oil, $3 gas, we're going to take 70% of current capital expenditures. But the $85, $4.25 is at current costs. And so depending on where you want to cut it off, if I say, all right, how much of that hurdles at a 1.25 PVI10, which I think is a reasonable long-term inventory cut off, we've been using 1.5 in one of our disclosure, but I'm going to give you 1.25. At $60 and $3, 75% of our total inventory would hurdle at a 1.25 PVI10. And at $85 and $4.25, 91% of our inventory would hurdle at a 1.25 PVI10. And again, at $85, $4.25, that is the current cost. So we have a fair amount of downside protection on this inventory.

Tom Jorden:

Well, Doug, we've heard very mixed signals out of our investor base. Some people want us to do A and some people want us to do B. We've also looked at the market response to the variable dividend and I think that's a strong signal as to what the market is looking for. And then we listen to our critics, and we think about it and we really do have an honest attempt to get better and adopt the best approach. And we think that long term, buyback not only is the best acquisition opportunity in the market when we look at Coterra stock, but it's also highly accretive to our long-term owners, and that kind of checks two boxes. And so I won't tell you it was a casual decision to readjust our priorities. But we're very, very confident that in 2023, it's the right decision.

Tom Jorden:

Thanks, Doug.

David Deckelbaum:

Good morning, Tom and Scott. Thanks for taking my questions today.

David Deckelbaum:

Hello. If I could just dive into the upper Marcellus a little bit just from my -- to better my understanding here. This year, it sounds like the mix is going to be higher relative to the overall upper versus lower mix in the next several years. So I guess I'm curious, based on the wells that you have in the plan now in the upper, how much of the sort of resource do you think that you're going to be derisking this year relative to what you have sort of envisioned overall? And then how many of those locations are going to be in areas where the lower Marcellus has already been depleted?

David Deckelbaum:

Thanks, Tom. And I guess my follow up to that is just as you look to that ramp of 100 million a day or so in the next couple of years, I suppose that assumes sort of similar activities in the Marcellus. So is that just reflecting a quality mix between having more of the lower and perhaps just better infrastructure availability?

David Deckelbaum:

Sorry. I thought that I saw in your presentation that the implication was that you would get, call it, from 3.8 to 3.9 [ph].

David Deckelbaum:

All right. Best of luck with the garden. Thanks, Tom.

Operator:

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

Tom Jorden:

Thank you.

Blake Sirgo:

Yes, Derrick, this is Blake. I'll take that one. It's hard to pin a service cost to a commodity price. It's really ultimately a function of activity and how much services are available on the market. We're seeing some softening. I'm happy to say we've seen a little bit in rig rates here recently, and that's a good sign. We've seen a softening in casing, our OCTG going out three to six months. We're starting to see some price coming down, and that's a good sign. But ultimately, it's going to be a function of activity across the lower 48. All rigs and crews have wheels and they will travel. So we'll see where activity goes.

Tom Jorden:

Yes. Specifically, Leota/Clark was an outgrowth of a lot of work we've done over the years. We did space those wells a little further apart. One of the things we also learned is to put our wells a little further away from parent wells, and very, very pleased with the results. As we look ahead in our three-year plan, the Anadarko has a few very, very nice projects this year, and then we take a little pause and then we start up January 1 of '24 with additional activity. But as you look at that inventory slide, these are high quality locations really begging for more capital, quite frankly. And the team is making it really hard for us. And as we asked them to do, they've come forward with some really, really nice projects in inventory. And we're just in the progress of trying to manage and embarrass from the riches.

Operator:

Your next question is from Matt Portillo of TPH. Please go ahead. Your line is open.

Tom Jorden:

Hi, Matt.

Tom Jorden:

Well, if 2.75 were the price, I think that's probably something we'd look at seriously. Our current plan has fairly flat level of activity in the Marcellus and our intention is to solider on. But if we look very carefully at the oil/gas ratio and the return differential, and we're going to pivot and try to find the best returns within our portfolio. The oil/gas ratio last year was 10 to 1. It's currently 30 to 1. And we talked about mid cycle pricing. That mid cycle ratio is really what we're looking at. And we don't want to react -- we don't want to kneejerk near term. We've got the wherewithal to be patient on this.

Tom Jorden:

Yes, in that three-year plan, the upper Marcellus is the highest percentage this year that we're currently projecting over the next three years. But in the out years, '24 and '25 and our current plan is the upper Marcellus is going to be about 30% to 40% of our total program. And I will just reaffirm we stand by our statement that that frac barrier is indeed a hydraulic isolation between the two units, which does give us the luxury to stage the development in the most prudent way.

Operator:

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

Tom Jorden:

Well, I'll chime in and then Blake will come in as well. That 8 to 10 well project size, we didn't come up with that through some deep thinking. It kind of just happened operationally as we look at cycle times. We look at facility design that seemed to be what looked to work. The Delaware is a little different beast than a lot of other basins you'll look at. We have a single pad in the Delaware that we're flowing back -- that is flowing back in excess of 200,000 barrels of water a day, a single project. And so pad design in the Delaware is a function of a lot of things, one of which is infrastructure.

Tom Jorden:

Neal, I want to correct myself that projects and pads or one pad is producing 100,000 barrels a day. I said -- I was talking about project. One pad is producing 100,000 barrels a water a day.

Tom Jorden:

In Marcellus, we produced 5,000 barrels a day in the whole field.

Blake Sirgo:

This year, we do have a pretty good delineation across the field that we're testing upper Marcellus in. Really it's a function of takeaway and infrastructure too. We're careful where we bring that on. And you'll kind of see that theme in the upper as we go forward where we put those locations, similar to the lower, how we've done in the past. Infrastructure is a real guiding light there.

Neal Dingmann:

That’s a great answer. I look forward to hearing all the details. Thanks, Tom.

Kevin MacCurdy:

Hi. Good morning. I was wondering if you could give some color on how you plan to execute the share buybacks. Will there be a set amount that you do each quarter based on your free cash flow, or are you going to be more opportunistic based on your internal NAV?

Kevin MacCurdy:

Great. And then just, if I can, a question on the multi-year outlook. What would you say is the main driver of the increased oil production? Obviously, you're going to put on more wells, but are there any changes in productivity, drilling in more productive areas or higher working interest areas that are contributing to that impressive growth?

Kevin MacCurdy:

Great. Thank you for taking my questions.

Leo Mariani:

Hi, guys. I just wanted to ask a little bit about the CapEx outlook here. So you guys are talking about 2 billion to 2.2 billion this year in terms of the range. I was hoping to get a little bit of color around in terms of what puts you at the higher end versus the lower end. I'm assuming it might just be service costs. And then as I look at the three-year outlook, you guys are expecting that to come in slightly to kind of more 2.0 billion to 2.1 billion in the next couple of years. So just wanted to get a sense of why that's coming down a little bit. Is there any expectation that service costs might come in? Obviously, you talked about some of the trends maybe starting to look favorable.

Leo Mariani:

Okay, that's helpful. And then just wanted to follow up on some of the comments you guys made about the variable dividend versus the buyback. Just wanted to get a sense, I know you guys are going to continuously monitor this, but can we have an outcome this year where we get very, very little variable dividend and the buyback increases rather significantly versus kind of where it had been in the second half of 2022. Obviously, the stock while it's doing well today has come in quite a bit off the highs from last year or so. Just trying to get a sense if you guys are really going to kind of lean pretty hard on the buyback this year and do kind of very little on the variable dividend depending on how things play out?

Leo Mariani:

Okay. I appreciate it, guys. Thanks.

Paul Cheng:

Hi. Good morning.

Paul Cheng:

Two questions, please. One question is going back into the buyback and fixed dividend. Let's assume that later this year that you already raised your cash balance to $1 billion. And at that point, should we assume that the excess cash will be essentially both for the shareholder return. And that means that if you end up that going to be above 50% or that even which that level that you may want to further strengthen your balance sheet. So trying to understand that once you reach that level, what kind of distribution that we should assume? Secondly, Tom, can you talk about -- you have a pretty huge inventory backlog already. So bolt-on acquisition is something that you guys think is attractive or that is important for you over the next couple of years or that you would be still focusing on your existing assets? Thank you.

Tom Jorden:

And I'll take that question. Inventory is always an important issue. As I've said in the past, having a long inventory really gives you the opportunity to run your program with only solid financial and operational considerations and not be panicked about some kind of a runway that's short. We have a very deep inventory, and we have the luxury of being able to run our program based on the best financial returns. That said, we're a learning organization and we're constantly looking for opportunities. We would love to find bolt-ons that we could handle our operational teams. We're very proud of our operational teams and their ability to integrate, operate smartly and really bring a hidden value forward. We're going to constantly look. But M&A is a perilous territory. When you typically want to have some advantage, that advantage can be information advantage, it can be operational advantage, it could be geographic advantage. But we're probably not going to be showing up to auctions and trying to outbid people that have the same information we do. So we'll be opportunistic, but we're blessed with the luxury of not having to do something, and that's a nice place to be.

Charles Meade:

Good morning, Tom and Scott. Thanks for fitting me in. I just have one more question on the buyback. And I know you guys have covered a lot of territory on it, but I think it's an important shift. And Scott, I know this is a conversation that you engage in for a long time. But the sense I get is that in the current environment, you guys are tilted hard towards the buyback, and I think you've been clear on that. My question is about whether you guys view this pivot as a durable pivot across time and also across price. And if you are thinking about it as a durable pivot, maybe you can share kind of up to what price you view it as being durable?

Tom Jorden:

But we are also going to make the best decision quarter-by-quarter and be prepared to pivot. We're not making some wholly pledge for all time. What we're saying is we're reaffirming our commitment to return cash to our owners and we think there's a better way to do it in 2023, and we're very confident with our move this morning.

Operator:

We have completed the allotted time for questions. I will now turn the call over to Tom Jorden for closing remarks.

Operator:

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

Dan Guffey:

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.

Scott Schroeder:

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.

Jeanine Wai:

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

Jeanine Wai:

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?

Jeanine Wai:

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.

Jeanine Wai:

We appreciate all the details. Thank you, Tom.

Umang Choudhary:

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?

Blake Sirgo:

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.

Blake Sirgo:

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.

Operator:

Your next question is from Arun Jayaram of JPMorgan. Please go ahead. Your line is open.

Tom Jorden:

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.

Tom Jorden:

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.

Operator:

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

Tom Jorden:

Loud and clear, Neal.

Tom Jorden:

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.

Tom Jorden:

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.

Operator:

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

Tom Jorden:

Hi, Derrick.

Tom Jorden:

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.

Tom Jorden:

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.

Operator:

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

Tom Jorden:

Hey, David.

Tom Jorden:

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.

Blake Sirgo:

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.

Blake Sirgo:

No, typically 12 months or less.

Operator:

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

Tom Jorden:

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.

Tom Jorden:

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.

Operator:

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

Tom Jorden:

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 Jorden:

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?

Tom Jorden:

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.

Tom Jorden:

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.

Operator:

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

Tom Jorden:

Good morning, Noel.

Tom Jorden:

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. .

Tom Jorden:

You’re talking specifically to Anadarko?

Tom Jorden:

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.

Operator:

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

Operator:

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

Dan Guffey:

Thank you, Cheryl, and good morning, and thank you for joining Coterra Energy's second 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 the Q&A session. As a reminder, on today's call, we will make forward-looking statements based on 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.

Scott Schroeder:

Thanks, Tom. Today, I will briefly touch on second quarter results, shareholder returns and then finish with updated [guidance]. During the second quarter, Coterra generated discretionary cash flow of $1.49 billion in the quarter, which was up 21% quarter-over-quarter, driven by strong operational execution and robust commodity prices. Accrued second quarter capital expenditures totaled $472 million with drilling and completion making up 93% of that total, while cash capital expenditures totaled $474 million. Coterra's free cash flow totaled $1.02 billion for the quarter, which included severance costs of $14 million. Additionally, the free cash flow figure included cash hedge losses totaling $297 million. Second quarter total production volumes averaged 632 MBoe per day, with oil volumes averaging 88.2 MBO per day and natural gas volumes averaging 2.79 Bcf per day. As Tom indicated, all three streams were at the high end of our guidance range. The strong second quarter performance was driven by a combination of operational efficiencies, which accelerated cycle times, positive well productivity and an increase in non-operated production. Second quarter turn-in-lines totaled 32 net wells, which was in line with the high end of our guidance range. One note, during the quarter, we were primarily an ethane recovery in the Permian Basin, whereas we have primarily in rejection over the prior year. This caused natural gas volumes to be slightly lower, NGL volumes to be slightly higher and NGL realization as a percent of WTI to fall slightly. We expect to see a blend of rejection and recovery for the remainder of the year. The company exited the quarter with approximately $1.1 billion of cash, down from $1.4 billion in the first quarter. During the second quarter, the company had a stronger than usual -- excuse me, a larger-than-usual change in its current assets liabilities account on the cash flow statement, due primarily to large AR changes, which were driven by strong commodity prices. Company's combined net debt to trailing 12 months EBITDAX leverage ratio at quarter end was 0.4x. Liquidity stood at just over $2.5 billion when combining our cash position with our undrawn $1.5 billion revolver. Turning to return of capital. We announced shareholder returns totaling 80% of second quarter free cash flow or 92% 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 common dividend yields in the industry. Second, we announced a variable dividend of $0.50 per share. Combined, our base plus variable dividends totals $0.65 per share up from our $0.56 per share dividend paid in the first quarter and our $0.60 per share dividend paid in the second quarter. Our total cash dividends for the quarter is equal to 50% of free cash flow. Third, during the second quarter, we repurchased $303 million of common stock or 11 million shares at an average price of $28.60. Buyback amounted to a $0.38 per share number or 30% of free cash flow. Just over four months since our $1.25 billion buyback authorization, we have repurchased 18.9 million shares for $487 million, utilizing 39% of our original authorization. We have previously discussed our intention to execute the full authorization within a year and remain on track to do so. Entering the third quarter, the company had a 10b5-1 plan in place, and we will provide details of its third quarter share repurchase activity with next quarter's update. In addition, we announced the conversion of $38 million of preferred stock and a retirement of $124 million in principal of long-term debt, which had a weighted average interest rate of approximately 6%. We remain committed to returning 50-plus percent of free cash flow through the base dividend and variable dividends and incremental returns come in the form of share buybacks and enhanced variable dividend or possible future debt reduction. Lastly, I will discuss our guidance. In the release yesterday afternoon, we updated full year production, capital and unit cost guidance. Following another strong quarter of execution and performance, we are raising our full year '22 production guidance. Our annual guidance at the midpoint for BOE is up 1% to 615 to 635. Natural gas is up 1% to 2.75 to 2.83 Bcf per day. And oil is up 4% to 85.5 to 87.5 MBO per day. We have no change to our '22 turn-in-line guidance but could be toward the high end of the range. We are increasing our full year capital investment guidance 10% above the high end of our previous range to $1.6 billion to $1.7 billion. The increase is driven by incremental inflation and a modest uptick to second half '22 activity. We now expect '22 inflation to drive capital up 20% to 25% year-over-year, up from the estimate of 15% to 20% back in May. While we have the majority of our big ticket items locked in for the second half of 2022, the majority of our '23 program remains subject to market rates. Based on preliminary estimates, we expect inflation to increase dollars per foot an incremental in 2023. On the activity increase, Tom already noted the third rig in the Marcellus in the second half of '22. Additionally, we are increasing our facilities capital minimize execution risk and the impact of high service and materials markets. While we are continuing to see inflationary pressure relating to operating costs, we are maintaining our LOE, GP&T and G&A unit cost guidance. We are increasing our taxes other income guidance and lowering our expectations for the deferred tax ratio. With operational efficiencies pulling volumes forward into the second quarter, we now expect production volume for the second half to be relatively flat. In summary, we expect capital discipline, continued execution and our unrelenting focus on maximizing return on capital to drive a differentiated value proposition. As always, maintaining one of the best balance sheets in the industry remains foundational for our future success. With that, I will turn it back over to the operator for Q&A.

Jeanine Wai:

My first question is on cash returns. You returned in a very impressive 80% of free cash flow this quarter, 69% last quarter. And we know the official framework calls for 50% or more payout with the base plus variable dividend. And then you have the buybacks as a sweetener. So you already have a strong balance sheet, you don't have much debt coming due. And our question is, if prices remain around where they are currently, is that 70% to 80% range a good ballpark going forward?

Jeanine Wai :

Okay. Understood. Thank you. Our second question is on inflation, a topic these days. Some folks are a little surprised that the Marcellus is seeing as much inflation as it has been. So can you discuss the dynamics between the relative inflation between the Marcellus and the Permian and any implications for '22 or '23? And your prepared remarks on Slide 8, they were really helpful, and we're just looking for maybe any additional commentary.

Operator:

Your next question is from Matt Portillo of Tudor, Pickering & Holt.

Tom Jorden:

Well, Matt, we've learned kind of what we've talked about in the past. We believe we can recover the same amount of oil volumes in much -- if -- much of our Permian asset by drilling fewer wells. And so we're seeing a significant increase in capital efficiency, as we widened our spacing. And in some areas, we've increased our completion energy. And what we're finding is that as we compare our projects to some offsets, we're tracking right on line with recovery per drilling spacing unit with a lower capital investment. We continue to explore landing zones. We've done a lot of science over the years, and we're seeing, I think, good recovery from our section of rock. But as I said in my prepared remarks, all that in great rocks and you have a formula for success. So we're very pleased with the changes we've made over the last couple of years.

Tom Jorden:

Our learning curve in the Upper Marcellus right now is steep, and it's kind of fun. It's nice to have a new landing zone with that kind of potential and kind of a race what you've known that doesn't apply and apply which you've known and directly applies. We're doing some science right now in the Marcellus. We've got a fiber optic project with some downhole pressure sensors, kind of exploring the fracture efficacy of our completions. We're very encouraged by what we're seeing in the air from Marcellus, and we look forward to bringing those results to the floor as soon as we get a little more production behind us. We want to be conservative and watch these multipad developments before we start high-fiving ourselves. But the Upper Marcellus is wide open territory. We're very encouraged and look forward to discussing it in the future.

Arun Jayaram:

A couple of questions regarding your initial thoughts on 2023, really appreciate those. You mentioned -- maybe Scott mentioned how preliminarily maybe dollar per foot up about 10%, and you could deliver, call it, mid-single digits growth kind of preliminarily, I wanted to get your sense on kind of footage. You guys gave us a lot of great details on the amount of footage. If you run a six-rig program in the Permian and three rigs in the Marcellus. What kind of year-over-year increases would you anticipate in just overall footage?

Arun Jayaram :

No. No, I just -- you gave a lot of great detail, so I was trying to lead the witness. The -- just maybe my follow-up, we continue to be intrigued by your delineation activity in the Harkey Shale. It sounds like you got a couple of wells online and the fact that you're doing more suggests that you're liking what you see. But can you maybe put this zone in the context, Tom, what could this do for your inventory and maybe characterize what you're seeing in terms of some of the early results?

Operator:

Your next question is from Neal Dingmann of Truist Securities.

Tom Jorden:

Well, I'll tee it up and let Scott bring it home on this. One of the things I've said is flexibility is the coin of the realm. And one of the nice things, Coterra is we have an absolutely pristine balance sheet, fantastic assets, great return on investment, and that gives us almost embarrassment of riches on options. . We also live in a very uncertain world and that flexibility is going to be really important. I can't tell you when and where, but the span of my career tells me that the best laid plans tend to not come through. I was thinking last night of Mike Tyson's famous quote that, "Everybody has a plan till you get hit in the face." And we haven't had our last hit in the face in this industry. Scott?

Neal Dingmann :

Tom, my second question, again, is on shareholder return allocation or maybe dividend versus buybacks. So I'm just wondering, specifically, you all had mentioned or had mentioned opportunistic buybacks. And I'm just trying to get a sense of periods such as in late -- early to late June when your shares like others fell maybe around 30%, does that qualify such an opportunity?

Operator:

Your next question is from Michael Scialla of Stifel.

Tom Jorden:

Well, we're still studying it, Mike. And I know there's been some really good commentary. There's some good commentary this morning in the Wall Street Journal. And I'll say this, I will be surprised if a lot of its current form ultimately survives. With respect to the methane fee, there are some concerning provisions in there. It calls for as to conform to EPA requirements that aren't yet published, and it calls for us to conform in the time line that looks like it will predate the effect of new EPA regulations. So that's a bit baffling as to how we're going to comply with that. There's also a provision in there for a methane intensity to be measured by direct measurement, and we are -- we've tried every technology, and we're evaluating a lot of continuous monitoring technologies currently. We haven't found one we think is scalable to address that requirement. And so how that 1 ultimately gets implemented, we'll wait and see. We do like the provision that lets it be a corporate methane intensity as opposed to basin by basin. As far as the alternative minimum tax, there's a lot of provisions of that, that are concerning. And I know others have commented on that. And then I'll finish with the addressing of infrastructure in the bill. I think it's a credit to Senator Manchin mentioned that there's a pretty strong statement on the infrastructure. There are some confusing elements to that. And we wait to see how that bill survives final passage. So I know that's a wandering answer. We're studying it carefully. I'll say this, there's no substitute for sound energy leadership. We really need an energy policy that is coherent, focused and resolute. And I'd like to see that be a whole of government approach and not just a Senate Bill. I'd like to see a little more leadership from the rest of our government on this subject, but we'll see. The ball is still in the air on that one.

Scott Schroeder :

Yes, Michael, this is Scott Schroeder. Again, we're continuing our hedging discussions internally. As Coterra was formed, obviously, the big dynamic was we -- and the balance sheet that we have, we don't have to lean in heavily on hedging. But we do like to have some of our cash flows covered in the event of some disconnects. And when we see opportunities, we'll take advantage of that. We've done that so far. You can see that in our 10-Q filing that will be made today, and we'll continue to address that. In the end, it's much like buying insurance. We don't have to have it, but it's prudent to add some protection to the overall profile.

Douglas Leggate :

Guys, I wonder if you could touch on the sustaining capital breakeven that you put in the deck? With the run rate capital increase and higher cash taxes, how do you expect that to evolve in 2023?

Scott Schroeder :

Doug, I don't if you have the page number on here, but it's Page 7 in the deck, free cash flow breakeven is still at $40 and $2.25. So I don't -- again, stress testing it down to that level. We're very confident that we have a sustainable program without having to really jeopardize what we want to accomplish.

Scott Schroeder :

It could be 15% to 25% deferred taxes, so you're a cash taxpayer between 75% and 85%. But to your question there, it is going to trend higher.

Tom Jorden:

Well, your observation is quite spot on, Doug. We do have a lot of gas in our portfolio generally. As you know, the Delaware Basin is very prolific from a gas standpoint. I really -- as I've said over and over, really look at capital allocation in terms of return on invested capital. And the Marcellus is absolutely second to none. I mean it's really an outstanding economic fairway. We do have the opportunity to grow a little bit in the Marcellus. I said in my opening remarks, we do need some additional pipelines. But from a capital allocation standpoint, based on returns on the Marcellus and the Permian are neck and neck. We've done some interesting analysis on how that changes with different oil and gas price swings. And at current multiple of gas to oil, you could -- with a blindfold on, you could really pick out the basin and really find very comparable returns. So we like the revenue balance. We like the geographical balance and we like our capital allocation as it currently stands.

Paul Cheng :

Tom, can we talk about Anadarko? And what's that asset’s in the long term the road to your portfolio? You are not doing much over there. So what exactly is the game plan? That's the first question.

Paul Cheng :

Right. The second one, hopefully, is pretty short. Looking at your production guidance for natural gas in the third quarter, you're actually sequentially down, but you're going to have more wells online than the second quarter, I assume. So is there anything that is driven for the lower sequential production? Is it the timing of the well coming on chain or other reasons that we should be aware?

Operator:

Your next question is from Leo Mariani of MKM Partners.

Tom Jorden:

Well, our -- we're very constructive on gas. I think most watchers are. With growing LNG exports, storage where it is, increased power demand, gas, and I think also a reawakened conversation around the critical role gas has to play in addressing the climate, particularly when it comes to power generation. I think we're quite bullish on natural gas. Marcellus is a great asset. It's in a great part of the world. And to answer your question is as we look ahead to the next couple of years, I would say we are more constructive on gas than we've probably been in a long, long time.