Ladies and gentlemen, good morning and thank you for standing by. My name is Brent and I’ll be your conference operator today. At this time I’d like to welcome you to the Coterra Energy Fourth Quarter 2021 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. Thank you. It is now my pleasure to turn today's call over to Ms. Caterina Papadimitropoulos. Please begin.

Thank you, Brent. Good morning, everyone, and thank you for joining Coterra Energy’s Fourth Quarter 2021 Earnings Conference Call. During today’s call, we may reference an updated investor presentation, which can be found on the company’s website. Today’s prepared remarks will include a business overview from Tom Jorden, CEO and President; and Scott Schroeder, Executive Vice President and CFO. Also in the room, we have Steven Lindeman, Blake Sirgo, Dan Guffey, and Todd Roemer. 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 yesterday afternoon’s earnings release, which can be found on our website. Following our prepared remarks, we will take your questions. Please limit yourself to one question and one follow-up. With that, I’ll turn the call over to Tom.

Thank you, Caterina, and thanks to all of you who are joining us this morning for the Q4 2021 Coterra conference call. I will be making a few overview remarks followed by our Chief Financial Officer, Scott Schroeder. We will then turn the call over to Q&A. Yesterday afternoon, we reported our fourth quarter 2021 results, which was our first full quarter as Coterra. All in all, things lined up nicely during the quarter. Our production came in right on top of the midpoint of our guidance, including a quarterly average oil production of 88,600 barrels of oil per day. This was an increase of 31% over the legacy Cimarex Q4 2020. Our Marcellus program delivered as promised, and company-wide all three streams—oil, gas, and natural gas liquids—came in at or above forecast. Scott will walk us through the financial details later on. We’re very pleased to have delivered a strong Q4. We also announced our enhanced return to shareholders, including a 20% increase in our common dividend, our fourth quarter 2021 total dividend equal to 60% of our fourth quarter free cash flow, and the launch of a $1.25 billion share buyback. Taken as a package, this positions Coterra to be one of the most attractive yield stories in our sector. Furthermore, we have confidence that this three-pronged approach is sustainable through the cycles. There are good times in our industry, so they will not last forever. Our experience tells us that things tend to stay good until they turn back, and these turns are swift and unanticipated. There is every reason to be optimistic about our business right now. Oil demand and prices are firming, supported by fundamental supply-demand imbalances; natural gas demand and LNG exports are increasing, driven in part by a reawakening to the fact that natural gas is an essential component of the world's energy transition needs. Public policymakers in the United States and abroad are reexamining their energy policies in a manner that favors natural gas demand. We hope these good times last, but Coterra is prepared for whatever the future may bring. As we look ahead into 2022, we have a well-crafted plan, backstopped by the outstanding returns that our assets are providing. Our goal in formulating the 2022 capital plan was simple: to maximize our cash flow, capital efficiency, and hold production relatively flat. As we have previously discussed, we are strategically interested in balancing liquids upward as a percent of our overall revenue and cash flow. In 2022, we expect liquids to account for 47% of our revenue mix, up from 40% in 2021. We plan to accomplish this by weighting more capital to our oil and liquids-rich areas with 49% in the Permian, 7% in the Anadarko, and 44% Marcellus. While all three basins offer comparable returns, the tilt towards our liquids-rich areas was a multifactor decision driven by the current commodity environment, service and inflation headwinds, and the goal to maximize free cash flow. As a result of our plan, we expect to generate $3 billion in free cash flow in 2022 while investing less than 35% of cash flow into our capital program. Our 2022 plan hits the right stride, deploying the power of our portfolio to maximize cash flow, not production. A few words on the impact of inflation. Like all of our peers, we are experiencing inflation across our supply chain. This includes rig rates, pressure pumping, labor, fuel, sand, and chemicals. We are also seeing increased pressure on trucking services, particularly in the Marcellus. Comparing 2021 service rates to projected 2022 service rates, we see 12% to 14% inflation in total well cost. Although we continue to push back with ongoing operational efficiencies, it does remain a factor in our overall capital level. Among the ways we are pushing back is increased project size as measured by the number of wells per pad. In the Permian, our average wells per pad is increasing from 5.5 in 2021 to 8.3 wells per pad in 2022. We are also striving to capitalize on longer well lengths wherever possible, and our average will be 11,000 feet, up over 10% year-over-year. Overall, we are seeing a net Permian inflation impact of 7% when we factor in inflation against ongoing operational efficiencies. Both of these counter-inflationary pushbacks, the number of wells and the longer welding are illustrated by our prudent justify authentic project in Culberson County, where we are drilling a 14-well project with an average lateral length of 15,750 feet. The prudent justify authentic project is projected to deliver total well costs, including drilling, completion, and facilities of approximately $700 per foot, the lowest of our 2022 program. To our knowledge, this project is the largest three-mile lateral project in the Permian Basin. We are already hard at work on our 2023 plans. As I have said in the past, owing to the long lead times required for pad development, much of our 2022 plans were baked in before we closed on the Coterra transaction. However, we were able to impact these plans by balancing our oil and liquids contribution upwards. We will continue to work to optimize our portfolio and deliver consistent results through the cycles. As we look into the future, Coterra is blessed with a deep inventory throughout our asset base. The Permian, Marcellus, and Anadarko all have greater than 15 years of top-tier inventory at our current investment rates. For these purposes, we consider top-tier inventory as those locations that generate a PVI 10 of 1.5 or greater at mid-cycle price, which we define as index prices of $55 oil and $2.75 gas. A PVI 10 of 1.5 generally equates to an after-tax rate of return of 50% to 60% depending on the decline profile. If we look at lower returns, our inventory gets even longer at current conditions. We worry about a lot of things at Coterra; inventory is not one of them. Finally, allow me to make a few comments on the progress of the integration of our two legacy companies. Thus far, the integration has gone remarkably well. Our organization is in place and functioning as one team. We are in the midst of integrating our various software systems and databases: accounting, land, engineering, geoscience, human resources. The team is making tremendous progress. Most importantly, we are seeing broad technical collaboration between our asset teams. We are exchanging ideas, gaining new insights from new colleagues, and raising the performance bar across our organization. We have an incredibly talented and dedicated team of professionals, and they are experiencing humility, as am I, as we come together and review the great work across our platform. We are exchanging spacing ideas, completion ideas, drilling efficiency, and EHS experiences as envisioned. We are challenging one another in developing trust. We are united in our commitment to make Coterra the best, most resilient company in our sector. I want to acknowledge our organization for the steadfastness of working through the integration process. This has involved long hours, occasional creative workarounds, and perseverance. The progress we are making is a testament to the quality of our workforce. I would also like to acknowledge our field staff, who once again, this winter, have been tasked with enduring severe winter storm events, and through it all, kept our production online and operated safely through exceedingly challenging conditions. I want to express my personal gratitude to these exemplary employees. With that, I will turn the call over to Scott.

Thank you, Tom. Let me elaborate on the fourth quarter results for Coterra and the shareholder return profile that we announced last night and given a little more granularity on our full year 2022 outlook. During the fourth quarter, Coterra generated discretionary cash flow of $1.03 billion, including the impacts of merger-related expenses. This figure was driven by a 6% increase in BOE production and a 28% increase in our average BOE realized price compared to the third quarter of 2021. Fourth quarter capital expenditures totaled $264 million, which were within our guidance range of $245 million to $275 million that we announced back in October. Coterra's free cash flow totaled $758 million for the quarter, which once again included the merger-related cost of $26 million and severance costs totaling $44 million. Additionally, the fourth quarter free cash flow included cash hedge losses totaling $370 million from legacy hedge positions from both parties. During the fourth quarter, production volumes beat the midpoint of guidance, as Tom indicated, by approximately 1% as the company's oil production averaged 88.6 MBO per day. Natural gas volumes averaged 3.1 Bcf per day and equivalents averaged 686 MBoe per day. The company exited '21 with just over $3.1 billion after the adjustment for the step-up related to the purchase accounting in the transaction, and a net debt to trailing 12-month EBITDAX leverage ratio of 0.65x. The company's liquidity stood at $2.5 billion, combining our cash position and the undrawn $1.5 billion revolver. Turning to the return of capital topic. We announced three actions last night that highlight our commitment to increasing shareholder returns. First and foremost, we announced a 20% increase in the annual base common dividend from $0.50 per share to $0.60 per share or $0.15 per share per quarter. This increase positions Coterra with one of the larger common dividend yields among our peers and underscores management and our Board of Directors' confidence in our business. Second, based on fourth quarter free cash flow results, we declared a quarterly base plus variable dividend of $0.56 per share. The base plus variable dividend reflects the new $0.15 per share base component and a variable component of $0.41 per share on the company's common stock. The combined base plus variable dividend represents 60% of fourth quarter '21 free cash flow and 48% of cash flow from operations. Third, we announced the initiation of a supplementary share repurchase program totaling $1.25 billion. This represents approximately 7% of our current market capitalization. The company remains committed to paying over 50% of our free cash flow via the common and variable dividends and plans to use buybacks as an incremental method to return cash to our owners. Our buyback program will be driven by relative and intrinsic value opportunities as we see them. Next, I would like to highlight our '22 outlook. Our full year '22 capital investment that we disclosed last night is expected to be between $1.4 billion and $1.5 billion. Included in that is $1.1 billion to $1.3 billion allocated to drilling and completion activities. Tom has already alluded to the split across the three business units. Our '22 capital program is expected to equal less than 35% of full year '22 anticipated cash flow at recent strip prices. As such, we expect to generate approximately $3 billion of free cash flow, which equates to a 16% free cash flow yield based on last night's closing stock price. In the Permian, we expect to run six rigs and two completion crews during 2022. This is a modest increase in activity coupled with a 7% increase in dollars per foot to $865 per foot at the midpoint. This will drive our Permian D&C up approximately $80 million year-over-year. Average gross project size in the Permian is expected to also increase to over eight wells per project, up from the 2021 average that Tom alluded to of a little over five, and lateral lengths will average up to 11,000 feet, up more than 10% year-over-year based on frac end. The increase in pad size and longer laterals will increase cycle times year-over-year, causing absolute turn-in line footage to fall approximately 10% year-over-year. In the Marcellus, we expect to average 2.5 rigs and 1.25 completion crews during the year. The region's dollar per foot is expected to increase 12% year-over-year to just above $900 per foot. However, due to pad timing and completion cadence, we expect to complete 8% less lateral footage and turn in line 22% less footage during 2022. Marcellus D&C capital is up 5% year-over-year, less than the region's inflation rate, which is expected to be 12% year-over-year as I previously mentioned. Our full year 2022 oil production is expected to average 81 to 86 MBO per day, which is up approximately 7% year-over-year at the midpoint. Our equivalent production is expected to fall approximately 2% to 3% at the midpoint. This is driven by natural gas volumes expected to fall approximately 5% year-over-year, driven by the previously discussed lower turn-in-line activity throughout the year. Highlighting unit cost guidance, we expect to see modest increases in LOE per BOE in 2022, driven by inflation and a modest increase in workover activity. Our transportation expense is up as well, primarily driven by increased fuel costs and POP contracts. Our 2022 G&A guidance of $1 to $1.30 per BOE includes anticipated severance expenses related to the merger. In 4Q 2021, our G&A included $44 million of severance. Excluding this charge, our fourth quarter results would have been within our guidance range of $0.65 to $0.85 per BOE. In 2023, once the integration is complete, we expect G&A to be more in line with our fourth quarter guidance range than the full year 2022 guidance range. Fiscal year 2022 DD&A guidance now fully reflects the results of our purchase price allocation, which was finalized at year-end 2021. Lastly, our deferred tax guidance for the year assumes a deferred tax rate between 20% and 30%. This estimate is based on the recent strip and assumes we fully utilize legacy Cimarex NOLs during 2022. This percentage could change depending on commodity realizations throughout the year. Our first quarter BOE production is expected to fall 10% sequentially and average 610 to 630 Mboe per day. This decline is driven by timing around the program, specifically turn-in lines in the Permian falling 31% sequentially and no turn-in lines occurring in the Marcellus during the quarter. Furthermore, base declines are likely to be higher in Q1 following the 31% year-over-year oil growth and the 6% quarter-over-quarter natural gas growth. We expect this decline to moderate throughout 2022 and into 2023. Our recent shareholder initiatives and our 2022 outlook highlight our commitment to capital discipline, our dedication to increasing shareholder returns and an expectation to maintain one of the best balance sheets in the industry.

Your first question comes from Nitin Kumar with Wells Fargo. You can go ahead, Mr. Kumar.

Sorry. I was on mute. Good morning, everyone and thanks for taking my questions. My first question is a bit of a two-part question, but congrats on getting the repurchase authorization. We noticed you had over $1 billion of cash on the balance sheet, leverage is below one times, and the stock is trading at a 16% free cash flow yield. So just perhaps, could you talk a little bit about how aggressively we should expect to see you execute on this buyback program? And then Scott, specifically for you, how much cash do you think you need on an ongoing basis to run this business?

Thanks for the question. Yeah, we're excited about the buyback. I can assure you our board is excited about the buyback, and we're planning on leaning in very heavily to execute on that, starting as soon as we possibly can. Again, all the facts that you laid out in terms of the free cash flow, the head space we have this year, look for us to make a tremendous impact on that amount starting right now in the second quarter or even in the first quarter. In terms of the cash on the balance sheet, I'm comfortable with what we have on the balance sheet. It doesn't mean we have to stay there. If we see an opportunity, we can go a little below it and—but we're not inclined to sit around and build large cash balances above where we're at today.

Great. My second question, Tom, you've been an early proponent of Shale 3.0. So I guess, oil is $100 gas is $5 right now. Is this a license to grow for Coterra in 2023 and beyond? I know you just gave us 2022 guidance. But I'm looking for some thoughts around how long do you stick with capital discipline?

That is a great topical question. Driving in this morning, I heard a fascinating discussion about just oil markets globally and their response and the public policy position around U.S. shale. So this is a very topical issue, not only in management meetings and boardroom, but also global policy. We're going to continue to engage with our owners and listen to our owners. I will not be surprised if there is a call on the U.S. shale producer to grow, depending on what happens to world energy markets, global inflation and some of the turmoil we're seeing around energy security. The U.S. producer has the wherewithal to grow. Coterra certainly has both. We have the assets that can generate growth. But we also—our commitment to Shale 3.0 is real and it is steadfast, and we are going to stay very close to our owners on this topic. We made that pledge for Shale 3.0 a couple of years ago at legacy Cimarex. At that point in time, we were talking about going forward investing 60% to 70% of our cash flow in our capital program. And here we are today, able to maintain or modestly grow our production, investing less than 35% of our cash flow in our operations. It's a remarkable time in our business, which means our industry has tremendous optionality on this topic. But we're going to stay close to our owners and make sure that our pledge to return to our owners is not cast aside.

Thanks, Scott and Tom.

Your next question comes from the line of Neil Mehta with Goldman Sachs. Your line is open.

Thank you. Thanks for the incremental color around capital returns and framework. The first question is around natural gas production. And in the plan, you have it declining in 2022. Just your thoughts, Tom, about your natural gas profile? And how would you respond to those who are concerned that the decline in production is evidence that the Marcellus is seeing a degradation in capital efficiency?

Well, look, there are a lot of factors that go into that, and Scott did a nice job laying them out. But one is pad size and just timing of our program. Running two rigs and Scott said, one-plus completion crews in the Marcellus certainly puts us at the mercy of project timing, and that's a big, big impact on our 2022 program. These assets are tremendous. I will tell you that. Obviously, over the last couple of days reviewing the returns of our 2021 program and our expected returns of our 2022 program. And I will say that they are top of the heap across corporate-wide. They compete heads up in every way, shape and form with Permian returns. We made a tactical decision to rebalance our liquids revenue up a little bit in 2022. Marcellus is alive and well, and I think you'll look for 2023 to see a return to growth in the Marcellus. We're very satisfied with where we are.

Thanks, Tom. And then clearly you talked about buybacks and dividends, but one of the things that you had let the door open for an announcement, the Cimarex transaction and Cabot transaction with the potential for incremental M&A. Do you view the combined company, Coterra, as a logical consolidator? And then how do you think of the market right now as a seller's market or a buyer's market?

Well, that's the easiest question I'm going to get all day. At $100 oil and where gas prices are, it's a seller's market. That said, when I see the progress we're making across our portfolio, and I see the power of idea sharing and it's coming in two ways. We're going to get better across all three of our basins because of the collaboration that's ongoing. That gives me tremendous faith in the organizational capacity to be a consolidator. Now that said, we are going to be extremely disciplined on that subject. We don't have an inventory problem. Hopefully, I've made that point loud and clear. When I look at our inventory, I just—it would be foolish to sacrifice return on capital in the interest of beefing up our inventory. And with the way we view the world, return on capital is our top priority in capital allocation. So, it would really need to be an extraordinary opportunity. They do come; they come few and far between. But if one got dropped in our lap at the right price and it made sense for our owners, we'd certainly look at it seriously. But it's not a near-term strategic priority for us. Scott, do you want to follow-up?

Yes. Let me just add to that in terms of just a one-liner. You started that commentary with a buyback. And the best acquisition activity for us right now is buying in our shares based on our overall valuation. So, that's where you lean in hard on an M&A transaction.

Yes, super clear. Thanks guys. Thanks, Tom.

Your next question comes from the line of Jeanine Wai with Barclays. Your line is open.

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

Hi, Jeanine.

Good morning. Our first question, maybe just following up on Nitin's question on cash returns. You updated the return framework such that to be at least 50% now referred to just dividends instead of total payout. Can you talk a little bit about how you landed on the 60% for the 4Q calculation? And given the new buyback program, should we anticipate that, that percentage will stay closer to that 50% range in order to leave room for the buyback?

Well, Jeanine, thank you for that question. We had a lot of debate about our fourth... We had a good fourth quarter. We really looked at our free cash flow. And we did look at a range of options on that free cash flow variable dividend payout. We were really pleased to increase the ordinary dividend because that's something that is a strong marker on our income statement year in, year out that people can count on. We looked at higher payouts, but we looked at that share buyback. And so we wanted a share buyback to be additive to our dividend and not supplant any of it. So that 50% plus is a cash return pledge and then the buyback is in addition to that. So, we thought 60% was a good place to land because that leaves us plenty of room to attack that buyback aggressively. Scott, do you want to follow?

No, I wouldn't end up in the fallback position that because we added the buyback, we're going to go back to just 50%. Tom emphasized—let me emphasize what Tom has said, the plus is still in play. And we will do the same level of debate that we do every time when we sit around the table. Part of what drove the above the 50% this time was the fact that we didn't have the buyback in place in the market time when we could have been buying on some dislocation between our shares and our peers' shares. So that also stepped the scale in terms of the decision-making process to go to the 60%.

Okay, great. Thank you. That's very helpful. Our second question, maybe going back to the 2022 outlook. We always find it really helpful that you provide the quarterly cadence on wells to sales on slide 21. On the oil side, it's expected to be down in Q1 about 10%. And then to get to your full year guide, there needs to be growing oil production on pretty much consistent well sales each quarter, which we thought was interesting. So, you mentioned in the prepared remarks that the oil base decline will be higher earlier in the year and then moderate. Can you just give us a sense of where the oil base decline currently is? And how you think that will improve by year-end?

Yes, of course. We ended '21 with a strong rush of oil production. So that's going to drive our decline. It's, give or take, around 40% as we exit '21. I don't have in front of me what it is in '22. It's going to moderate; it's probably down to about 33%. I just had a note handed to me, so my memory was suddenly refreshed on that. And then going forward, you're going to see a more consistent cadence. We're really in the process of really getting our arms around multiyear plans. So we're looking at '22 and '23 plans, and we have in front of us, although we're not prepared to talk about it publicly. We do have in front of us actual firm plans that carry us through '23. And going forward, we're going to be talking about our program rolling two-year averages. So a lot of the consistency of our field operations will pay off in future consistency. So that decline will moderate by the end of '22.

Thank you very much.

Your next question comes from the line of Holly Stewart with Scotia Howard Wheel. Your line is open.

Good morning, gentlemen. Thank you for taking our question. Maybe first one, still just trying to get a better sense on the pro forma gas. It looks like for 2022 it should be down about 5%. I know you mentioned, Tom, that a lot of the gas volume is just driven by project timing, second half weighted, obviously. So maybe a better representation is kind of an exit-to-exit rate. Do you have that available for us?

No. We don't—yes, we're just not going to talk about action rate at the current time.

Okay. Maybe then moving on to natural gas basis. It felt like everybody was a little bit weaker in the fourth quarter than certainly than expectations. You've laid out your '22 Marcellus exposure kind of by index. Can you give us a sense when you kind of lap in that Permian and Anadarko sort of where those end markets impact? And then if you have sort of some thoughts on the overall basis for 2022 for the entire portfolio, that would be helpful?

Yes. Now our Marcellus program is spread among a number of East Coast basis. I will say that in the Marcellus, we sell about 20% of our volume on gas daily pricing. About 12% is at fixed price. And then about 68% is based on some monthly go-forward index. And so it's always—it's been remarkable to me to watch how much decoupling there has been against a monthly basis in gas daily over the last month or two. And then in the Marcellus, about 12.5% of our gas ultimately goes to the water on LNG contracts. And yes, we can provide some more detail on those bases that Marcellus is. In the Permian, we—it's a little different story. We sell about 87% of our gas on daily pricing and about 13% of our gas on a monthly index. And then Anadarko, it's about 50/50 daily vs monthly. So we like to have that mix of monthly index and daily exposure in our portfolio.

Okay. That's helpful. And maybe one final one for me, Scott, just on the hedging strategy. I know last quarter, you mentioned you'd rather be a little bit front-footed than defensive. You've added some contracts here for 2022. How do you think about the portfolio now from a hedging standpoint?

Yes. Thanks, Holly. We're much like we're telegraphing on the buyback, where we've been leaning in on the hedge front. You saw the announcement of the ones that we have put in place. So far, we've focused on gas. We're—obviously, with oil at $100 here, we're getting indications as we speak while we're sitting around the table. So we're looking at potentially adding that. The overall philosophy for Coterra is to lean on wide collars or collars that make a lot of sense. You'll see a lot of what we’ve added. Recently, we've implemented, kind of, started touching winter next year and expanding, and we'll kind of keep things 12 to 18 months out in front of us, leaning on wide collars with an over—again, we've got a tremendous balance sheet. We've got a tremendous return profile out in front of us. Hedging can underpin some of that, but we don't need a lot of hedging to underpin it. We're very confident in what we can do. At the same time, historically, legacy Cabot was a third to two-thirds. I would say that percentage is probably down, targeting 25% to 50%; 50% would be more of an outlier based on where we're at.

Yes. Okay. That’s great. Thank you, guys.

Your next question comes from the line of Arun Jayaram with JPMorgan. Your line is open.

Good morning, Tom and Scott. My first question is just looking at the 2022 plan in the Permian, Tom, as you mentioned, you're increasing the average development size to just over eight wells per project from, call it, 5.5, and increasing your lateral lengths by a little bit more than 10%. Obviously, overall tightness in the Permian. So I was wondering if you could just provide some thoughts on how Blake and team are managing some of these risks, some of the projects you talked about authentic. And how is these larger projects affecting the shape of your 2022 production profile?

Well, obviously, as these projects come on, there are surges of production. We really do look at annual averages. Quarterly timing is what it is, based on project architecture. But what we focus on is annual averaging. It's all baked in, in terms of what we've announced this morning. We're going to hit that annual average. Now the risks you talk about, I assume our market and operational risks?

Yes.

Yes. I think we're in reasonable shape. I mean, the Permian is really tight right now, and it's been very topical on sand. We—we have great relationships with our vendor network, and we anticipate having any plays. That said, there have been times when frac crews have been waiting on sand, but we don't see that as a huge hurdle. Blake is in the room. I'm going to invite Blake to just comment on this.

Yes. Thanks, Tom. Arun, we're still laser-focused on efficiency like we always are. That's the needle we can move. So wells per pad, lateral length. We also have our e-frac crew coming on mid-year that we're really excited about. We think that's really going to move the lever on cost. And then the market is going to do what it's going to do. So we've been watching it closely. We've fixed the vast majority of our big cost movers for 2022 are locked in. So we know what those prices will be. And it will be up to our operations teams just to continue to execute and innovate as they've done year after year.

Great. Thanks for that. And just my follow-up is—in terms of the Marcellus, you guys are guiding to roughly 80 net wells to sales this year. Tom, you highlighted, call it, five to seven years of lower Marcellus inventory. I was wondering if you could give us thoughts on how many locations do you have in the Lower Marcellus and maybe a sense of that range—is that activity driven or spacing, I'd love to see if you provide a little bit more color on the lower Marcellus inventory.

No, I'd be happy to, Arun. I love talking about the business, and we're making some progress here. First, I'm going to say that our team is amazing. I mean not only operating, but also new, it's just remarkable what they've accomplished. So, I think everybody is benefiting from Coterra equally. And it's been really fun to see learnings go both ways. And you'll remember, Arun, that at Cimarex, we had a bit of a challenge with spacing and completion design and how that interplay and parent-child interference, I mean—all these things are real, and they particularly show up as you get into infill development. I will say, certainly, the Marcellus is facing those same issues, and I think there's some great ideas floating around. We're looking at where we can enlarge our spacing a little bit in the Marcellus. So that's going from 800 feet between wells to 1,000 feet. And with that, we're actually looking at upsizing our completion energy a little bit. And we think that is—it's a complex problem. It's not just spacing; it's parent-child interference and child to child response. But we've got early indications that that's really an effective approach. It won't be the last answer, but it's certainly guiding a lot of our go-forward program. So the difference between the five and seven wells in Lower Marcellus as a direct answer to your question is whether we go to a 1,000-foot spacing or 800-foot spacing. Where we can, we're planning on going to 1,000-foot spacing. Now because of the geometry available to us, that's not something we can do everywhere. But we think it's really going to address some of these issues in the Marcellus as it did in the Permian.

Great. Thanks a lot.

Your next question is from the line of Michael Scialla with Stifel. Your line is open.

Hi. Good morning, everybody. I just want to get your latest thoughts on WAHA baseline gas takeaway from Permian.

Well, Michael, I'll just tee it up. I'm going to let Blake chime in here. It's certainly back on the worry list as production increases in the baseline gas production increases also. A few summers ago, this was a hot topic. And at the time, I said there are three words that gave me solace here, and it's God bless Texas. In Texas, you have the opportunity for markets to adapt swiftly. You can—what happened then? They can service oil and pipelines were repurposed. Some NGL lines went to oil. There were some new pump stations built, and the market reacted swiftly. And so the smart play there was to just trust the market and throttle through it. I think gas is going to be similar to that. We're seeing some really encouraging signs of innovation, stepping up to get us through the bridge between now and when we'll have some new pipelines. But I'm going to let Blake specifically address that.

Yeah. Thanks, Tom. When we look at our Permian portfolio, our entire gas portfolio is covered by firm commitments that give us surety of flow contractual obligations. And like Tom mentioned, we've been through this before that we never shut in a barrel of oil or flared an extra Mcf of gas. So we have great midstream partners, and we rely on them. So we do within our portfolio, we have deals at Houston ship, and we have deals at Waha. We have opportunities on the table right now to increase our Gulf Coast exposure. If we decide that's a good long-term decision, we'll pursue it. We're also in constant contact with our downstream partners, and there's a lot of really good greenfield and brownfield projects that are floating around. And we think those will absolutely come to fruition if the supply curve materializes. So we're going to stay engaged on it. We also, of course, always have basis hedging if we need to protect from price. So got lots of levers we can pull on this one.

Thanks for the color. Just looking at the Anadarko Basin, it looks like the next two projects there in that down dip in 13 8 areas. Can you say what, if anything, you're going to do differently there than what you did when you developed those areas previously? And any learnings from Carol Elder that are transferable to those areas that you're going back to?

Mike, a remarkable thing is we drilled some wells out there five or six years ago that have performed really well over time. And so when we look at those wells and uplift them to 10,000 feet, if we change nothing other than use that information, the returns on these Anadarko projects are stellar. But we're also looking at some new completion designs and using what we've learned on completion. And then there are some new offset wells in that deeper part of the basin that are just remarkable. And one of the things that makes them so remarkable isn't just the absolute gas rates, but you also get a pretty good NGL stream index. It's a rich gas. So you have a turbocharge to your revenue. So we're—this is not an uncalibrated project. And there are a couple of other operators out there that include as well, much to our dismay, because we did a pretty good job of consolidating our position. So we have a good inventory of opportunities where we can exploit this with two-mile laterals. The Carol Elder was a good project. We learned a lot there. But Lone Rock is a different beast. It's a little different pressure sync within the basin. So some of the lessons of Lone Rock are more applicable to Lone Rock in the basin real large, but we're pretty excited about the opportunities. And we love to the question about market constraints, having that Anadarko is a tremendous relief fall for our program. We're glad to have it.

Sounds great. Thank you.

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

Good morning, all. Maybe just a quick first one for Scott. Scott, you talked a lot about the shareholder return, but I'm just curious on the buybacks. I don't know if you all said this, but just are there optimal drivers or requirements you all look at the buyback? I mean, you talked about given how high your free cash flow yield is, but I'm just wondering when you consider starting repurchases. A lot of guys say, well, we just buy back shares opportunistically. Others use that mid-cycle valuation. I'm just wondering—I know last time you I met up, I know you looked at a lot of things. I'm wondering how you all sort of think about this.

One of the things we did in the discussion with the Board, we look back, as we said in our prepared remarks, kind of, our relative valuation and also our intrinsic valuation, and surprise, surprise, we're undervalued on both of those accounts and particularly when you look from Coterra's underlying performance from October 1 to date, no one around this table is happy with that. Unlike legacy Cabot, who did buybacks before pretty much 100% opportunistically, we're going to be, as I said in my answer to the first question, we're going to lean in and be more focused on dollar cost averaging and be more consistent over the course of our periods when we can buy. We're subject to the same blackouts that our individual people are subject to. So the first two months of this year, even if we had had an authorization, we've been blacked out because of the knowledge of the financial statements. So you got a window in March, a couple—then you get a couple of months each quarter after that. So we'll be leaning in, creating a formulaic approach for a base buyback and still having the opportunistic when we see disconnects in the market on things that just are misinterpreted or misrepresented, or however it takes place to step on a scale when we do that. But we are very focused on making a lot of progress on this immediately.

Good to hear. And then just a follow-up, maybe more just on the maintenance capital. I'm just wondering, do you have an estimate of maintenance capital, I guess we're ongoing with this, kind of, been asked around. But when you look at the—I guess my question would be around maintenance capital or how you think about your natural gas baseline decline, just given how the Cabot and Tom, new wells a bit on the gas side was a little bit surprised on to see even any gas decline this year. So I'm just wondering maybe if you could address that from a couple, just how we should think about that maybe as far as that capital allocation, anything around that?

Yeah, Neal, again, we just reported the first quarter as Coterra and we're kind of in our—starting our first full year, our first full year guidance. My expectation is that the maintenance CapEx number would be less than what we're looking at this year. But I would echo around the gas question that you talked about. Let's understand that—and this was something that we—not struggled, but we had to manage around as legacy Cabot. Just as what Tom said before, the cadence when you—the high capital efficiency and the high productivity of those wells only requires you to run two rigs, maybe 2.5 rigs and less than two completion crews. And so you don't have a whole inventory of wells to roll on. So depending on the cadence of the pad, one of the things we looked at our—right now this morning—right now is a moment in the year when we have—we just added a third rig in the Marcellus. But two of those three rigs are on eight-well pads and 10-well pads. And so when you do the lead time on that, you're looking way late in the year before you're going to see the impact of that investment today. And so while a maintenance—when we get more in a cadence across all three basins, I think maintenance will definitely come down from where it is right now. And at the same time, the question is, is maintenance the way to manage this company in terms of a question that was asked of Tom earlier in terms of where the market is? We're going to run it judiciously like we are. We're going to move capital where it makes the most sense. We moved more capital in 2022 to the oil province because the margins are just stellar and there's margin expansion more than in the gas market even with the good gas prices right now. So long-winded answer, I apologize for that, but try to give you a little more color.

I love the detail. I love the large-scale development. Thank you.

Your next question is from the line of David Deckelbaum with Cowen. Your line is open.

Good morning, Thomas, Scott. Thanks for the time today.

Good morning, David.

I was hoping—I was hoping to dig in a little bit around the larger development. Just my first question is, Tom, you talked about a lot of these development sizes; it seems like were decisions that were made pre-merger that was already going into 2022. You talked about planning for 2023, and it sounds like development sizes are increasing 2022 into 2023. Is that—was that informed more by rising service costs and pricing and logistics, or was it informed more by geology?

Well, I'm not sure I'd say either one. As we get more confident about our development scheme, it just begs for larger projects. You can take advantage of a tremendous amount of efficiencies there—efficiencies of operations, rig efficiencies, completion efficiencies. We've got our completion crews, as you know, we've got a really great partner in our completion vendor. And we've got some of the highest productivity in the basin in their fleet. And so we've got a really well-oiled machine going here, and that part of that is the larger project size. When you parsed out the smaller project size, and you're moving, you're demoving—you're moving, and there's just a lot of opportunity for things to interrupt. So we do have a natural bias to larger project sizes in the Marcellus, Permian, and Anadarko. And that's one of the reasons we're so excited about the Upper Marcellus. As Scott mentioned, we've got a nine-well pad flowing back. Seven of those wells are in the Upper Marcellus, or I say flowing back, about to come online. And this is the direct—I think this is the direction of our industry. If you have the assets, it really steers you to larger project sizes.

And I guess my follow-up, and you articulated this as well, is that certainly in the Marcellus and maybe to another extent in the Permian as well, we should expect to just see a greater percentage of co-development of sort of full zones over time?

Yes. It depends on the rocks. If you have frac barriers, you have the luxury of developing zone by zone and then coming back. And that's—we're going to need more time for that subject. We've recently acquired a lot of science that we've learned a lot about vertical communication within that stratigraphic section and a lot that we've learned is surprising. And it's informing how we're going to develop it. But whether it's the Marcellus or the Permian or the Anadarko, at the end of the day, it comes down to the rocks and the resource in place. And we just have some of the best rocks there in our business.

Appreciate the answers. Thanks, Tom.

Your next question comes from the line of David Heikkinen with Pickering Energy Partners.

Good morning. Thanks for taking the question. Sounds like on your innovative solutions out of WAHA, things like the Whistler expansion from 2 to 2.5 Bs a day. So really seeing some increments in places that you can get some more gas out of the basin. Is that kind of an accurate when you said innovative solutions?

Yes, that's certainly—we've got two or three different avenues that open to us. But yes, there are additional volumes we might be able to.

Perfect. And then it also sounds like—I know as you were looking at the Cabot assets that you did a lot of studying of the Upper Marcellus and you're really bringing some of the Cimarex thoughts to the program with the up spacing and larger fracs. So it's really like maybe a benefit of the integration of both companies. Is that accurate as well?

Yes, I really want to brag on that team in Pittsburgh. They are innovative, they're great at the business. And it's just remarkable what they've accomplished. So, I think everybody is benefiting from Coterra equally.

Okay. And then when you think about that mix of Upper Marcellus, is the shorter lateral length a representation of more Upper Marcellus, or I was curious as you think about the next several years where that mix goes as you go to 1,000-foot spacing and kind of the lateral lengths?

Well, David, you said shorter lateral length. I mean, the shorter lateral length is going to be a function of our remaining Lower Marcellus. Once we go to the Upper Marcellus, we're more or less wide open. And that's one of the many reasons to be really excited about the Upper Marcellus.

So really, you stretch back out. So, this one year downtick from 7,500 to 7,200 is kind of the—as you get more upper, we're just trying to weigh things out. That makes sense, I guess.

Yes. No, that is completely a function of—we're in a process now; the five to seven years of Lower Marcellus inventory is excellent, but it's not wide open. We're going back and infilling gaps, and one of the constraints there is lateral length.

I had that wrong in my head. That actually makes more sense. And I just had it wrong. Thanks guys.

Due to time constraints, your last question comes from the line of Leo Mariani with KeyBanc Capital Markets. Your line is open.

Hey guys. I was hoping you could talk a bit about the synergy progress in 2022. Have you started to see some of those G&A synergies at this point in time? And I guess should we just expect to see maybe the G&A per BOE just kind of drop throughout the year? And any indication on kind of what the severance payments are roughly in 2022, but obviously, you described would go away by the time we get to 2023.

We're seeing progress. We made tremendous progress. One of the best things we did was hire an independent consulting firm to come in and help with us. We have dedicated an employee to the value capture around synergies, not just from a G&A perspective, but have identified, as Tom has talked a lot about, the thinking between the new ideas—the cross-pollination of ideas between all the teams. And so there's dollars that far exceed what the anticipated G&A savings were that we laid out kind of when we didn't know a lot; we were trying to have a guess. We're going to hit the $100 million in G&A savings. But like we said, I think that the big carrot around where we were, we were very clear in the press release to say, give us 18 to 24 months to do that because of some legacy severance programs that are fairly robust in terms of timing and trying to get new people in, legacy people out that aren't willing to move. And so at the end of the day, we're hoping to accelerate that up to the kind of the 15-month time period at the end of this year. The severance is probably—we're probably 40% of what ultimately it will be. I don't know the cadence through the rest of this year, and maybe some does bleed into '23. But our goal is to have that overhead expense function rock solid for '23, as rock solid as it can be.

Okay. That's really good color at the end of the day. And then just in terms of Upper Marcellus, I know you mentioned kind of 7 wells on a 9 well pad, but roughly speaking, do you have the number of wells here you're going to prosecute in '22? I think it's 80-something Marcellus well. Just wanted to get a sense of it, is it half of those or Marcellus? Can you tell us about the split?

No, it's a handful. I don't have the number in front of me, but we're still primarily focusing on the Lower Marcellus. And as we go, what we're doing is we're very carefully delineating this project; we're flowing back here shortly is important to us. But we really do want to—we've got plenty to do in Lower Marcellus. We'll throw in a project or two along the way in the Upper Marcellus to just gain understanding. But one, because of our overall system constraints, we're mostly focused on the Lower Marcellus.

Okay. Thanks guys.

At this time, I would like to turn the call back over to Mr. Tom Jorden.

Thank you. And I want to thank everybody for a good set of questions. Just in closing, I want to say we were very pleased to announce our ordinary variable dividend. Very pleased to be embarking on our share buyback. And if you heard anything on this call, I hope you heard that that 50-plus commitment of cash return is not competing with the buyback. It's additive to it. And we really do look forward to continuing to be one of the leading companies in our sector on yield to our owners. So looking forward to a great '22 and great '23. We are hard at work here. So thank you very much, and appreciate you joining us.

Ladies and gentlemen, thank you for your participation. This concludes today's conference call. You may now disconnect.