Thank you for standing by. My name is Cheryl, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy Q2 2022 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star one. Thank you. Dan Guffey, Vice President of Finance, Planning and Analysis, and Investor Relations, you may begin your conference. Thank you, Cheryl, and good morning, and thank you for joining Coterra Energy's Q2 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 Raymer. 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. Thank you, Dan, and thank all of you who are joining us today for our Q2 2022 recap. As you read from our earnings release, we had an excellent Q2. If I were asked to write the news headline describing our release, it would be, "Coterra hits its stride." With these quarterly results, which are our third since forming Coterra, we have affirmed our commitment to capital discipline, prudent capital allocation, and returning free cash to our owners. We beat on all three product streams, oil, gas, and natural gas liquids. This was a result of outstanding organizational execution during the quarter, as well as having some great rock. I want to give a big shout-out to our organization, particularly our field staff, who worked relentlessly during the quarter and brought wells online ahead of their planned first production date. Our solid execution was turbocharged by excellent reservoir performance. We continue to see positive results from our spacing configurations, landing zone selections, and completion designs. You will also note that we increased our capital guidance for the year. This was a combination of two factors, inflation and a modest increase in activity. I will discuss these individually. Inflation continues to be a headwind. This includes cost increases for rigs and frac fleets as our term commitments expire, and we move to prevailing rates. Prices for diesel fuel, steel, and sand continued to climb during the quarter. It is hard to point to any significant item that has not seen some level of price increase. We are adding a modest amount of incremental activity in the H2 of 2022. This includes keeping a third rig running in the Marcellus, where our prior plans called for us to drop back to two rigs. In the final analysis, we decided against releasing a high-performing drilling rig in an environment where we had doubts that we could have replaced it with one of comparable quality and performance. This decision will provide operational momentum and increase optionality as we enter 2023. We are achieving outstanding economic returns from our capital investments in each of our three basins. One measure of the quality of returns is project payout time. It has been many years since payout was a meaningful descriptor of our program. Our industry has been fooled many times by a strip price file that has ultimately been a mirage, and which has at times resulted in returns that are lower than pre-drill models. In an environment where we are cautious about future commodity prices and possible global recession, short payout times add a safety backstop to a capital program. In 2022, our Permian and Marcellus drilling projects are achieving full project payout in a range between two and six months. Looking ahead into 2023, Coterra is well-positioned for success. Although we are not prepared to discuss specific plans for 2023, we are positioned to deliver on all of our commitments. Significant free cash flow generation, the return of at least 30% of cash flow from operations in the form of dividends, supplemental share repurchases and debt reduction, and an investment program that generates mid-single-digit growth. In Coterra fashion, we intend to under promise and overdeliver. We are also pleased to report that we have not relaxed on our mission to significantly reduce our emissions footprint. We are on track to hit our greenhouse gas intensity goals, methane intensity goals, and flaring reduction. As of fall of 2021, we have eliminated all routine flaring. We also continue to make great progress on our multi-year electrification goals. Fully two-thirds of our Permian wells drilled in 2022 will be drilled by rigs running directly on grid power. We took delivery of a fully electric frac fleet during the Q2, which we are powering directly off our electrical distribution grid. We have begun to pivot to electric compression within our Permian midstream assets and are seeing excellent operational performance. These initiatives are smart, timely, and result in significant efficiencies and fuel savings. Hats off to our operational staff and vendor partners for championing these creative and impactful technologies. Finally, on the macro front, we have not lost sight of the fact that we are in the midst of a growing global energy crisis. Long-term under-investment in our sector, combined with the rebound in demand, has created a shortage of oil and natural gas, and the impacts of which have ricocheted around the world. The war in Europe and growing inflation has exacerbated the problem and impacted those who can least afford it. Thus far, the response from our policymakers in Washington has been underwhelming. Although we are encouraged by some elements of the recently announced Inflation Reduction Act, we are cautiously studying its many provisions. Our industry and our nation have the capacity to produce clean, reliable, affordable energy that provides energy security to the free world. We not only have the ability to accelerate delivery of LNG to the world, we have the responsibility to do so. We need strong leadership in energy policy. We need more pipeline infrastructure, and we need it now. Many of these projects will take years from design to completion, which means that we should get started today. Unleash us and watch what we can do. With that, I will turn the call over to Scott, who will walk us through a more detailed rundown of our Q2 results. Thanks, Tom. Today, I will briefly touch on Q2 results, shareholder returns, and then finish with updates. During the Q2, 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 Q2 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. Q2 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 Q2 performance was driven by a combination of operational efficiencies, which accelerated cycle times, positive well productivity, and an increase in non-operated production. Q2 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 in ethane recovery in the Permian Basin, whereas we have been 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% 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 Q1. During the Q2, the company had 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. The company's combined net debt to trailing twelve months EBITDA leverage ratio at quarter end was 0.4 times. 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 Q2 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 Q1 and our $0.60 per share dividend paid in the Q2. Our total cash dividends for the quarter is equal to 50% of free cash flow. Third, during the Q2, 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 Q3, the company had a 10b5-1 plan in place, and we will provide details of its Q3 share repurchase activity with next quarter's update. In addition, we announced the conversion of $38 million of preferred stock and the 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%+ 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 a 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 2022 production guidance. Our annual guidance at the midpoint for BOE is up 1% to 615-635. Natural gas is up 1% to 2.75-2.83 Bcf per day. Oil is up 4% to 85.5-87.5 MBO per day. We have no change to our 2022 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 high end of our previous range to $1.6 billion-$1.7 billion. The increase is driven by incremental inflation and a modest uptick to H2 2022 activity. We now expect 2022 inflation to drive capital up 20%-25% year over year, up from the estimate of 15%-20% back in May. While we have the majority of our big ticket items locked in for the H2 of 2022, the majority of our 2023 program remains subject to market rates. Based on preliminary estimates, we expect inflation to increase dollars per foot an incremental 10% in 2023. On the activity increase, Tom already noted the third rig in the Marcellus in the H2 of 2022. Additionally, we are increasing our facilities capital to minimize execution risk and the impact of tight 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 than income guidance, and lowering our expectations for the deferred tax ratio. With operational efficiencies pulling volumes forward into the Q2, we now expect production volumes for the H2 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. To ask a question, please press star one. Please limit yourself to one question and one follow-up. Your first question is from Jeanine Wai of Barclays. Please go ahead. Your line is open. Hi. Good morning, everyone. Thanks for taking our questions. Morning, Jeanine. Good morning. Our first question is on cash returns. You returned a very impressive 80% of free cash flow this quarter, 69% last quarter. We know the official framework calls for 50% or more payout with the base plus variable dividends, and then you have the buybacks as a sweetener. You already have a strong balance sheet, you don't have much debt coming due. Our question is, if prices remain around where they are currently, is that 70%-80% range a good ballpark going forward? Jeanine, this is Scott Schroeder. Again, our framework is the 50%+. If you listen to the comments we made and how we're leaning in and our goal of, you know, getting most of the buyback done, I think it's a safe assumption that we will be higher than the 50%. At the end of the day, our main commitment is the 50%+. Okay. Understood. Thank you. Our second question is on inflation, topic du jour these days. Some folks are a little surprised that the Marcellus is seeing as much inflation as it has been. Can you discuss the dynamics between the relative inflation, between the Marcellus and the Permian and any implications for 2022 or 2023? Your prepared remarks in slide 8, they were really helpful, and we're just looking for maybe any additional commentary. Thank you. Hey, Jeanine, this is Blake. I'll take that one. You know, when we look at inflation across the basins, it's really kind of amazing how close they track. We, you know, casing's casing, we feel that everywhere. Even with rigs and crews, they're in hot demand all over the US, and so the service providers have pressure to bring those to whatever basin they can get the best pricing in. It's been interesting to watch those costs really track closely. What's differentiating the Permian this year is one, just some more operational efficiencies, specifically the three-mile lateral projects in the e-frac is offsetting some of the inflation. But also in the Marcellus, just with contract timing, the Marcellus contracts rolled off earlier in the year, so we went to new contracts at higher rates. It kinda took their lumps earlier in the year, whereas in the Permian, that'll be a little later. As far as inflation going forward, you know, I think we've built in everything that we know today, and so that's what we're guiding to. Great. Thank you. Can we go to the next question, operator? Your next question is from Matt Portillo of Tudor, Pickering, Holt & Co. Please go ahead. Your line is open. Good morning, all. Hey, Matt. Just a quick one, I guess two on the operational front. I know that part of the production uplift in Q2 was related to the timing of the wells, but it's been a couple of quarters now where we're seeing positive performance that looks to be driven by some of the changes you've made to the spacing design in the Permian. Tom, maybe just a question around what you've learned so far and maybe any learnings that you're seeing in terms of the outperformance on well results as you move forward there. 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 of our Permian asset by drilling fewer wells. We're seeing a significant increase in capital efficiency. As we widened our spacing in some areas, we've increased our completion intensity. What we're finding is that as we compare our projects to some offsets, we're tracking right online with recovery per drilling spacing unit with a lower capital investment. You know, 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. As I said in my prepared remarks, all that and great rocks, and you have a formula for success. We're very pleased with the changes we've made over the last couple of years. Great. Maybe shifting a bit towards the Marcellus. I know part of the strategic combination was the diversification of the commodity between gas and some of the Permian assets, but also seems like there's quite a bit of potential to unlock value in the Upper Marcellus. I know you have seven wells or so online and more to come in the back half of the year. Just curious if you could give us any insight into what you've learned so far on the Upper Marcellus and how that might continue to extend the fairway on the development program for that asset moving forward. 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 erase what you've known that doesn't apply and apply what you've known that directly applies. We're doing some science right now in the Marcellus. We've got a fiber optic project with some down-hole pressure sensors, kind of exploring the fracture efficacy of our completions. We're very encouraged by what we're seeing in the Upper Marcellus, and we look forward to bringing those results to the fore as soon as we get a little more production behind us. You know, we wanna be conservative and watch these multi-pad developments before we, you know, start high fiving ourselves. You know, the Upper Marcellus is wide open territory. We're very encouraged and look forward to discussing it in the future. Thanks so much. Your next question is from Arun Jayaram of JP Morgan. Please go ahead. Your line is open. Good morning, Tom. How are you? Doing well, Arun. How you doing? I hope Houston is treating you well, my hometown. Couple questions regarding, you know, your initial thoughts on 2023. Really appreciate those. You mentioned, maybe Scott mentioned how, you know, preliminarily maybe $ per foot up about 10%, and you could deliver mid-single digits growth kind of preliminarily. I wanted to get your sense on kind of footage. You guys give 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? Yeah. Well, Arun, we're not prepared to give that specific guidance into 2023. We've got a lot of what-if-ing going on right now. We really haven't crystallized final plans. I'll just leave it at that. I hope that answer doesn't surprise you. No, no. It's just that you gave a lot of great detail, so I was trying to lead the witness. You know, just maybe my follow-up. You know, we continue to be intrigued by your delineation activity in the Harkey Shale. 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. Can you maybe put this zone into context, Tom? What could this do for your inventory? Maybe, you know, characterize what you're seeing in terms of some of the early results. We've talked in the past when we first discussed the Harkey last quarter that we think it adds about five years of top tier to our inventory. Harkey is terrific. We're seeing outstanding results from it. It's just a very prolific member of a very prolific hydrocarbon section. You know, as you work the Delaware Basin, it's been described to me as a very forgiving basin, but it's also just wonderful in terms of a target-rich environment. Harkey stands shoulder to shoulder with the best of our landing zones, and we think we've got a lot to do in the upcoming years. Great. Thanks a lot, Tom. Your next question is from Neal Dingmann of Truist Securities. Please go ahead. Your line is open. Morning, guys. Thanks for the time. Tom, my first question is just wondering a little bit on a broader scale overall free cash flow strategy. I'm just wondering. Do you all believe that the maximum shareholder returns will remain your most prudent use of free cash flow? Or, you know, maybe down the line, I'm thinking more next year or so, is there a chance you would entertain potentially more growth, often like you did at Cimarex? Well, I'll tee it up and let Scott bring it home on this. You know, one of the things I've said is, flexibility is the coin of the realm. 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 an embarrassment of riches on options. We also live in a very uncertain world, and that flexibility is gonna 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. You know, I was thinking last night of Mike Tyson's famous quote that everybody has a plan till you get hit in the face. We haven't had our last hit in the face in this industry. Scott? Yeah. That's interesting. Neal Dingmann, I think that Tom Jorden hit it well, but the other thing I would add to what he said is in terms of the flexibility we have, we've got to maintain that flexibility. We've got a phenomenal balance sheet. We kind of leaned in in our comments in here, you know, the mid-single digits. We're kind of all. There's a little bit of a lean in towards your question already. At the same time, the other dynamic that's happening because Tom Jorden's reference to Greater Rockies, we're able to invest less and less money to get better outcomes than we have historically. I think where you end up is you're gonna have the ability, unless, you know, quite honestly, if it goes to $42, that's a different dynamic. You're gonna have the ability to deliver both and continue to manage through this. Can't argue with Tyson, Tom. My second question, again, is on shareholder return allocation or maybe dividend versus buybacks. I'm just wondering, specifically, you all had mentioned or have mentioned opportunistic buybacks, and I'm just trying to get a sense of, you know, periods such as in, you know, late June, early to late June when your shares, like others, you know, fell maybe around 30%. Does that qualify as such an opportunity? If you saw the cadence of the slide that we put in front of our board of directors, the answer to that question is yes. Great. I thought you were gonna say that, Scott. Thanks so much. Your next question is from Michael Scialla of Stifel. Please go ahead. Your line is open. Yeah. Good morning, everybody. Tom, you said you were encouraged by some aspects of the Inflation Reduction Act. You also mentioned you're on target to hit methane emission goals. If that bill becomes law, would you anticipate any impact on Coterra from the methane fee? I guess, what can you say about the other aspects of the bill that have you encouraged? Well, we're still studying it, Mike, and you know, I know there's been some really good commentary. There's some good commentary this morning in The Wall Street Journal. 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. You know, it calls for us to conform to EPA requirements that aren't yet published, and it calls for us to conform in a timeline that looks like it will predate the effect of new EPA regulations. So that's a bit baffling as to how we're gonna comply with that. There's also a provision in there for a methane intensity to be measured by direct measurement. You know, 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. You know, how that one 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. You know, 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. I'll finish with the addressing of infrastructure in the bill. I think it's, you know, credit to Senator Manchin that there's a pretty strong statement on infrastructure. There are some confusing elements to that, and we wait to see how that bill survives, you know, final passage. You know, I know that's a wandering answer. We're studying it carefully. You know, I'll say this, there's no substitute for sound energy leadership. We really need an energy policy that is coherent, focused, and resolute. 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, you know, we'll see. The ball is still in the air on that one. Yeah, for sure. You also mentioned, you know, the market and about, you know, potential for recession. The market does seem to be baking in a fairly high probability of a recession. At least the equities seem to reflect that and have kind of become disconnected from the commodity prices, and I think that's caused a lot of E&P companies to start buying back shares. I guess, as you look at the risk to the global economy, how does that affect your hedging policy going forward? As you look at the cash balance heading into next year, does it have any impact on what you think the appropriate cash balance is? Yeah, Michael, this is Scott Schroeder. Again, we're continuing our hedging discussions internally. As Coterra was formed, obviously the big dynamic was the balance sheet that we have. We don't have to lean in heavily on hedging. We do like to have some of our cash flows covered in the event of, you know, some disconnects. 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'll 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. It's prudent to add some protection to the overall profile. Very good. Thanks, Scott. Thanks, Tom. Your next question is from Doug Leggate of Bank of America. Please go ahead. Your line is open. Thank you, everyone. Good morning, Tom, thanks for getting me on. 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, you want to take that one? Again, Doug, and I don't have the page number on here, but it's page seven in the deck. You know, free cash flow breakeven is, you know, still at $40 in 2025. 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. I guess I'll take it offline with Don and see if we can get a number. I'm guessing it's risked higher at this point with full cash tax and well, maybe the way to ask it, Scott, is what are you assuming for cash taxes in that $40? It'd be 15%-25% deferred taxes. So you're a cash taxpayer between 75% and 85%. Got it. Okay. Thank Thank you. To your question there, it is going to trend higher. Not just for you, I might add, but for the whole sector. Thanks, Scott. I guess my second question, Tom, is on relative capital allocation. I guess, you know, you've talked often about Marcellus and inventory depth, but with gas where it is today, how do you think about where you put capital? Because you've got a lot of gas-weighted options in your portfolio. How does that play into your thinking for over the next maybe 6-12 months or even longer? 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. You know, I really, as I've said over and over, really look at capital allocation in terms of return on invested capital. The Marcellus is absolutely second to none. I mean, it's really an outstanding economic fairway. You know, we do have the opportunity to grow a little bit in the Marcellus. You know, I said in my opening remarks, we do need some additional pipelines. From a capital allocation standpoint, based on returns, the Marcellus and the Permian are neck and neck. You know, we've done some interesting analysis on how that changes with differing oil and gas price swings. You know, at current multiple of gas to oil, it, you know, with a blindfold on, you could really pick out a basin and really find very comfortable returns. You know, we like the revenue balance, we like the geographical balance, and we like our capital allocation as it currently stands. Appreciate the answers, Tom. Thank you. Okay. Your next question is from Paul Cheng of Scotiabank. Please go ahead. Your line is open. Thank you. Good morning, guys. Tom, can we talk about Anadarko? What's that asset in the long, long term, the role in your portfolio? You are not doing much over there. What exactly is the game plan? That's the first question. Yeah, well, you know, we've talked at length about the Anadarko and the fact that, you know, it's kind of in a rebuilding phase. We've got a couple projects coming online this year, one of which is flowing back now. We're too early in that to really be definitive, but I will tell you that we're very encouraged. The Anadarko has an excellent inventory. Quite frankly, we've been in the Anadarko a long time and we're pretty good at it. So, I'm very pleased with what we see. I think over time, an owner of Coterra is going to benefit quite nicely from having that asset in our portfolio. Right. The second one hopefully is pretty short. Looking at your production guidance for natural gas in the Q3, yeah, that three is sequentially down, but you're going to have more wells online than the Q2, I assume. Is there anything that is driving the lower sequential production? Is it the timing of the well coming on stream or other reasons that we should be aware? Thank you. No, it's all a timing issue. When you bring a well on in the H2 of the year, you're typically in a range depending on timing, where you have little impact on that calendar year. It's, you know, it's just purely a timing issue. Now, one thing, you know, we've talked in the past is because we starved the Marcellus a little bit for activity. We're doing a little catch up in the Marcellus, so we look forward to seeing some growth out of the Marcellus, and that will be reflected primarily in 2023 and even 2024 as we currently model it. It's all timing. Thank you. Your next question is from Leo Mariani of MKM Partners. Please go ahead. Your line is open. Hey, guys. Wanted to just follow up on a few of the prepared comments here. So you just talked about, you know, growing the Marcellus maybe a little bit here in 2023, in 2024. You're kind of citing timing, but I'm assuming that there may be, you know, some macro factors at play as well. Obviously, you guys let the Marcellus production decline, you know, for, you know, the better part of the last handful of quarters. Is there just some thinking that just gas macro over the next couple years looks a lot better? I know there was an original goal to get a more balanced mix, but maybe just any comments around gas macro and some of that kind of presumably modest production growth you're expecting. We're very constructive on gas. I think most watchers are, you know, with growing LNG exports, storage where it is, increased power demand from 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, you know, we're quite bullish on natural gas. Marcellus is a great asset. It's in a great part of the world. To answer your question is, you know, 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. Okay. I guess just to follow up on that, are there any concerns on takeaway over the next couple years? I think there's a handful of producers that have talked about maybe trying to do a little bit more up in Appalachia. Just wondering if you think at some point there's a pinch point there with some wider dips in 2023 or 2024. Well, yes. I mean, there's always concerns about takeaway. We certainly couldn't support unbridled growth out of the industry. The region has a greater potential to deliver gas than the market currently has capacity to take away, which is why we say we need some new pipelines. Now, as we look at it currently, we could grow a little, you know, depending on what our peers do. You know, production in the six county area that's near our Susquehanna County, it's kind of a sub-region of the Marcellus, is down a fair amount. We do have some capacity to grow. But, you know, we want to be very mindful of that. We don't want to cause activity that would lead to basis blowout. But, you know, we're not currently hidebound. I would say over the long term, your question is well taken. We need some additional takeaway capacity out of the basin to deliver what our industry has the capacity to. Okay. That's helpful. Just any comments on the integration of Cimarex and Cabot in terms of, you know, where you stand, you know, in that process and maybe we can expect going forward? Well, I think it's going very well. I'll let Scott comment on that also. You know, probably the laggard is integration of financial accounting systems, which is the right order to do things because of the, you know, critical nature of that and the concerns over, not dropping the ball on anything as we integrate our financials. I would say organizationally, integration is going extremely well. You know, I'm having a lot of fun. Scott, you want to comment on that. Sure. Yeah. The one thing I'd add, Leo, is, again, we're still on track to try to get all the integration done and the new people hired, the old people out by the end of the year so that 2023 is truly a clean bill of health for the Coterra Energy going forward. That would be the only thing I would add. Okay. Thanks, guys. Your next question is from Noel Parks of Tuohy Brothers. Please go ahead. Your line is open. Hi. Good morning. Morning. Just had a couple questions. Wanted to ask, you know, we've heard a couple other Appalachian producers express a bit of cautious optimism about additional LNG export capacity on the East Coast. Just wondered if you had any thoughts on that. If so, you know, maybe what were the underpinnings of that? Yeah. Noel, this is Blake. I'll take that one. I mean, as you can imagine, we're talking to everybody and anybody who's involved in that space, and there is some interesting projects out there, and they just make a lot of sense. I mean, you got the premier gas basin in North America on the East Coast with a straight shot to Europe. We have an existing LNG deal at Cove Point that we safely move 350 million a day through every day, and we need more of that. We're talking to all those parties. You know, we're trying to help find a way to advance the ball on that and get some more deals like that done. Is there any particular, you know, part of the ecosystem, whether it's, you know, public opinion or financing, lending environment that you think might budge first to sort of help make that a reality? Well, I'll just echo what Tom said. It's about pipelines and infrastructure. You know, the industry needs certainty that those things can get built so that the investments can be made. There's a long list of builds that have not happened. That's very front and center in everyone's mind. I think some help there would really go a long ways towards making those projects happen. Got it. Just my second one. Just curious, as you know, given the cost environment and as the year moves along, you start thinking about 2023. I'm just curious what components you think maybe you have better visibility into where they might be headed and which ones maybe it's more challenging. I'm thinking about, you know, materials versus services versus labor. Just to, you know, where do you think there's better clarity and what's gonna be sort of harder to pin down until the last minute? Yeah. Noah, this is Blake. I'll take that one too. You know, really when we look at our service costs right now, the thing first and foremost that we focus on is execution. It's paramount that we have premium rigs and crews in order to safely execute our capital program. If that requires longer term contracts, then that's what we'll do. It's not lost on us that each new contract we sign is at an all-time high when we look at our historical costs. That just leads us to take a measured approach. We've taken a bite of 2023. We've extended some contracts into 2023, but most of it we have not. We'll just be watching it closely and discussing it more as we go through the year. Okay, good enough. Thanks. There are no further questions at this time. I will now turn the call over to Tom Jorden for closing remarks. Well, thanks everyone for joining us this morning. We are pleased to have discussed our quarter. It was a great quarter. Hopefully, we've been able to reaffirm our commitment to our capital discipline, return of cash to our owners and outstanding assets. We really do look forward to continuing to perform and updating you as quarters go on. You know, as I'll finish where I started, Coterra's hit its stride. Thanks everybody. This concludes today's conference call. Thank you for your participation. You may now disconnect.