Thank you for joining us. My name is Cheryl, and I will be your conference operator today. I want to welcome everyone to the Coterra Energy Second Quarter 2022 Earnings Conference Call. All lines have been muted to reduce background noise. After the speakers' remarks, there will be a question-and-answer session. Dan Guffey, Vice President of Finance, Planning and Analysis and Investor Relations, you may start your conference.

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.

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 second quarter. 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 second half 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 through 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 over deliver. 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 multiyear 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 second quarter, 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. And 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 underinvestment in our sector, combined with the rebound in demand, has created a shortage of oil and natural gas, 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 support 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 and 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 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 in ethane recovery in the Permian Basin, whereas we had 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. The 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 are 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 dividends 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 to 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.

Your first question is from Jeanine Wai of Barclays.

My first question is on cash returns. You returned an 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, and 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, this is Scott Schroeder. Again, our framework is the 50-plus percent. If you listen to the comments we made and how we're leading in and our goal of getting most of the buyback done, I think it's a safe assumption that we will be higher than the 50%. But at the end of the day, our main commitment is the 50-plus percent.

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.

Hey, Jeanine. This is Blake. I'll take that one. When we assess inflation across the regions, it's quite remarkable how closely they align in terms of casing; we see that trend everywhere. Additionally, rigs and crews are in high demand across the U.S., putting pressure on service providers to allocate them where they can secure the best pricing. It's been interesting to observe these costs closely follow each other. What's setting the Permian apart this year includes improved operational efficiencies, particularly with the three-mile lateral projects and eFracs, which are helping to mitigate some of the inflation. In the Marcellus, there have been changes in contract timing, as the contracts rolled off earlier in the year, leading to new agreements at higher rates. Consequently, the Marcellus faced its challenges early, while the Permian will experience this impact later. Regarding inflation moving forward, I believe we've accounted for all the information available to us today, and that's what we are basing our guidance on.

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

Just a quick one, I guess two on the operational front. I know that part of the production outlook in Q2 was related to the timing of the TILs, but 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. And 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 the well results as we move forward there?

We've observed that we can achieve similar levels of oil recovery in much of our Permian asset by drilling fewer wells. This has led to a notable improvement in capital efficiency as we've increased the spacing between wells and, in certain areas, enhanced our completion energy. When we evaluate our projects against nearby operations, we find that our recovery rates per drilling spacing unit are on track, but with a reduced capital expenditure. We are also continuing to investigate landing zones. Our extensive research over the years has revealed promising recovery rates from our section of rock. As I mentioned earlier, with high-quality rocks and a solid strategy, we have a successful formula. We are very satisfied with the adjustments we've made over the past couple of years.

Great. And then maybe shifting a bit to the Marcellus, I know part of the strategic combination with 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 can 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 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.

Your next question is from Arun Jayaram of JPMorgan.

I have a couple of questions about your initial thoughts on 2023, which I appreciate. You mentioned that there might be a preliminary increase of about 10% in dollar per foot, and that you could potentially achieve mid-single digits growth preliminarily. I would like to understand your expectations regarding footage. You provided great details about the amount of footage. If you operate a six-rig program in the Permian and three rigs in the Marcellus, what year-over-year increases do you anticipate in overall footage?

Yes. Well, Arun, we're not prepared to give that specific guidance in 2023. We've got a lot of what if'ing going on right now. We really haven't crystallized final plans. And I'll just leave it at that. I hope that answer doesn't surprise you.

I appreciate the detailed information you provided. I’m curious about your delineation efforts in the Harkey Shale. It seems like you have a few wells operational, and your increasing activity indicates you're satisfied with the results. Could you put this zone into context and explain how it might impact your inventory? Additionally, could you share your observations regarding the initial 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. 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. So 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.

Your next question is from Neal Dingmann of Truist Securities.

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 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. 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, and 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 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.

Yes, Neil, I think Tom made a good point. I would add that we need to maintain our flexibility. Our balance sheet is strong, and we’ve indicated a mid-single digit outlook. This aligns with your question. Additionally, as Tom mentioned, we are able to invest less while achieving better outcomes than in the past. Therefore, we have the capacity to manage through this effectively, unless the situation changes drastically.

Tom, my second question is about shareholder return allocation, specifically regarding dividends versus buybacks. I am curious if the recent drop in your shares, around 30% from early to late June, qualifies as an opportunistic buyback 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.

Your next question is from Michael Scialla of Stifel.

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. So if that bill becomes law, would you anticipate any impact on Coterra from the methane fee? And I guess, what can you say about the other aspects of the bill that have you encouraged?

We're still examining the situation, and I appreciate the insightful discussions that have taken place, including a noteworthy piece in the Wall Street Journal this morning. I would be surprised if much of the current form remains unchanged. Regarding the methane fee, there are troubling aspects; it requires us to meet EPA guidelines that haven't been finalized yet, and the timeline for compliance seems to precede the introduction of new EPA regulations, which is puzzling. Additionally, there's a requirement for methane intensity to be determined through direct measurement. We've explored various technologies and are currently assessing continuous monitoring options, but we haven't identified any that are scalable to meet this requirement. How this will be implemented remains to be seen. We appreciate the provision that allows for corporate methane intensity measurement rather than a basin-by-basin approach. As for the alternative minimum tax, there are several concerning provisions, as highlighted by others as well. Regarding the infrastructure aspect of the bill, I commend Senator Manchin for including a strong statement on it, although there are some confusing elements. We will have to wait to see how the bill progresses. I realize this is a broad answer, but we are carefully analyzing all of this. Ultimately, we require sound energy leadership and a coherent, focused energy policy. I hope to see a comprehensive government approach, not just limited to Senate discussions, and I would like to see more leadership from the government in this area. It's still uncertain at this point.

For sure. You also mentioned the market and about potential for recession. The market does seem to be baking in a fairly high probability of a recession; at least the equity seems 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? And as you look at the cash balance heading into next year, does it have any impact on what do you think the appropriate cash balance is?

Yes, Michael, this is Scott Schroeder. We are continuing our internal discussions about hedging. Since Coterra was formed, we have a solid balance sheet that allows us not to rely heavily on hedging. However, we prefer to cover some of our cash flows to protect against potential disconnects. When good opportunities arise, we will take advantage of them, as we have in the past. This can be seen in our 10-Q filing that will be released today, and we will keep addressing this matter. Ultimately, it's akin to purchasing insurance. While it's not essential, it is wise to incorporate some protection into our overall profile.

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

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, do you want to take that one?

Doug, I'm not sure if you have the page number, but it's on Page 7 in the deck where it shows that the free cash flow breakeven is still at $40 and $2.25. We are very confident that we have a sustainable program without compromising our goals.

I guess I'll take it offline with Dan and see if we can get a number, but I'm guessing it's risked higher at this point with full cash tax. And maybe the way to ask it, Scott, is what are you assuming for cash taxes in that $40, $2.25?

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.

Not just for you I might add, but for the whole sector, but thanks, Scott. I guess my second question, Tom, is on relative capital allocation. And I guess you've talked often about Marcellus inventory depth. But 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 six to 12 months or even longer?

Your observation is quite accurate, Doug. We have a substantial amount of gas in our portfolio. As you know, the Delaware Basin is very productive in terms of gas. I consistently view capital allocation through the lens of return on invested capital, and the Marcellus is exceptional. It's truly a remarkable economic area. We do have the chance to expand a bit in the Marcellus, although we mentioned the need for more pipelines. However, regarding capital allocation based on returns, the Marcellus and the Permian offer similar advantages. We've conducted some interesting analyses on how returns fluctuate with varying oil and gas prices. Currently, with the gas to oil price ratio, one could choose a basin blindly and still find comparable returns. Therefore, we appreciate the balance in revenue, geography, and our current approach to capital allocation.

Your next question is from Paul Cheng of Scotiabank.

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.

Yes. Well, we've talked at length about the Anadarko and the fact that it's kind of in a rebuilding phase. We've got a couple of 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. And 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. And I think over time, owners of Coterra are 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 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?

No. It's all a timing issue. When you bring a well on in the second half of the year, you're typically in an area, depending on timing, where you have little impact on that calendar year, and it's just purely a timing issue. The one thing we talked about 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 '23 and even '24 as we currently model it, but it's all timing.

Your next question is from Leo Mariani of MKM Partners.

I wanted to just follow up on a few of the prepared comments here. So you just talked about growing the Marcellus maybe a little bit here in '23, in '24. You're kind of citing timing, but I'm assuming that there may be some macro factors in play as well. Obviously, you guys let the Marcellus production decline for the better part of the last handful of quarters. Is there just some thinking that this gas macro over the next couple of 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?

Well, 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, 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. And I guess just a follow-up on that. Are there any concerns on takeaway over the next couple of 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 could think at some point, there's a pitch point there with some water dips in '22 or '24?

There are always concerns about takeaway capacity. We can't support unchecked growth in the industry. The region has more potential to produce gas than the market can currently handle, which is why we need new pipelines. As it stands now, we could see some growth depending on what our competitors do. Production in the six-county area near Susquehanna County, a subregion of the Marcellus, has decreased significantly, so we do have some room to grow. However, we want to be cautious and avoid causing issues that could lead to a basis blowout. While we are not currently limited, we do recognize that over the long term, additional takeaway capacity from the basin is necessary to utilize the industry's production capabilities.

Okay. That's helpful. And just any comments on the integration of Cimarex and Cabot in terms of where you stand in that process and maybe what we can expect going forward?

Well, I think it's going very well. I'll let Scott comment on that also. Probably the laggard is integration of financial accounting systems, which is the right order to do things because of the critical nature of that and the concerns over not dropping the ball on anything as we integrate our financials. But I would say, organizationally, integration is going extremely well. And I'm having a lot of fun. But Scott, do you want to comment on that?

Sure. Yes, 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 '23 is truly a clean bill of health for the Coterra Energy going forward. That would be the only thing I would add.

Your next question is from Noel Parks of Tuohy Brothers.

I just had a couple of questions. I wanted to ask, we've heard a couple of other Appalachian producers expressed a bit of cautious optimism about additional LNG export capacity on the East Coast. And just wondered if you have any thoughts on that? And if so, maybe what were the underpinnings of that?

Yes. 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 are 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 with Cove Point that we safely moved 350 million a day through every day, and we need more of that. So we're talking to all those parties. 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 part of the ecosystem, whether it's 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. The industry needs certainty that those things can get built so that the investments can be made. And there's a long list of blood that has not happened. So that's very front and center in everyone's mind. So I think some help there would really go a long way towards making those projects happen.

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. So we really do look forward to continuing to perform and updating you as quarters go on. But as I'll finish where I started, Coterra has hit its stride. So thanks, everybody.

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