Hello, ladies and gentlemen, this is the operator speaking. Today's conference is scheduled to begin momentarily. Until that time, your lines will again be placed on music hold. Again, this is your operator speaking. Today's conference is scheduled to begin momentarily. Until that time, your lines will again be placed on music hold. Thank you for your patience. Ladies and gentlemen, thank you for standing by, and welcome to Q1 2022 Comstock Resources, Inc. Earnings Conference Call. At this time, all participants' lines are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference over to your first speaker today, our Chairman and CEO, Jay Allison. Thank you. Please go ahead. Thank you. I know it's a busy day in the world of earnings for oil and gas, so if you're an analyst or stakeholder, thank you for the time that you're going to give us. You know, welcome to the Comstock Resources first quarter 2022 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly result presentation. There you will find a presentation titled "First Quarter of 2022 Results." I'm Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentation as a note that our discussion today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you'll flip over to slide three. You know, what a great day to have an earnings call. I mean, natural gas is at a 13-year high. Natural gas, I looked, is at 8.54, and the 12-month strip is in the 8.40s. You know, we're sitting as a company on 1,600 drilling locations in the Haynesville-Bossier, which is a natural gas play nearest the LNG export terminals. Yes, free cash flow is up to probably $1 billion in 2022 at these prices and with our hedges in place. Yes, someone has to come out and tell you that the oil and gas patch has inflationary pressures, and we're doing that. At $8.54 natural gas price, it should be expected. If you look on three, we cover the highlights of the first quarter on slide three. In the first quarter, we generated $68 million of free cash flow from our operating activities. With the free cash flow, we reduced our debt by $85 million during the quarter. Our EBITDAX for the quarter came in at $333 million, and we had operating cash flow of $297 million or $1.07 per diluted share. Revenues after hedging were $408 million. Our adjusted net income for the quarter was $136 million or 0.51 per diluted share. Our Haynesville drilling program is going very well, as demonstrated by the 15 operated wells that we turned to sales since our last operational update that Dan Harrison will review momentarily. The IP rates for these wells average 29 million cubic feet per day. Now I'll turn the call over to Roland Burns to go over our financial results. Roland? Thanks, Jay. On slide four, we compare some of the first quarter financial measures to the first quarter of 2021. Yeah, pro forma for the sale of our Bakken properties, which we completed last October, our production increased 3% to 1.3 BCFE a day. Our adjusted EBITDA for the first quarter grew by 33% to $333 million, driven mostly by stronger natural gas prices, which was also supported by the fact that we were a little less hedged than last year. We were only about 67% hedged this quarter versus in the 70% area last in the fourth quarter last year. We generated in the quarter $297 million of cash flow, which was a 52% increase over the first quarter of 2021. On a per share basis, that's $1.07, which was 0.75 higher than the first quarter of 2021. We reported adjusted net income for the quarter of $136 million, 114% higher than the first quarter of 2021, and our earnings per share were 0.51 as compared to 0.25 in the first quarter of 2021. We generated $68 million of free cash flow from operations in the quarter, 73% more than we generated in the first quarter of 2021. The growth in our EBITDA and the pay down of debt that we achieved in the first quarter drove a 30% improvement to our leverage ratio, which improved to 1.9x, down from 2.7x in the same quarter of last year. Improved natural gas prices were the primary factor driving the strong financial results in this quarter. On slide five, we break down our natural gas price realizations. On the slide, we show the NYMEX contract settlement price and the average NYMEX spot price for each quarter, including this most recently completed first quarter. During the first quarter, there was another significant difference between the quarterly NYMEX settlement price, which was $4.95 per Mcf, and the average Henry Hub spot price, which is $4.60. This difference is probably due just to the high settlement price that the February contract had. During the quarter, we nominated 69% of our gas to be sold at index prices, which were more tied to that, the contract settlement price, and then we sold the remaining 31% on the, in the spot market. Therefore, the appropriate NYMEX reference price for our sales in the first quarter would have been about $4.84 per Mcf. Our realized gas price during the first quarter averaged $4.55, reflecting a 29-cent differential, which is more or less in line with the prior quarters. In the first quarter, we were 61% hedged, so that reduced our realized price to $3.53. The first quarter realized price after hedging was still 27% higher than the first quarter of 2021, and it was 18% higher than the fourth quarter of last year, even though NYMEX prices were down in the quarter, and this was mainly due to the decrease in the percentage that we were hedged in this first quarter versus the fourth quarter of last year. We also generated third-party marketing income in the quarter of approximately $4 million using the spare capacity we had on some of our premium marketing contracts. This added another 0.03 to our overall natural gas price realization in the quarter. On slide six, we detail our operating cost per Mcfe and our EBITDAX margin. Operating cost per Mcfe averaged 0.69 in the first quarter, 0.02 higher than the fourth quarter rate. Our lifting costs and production and severance taxes both increased by 0.02 while our gathering costs remained unchanged. Our G&A costs, though, came in 0.02 lower at 0.06 in the quarter. Our EBITDAX margin after hedging came in at 81% in the first quarter, improved from the 78% margin we had in the fourth quarter of last year. On slide seven, we recap our first quarter spending on drilling and other development activity. We spent $224 million on development activities in the quarter, $187 million that related to our operated Haynesville-Bossier Shale drilling program. We also spent another $14 million on non-operated wells and $23 million on other development activity, including a lot of workover and tubing up that we did on older wells in the quarter. In the first quarter, we drilled 15 or 13.1 net to us operated horizontal Haynesville-Bossier wells, and we turned 20 or 14.6 net operated wells to sales in the quarter. We had an additional 0.6 net non-operated wells that we turned to sales in the quarter also. Slide eight, we show our balance sheet at the end of the first quarter. We had $150 million drawn on our revolving credit facility at the end of the quarter after repaying $85 million during the quarter. The reduction in debt and the growth in the EBITDAX we had in the quarter continue to drive substantial improvement to our leverage ratio, which we said earlier, it's down to 1.9 times in the first quarter compared to 2.7 times in the first quarter of 2021. We plan on retiring an additional $394 million of debt over the rest of this year, including redeeming our 2025 senior notes on May 15. We've already issued the formal redemption notice for those notes. We're targeting to have our leverage below 1.5 times levered in 2022, and these high gas prices are making that happen very, very quickly. We did end the first quarter with financial liquidity of almost $1.3 billion. Now I'll turn it over to Dan to kind of talk about our operations in the first quarter. Okay. Thank you, Roland. Over on slide nine, this is a graph that shows the progression in our average lateral length drilled by year going back to 2017, along with our current average lateral length for the quarter and our record longest lateral completed to date. Since 2017, our average lateral length has grown 725 feet on average every year, and of an annual average, we're at 9,858 foot average for the first quarter as we continue to integrate more of our extra long laterals. That's the laterals greater than 11,000 feet into our drilling program. By year-end, we anticipate our full year average lateral to increase further to approximately 10,250 feet. As of today, we have drilled six 15,000-foot laterals, four of which have been completed, including our record longest lateral completed to date of 15,291 feet. We're currently drilling an additional two wells with 15,000-foot laterals. In 2022, we anticipate drilling 24 extra long laterals exceeding 11,000 feet, with 15 of these wells having laterals exceeding 14,000 feet. We are expecting the longer laterals to play a key role in minimizing the impact of inflation as we move into a higher cost environment. On slide 10, this is a plot of our updated D&C cost trend for our benchmark long lateral wells. This includes all our wells with lateral lengths greater than 8,000 feet. Our D&C cost averaged $1,124 a foot in the first quarter. This is an 8% increase compared to our full year 2021 D&C cost and a 9% increase versus the fourth quarter of last year. Our drilling costs increased 13% in the quarter to $450 a foot, while our completion costs increased 5% up to $673 a foot. The cost increase is primarily due to the higher cost of services that have arisen during the first quarter. With sharp increase in commodity prices and demand for services in the last couple of months, we have experienced additional cost increases. As mentioned earlier, we see these longer laterals as a means for us to further improve our efficiencies to alleviate some of these cost increases. On slide 11 is a summary of our first quarter well activity. Since the last call, we have turned to sales 15 additional wells. The wells were drilled with lateral lengths ranging from 4,428 feet up to 15,291 feet with an average lateral of 10,115 feet. We had some really good performance from this group as a whole, with the individual wells testing at rates ranging from 24 million cubic feet a day up to 37 million cubic feet a day, and with an average IP of 29 million cubic feet a day. The first quarter results also include the completion of our third and fourth 15,000-foot laterals. These same wells also represent our first two 15,000-foot laterals that we've completed into the Bossier. The BSMC LA 58-17 number one and number two wells were completed with laterals of 15,291 feet and 15,273 feet and tested at rates of 24 million cubic feet a day and 27 million a day. We are currently running seven rigs and have three frac crews running full-time across our acreage. On one last note, we want to mention that as early as last month, we have deployed our first 100% natural gas-powered frac fleet. The operation of the fleet is off to a good start. We've been pleased with their progress. We'll now turn it back over to Jay to summarize our 2022 outlook. All right. Thank you, Dan. Thank you, Roland. Again, what a great day to have an earnings call with 8.54 gas being a pure, publicly traded Haynesville-Bossier producer. It's a great corporate background. If you go to 12, you know, I direct you to slide 12, where we summarize our outlook for the rest of the year. You know, we expect our 2022 drilling program to generate 4%-5% production growth year-over-year, and we now expect to generate significantly more than the targeted $500 million of free cash flow at current commodity prices. Given current strip prices and our existing hedge position, we anticipate generating anywhere from $800 million-$1 billion in free cash flow in 2022. The top priority or the first priority of the free cash flow generation is to reduce our debt level to pave the way to reinitiating a return on capital program. Once certain goals are met, we plan on reinstating a dividend, and we'll set the initial dividend at a conservative level to be sustainable even in a low gas price environment. We are redeeming the 244 million outstanding on our 2025 senior notes on May the fifteenth, and we expect to pay the $150 million, the remaining borrowings outstanding under our bank credit facility. We're also earmarking up to $100 million for bolt-on acquisitions and additional leasing activities. We're targeting a leverage ratio, as I mentioned earlier, of less than 1.5x before initiating a return of capital program. Again, with our rapidly improving leverage profile and the substantial free cash flow generation expected for this year, we are looking towards reinstating our shareholder dividend as early as the fourth quarter of this year. As expected, we're experiencing cost increases for our drilling program this year, given the high activity level in the Haynesville. The longer lateral lengths, as Dan mentioned, of this year's program will create improved capital efficiency to partially offset some of the higher service costs. Lastly, we'll continue to maintain and grow our very strong financial liquidity. I'll now turn it over to Ron to provide some specific guidance for this year. Ron? Thanks, Jay. On slide 13, we provide the financial guidance for the second quarter and the full year 2022. We're providing the initial second quarter production guidance of 1.31-1.38 BCFE a day, and the full year guidance has remained unchanged at prior levels of 1.39-1.45 BCFE a day. During the second quarter, we plan to turn to sales 11-15 net wells. The biggest change on the guidance page is the development capital, which, for the full year, the guidance is $875 million-$925 million, which incorporates an additional 15% increase in service costs from our prior estimates when we last provided guidance in February. Our 2022 wells will have an average lateral length being approximately 16% longer than last year, which is helping to offset some of the inflation. In addition to those D&C dollars that we will spend on the drilling program, we could spend up to $100 million on bolt-on acquisitions and new leasing. On the cost side, LOE is expected to average 0.20-0.25 in the second quarter and for the full year, while gathering and transportation costs are expected to average 0.26-0.30 in both the second quarter and the full year. As gas prices have increased, our production and ad valorem tax guidance has increased to 0.14-0.16 per Mcfe, as that's just related to gross pre-hedge sales revenues. DDA rate is expected to remain in the 90%-96% per Mcfe range, while cash G&A is expected to total $7 million-$8 million in the second quarter and $29 million-$32 million in 2022. On a quarterly basis, the non-cash G&A is expected to run approximately $2 million per quarter. Cash interest during the second quarter expected to total $38 million-$42 million and $152 million-$160 million for the full year, which includes the impact of the redemption of our 7.5% notes here in the middle of this month. Effective tax rate for the year expected to be 22%-25%, and we now expect to defer 75%-80% of our taxes. Given the significantly improved commodity price outlook, we now anticipate our current taxes representing a larger portion of reported income taxes. Now turn the call back over to the operator to answer questions from analysts who follow the company. Thank you. As a reminder, to ask a question, please press star followed by the number 1 on your telephone keypad. Again, that is star one. To withdraw your question, please press the pound or hash key. Please stand by while we compile the Q&A roster. Your first question comes from the line of Derrick Whitfield with Stifel. Your line is open. Thanks, Dan. Good morning, all. Morning. With my first question, Jay, I wanted to focus on your 2022 plan and your confidence in executing against it. In consideration of the operational environment that you guys are facing and the tightness in services, supplies and labor, have there been, or do you expect any business impacts beyond inflation? If I could add a second part to that question, are there any unique factors specific to Comstock that makes you more susceptible to industry inflation? Yeah, this is Dan. I'll say, as far as for the first part of your question on the long laterals, I mean, we've got good relationships with all of our suppliers. We don't really see any, you know, really additional risk in that regard. As far as the second part, I think what it is is on the CapEx increases, it's really just probably more of a little bit of a localized demand for services here with the ramp up and the number of rigs, you know, just in the Haynesville area and the high gas prices. You know, it's just been really across the board. We've seen it in all services. It kind of started out with really probably the bigger ticket items, the rigs, the frac crews, but obviously the cost of diesel, you know, is driving up everybody else's cost of services also. You know, I would also add that, you know, we do use two or three different service companies as far as drilling contractors and then two or three different frac companies, so we're not isolated with one company. As Dan said, we do blend it out and we do have competitive bids, and then this is where we've landed. Got it. As my follow-up, looking out beyond 2022 and thinking about your unique position in the LNG corridor, how do you envision the role that Comstock will play in the multi-year opportunity ahead of us to address European supply needs? Further, how would you like to position Comstock in the value chain for LNG offtake to maximize your exposure to higher prices? Well, you know, as of April first, we're selling gas directly to every LNG facility in Louisiana. That's only a month ago when we were doing that. I think that, as you're well aware of where our location of our fields are, it's the closest major gas field to LNG export facilities. We've got more undedicated gas than any other producer there, I believe. You know, we plan on being a material supplier of gas that's needed both in Asia and Europe, and that's really driven by the location that we're at. We started doing it. You know, 14% of our current gas is sold to LNG facilities, and then 66%, you talk about cost, is sold, you know, to the Gulf Coast market. That's your LNG market. I think we're well positioned to do that with the high margins and low costs that we continue to put up quarter after quarter. And the success we've had like that Dan has had on the drilling of the wells, the last 15 wells, you see the extended laterals. And even the efficiency we've had in our inventory. You know, we took our inventory from about 1900 locations to 1600, and all those became more valuable than where they're located. They're located near where the gas needs to go, and that is LNG overseas. Sorry about that. Derrick, can I just add that. That is kind of the direction. We expect to be selling more and more of our production directly to the LNG shippers and you know in constant talks you know looking to develop long-term relationships you know with them and continue to tie more and more of our gas to the Gulf Coast yeah indexes versus the regional hubs of Carthage and Perryville. That's very helpful. Thanks, Roland. Thank you. Good question. Your next question comes from the line of Umang Choudhary with Goldman Sachs. Your line is open. Hi, good morning, and thank you for taking my questions. Yes, sir. I appreciate your comments on costs and inflation. Wanted to get your thoughts on what you're doing differently on supply chain or services to manage costs today, not only just for 2022 program but also looking ahead to 2023. Yeah. This is Dan. I mean, obviously we've got, you know, our first 100% gas fleet that we just put into service, I guess a month ago. We did sign a long-term deal on that, so that's going to keep us somewhat protected over the next few years on our freight cost. We have, you know, we enter into some longer contracts when we can. We bought ahead on all of our pipe, you know, tubing casing. So we do stay kinda protected on that. Now, eventually, those prices do roll off in the future and, you know, you're buying it to future prices, you know, to look out even further. I think the main thing is just with our level of activity, the relationship with our vendors, you know, we feel pretty protected there for future cost increases. I think we got a little bit of leverage there. Great. Thank you. The other question was on non-operated activity. You mentioned it could potentially be higher in 2022. Any impacts to production from higher non-op activity this year or next year? Also, do you see any increase in shut-in production offsetting any production benefits? Seems like most of the industry is bringing online wells in Q2 and Q3. I'm just trying to understand if there's any risk to growth there. Yeah, good questions. Also, this is Roland Burns. Yeah, on the non-op activity, we did see, you know, additional non-op costs here in the first quarter. We saw some non-op refracs, which are not very, you know, weren't very common in the lower price environment. Yeah, we don't have a huge exposure to non-op 'cause we have very high working interest, but we have some. The projects are also, they have such high returns, it's very difficult not to participate. We don't like to count on non-op activity for, you know, giving you guidance on production. You know, hopefully there'll be a little, you know, upside from as those come on. We see, you know, that's part of the overall level of extra CapEx we had to provide for was just higher level of non-op that's out there, you know, that we kind of expect and really want to participate in because they're all such high return projects, you know, and with the high commodity prices. On shut-in time, you know, our first quarter, we had about a 4% average shut-in time, which is very normal, you know, for us. 4%-5% is kinda what we always expect. you know, we've tried to manage that better by grouping our kind of completions together in larger kind of units, so we can kinda get that done at one time, like the seven wells that we actually had to you know, put online all at the same time, kind of in our high kind of production area of Elm Grove. you know, we try to manage that as best we can. We're fairly, you know, we have some offset operator influence over our production, but you know, our acreage is fairly blocky and we, you know, more or less, you know, determine how much we're shut in, you know, just by our own activity. We do try to schedule and plan to minimize that 'cause that, you know, that's a big factor. Yeah, but always, you know, really, you know, to keep it in this 3%-5% level is kinda the norm we expect. You know, as you're asking the questions about the, you know, non-op opportunities and costs, you know, it probably is a good time to address that we said we're kinda earmarking 100 million for bolt-on acquisitions. Now, we threw that number out. I mean, we may not spend that number. Another reason we threw that number out is, if you remember in December, we had an East Texas bolt-on acquisition for $35 million, and we picked up about 58 net drilling locations. That's about a year's worth of inventory, and 94% of that was HBP. With 44 of our existing Comstock locations, our laterals extended because this new acreage. We did put a number out there to earmark that. If we see something like that, then, you know, don't be surprised if we would go forward on it. It's not that we have to spend that, but we just want to throw that out there to show you that even if we spent that on bolt-ons and additional leasing activity, you know, we think we've got this $1 billion of free cash flow, et cetera, and that we think that our leverage ratio will come down, materially, maybe below that 1.5 times, and then we can take a serious look at reinstating a dividend. That's why we put that out there, just for total clarity, kinda like we have clarity that you should expect inflationary pressures at $8.58 in natural gas in the Haynesville. Got it. Appreciate the comments. Thank you. Yes, sir. Your next question comes from the line of Neal Dingmann with Truist. Your line is open. Good morning, all. Jay, just on that last question, maybe last, just a bit of follow-up just on the OFS inflation. You guys, you know, appropriately boosted the anticipated cost, I think, for the rest of the year by about 16% for overall 2022. I'm just wondering, given, you know, the uncertainty with inflation and, you know, you and most others are kinda rig-locked well-to-well on your rigs and fracs, what type of confidence do you have that that's going to be high enough for the rest of the year? I think it's a really high number. I mean, well, I think we're one of the first ones to come out with a, you know, a 10% number. I mean, maybe at the end of the year. You know, our drilling costs are up, like, 13%. Our completions are up, like, 5%, and our total D&C costs are up about 8%. I think that we've got a pretty good handle on it. You know, I think we've added a little bit more to it, just for wiggle room to make sure that our, you know, second, third, fourth quarter numbers are good. Now, you know, again, you take. You look at a 6.80 environment, which is where we're at last Friday, versus an $8.54 environment, even the 12-month strip, you may see a little more of this. We don't expect it, but we want to be honest about it and see where we are right now. No, we don't expect it. I think we're the first ones to come out on an earnings call and say, yes, someone has to come out and tell you that the oil and gas patch has inflationary pressure. We've done that. I think we've given the right number. I think we've given the right signal. If you bake that in your numbers, I think we're going to be pretty correct, unless, you know, gas goes to that $10+ number, and everybody may want a little bit more money to drill the complete wells. No, good. Thanks for the guidance. Then just follow up for maybe you, Roland or Ron, just really on cash returns. I'm just wondering, you know, ballpark how quickly today, at today's strip now. I mean, you mentioned start of the call, obviously, these fantastic prices. How quickly today's strip you anticipate being able to start your cash return program? I forget what y'all have exactly said. Will the program initially consist of just exclusive dividends, as you mentioned about, you know, wanting the divs payout high enough preferred holders, or would you consider some buybacks as well when this begins? That's a good question. Yeah, well, obviously, with the much higher commodity price environment, it's accelerating, you know, everything. You know, we don't want to get ahead of the overall plan. You know, the centerpiece of our this whole year is the bond redemption. You know, we're just, you know, we're coming up to that. We want to check the box there and get the debt reduction, you know, all completed, which probably happens, you know, a lot quicker than we thought earlier. Really, you know, I think we are signaling that, you know, at least, you know, probably by the fourth quarter for sure, you know, hopefully reinstate the dividend that we, you know, have not had since 2014. But those are all very key. I think after that, you know, we have guided that, hey, we do want to invest in, you know, in our overall footprint in the Haynesville. So we're saying we earmarked $100 million toward, you know, lease acquisition bolt-ons. Might not be able to spend all that this year, but it's a priority. So that's the reason why we signaled that. And lastly, you know, I think we will consider, you know, other forms of return of capital after all those things, you know, have been completed. You know, I think in the scope of that question, we need to tell you that we are not chasing any large corporate acquisitions. So you can put an X through that. We're not chasing any of those. Instead, we're going to target these smaller bolt-on ones, and we've been successful in doing that. But the other thing, you know, you could put a big X on. We're not looking to make an acquisition in the Haynesville to scale up production, you know, at an expensive price. We're not looking to do that either. So if you look at where we would be spending money, you can mark those two out. Look at where we'd be spending money. It is not out of basin. It's the Haynesville-Bossier. If you look at what we'd be doing with that money, we're going to get this leverage ratio down as low as we can get it. We would look to reinstate a dividend that would be there even when gas prices are lower. That's important. I guess the other comment, you know, you ask about inflation. You know, if gas prices go up, you know, we're going to have a lot greater increase in free cash flow versus what the inflation might be. So we're always- I was just going to mention that, Jay. I think that's exactly right. Yeah. I appreciate the details. Yeah. No, go ahead. I'm sorry. I mean, I think the other thing to add is that as we progress through this year, we become less hedged every quarter, and we're participating more in the higher prices. Even this year's hedge position is, you know, a little more than half into collars. So, you know, we're participating a lot more in the higher prices, you know. As we progress through this year, that every quarter we'll participate more. In 2023, you know, we are participating almost fully in the futures prices. So, you know, that's a big change that's also happening in the company compared to, you know, kinda last year. Great details. Thanks, guys. Your next question comes from the line of Charles Meade with Johnson Rice & Company. Your line is open. Good morning, Jay and Roland, and to the rest of the Comstock crew there. Yes, sir. Hi, Charles. Jay, you've touched on this 100 million for bolt-ons a bit already, but I want to explore this a little bit more. You already made the point, you've been successful with these deals in the last several quarters. What has changed that makes you want to you know prepare the market or prepare analysts for $100 million this year? Is it the opportunity set that's changed, that the opportunity set's looking richer? Or is it perhaps alternatively your appetite for going after these bolt-on deals has changed? What. Just give us. Well, I think what's really changed, Charles, is we think there are good opportunities, and we do think we're going to do some. We have, you know, I think, unique to us, we've got opportunities to do that. We really, as people are looking at the free cash flow and the debt reduction, you know, goal is going to be finished, you know, and we don't have a lot of prepayable debt, we just wanted to set aside that that's something that we want to have established, and we want to have that money reserved for that opportunity. It's not that we probably think that, you know, it's not a huge change in the availability, but we just want to say, as people are looking, we just want to make sure the market's focused that, hey, that will be something they'll be doing also, you know, out of the free cash flow. We're not going to do it, you know, with additional leverage, and that's really what we're just trying to properly signal. As you know, we're getting very close to our return on capital programs being put in place, we want to have everybody thinking of all the right priorities. I think we want to have enough wiggle room out there with the audience, Charles, like you and others, that if we added some new acreage or if we did a bolt-on, you know, in the $30-$35 million range, kinda like the last one, that it wouldn't be a surprise to you. In other words, we wanted you to put that in your numbers, because even when you put it in your numbers, I mean, we look really, really strong. That was just. That's not a foreshadow of what we're doing. It's just trying to be, have clarity to tell you what we might be doing if an opportunity comes along. Got it. I think if I understand right, it's because your de-leveraging is happening more quickly, you guys want to make sure that's in the picture too so people have the right kinda landing spot for year-end, you know? Right. Yeah. That is absolutely correct. Okay. Explain our appetite for that type of activity. We think that's a number that will encompass what we could possibly do. It may take more than, you know, a year to do that, you know. You will see us spend dollars, and as we can pick up additional acreage. You know, even in the first quarter, we had, you know, a modest amount of that spending in that category. Well, I don't think you can look at us trying to buy something, Charles, that would increase the amount of wells we have to drill either. In other words, I think this is a good point. The bolt-on we did in December was 94% HBP. It gave us a year's worth of drilling, and it increased our lateral length on existing locations that we had. In other words, if it complements us like that's what we're looking for. Those are a little hard to find, but we're broadcasting it. If we did find something like that we think you'd want us to do anyhow, you know, we're setting those dollars aside, period. Got it. Then my follow-up question is on your CapEx trajectory over the year. If we look at, you know, what you did in 1Q and then your guide for 2Q, it looks like 2Q is the peak CapEx quarter, or peak CapEx quarter. But then it trails off significantly in the back half of the year. Is activity going to follow that same trajectory, or is there something else in the picture that I should be thinking about? Charles, it's really the timing. It's, you know, the biggest production growth quarter is going to be the third quarter, and so you end up spending more money in the second quarter ahead of the production. It's just as in our current D&C schedule, it's the timing of the completions and when those wells are turned to sales. It's not you guys. So it's maybe a reduction in completion activity in the back half of the year, but it's not a reduction in rig activity, if I understand right? No. No, it is not. It's not. You know, I think- Okay Dan mentioned, you know, the number of long lateral wells we were going to drill this year and, you know, even the number of greater than 14,000-foot. Some of it's probably the timing of when those drilling and completion dollars are spent. It's no change in the rig count or the frac fleet count. Yeah. We use some of our operated rigs and operated frack crews for third party activity, including, you know, what we do with our majority stockholder. Right. I think just the way the rig schedule works, the activity on that front is ramping up in the third quarter, you know, compared to the second, where maybe I think we're probably using you know almost 100% of our operated you know services for our own stuff. I think I'm pretty certain that we do have a ramp up of activity in our infill wells that we have a little bit lower working interest, which also have a you know kind of influence on how that the cadence of the capital spending. Right. That's all helpful detail. Thank you, Roland. Thank you, Ron. Thank you. Thank you. Your next question comes from the line of Phillips Johnston with Capital One. Your line is open. Hey, guys. Thanks. Just to follow up on the earlier question, you mentioned about 14% of your volumes are being sold directly to LNG shippers and, you know, that should grow over time and give you more exposure to Gulf Coast pricing rather than more regional pricing. My question is there any potential over the next few years to sign long-term contracts that are more directly linked to international gas prices and maybe capture some of the economic rent of the large arb out there? Yeah, that's a great question. I think that, you know, right now we see directly supplying the LNG shippers, you know, but probably more at, you know, Henry Hub pricing. I think we do have a new long-term supply agreement with one of them that's a 10-year agreement. It's, you know, like it's priced off an NYMEX, you know, very tightly off an NYMEX, minus a penny or so. As far as participating in international pricing, you know, I think that's, yeah, that's something we're exploring. I think you actually have to own the facilities. I think as you start to, you know, potentially invest in owning the facilities, I think you can probably achieve that. 'Cause you actually physically need to be able to participate in that market to do that the right way. We don't want to try to do that through derivatives and have, you know, have unusual price changes cause us not to be correlated, you know, with our physical sales. I think that's the. We're exploring that, and I think other maybe producers are exploring it. Maybe that, you know, we have own equity in these facilities. From that viewpoint, then you would have the ability to, you know, to use some of the capacity you own to maybe, you know, actually sell in a different market. Yeah. Okay. Question. That's a logical, you know, step for us to look at as we have been looking at it. Okay, guys. Sounds good. Thank you. Your next question comes from the line of Steven Dechert with KeyBanc Capital Markets. Your line is open. Hey, guys. Based on our math, it looks like production has to increase by about 9% in the second half of 2022 versus the midpoint of your second quarter production guide to hit the bottom end of your full year 2022 production guide. Do you see any challenges in hitting that number? Thanks. I mean. Ron? Per our drilling schedule, no. We would have updated guidance if that would have been the case. I think when I look at a kind of sequential growth rate, I don't know if I get all the way up to 9% in the second half of the year to get there. I mean, I'm in the mid or the upper single digits, but I don't think I want all the way up to 9%. Yeah, we did, you know, earlier you know, we increased our rig count, increased our activity levels, you know, as we began this year. If you know, if you really look at the way that the, you know, when you start drilling, and we do these wells and multi-well pads, two to three to four together, it takes almost six months before you start seeing the fruit of that investment. I think that's really the second half of the year. You know, it was always the higher growth part of our year as we're seeing the, you know, the investments we started making as early as even this quarter, you know, start to come online. You know, I think we have some increases that we expect in the second quarter as we've guided to. Right. That lag is why the third quarter is the highest growth, sequential growth period of the year. Yeah. We drill high volume wells, you know, and they, you know, and they just don't perfectly because there's only so many of them. They just don't come in a balanced way. Yeah. That's kind of the nature of our business. It's, you know, that it gets a little lumpy. Yeah. This is it. It really is the fact that we added the two rigs back in February. By the time those flow through the pipeline. Time to drill the wells, complete the wells, you don't see that show up until later in the year. I mean, that's really the primary- Yeah, that's the easy answer. Okay, great. Thank you. Thank you. Your next question comes from the line of Noel Parks with Tuohy Brothers. Your line is open. Hi, good morning. Morning. Wanted to ask you about lateral length and just to sort of give us some perspective. Can you talk about the technical piece and the land piece being able to increase the length? You already expect to take them over 10,000 this year versus I think it was 8,800 last year. If you could sort of break that out, that'd be great. Well, I'll start with the land piece. I mean, you have to have the land piece available, obviously, to even have the opportunity to drill the 15,000-foot laterals. It's a little bit different between Louisiana and Texas. In Louisiana, obviously, you got sectional units, so you know, you've kinda got some preset lengths you can, you can pick to drill. You know, you can drill one section, you can drill, you know, a 10K, two sections, or you can drill, you know, three sections as a 10K, or you can drill, you know, two 7,500-foot laterals instead of one 15,000-foot lateral. You know, over in Texas, you know, you just basically got, you know, the acreages and the units that are just, random, you know, sizes and shapes. Really it's just kinda more random lengths. I mean, you could have some 11,000-foot laterals, 13. You know, just any number that you want to make it if you've got a big enough position. We're fortunate in Louisiana that we do have a lot of areas where we can drill. They have the opportunity to drill the 15,000-foot laterals, and we do. It's obviously way more, you know, economical, and the benefits are so much greater to drill one 15,000 than two 7,500s. On the technical side, I mean, really we're very confident we could drill the 15,000-foot laterals. On the ones we've drilled to date, you know, from a technical perspective, we've had no issues drilling the 15,000-foot laterals and completing and getting them to sell. We've been super excited, you know, about what we've accomplished to date. We're super confident in our ability to execute on the long laterals in the future. We even foresee maybe a few, you know, laterals longer than 15,000 foot in the near future. I think really for us, you know, with the increase in industry activity, we've seen, you know, just kind of the downhole tool reliability has suffered a little bit, just the amount of tools, you know, coming into the shops and going back out, maybe from a quality control standpoint. I mean, that's probably the biggest battle that we're fighting today. As far as the 15,000-foot themselves making things more difficult, that has not been the case. Got it. I was just wondering about your suppliers in general. I understand what you're saying about with your size, it's easy to have some negotiating power. I'm just wondering about the logistics and whether your suppliers have been able to maintain some stability in their labor forces or are they affected to a degree that affects you around about people hopping around, labor cost pressures and so forth? Well, we haven't seen anything really to date. I mean, obviously we've part of these cost increases has been labor related. You know, I mean, from all of the we've got two rig providers and both of them basically have come forward with cost increases, you know, for the their increased cost in labor. That's part of it. You know, I think on the service side, as far as our tools, you know, I think things got pretty tight maybe with some of their suppliers on just kinda servicing their some of the tools. You know, that kinda comes across to us as a cost increase, you know, as a way for them to try to mitigate that and to, you know, just not let that affect their business. Great. Thanks a lot. There are no further questions over the phone line at this time. I'd like to turn the call back to our speakers for their closing remarks. All right. Again, start this, you know, it's just a great day for earnings call. I mean, natural gas, 13-year high. It's at 8.54. You look at the performance we've had quarter after quarter. I mean, we've had a great quarter with the 15 wells that we turned to sales in the first quarter of 2022. If you look at just the catalyst for natural gas, I mean, you've got international supply disruptions. You've got the U.S. inventory 18% below normal. You've got constraints on service sector, which we factored into our numbers. You know, you've got storage inventory low in both Europe and Asia. You've got Comstock and others that produce dry gas. It's the cleanest fossil fuel. It's abundant, it's needed, it's reliable. You look at where we're comfortable at. We're comfortable where we're headed. Maybe $1 billion of free cash flow. We're the only pure play Haynesville publicly traded company. You got 25 years of drilling inventory. Again, we're an industry leader in margins. We've got great free cash flow, and we've got low cost, flexible gas marketing options, which you know one of the questions was about. Take a look at us. Thank you for the time. You could have spent it elsewhere. We appreciate it, and we'll put in a good day's work for you. Thank you. Ladies and gentlemen, this concludes today's conference call, and we thank you all for participating. You may now disconnect.