Thank you. I know it's a busy day in the world of earnings for oil and gas. If you're an analyst or stakeholder, thank you for the time that you're going to give us. Welcome to the Comstock Resources first quarter of 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 inside for the first quarter of 2022 results. I am 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 Ronald Mills, our VP of Finance and Investor Relations. Please refer to slide 2 in our presentation. There's a note that our session today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations in such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. If you have flipped over to Slide 3, what a great day to have an earnings call. I mean natural gas is at a 13-year high. Natural gas outlook is at $8.54 and the 12-month strip is in the $8.40s. We're sitting as a company on 1,600 drilling locations in the Haynesville Bossier which is a natural gas play. Nearest to LNG export terminals and gas-free cash flow is up to probably $1 billion in 2022 at these prices and with our agents in place, and yes, someone has to come out and tell you that the oil and gas pie continues to expand and we're doing that. At $8.54 natural gas prices, it should be expected. If you look on Slide 3, we cover the highlights for the first quarter. 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. We had operating cash flow of $297 million or $1.07 per diluted share of revenues. Then for hedging for $408 million. Our adjusted net income for the quarter was $136 million or 51¢ per diluted share. Our Haynesville drilling program is going very well as demonstrated by the 15 operative wells that we turned to sales since our last operational update that Dan Harrison will review momentarily. The IP rates for these wells averaged 29 million cubic feet per day. So now I'll turn the call over to Roland Burns to go over our financial results.

Thanks, Jay. In Slide 4, we compare some of the first quarter financial measures to that of the first quarter of 2021. 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 EBITDAX for the first quarter grew about 33% to $333 million, driven mostly by stronger natural gas prices which is 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 of last year. We generated in the quarter $297 million of cash flow, which was a 52% increase over the first quarter of 2021. And on a per-share basis that's $1.07 which was 75¢ higher than the first quarter of 2021. Reported adjusted net income for the quarter of $136 million, 114% higher than the first quarter of '21. Our earnings per share were 51¢ as compared to 25¢ in the first quarter of '21. We generated $68 million of free cash flow from operations in the quarter, 73% more than we generated in the first quarter of '21. The growth in our EBITDAX, and the paydown of debt that we achieved in the first quarter drove a 30% improvement in our leverage ratio which improved to 1.9 times down from 2.7 times 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 5, 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 partly due 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 the contract settlement price, and then we sold the remaining 31% in the spot market. Therefore the appropriate NYMEX reference price for our sales in the first quarter would have been about $4.84 for MCF. Our realized gas price during the first quarter averaged $4.55 reflecting a 29¢ 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 '21, and it was 18% higher than the fourth quarter of last year, even though NYMEX prices were down in the quarter. 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 3¢ to our overall natural gas price realization in the quarter. In Slide 6, we detail our operating costs per MCFE and our EBITDAX margin. Operating costs for MCFE averaged 69¢ in the first quarter, 2¢ higher than the fourth quarter rate. Our lifting costs in production and severance taxes both increased by 2¢ while our gathering costs remained unchanged. Our T&A costs though came in 2¢ lower at 6¢ 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.

Okay, thank you, Roland. Over on Slide 9, this is a graph that shows the progression of 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 now our average, we're at 9,858-foot average for the first quarter as we continue to integrate more of our extra-long laterals into our drilling program. By year-end, we anticipate our full-year average laterals to increase further to approximately 10,250 feet. As of today, we have drilled 6, 15,000-foot laterals, 4 of which have been completed, including our record longest lateral completed to date, to 15,291 feet. We're currently drilling, in addition, 2 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 extending beyond 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 lateral updated DNC cost trend for our benchmark, long lateral wells. This includes all our wells with lateral links greater than 8,000 feet. Our DNC cost averaged $1,124 a foot in the first quarter. This is an 8% increase compared to our full year of 2021 DNC 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. The sharp increase in commodity prices and demand for services in the last couple of months has resulted in 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.

All right, thank you, Dan. Thank you all 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 backdrop. If you go to Slide 12, I'd 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% to 5% production growth year over year. We now expect to generate significantly more than the targeted $500 million for free cash flow with current commodity prices. Given current strip prices on our existing hedge position, we anticipate generating anywhere from $800 million to a billion dollars in free cash flow in 2022. The top priority for free cash flow generation is to reduce our debt level to pave the way for 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 15th. We expect to pay the $150 million remaining borrowings outstanding under our bank credit facility. We're also earmarking up to $100 million for both acquisitions and additional leasing activities. We're targeting a leverage ratio, as I mentioned earlier, of less than 1.5 times 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 length, 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 Roland to provide some specific guidance for this year.

Thanks, Jay. On Slide 13, we provide the financial guidance for the second quarter and the full year 2022. We are providing the initial second-quarter production guidance at 1.31 to 1.38 BCF a day and the full-year guidance has remained unchanged at prior levels of 1.39 to 1.45 BCF a day. During the second quarter, we plan to turn to sales 11 to 15 net wells. The biggest change on the guidance page is the development capital, which for the full year the guidance is $875 million to $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 B and C dollars that we will be spending on the drilling program, we could spend up to $100 million on both acquisitions and new leasing. On the cost side, LOE is expected to average 20¢ to 25¢ in the second quarter and for the full year, while gathering and transportation costs are expected to average 26¢ to 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 14¢ to 16¢ per MCFE as that's just related on gross pre-hedge sales revenues. The DEA rate is expected to remain in the 90% to 96% per MCFE range while cash G&A is expected to total $7 million to $8 million in the second quarter and $29 million to $32 million in 2022. On a quarterly basis, the non-cash Q&A is expected to run approximately $2 million per quarter. Cash interest during the second quarter is expected to total $38 million to $42 million and $152 million to $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. The effective tax rate for the year is expected to be 22% to 25%. We now expect to defer 75% to 80% of our taxes given the significantly improved commodity price outlook. We no longer expect our current taxes to represent a larger portion of reported income taxes.

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 in the tightness and 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?

Yes, 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 additional risk in that regard. As far as the second part, I think what it 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 in the number of rigs, you know, just in the Haynesville area and the high gas prices. It's just really been 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 frack arrays but obviously the cost of diesel was driving up everybody else's cost of services also.

You know, I would also add that we do use 2 or 3 different service companies as far as drilling contractors, and then 2 or 3 different track companies, so we're not isolated with one company. So, as Dan said, we do blend it out and we do have competitive bids and then this is where we've landed.

And 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? And 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 1st we're selling gas directly to every LNG facility in Louisiana. That's only a month ago. I mean, we're doing that. I think that as you're well aware of where our fields are located, it's the closest major gas field to LNG export facilities. We've got more undedicated gas than any other producer there, I believe. So, you know we plan on being a material supplier of gas. It's needed both in Asia and Europe. And that's really driven by the location that we're at. And we've started doing it; 14% of our current gas is sold to LNG facilities. And then 66% of our cost is sold to the Gulf Coast market, and that's your LNG market. So 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 1,900 locations to 1,600 and all those became more valuable than where they're located. They're located near where the gas needs to go when that is LNG overseas.

Can I just add that we expect to be selling more and more of our production directly to the LNG shippers and, you know, constant talks are looking to develop long-term relationships with them and continue to tie more and more of our gas to the Gulf Coast indexes versus the regional hubs of Carthage and Perryville.

Appreciate the comments on costs and inflation. I wanted to get your thoughts on what you're doing differently on supply chain or services to manage costs today? Not only just for the 2022 program but also looking ahead to 2023?

Yes, so this is Dan. We, I mean, obviously we've got our first 100% gas-powered 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 frack cost. We have, you know, we enter into some longer contracts when we can. We buy ahead on all of our pipe, you know, tubing casing so we do stay somewhat protected on that. Now, eventually, those prices do roll off in the future and you know, you're buying at future prices, you know, to look out even further, but I think the main thing is, just with our level of activity, the relationship with our vendors, you know, we feel pretty protected there from future cost increases. I think we've got a little bit of leverage there.

Great. And then, 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? And also, do you see any increase in shutting production offsetting any production benefits? It seems like most of the industry is bringing online wells in Q2 and Q3, so I'm just trying to understand if there's any risk to growth there.

Yes, good question. Also, this is Roland. Yes, on the non-op activity, we did see, you know, additional non-op costs here and there. The first quarter, we saw some non-op refracks which are not, you know, very common in a lower price environment. Yes, we don't have a huge exposure to non-op because we have a very high working interest, but we have some, and the projects have such high returns, it's very difficult not to participate so we don't like to count on non-op activity to provide you guidance on productions. So, you know, hopefully, there'll be a little upside from as those come on maybe. And we see, you know, that's part of the overall level of extra Capex we had to provide for with just a 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. At the same time, in our first quarter, we had about a 4% average setting time, which is very normal. You know, for us, 4% to 5% is kind of what we always expect. You know, and we've tried to manage that better by grouping our completions together in larger units so we can kind of get that done at one time, like the 7 wells that we actually had to put online all at the same time, kind of in our high production area of Elk Grove. So, you know, we try to manage as best we can. Fairly, you know, we have some offset operator influence over our production, but, you know, our acreage is fairly blocky and we more or less determine how much we shut in just by our own activity. But we do try to schedule and plan to minimize that because at the end, that's a big factor. And, you know, but always, you know, to keep it in this 3% to 5% level is kind of the norm we expect.

You know, as you were asking the questions about non-op opportunities and cost, you know, it probably is a good time to address that. We said we're kind of earmarking $100 million for both acquisitions. You know, we threw that number out. I mean, we now 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 HPP. And 44 of our existing Comstock locations are laterals-extended because of this new acreage, so 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 billion dollars of free cash-flow, et cetera. You know, we think that our leverage ratio will come down materially. It might be 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, kind of like we have clarity that you could expect inflationary pressures at $8.54 on natural gas in the Haynesville.

I want to know, Jay, just on that last question. It's just a bit of follow-up just on the offset inflation. You guys, you know, properly boosted the anticipated cost, I think, for the rest of the year by about 16% for overall '22. I'm just wondering, given the uncertainty with inflation and, you know, you and most others are kind of rig to rig or well to well under rigs and fracks. 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 hard 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, and then in our drilling is up, like I think costs trip, like 13% or completions are up like 5% and our total DNC costs trip about 8%. I think that we've got a pretty good handle on it. And, 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, and fourth-quarter numbers are good. Now, you know, again, you look at an AD environment, which is where you were 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. They'd say where we are right now, but no, we don't expect. And 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. So, we've done that. I think we've given the right number, I think we've given the right signal. So if you like that in your numbers, I think we're going to be pretty correct. Unless, you know, gas goes to that $10 plus number and everybody may want a little bit more money to drill the complaint wells.

Thanks for the guide. And then just follow up for maybe you, Roland, or Ron just as a really on cash returns. I'm just wondering, ballpark, how quickly, today's trip now, I mean, you mentioned at the start of the call, obviously, it's fantastic prices. So, how quickly today's trip do 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 wanting the div payout high enough for preferred holders or would you consider some buybacks as well when this begins?

That's a good question. Yes, well, obviously, with the much, much higher commodity price environment is accelerating, you know, everything, but you know, we don't want to get ahead of our plan. So, you know, the centerpiece of this whole year is the bond redemption. Yes, 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. And then really, you know, I think we were signaling that, you know, at least probably by the fourth quarter for sure, you know, hopefully reinstate the dividend that we, you know, have not had since 2014. Those are all very key. And I think after that, you know, we have guided that, 'Hey, we do want to invest and, you know, in our overall footprint in the Haynesville.' So, we're saying we're earmarked at $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 we signaled that. And lastly, you know, I think we will consider, you know, other forms of return to 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 to that. We're not chasing any of those. I said we're going to target the smaller bolt-on ones and we've been successful in doing that. 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 2 out. I think that where we'd be spending money, it is not out of basin, it's the Haynesville Bossier. But then, 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, and we would look to reinstate a dividend that would be there, even when gas prices are lower. That's important. And 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 trade cash-flow versus what the inflation might be. So if I was...

I was going to mention that, Jay, I think that's exactly right. I appreciate the details.

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 a little more than half into collars. So, you know, we're participating a lot more in the higher prices, you know, and as we progress through this year, every quarter we'll participate more, and then in '23, 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 last year.

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've already made the point, you've been successful with these deals in the last several quarters, but what has changed that makes you want to prepare the market or prepare analysts for $100 million this year? Is it the opportunity set that's changed, that the opportunity sets looking richer, or is it perhaps, alternatively, your appetite for going after these bolt-on deals has changed?

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 really, as people, were looking at the free cash-flow and the debt-reduction, you know, goal is going to be finished, you know, when we don't have a lot of pre-payable 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. 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 markets focus that, 'Hey, that will be something that we'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 well, we're just trying to properly signal. As we're getting very close to our return to capital programs being put in place, we want to have everybody thinking of all the right priorities.

Yes, 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 million, $35 million range, kind of 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, really, really strong. That's not a foreshadow of what we're doing, it's just trying to have clarity to tell you what we might be doing if that opportunity comes along.

Got it. I think, if I understand right, it's because your deleveraging is happening more quickly, you guys want to make sure that's in the picture too, so people have the right kind of landing spot for year-end, you know?

Right. That is absolutely correct.

And I explained our appetite for that type of activity. We think that's a number that well encompasses what we could possibly do. It may take more than a year to do that, you know, but you will see us spend dollars as we can pick up additional acreage. You know, even in the first quarter, we had a modest amount of that spending in that category.

Well, I don't think you can look at us trying to buy something 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% HPP. They gave us a year's worth of drilling and it increased our lateral lengths on existing locations that we had. In other words, if it complements us like that, 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 that we think they'd want us to do anyhow, you know, we're setting those dollars aside, period.

So, it's really the timing. 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. And so, it's just in our current DNC schedule, it's the timing of the completions and when those wells are turned to sales.

No, it's not.

And I think, 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, and so, some of it's probably the timing of when those drilling and completion dollars are spent, but it's no change in the rig count or the frack account.

Yes, and we use some of, Charles, we use some of our operating rigs and operating frack crews for third-party activity including the, you know, what we do with our majority stockholder. And 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 or maybe I think we're probably using, you know, almost 100% of our operated, you know, services for our own stuff. So, I think that there's a, I'm pretty certain that we do have a ramp-up of activity and in wells that we have a little bit lower working interest which also have a, you know, kind of influence on how the cadence of the capital spending.

Just a follow-up on that earlier question. You mentioned about 14% of your volumes are being sold directly to LNG and that should grow over time and give me more exposure to Gulf Coast pricing rather than more regional pricing? My question is this, 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 realm of the large trades out there?

Yes, that's a great question. I think that, you know, right now we see directly supply in 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 that it was priced off on IMAX, very tightly off on IMAX minus a penny or so. But as far as participating in, you know, international pricing, you know, I think that's something we're exploring, but, you know, I think you actually have to own the facilities. I think, as you start to potentially invest in owning the facilities, I think you can probably achieve that because 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, unusual price changes cause us not to be correlated, you know, with our physical sales. But I think that we're exploring that and I think other maybe producers are exploring it. It may be that, you know, we have own equity in these facilities, and then from that viewpoint, then you would have the ability, you know, to use some of that capacity you own to maybe actually sell in a different market.

Yes, and that question, that's the logical step for us to look at is we have been looking at it.

Based on our math, it looks like production has increased by about 9% in the second half of '22 versus the midpoint of your second-quarter production guide. Hit the bottom end of your full-year 2022 production guide. Do you see any challenges in hitting that number?

I mean one. For 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 a sequential growth rate, I don't know if I'll 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 to go all the way up to 9%.

But yes, we did, you know, earlier, you know, we increased our rig count, increased our activity levels, you know, as we began this year. But if you, 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 2 to 3 to 4 together. It takes almost 6 months before you start seeing the fruit of that investment. And I think that's really the second half of the year. Yes, 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, and I think we have some increases that we expect in the second quarter as we've got it too.

Right. And that lag is why the third quarter is the highest growth, sequential growth period of the year.

Yes. And this really is. It's the fact that we added the 2 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.

Yes, it's just the nature of our operations; we drill a high volume of wells, and they don't always come in a consistent manner due to their limited availability. This is simply how our business operates, and it can be a bit uneven.

I wanted to ask you about lateral lengths and to provide some perspective. Can you discuss the technical aspects and the land factors that will allow you to increase the length to over 10,000 this year, compared to 8,800 last year? A breakdown of that information would be appreciated.

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, and Louisiana obviously, you got sectional units, so, you know, you've kind of got some preset lengths. You can pick to drill, you know, you can drill one section, you can drill, you know, a 10K 2 sections, or you can drill, you know, a 3 sections as a 10K or you can drill, you know, 2 7,500-foot laterals instead of one 15,000-foot lateral, you know, over in Texas, you know, you just basically got the acreages and units that are just random sizes and shapes. So really it's just kind of more random lengths. So, I mean, you could have some 11,000-foot lateral 13, you know, just any number that you want to make it if you've got a big enough position. So, we're fortunate, Louisiana, that we do have a lot of areas where we can drill to have the opportunity to drill 15,000-foot laterals. And we did it, it's obviously way more economical, and the benefits are so much greater to drill one 15 and 2 7,500s. And, on the technical side, I mean, really, we were very confident we could drill the 15,000-foot laterals. On the ones we've drilled today, you know, from a technical perspective, we've had no issues drilling the 15,000-foot laterals and then completing and getting them to sell. So, we've been super excited, you know, about what we've accomplished today. 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 feet in the near future. So, you know, I think, really, for us, you know, with the increase in industry activity we've seen, you know, this kind of downhole tool, reliability has suffered a little bit just as the amount of tools, you know, coming into the shops, and going back out, maybe from a, you know, quality control standpoint. I mean, that's probably the biggest battle that we're fighting today. But as far as the 15,000-foot laterals themselves and making things more difficult, that has not been the case.

Got it. And I was just wondering about your suppliers in general, and 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, part of these cost increases has been labor-related. You know, we have seen coming from all of the, we got 2 rig providers and both of them basically have come forward with cost increases, you know, for their increased cost and labor. So, 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 in just kind of servicing some of the tools. But, you know, that kind of comes across to us as a cost increase. You know, it's a way for them to try to mitigate that into, you know, just not get that affected business.

Again, I can start this. You know, it's just a great day for our earnings call. I mean, natural gas, a 13-year high. It's at $8.54. You look at the performance we've had quarter to quarter, I mean, we've had a great quarter with the 15 wells that we turned to sales in the first quarter of '22. If you look at just the catalyst for natural gas. I mean, you got international supply disruptions, you got the US inventory 18% below normal and you've got constraints on the service sector, which we factored into our numbers. You've got storage inventory low in both Europe and Asia, and 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. And then you look at where we're comfortable. We're comfortable where we're headed. Maybe $1 billion for free cash flow. We're the only pure-play Haynesville publicly-traded company, we got 25 years to building inventory. Again, we really are 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. So, 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.