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spk08: Ladies and gentlemen, thank you for standing by and welcome to Q1 2022 Comstock Resources Incorporated 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 1 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.
spk04: 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. 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 entitled, quote, First Quarter 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 presentations and note that our discussion 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'll flip over to slide three. Hannah, 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 script is in the $8.40s. You know, we're sitting as a company on 1,600 drilling locations in the Hainesville-Bossier, which is a natural gas plate nearest the LNG export terminals. And yes, free cash flow is up to probably a billion dollars in 2022 at these prices, and with our hedges in place. And 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 EBITDA 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 51 cents per diluted share. Our Hainesville drilling program is going very well, as demonstrated by the 15 operated wells that we turned to sell since our last operational update that Dan Harrison reviewed momentarily. The IP rates for these wells average 29 million cubic feet per day. So now I'll turn the call over to Roland Barnes to go over our financial results. Roland?
spk05: 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 Balkan properties, which we completed last October, our production increased 3% to 1.3 BCFE a day. Our adjusted EVA DAX 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. So we were only 52, we were only a about 60% hedge this quarter versus in the 70% area in the fourth quarter last year. We generated in the quarter $297 billion 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 cents 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 21, and our earnings per share were 51 cents as compared to 25 cents 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 to 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 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. And 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 are more tied to the contract settlement price, and then we sold the remaining 31% in the spot market. Therefore, the appropriate NIMEX 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 $0.29 differential, which is more or less in line with 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, 21%, 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 three cents to our overall natural gas price realization in the quarter. In slide six, we detail our operating costs per MCFE and our EBITDAX margin. Operating costs per MCFE averaged 69 cents in the first quarter, two cents higher than the fourth quarter rate. Our lifting costs in production and severance taxes both increased by 2 cents, while our gathering costs remained unchanged. Our G&A costs, though, came in 2 cents lower at 6 cents in the quarter. Our EBITX 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 7, we recap our first quarter earnings. Spending on drilling and other development activity, we spent $224 million on development activities in the quarter, $187 million of that related to our operated Hainesville and 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 work over work 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 Hainesville and 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 8, 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 is down to 1.9 times in the first quarter, compared to 2.7 times in the first quarter of 21. We plan on retiring an additional $394 million of debt over the rest of this year, including redeeming our 2025 senior notes on May 15th. We've already issued the formal redemption notice for those notes. We're targeting to have our leverage below one and a half 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, and now I'll turn it over to Dan to kind of talk about our operations in the first quarter.
spk01: 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 corridor and our record longest lateral completed to date. Since 2017, our average lateral length has grown 725 feet on average every year. And over an hour 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 laterals 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 addition of 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 DNC cost trend for our benchmark long lateral wells. This includes all our wells with lateral lengths 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 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. With a 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. 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 tested 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. And these same wells also represent our first two 15,000 foot laterals that we've completed into the Bossier. The BSMC LA 5817 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 today. We are currently running seven rigs and have three frac crews running full time across our acreage. And on one last note, I'd 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.
spk04: All right. Thank you, Dan. Thank you all again. What a great day to have an earnings call with 854 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% to 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 on our existing hedge position, we anticipate generating anywhere from $800 million to $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 will 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 15th, and we expect to pay the $150 million of remaining borrowings outstanding under our bank credit facility. We're also earmarking up to $100 million for both on 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 Hainesville. 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. And 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.
spk09: 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 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 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 D and C, dollars that we will spend in 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 20 to 25 cents in the second quarter and for the full year, while gathering and transportation costs are expected to average 26 to 30 cents 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 to $0.16 per MCFE, as that's just related on gross pre-hedge sales revenues. DDA rate is expected to remain in the $0.90 to $0.96 per MCFE range, while cash DNA is expected to total $7 to $8 million in the second quarter and $29 to $32 million in 2022. On a quarterly basis, the non-cash GNA is expected to run approximately $2 million per quarter. Cash interest during the second quarter expected to total $38 to $42 million and $152 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. Effective tax rate for the year expected to be 22% to 25%, and we now expect to defer 75% to 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. We'll now turn the call back over to the operator to answer questions from analysts who follow the company.
spk08: Thank you. As a reminder, to ask a question, please press star followed by the number one 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 Derek Whitefield with Stievel. Your line is open.
spk10: Thanks, Tim.
spk08: Good morning, all.
spk10: Morning.
spk03: 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? And 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?
spk01: Yeah, this is Dan. I'll say as far as for the first part of your question on the long live rules, 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 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, it's 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 crews, but obviously the cost of diesel, you know, is driving up everybody else's cost of services also.
spk04: 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 frack 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. Got it.
spk03: And as my follow-up, looking out beyond 2022 and thinking about your unique position in the LNG coolant door, 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?
spk04: Well, you know, as of April 1st, we're selling gas directly to every LNG facility in Louisiana. So that's only a month ago. I mean, we're 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. So, you know, we plan on being a material supplier of gas that's needed both in Asia and Europe, and really that's driven by the location that we're at. And we've 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. 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. And where are they located? They're located near where the gas needs to go, and that is LNG overseas.
spk05: Eric, I'd just add that that is kind of the direction we're We expect to be selling more and more of our production directly to the LNG shippers and constant talks 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.
spk03: That's very helpful. Thanks for your time.
spk04: Thank you. Good questions.
spk08: Your next question comes from the line of Umang Chowdhury with Goldman Sachs. Your line is open.
spk00: Hi, good morning, and thank you for taking my questions. Yes, sir. I appreciate your 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 2022 program but also looking ahead to 2023.
spk01: Yeah, so 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 frack cost. We have, you know, we enter into some longer contracts when we can. We've bought ahead on all of our pipe, you know, tubing, casing, So we do stay kind of 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. 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 for future cost increases. I think we've got a little bit of leverage there.
spk00: Great, thank you. 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 shut-in 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.
spk05: Yeah, good questions. Also, this is Roland. 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 refracts, which are not, you know, weren't very common in the lower price environment. Yeah, we don't have a huge exposure to non-op because we have very high working interest, but we have some. And the projects are also, they have such high returns, it's very difficult not to participate. So, We don't like to count on non-op activity for, you know, giving you guidance on production. So, you know, hopefully there will be a little upside as those come on. And 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 there's – they're all such high return projects, you know, 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. Four to 5% is kind of 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 kind of get that done at one time, like the seven wells that we – 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. So, 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. But we do try to schedule and plan to minimize that because, you know, that's a big factor. And, you know, but always – but, you know, really, you know, to keep it in the 3% to 5% level is kind of the norm we expect.
spk04: You know, as you're asking the questions about, you know, non-op opportunities and cost, you know, it probably is a good time to address that we – We said we're kind of earmarking $100 million for bolt-on acquisitions. Now, we threw that number out. I mean, we may not spend that number. And the only 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 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 both homes and additional leasing activity, you know, we think we've got this billion dollars 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, kind of like we have clarity that you should expect inflationary pressures at $8.58 in natural gas in the Hainesville.
spk00: Got it. I appreciate your comments. Thank you.
spk08: Yes, sir. Your next question comes from the line of Neil Dingman with Truist. Your line is open.
spk11: Morning, all. Jay, just on that last question, maybe I'll ask just a bit of follow-up just on the OFS inflation. You guys 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 and most others are kind of rig to rig or well to well on your rigs and tracks, what type of confidence do you have that that's going to be high enough for the rest of the year?
spk04: 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. And then, you know, our drilling is up like, I think, cost up like 13%. Our completions are up like 5%. And our total DNC cost up 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 take – you look at a 680 environment, which is where we were at last Friday, versus an 854 environment, even the 12-month trip. You may see a little more of this. We don't expect it, but – But we want to be honest about it and tell you where we are right now. But, no, we don't expect it. And I think we're the first ones to come out on an earnings call and say, yes, someone has 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 bake 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 and complete wells.
spk11: Thanks for the guide. And then just follow-up for maybe you, Roland, or Ron, just as really on cash returns. I'm just wondering, ballpark, how quickly today's strip now, I mean, you mentioned start of the call, obviously, these fantastic prices. So how quickly today's strip do you anticipate being able to start your cash return program today? And will this – I forget what you all have exactly said. Will the program initially consist of just exclusive dividends, as you mentioned about, you know, wanting to pay out high enough for preferred holders, or would you consider some buybacks as well when this begins?
spk05: That's a good question. Yeah, well, obviously with the much, much higher commodity price environment, it's accelerating, you know, everything. But, you know, we don't want to get ahead of the overall plan, so – you know, the centerpiece of our, of this whole year is the bond redemption. Yeah. 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. And then really, you know, I think we were signaling that, you know, at least by the, you know, probably by the fourth quarter for sure, you know, hopefully reinstate the dividend that we have not had since 2014. But, those are all very key. And I think after that, you know, we, we have guided that, Hey, we do want to invest in, uh, you know, in our overall footprint in the Hainesville. So we're saying we're earmarked a hundred million dollars toward, you know, lease acquisition bolt-ons might not be able to spend all that this year, but it's a priority. Um, so we, that's the reason why we signal that. And, um, 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.
spk04: 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 bulk-owned ones, and we've been successful in doing that. But the other thing, you know, You can put a big X on we're not looking to make an acquisition of the Hainesville 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 Hainesville-Bossier. And then if you look at what we'd be doing with that money, we're going to get the 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 free cash flow versus what the inflation might be.
spk11: I was going to mention that, Jay. I think that's exactly right. I appreciate the details.
spk05: Go ahead.
spk11: I'm sorry.
spk05: 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 we're participating a lot more in the higher prices, 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 is how it will happen in the company compared to, you know, kind of last year. Great details. Thanks, guys.
spk08: Your next question comes from the line of Charles Mead with Johnson Rice. Your line is open.
spk06: Good morning, Jay and Roland, and to the rest of the Comstock crew there.
spk04: Yes, sir. Hi, Charles.
spk06: 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, but what has changed that makes you want to – prepare the market and prepare analysts for $100 million this year. Is it the opportunity set that's changed, the opportunity set looking richer, or is it perhaps alternatively your appetite for going after these bolt-on deals has changed?
spk05: I think what's really changed, Charles, is we think there are good opportunities and we do think we're going to do some. And so 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 free 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. It's not that we probably – think that, um, 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, um, you know, out of the free cashflow. Uh, 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, as, you know, we're getting very close to our return of capital programs being put in place. We want to have, uh, everybody thinking of all the right priorities. Um,
spk04: Yeah, I think we wanted 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, 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, I mean, we look really, really strong. That's not a foreshadow of what we're doing. It's just trying to have clarity there. to tell you what we might be doing if that opportunity comes along.
spk06: 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.
spk05: Right. That is absolutely correct. And explain 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, you know, 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.
spk04: 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. 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, 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 you'd want us to do anyhow, we're setting those dollars aside, period. Got it.
spk06: Got it. My follow-up question is on your CapEx trajectory over the year. If we look at what you did in 1Q and then your guide for 2Q, it looks like 2Q is the peak CapEx quarter, but then it trails off significantly in the back half of the year. So is activity going to follow that same trajectory, or is there something else in the picture that I should be thinking about?
spk09: 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. 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.
spk06: but 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?
spk09: No, it's not. It's not. And I think Dan mentioned the number of long lateral wells we were going to drill this year, and 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 fleet count.
spk05: Yeah, and we use some of, Charles, we use some of our operated rigs and operated frack crews for uh, for third party activity, including the, you know, the, you know, what we do with our majority stockholder. And I think just the way the big schedule works, um, the activity on that front is, is, uh, is ramping up in the third quarter. Um, you know, compared to the second where maybe I think we're probably using, you know, almost a hundred percent of the, uh, 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, uh, a ramp-up of activity, and it wells that we have a little bit lower working interest, which also have a kind of influence on how the cadence of the capital expending.
spk06: Right. That's all helpful detail. Thank you, Roland. Thank you, Ron. Thank you.
spk08: Your next question comes from the line of Phillips Johnston with Capital One. Your line is open.
spk02: Hey, guys. Thanks. Just to follow up on the earlier question, question. You mentioned about 14% of your volumes are being sold directly to LNG shippers and that should grow over time and give you more exposure to Gulf Coast pricing rather than more regional pricing. My question is, 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?
spk05: 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, you know, a new long-term supply agreement with one of them that's a 10-year agreement that has, you know, like it's priced off of NYMEX, you know, very tightly off of NYMEX, minus a penny or so. But as far as participating in, you know, international pricing, you know, I think that's, Yeah, that's something we're exploring, but 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 unusual price changes cause us not to be correlated with our physical sales, but I think we're exploring that, and I think other maybe producers are exploring it. Maybe that, you know, we have own equity in these facilities, and then from that viewpoint, then you would have the ability to, you know, to use some of the capacity you own to maybe actually sell in a different market.
spk04: Yeah, that's a good question. That's a logical, you know, step for us to look at as we have been looking at it.
spk02: Okay, guys. Sounds good. Thank you.
spk08: Your next question comes from the line of Stephen Beckert with KeyBank. Your line is open.
spk10: Hey, guys. Based on our math, it looks like production has to increase by about 9% in the second half of 22 versus the midpoint of your second quarter production guide at the bottom end of your full year 2020, 2022 production guide. Do you see any challenges in hitting that number? Thanks.
spk09: I mean, for our drilling schedule, no. We would have updated guidance if that would have been the case. I think when I look at kind of a 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 upper single digits, but I don't think I'm all the way up to 9%.
spk05: But, yeah, we did earlier, we increased our rig count, increased our activity levels as we began this year. But if you really look at the way that 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. And I think that's really the second half of the year, you know, 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 we do have a, I think we have some increases that we expect in the second quarter as we've got it to.
spk09: Right. And that lag is why the third quarter is the highest growth sequential growth period of the year.
spk05: Yeah, just really the nature of these are, 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. And so that's kind of the nature of our business. It's, you know, it gets a little lumpy.
spk01: Yeah. This is that. It really is. It's 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.
spk10: Okay, great.
spk08: Thank you.
spk04: Thank you.
spk08: Your next question comes from the line of Noel Parks with Tuhi Brothers. Your line is open.
spk07: Hi, good morning.
spk02: Morning.
spk07: I 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've already taken them over, expect to take them over 10,000 this year versus, I think it was 8,800 last year. So if you could sort of break that out, that'd be great.
spk01: 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've 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, two sections, or you can drill, you know, three sections as a 10K, or you can drill, you know, 270, 500 foot laterals instead of 115,000 foot lateral. You know, over in Texas, you know, you just basically got, you know, the acreages in units that are just random, you know, sizes and shapes. So really it's just kind of more random links. 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. So we're fortunate in Louisiana that we do have a lot of areas where we can drill, 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 115 than 27500s. 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 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. So we've been super excited 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 laterals longer than 15,000 foot in the near future. So, you know, any 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. But as far as the 15,000 foot themselves making things more difficult, that has not been the case.
spk07: 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?
spk01: 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, we have seen, I mean, from all of the, we've got two reg providers and both of them basically have come forward with cost increases, you know, for their increased cost in labor. So that's part of it. You know, I think on the service side, as far as our tools, you know, they've had, I think things have got pretty tight maybe with some of their suppliers. We're just kind of servicing some of the tools. But, you know, that kind of 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.
spk07: Great. Thanks a lot.
spk08: And 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.
spk04: All right. Again, I'll start this. You know, it's just a great day for earnings calls. I mean, natural gas, 13-year high. It's at 854. 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 22. If you look at just the catalyst for natural gas, I mean, you've got international supply destructions. You've got the U.S. inventory 18% below normal. 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. You've got Comstock and others that produce tri-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 at. We're comfortable where we're headed, maybe a billion dollars of free cash flow. We're the only pure play Hainesville publicly traded company. You've got 25 years of drilling inventory. Again, we really were an industry leader in margins. We've got great free cash flows. 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 can spend it elsewhere. We appreciate it. And we'll put in a good day's work for you. Thank you.
spk08: Ladies and gentlemen, this concludes today's conference call. And we thank you all for participating. You may now disconnect.
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