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spk04: Thank you for standing by and welcome to Comstock Resources second quarter fiscal year 2022 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you're willing to press star 1 1 on your telephone. I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.
spk05: All right. Thank you. You got a good tone this morning. You started everybody off right. Let me tell you, we're thankful to be a natural gas producer in the Hainesville, which we think is the best base in North America to have dry natural gas. So anyhow, welcome to the Comstock Resources second 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 results presentation. There you'll find our presentation titled Second Quarter 2022 Results. I have Jay Allison, the Chief Executive Officer of Comstock, and 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 Investment Relations. If you'll flip over to two, please refer to slide two in our presentation and note that our discussions 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. Now, start the real presentation. Slide three, the second quarter 2022 highlights. We'll cover the highlights of the second quarter on slide three. In the second quarter, we generated $190 million of operating free cash flow. We also retired $271 million of our senior notes, including the redemption of our seven and a half senior notes we assumed when we acquired Covey Park, and we repurchased $26 million of our six and three quarter senior notes in the open market. We brought our leverage down to 1.2 times. Our EBITDAX for the quarter came in at $515 million or 105% higher than last year. Our operating cash flow increased 133% to $458 million or $1.65 per diluted share. Revenues after hedging for the quarter were $604 million and 86% higher than last year. Our adjusted net income for the quarter was $274 million, or a dollar per diluted share. Our Hainesville drilling program is going well, as demonstrated by the 14, or 12.6, net operated wells that we reported on this quarter, with an average initial production rate of 26 billion cubic feet per day. We completed a very attractive bolt-on acquisition, which included approximately 60,000 net acres prospective for the Hangel and Bossier Shell and a 145-mile high-pressure pipeline and natural gas treating plant for $36 million. We also achieved certification for our natural gas production under the MIQ standard for methane emissions measurement, which demonstrates environmental stewardship. I will now turn the call over to Roland Barnes to comment on our financial results. Roland?
spk07: All right. Thanks, Jay. On slide four, we recapped the very strong financial results we had for the second quarter. Pro forma for the sale of our Balkan properties, which we completed last October, our production increased by 1% to 1.4 feet equivalent per day. On a pro forma basis, our adjusted EBITDAX for the quarter grew by 122% over 2021's second quarter to $515 million, and it was driven mostly by stronger natural gas prices. We generated $458 million of cash flow during the quarter, a 159% increase over 2021's second quarter on a pro forma basis. Our cash flow per share during the quarter was $1.65, up from 71 cents for the second quarter of 2021. Our adjusted debt income for the second quarter was $274 million, a 454% increase from the second quarter of 2021, and earnings per share came in at $1 as compared to 20 cents in the second quarter of 2021. We generated $190 million of free cash flow from operations in the quarter, 586% higher than the second quarter of last year. The growth in EBITDAX and the retirement of our senior notes in the quarter drove a substantial improvement to our leverage ratio, which improved in the quarter to 1.2 times, down from 2.9 times in the second quarter of 2021. Improved natural gas prices were the primary factor driving the strong financial results in the quarter. A breakdown of our gas price realizations is presented on slide five. During the second quarter, the quarterly NYMEX settlement price averaged $7.17, and the average Henry Hub spot price averaged $7.39. So during the quarter, we nominated 83% of our gas to be sold at index prices tied to the contract settlement price, and we sold the remaining 17% of our gas in the daily spot market. Therefore, the expected NYMEX reference price for our sales in the second quarter would have been $7.21. Our real odds price during the second quarter averaged $6.93, reflecting that 28 cent differential. Our differential stayed tight in the quarter, as we only have 10% of our production subject to the wider regional indexes at Perryville and Carthage. In the second quarter, we were 54% hedged, which reduced our real odds price to $4.85. We also generated $2 million of margin from third-party market in the quarter, which added two cents to our average price realization. On slide six, we detail our operating costs per MCFE and our EBITDAX margin. Our operating costs per MCFE averaged 74 cents in the second quarter, five cents higher than our first quarter rate. The increase is directly related to the higher natural gas prices we're realizing as production taxes increased by six cents in the second quarter. Our gathering cost increased by two cents in the quarter, which was primarily due to the impact of higher fuel cost or the higher value of natural gas that's used in transportation. And that was offset by a three cent drop in our other lifting cost. Our G&A cost came in at six cents, the same as our first quarter rate. And our EBITDAX margin after hedging came in at 85% in the second quarter, up from 81% in the first quarter. On slide seven, we recap our first half of this year spending on drilling and other development activity. In the first six months of this year, we spent $487 million on development activities, including $426 million on our operated Hainesville and Bossier Shale drilling program. $263 million of our CapEx was spent in the second quarter. In the first half of this year, we've drilled 31 wells or 27.7 net wells operated horizontal Hainesville wells. And we've turned 36 or 29.1 net operated wells to sales. These wells had an average IP rate of 26 million cubic feet per day. We also had an additional 1.2 net non-operated wells that we turned to sales in the first half of this year. Slide 8 recaps our balance sheet at the end of the second quarter. We had $350 million drawn on our revolving credit facility at the end of the second quarter after having used Revolver to fund part of the redemption of our 2025 senior notes on May 15th. We also repurchased $26.1 million in principal amount of our 2029 senior notes at a discount for $25 million during the quarter. So in total, we retired $271 million in principal of senior notes during the second quarter. The reduction in our debt and the growth in our EBITDAX drove our leverage ratio down to 1.2 times in the quarter as compared to 2.9 times in the second quarter of last year. We plan on retiring the remaining $350 million outstanding on a revolver later this year using free cash flow from operations. And then we ended the second quarter with financial equity of almost $1.1 billion. I'll now turn the call over to Dan discuss the operations.
spk01: Okay, thanks, Roland. Over on slide nine, so this just shows our average lateral length for the wells we've drilled since 2017. Our lateral lengths averaged 9,612 feet in the second quarter on the 16 wells that we turned to sales. Among the 16 new wells were five extra-long wells with laterals greater than 11,000 feet, with the longest lateral this quarter coming in at 12,237 feet. To date, we have drilled nine 15,000-foot laterals. Four of these have been turned to cells. We've got three that are currently completing and two that are waiting on completion. We're also in the process of drilling our tenth 15,000-foot lateral. The longest lateral drilled and completed to date stands at 15,291 feet. By year end, we anticipate turning 69 gross wells to cells with an average lateral length of 10,050 feet. 18 of these wells are expected to be longer than 11,000 feet and nine of the wells being 15,000 foot laterals. We've been really pleased with our progress to date drilling these 15,000 foot laterals They're playing an increasing role in offsetting some of our cost increases we're experiencing in this inflationary cost environment. Slide 10 shows our latest D&C cost trend through the second quarter for our benchmark long lateral wells. These include all our wells with lateral lengths greater than 8,000 feet. 13 of the 16 wells that we turned to sales during the quarter were long laterals. Our DNC cost averaged $1,262 per foot in the second quarter, representing a 12% increase from the first quarter and a 21% increase from our average 2021 DNC cost. Our drilling cost were $478 a foot for a 6% quarter-to-quarter increase, while our completion cost increased 17% quarter-to-quarter, up to $784 a foot. The cost increases we experienced during the second quarter were purely driven by the cost inflation we're seeing across the basin. On slide 11, this is a summary of our second quarter well activity. Since the last call, we have turned to sales 14 additional wells. The wells were drilled with lateral lengths ranging from 5,373 feet up to 12,237 feet. and had an average lateral of 9,577 feet. The individual wells were tested at IP rates ranging from 12 million cubic feet a day up to 37 million cubic feet a day, with the average IP settling in at 26 million a day. The second quarter results also include the completion of the first well drilled on our western Hainesville acreage in Robertson County, Texas. The Circle M number 1H well was completed in the Boser shell with a 7,861 foot lateral. The well was tested at 37 million cubic feet a day and has been flowing for approximately 90 days with an average rate of 30 million a day. I'll now direct you to slide 12 where we discuss our natural gas powered completions with the BGA Titan fleet. Back in April of this year, we deployed our first Titan fracturing fleet, which is fueled by 100% natural gas. On the first two paths that were completed using the Titan fleet, we eliminated 1.4 million gallons of diesel fuel replaced by cleaner burning natural gas. The environment was positively impacted by removing approximately 2,000 metric tons of greenhouse gas emissions. In addition to drilling the longer laterals to help offset our higher cost of services, this fleet has played a key role in helping us minimize our completion cost as the cost of diesel has increased significantly. The completion costs on those first two pads were reduced by 15% compared to using one of our conventional diesel fleets. But based on the initial results, we have recently entered into a contract with BJ Energy Services for a second Titan natural gas powered fleet. And we expect this to be in service in the first quarter of 2023. I'll now turn it back over to Jay to summarize our 2022 outlook.
spk05: Thank you, Dan, and thank you, Roland. To go to 13, I would direct you to slide 13, where we summarize our outlook for the rest of the year. We are on pace to generate significantly more than our targeted $500 billion of free cash flow, which at current commodity prices could approach $1 billion. The first priority of the free cash flow generation remains the reduction of our debt level to pave the way to reinitiate a return of capital program. We did redeem $244 million outstanding on our 2025 senior notes on May the 15th, and we repurchased $26 million of our 2029 senior notes at a discount to par in June. We expect to repay the $350 million remaining borrowing outstanding under our bank credit facility by year end. We are investing a little more in our Haynesville drilling program by adding two operated rigs before the end of the year, which will drive additional production growth in 2023. We're also earmarking $50 million to $75 million for both on acquisitions and leasing activity for this year. which includes the $43 million already spent in the first half of this year. Even with our additional investment in our future growth and our plans to repay an additional $350 million of debt, we will have substantial free cash flow to start a return of capital program. We have now exceeded the leverage goal we set and now expect to reinstate our shareholder dividend during the fourth quarter of this year. And lastly, we will continue to maintain and grow our very strong financial liquidity. I'll now have Ron provide some specific guidance for the rest of the year. Ron. Thanks, Jay.
spk11: On slide 14, we provide updated financial guidance for 2022. Third quarter production guidance is 1.37 to 1.44 BCFP per day. and the full year guidance remains unchanged at the 1.39 to 1.45 BCF a day we provided back in May. During the third quarter, we currently plan to turn to sales 11 to 15 net wells. Our development CapEx guidance is $925 to $975 million, which incorporates the addition of two rigs and is up from the $875 to $925 million we provided in May. The 2022 wells have an average lateral length that's about 14% longer than last year, which is helping to offset some of the cost inflation. In addition to what we spend on our drilling program, we could spend up to a total of $75 million on bolt-on acquisitions and new leasing, which includes the $43 million we have already spent this year. Our LOE is expected to average 20 to 25 cents, both in the third quarter and the full year, while our gathering and transportation costs are expected to average 26 to 30 cents in both third quarter and the full year. With the higher prices for natural gas, our production and added warm taxes are now expected to average 16 to 18 cents per MCFE, while our DD&A rate is expected to average 90 to 96 cents per MCFE for the year. Cash G&A is expected to be $7 to $8 million in the third quarter and $29 to $32 million for the full year, while the non-cash portion of our G&A is expected to total approximately $2 million per quarter. Cash interest expense is expected to total $38 to $45 million in the third quarter and $152 million to $160 million for the full year, which includes the impact of the redemption of our 2025 notes in May. On the tax side, our effective tax rate is still expected to average 22% to 25%, and we still expect to defer 75% to 80% of our taxes this year. I'll now turn the call back over to the operator to answer questions from the analysts who follow the company. Lateef?
spk04: Thank you. As a reminder, to ask a question, you will need to press star 1-1 on your telephone. Please stand by while we compile the Q&A roster. Our first question comes from the line of Austin Alcorn of Johnson Rice & Company. Austin Alcorn, your line is open.
spk10: Good morning, Jay, and to your team. Congrats on a strong quarter. Thank you. My first question – oh, sorry. My first question is, with the second Titan fleet expected to be in service in 1Q23, is that a good timeframe for the additional two rigs, or should we think that they would be all trying to get them earlier?
spk01: So the two rigs, we got one that's just started, got underway, and the second additional rig is coming later this month, end of this month. Q1 of 2023 for the next Titan fleet is accurate.
spk05: Now, remember, the first titan plate we were supposed to have received in January of this year, and we didn't get it until April. So that's the guesstimated date right now. Thank you.
spk10: I appreciate that. As a follow-up, you showed impressive results from your Circle M well in Robertson County. Could you provide some more details as to why this was chosen for the step-out of the exploration? And as a follow-up, how many locations do you see on the acreage?
spk05: Yeah, let me, you know, we've managed, like to step out on the circle M, we've managed, our management style has been like this numerous times. If you follow us a long time, if you go back to 2015, you know, we drilled a bozier well in the Soda Parish when it wasn't popular to drill bozier wells. And we had drilled eight successful Hanesville wells before that. So we wanted to test the bozier. And that kind of kicked off a bogey program. And then five years ago, you know, we had a footprint in Caddo Parish, and we wanted to test it. And we drilled several wells, and it turned out to be nice. Same thing in Harrison County five years ago. We wanted to farm up our position there, and that worked. And even if you go back even to this last quarter, we drilled three wells in Nacogdoches where one was a bogey or two were angels. And we're bringing those online today and they look really good. So we really stepped out on the same thing with the Circle M. You know, our team wanted to see if we could technically drill a well out there. It looks good. We reported it. But, you know, one well is only one well. We'll test our technology on the next well and, you know, we call this the starter well.
spk10: Thank you. I appreciate the call. That's all from me.
spk04: Thank you. Our next question comes from the line of Umang Chaudhry of Goldman Sachs. Umang, your line is open.
spk00: Hi, thank you. Good morning, and thank you for taking my questions. My first question is on production outlook. Your guidance calls for a step up in production in fourth quarter. Wanted to get your thoughts on cadence of completions in the second half. And also, given you have added two rigs in 2023, any initial read on production next year would be really helpful.
spk07: Yeah, on production, yeah, we see obviously more completions. I think we're kind of expecting, you know, around 19 or so wells being coming online in the fourth quarter, about 14 or so in the third quarter currently, you know, and of course a lot of it depends on when they come on in the quarter. So, you know, we have seen kind of longer kind of drill times just due to inefficiencies just out there due to supply chain issues and, you know, And so I think that's kind of pushed some of the production a little bit later in the year, this year, but we do see getting all these wells online, you know, that we kind of had planned for this year. Yeah, and it's early for us to start giving a lot of guidance for 23 production, but, you know, we are obviously adding, you know, more rigs. And so as we get, you know, probably later on in the year, we'll kind of give a really good outlook to what we expect for next year.
spk00: Got it. That's really helpful. And acknowledging that you sell most of the volumes on the Gulf Coast markets, I wanted to get your thoughts on the recent Perryville differentials. What is driving the weakness, and when do you expect that to be alleviated?
spk07: Yeah, I think you're talking about higher basis differentials there at the main regional hubs of Perryville and Carthage. And I think those really reflect the tightness of transportation in the Haynesville you know, that we've seen, you know, as, you know, production has increased some there. And there's also been, you know, more kind of a little bit more maintenance than normal going on, which is, you know, aggravated the situation. We see some of that loosening up as we get to into October as far as the maintenance being over and, you know, some new capacity coming to the basin to alleviate a little bit of tightness. Given the tight market and, you know, the That's why you've seen the differentials, especially at Perryville, be volatile and maybe elevated here. We've expected this for years and really have moved to lock in a lot of our gas sales to Gulf Coast indexes and got more access to transportation to be able to deliver gas to the Gulf Coast indexes. We still have somewhere around 10% of of our basis still that's subject to the water differentials. Even some of the gas we sell at Prairieville, we've tried to do it under longer term sales agreements where we've been able to lock that in closer to that 20, 25 cent area that has been historically, and that's served us pretty well this summer.
spk05: Well, and to Roland's point, we are selling gas directly to every LNG facility in Louisiana.
spk07: Yeah, we see that increasing, especially as we go into next year and we continue to engage in talks. We want to be a big supplier to especially the Louisiana LNG shippers as we have a lot of gas that we can deliver to them. So that's the ultimate driver of demand in our region. And that's where we can probably get the best price realizations.
spk05: You know, we market over two bees a day and produce right at 1.4 bees. And if you look, we have about 1.7 bee a day with direct access to, as Roland said, this premium Gulf Coast market and sales.
spk07: Yeah, and you noticed in kind of this year we've had, you know, we've added some additional income through marketing third-party gas, and that's really because we We do have some extra capacity in some of our Gulf Coast transport that we're not able to use yet for equity production. So as we have that excess capacity and the difference between the Gulf Coast indexes and the regional differences have been pretty significant, we've been able to go to some third parties and help them get a better price and then also make some margin for ourselves by using some of that capacity. But as we need that capacity, as our production grows in the area, you know, we'll just use it for our equity gas first.
spk05: I'd rather mention, I mean, we probably, through David here and the marketing group, Whitney, et cetera, you know, we try to pre-plan this for a year, year and a half out. But we have 400,000 plus acres, and that footprint really provides us a lot of flexibility to optimize the drilling activity where we're going to put these wells and drill them.
spk00: No, great caller. Thank you so much for your response. Thank you.
spk04: Thank you. Our next question comes from the line of Neil Dingman of Truist Securities. Your question, please, Neil Dingman.
spk08: Morning, guys. On the two rigs that you talked about arriving later this year, Jim, just wondering, I know it's early. Any thoughts on the tenure of these rigs and, you know, what type of contracts you would lock into these rigs?
spk01: So this is Dan. Yeah, we've... All of our rigs we got now are on either basically well-to-well contracts or six-month contracts. You know, the rig companies have been reluctant to enter any long-term contracts just in the kind of recent past here. So, you know, we're looking at rates that are up probably overall. I mean, you're approaching 50% from, you know, a year and a half ago or so. So, you know, just kind of seeing where the market goes. I mean, we're going to kind of sit where we're at status quo for the moment and, you know, go from there as far as deciding on long-term contracts.
spk08: Yeah, I think that makes a lot of sense. And then just lastly, next question on LNG specifically, you all continue to be positioned very well. Jay, you pointed out early, I think, given the basin to benefit from potential LNG projects. I'm just wondering, again, I know it's really not a lot going on, but could you give any color on just any potential new LNG contracts you might be seeing out there?
spk05: You know, we, again, we visited with all the major LNG exporters, period. I mean, because I think we have more undedicated gas than any other Hainesville Bocher producer. But, you know, what we're trying to do, we're trying to have enough uncommitted current volumes to support transportation and long-term sales with a partnership, et cetera. We want to have, you know, if an LNG company comes in, we want to, showing we have 1,600 net locations in the primary area. We have takeaway. You know, we have 400,000 net acres perspective. We do market a lot of gas. I mean, and we have, you know, one of the key things is we've been in this area since probably 1991. So we have relationships with every midstream provider. So I think we have everything that they would want. The question is, What do you do with pricing? Do you expose yourself to international pricing as arbitrage, as an end game? Do you do Henry Hub, 115%, et cetera, which that's what 80% of the contracts look like. We just want to be in a position to have a competitive advantage for the stakeholders that we have when LNG continues to blossom. I mean, we're looking, as probably your numbers, Between now and maybe 2026, we expect the LNG export to decrease off the Gulf Coast by maybe six or seven Bs. We know that the world demands more LNG. If you look at even kind of the global deal, you know, Russia exports more gas than anybody in the world, multiple of two, multiple of two. But 80% of that is pipelines. But it's still an issue with Russia. So 20% is LNG. If you look at the big LNG exporters, I mean, it's the U.S. We just surpassed gutter. And then it's Australia. So those are all facts. And we want to be tied in with the biggest footprint, with more locations, with the most undedicated gas, with relationships that we have to these users. And we know them. So that's where we are. I think it's a little early in the game, but you see all these commitments. You know, the single largest financial investment in the world, I think we heard, was Venture Global's $13-plus billion commitment for LNG in the Gulf Coast area. So we're right in the middle of this good storm. That's where we want to stay and continue to de-risk our footprints.
spk08: Well said, Jay. Thank you for your time.
spk04: Thank you. Thank you. Our next question comes from Leo Mariani of MKM Partners. Your question please, Leo Mariani.
spk09: Hey guys, wanted to follow up on the addition of the two rigs. Just wanted to kind of make sure I understand where we're at. Were you guys at five rigs prior to these two new rigs and that gets you to seven? You know, is that right? And it sounds like you're signaling that these two rigs would you know, stay in place, you know, for all next year. So it sounds like a fairly good step up in activity if that's the case. And it seems like that would lead to kind of much higher production growth. I know you guys have talked about kind of low to mid single digit growth. Looks like this maybe could put you, you know, closer to double digits here.
spk05: Any thoughts on that? Leo, I think, again, we're going to add the two rigs as Dan answered the question earlier, which is the first question that was asked. We're going to add the two rigs. We do think there's going to be a demand. know in 2023 for more gas uh this will not impact uh materially our production of gas in 2022 but you'll see it grow in 2023 you know we still have that four percent production growth i think in 2022 we don't give a number for 2023 right now now and and leo we we were at seven rigs you know i mean if you go back i mean we've been at seven rigs for a good bit of this year so this would increase our operating recount to nine
spk07: Now, one of these nine rigs, I would say, you know, half of an entire rig during this entire year is doing third party, is drilling for, you know, for the Joneses. So it's probably really eight and a half rig kind of where we end up, you know, as far as the cadence for the company. That's the kind of activity we want to carry into 23.
spk09: Okay, so at the end of the day, when you guys look at the decision to kind of step up the rig count, obviously the whole natural gas strip futures curve has kind of moved up here. I'm sure that's a key part of it, but are you also going to try to center some of this incremental activity in some of the new acreage you picked up in East Texas? And obviously Circle M well is only one well, but it looks good so far. Are there plans to kind of drill a bunch of others in that area?
spk05: I think it's too early to tell. As we said, We've got a starter well. You know, we had a starter well in Caddo. We drilled some more. We had a starter well in Harrison County. We drilled some more. Rockliff had a starter well in Panola. They drilled a bunch of them. We had a big footprint of acreage in Nacogdoches. And for 2019, 2021, we didn't drill an acre. We just drilled three wells, two Hainesville, one Bossier, and they look really good. So it's too early to say what we'll do with that.
spk09: Okay, and then could you all just comment on hedging real quick? Notice you didn't really hedge anything, you know, versus the last update. Obviously, you know, prices have been, you know, pretty darn strong here, you know, thus far this summer. Just any update on hedging philosophy? I know you've got hedges that kind of last into the first half of next year, and then you're sort of naked after that.
spk07: Yeah, that's correct, Leo. We're kind of hedged through the first half of next year. And in 23, you know, our hedge position is more in wide callers. with kind of somewhere around a $3 floor, a little less than $10 ceiling. So we're much more exposed to the full gas prices in 23 than we are in 22, where we're a little bit under. For the second half of the year, we're just a little bit less than 50% hedged. So I think we really looked at hedging when we put in a lot of the hedges that we have to pay out on this year. it was because we had a lot of leverage and back in, after we bought Covey Park and then, you know, into a low gas price world of 2019 and 2020, you know, with advent of COVID, you know, so now that we're kind of, the balance sheet is really transforming, you know, and we're going to drive leverage under one times, you know, we view the need to hedge a large percentage of our gas is not necessary, you know, and to the extent that we do hedge in the future, it's probably going to be
spk05: more like the wide callers we did for the first half of 23. okay thanks again i think hopefully we can get our leverage below one this next quarter that's our goal and hopefully we can pay off the majority of that 350 million which is drawn on that rbl uh majority of that i mean the vast majority uh in this next quarter uh and on hedges i think you know we would we would do the same thing again yeah we bought covey we had we had to risk adjust I mean, I think all these companies did. A lot of them put in swaps. We had swaps initially, and then we put in the collars. And if you look at 2023, we're good or bad. I don't know what your opinion is, but we're one of the least aged natural gas companies on the planet. I mean, we'll have $3 floors and almost $10 ceilings for half of the production we have in the first half of the year, and then we're completely open the second half of 2023. But, you know, we committed to get our leverage ratio down. We got it down a quarter sooner than we thought to that 1.2. We committed to give a shareholder return program. We're pretty close to that. In fact, we've got the leverage ratio to do that. We've committed not, you know, we told you the last quarter, we're not looking to spend $3, $4, $5 billion buying PDP with inventory. We think we've got a lot of inventory that's quality, and hopefully we can, we can add some more inventory as we drill some wells. That's been our view and that's been our drumbeat for a long time and we've executed on it. And at the same time, we wanna show you that we love the environment as much as anybody. And so we've got the second Titan, a BJ Titan natural gas frac fleet coming our way.
spk09: Okay, thanks guys.
spk04: Thank you Leo. Thank you. Our next question comes from the line of Fernando Zavala of Pickering Energy Partners. Your question, please, Fernando Zavala.
spk02: Hey, guys. Good morning. I was wondering if the – on the bolt-on acquisition, the infrastructure portion, is that something that you're actively looking to do more of, or was that just a one-time opportunity that came with that package?
spk05: Well, you know what we did, and we kind of broadcasted that we were trying to do this in the last conference call, but toward the third and fourth quarter of last year, we added some deep rights on acreage that was HPP, and the shallow rights, we didn't operate. We did a transaction that we reported on, I think it's the fourth quarter of 2021. So all we were able to do is we were able to kind of do that same thing. It's in a broader scope. We were able to come in and acquire the deep rots on acres that are held by production. So, you know, we don't have to put a rig and start drilling out there immediately. It's HPP'd by another operator. But at the same time, you know, we did buy this 145 mile high pressure pipeline and the natural gas feeding plant for not a lot of money, really $36 million. If you look at the future of LNG, and you know the U.S. is the lowest cost provider of LNG in the world, you know, you can have the molecules, but you have to transport it. They're having trouble doing that in the Appalachia area. I mean, they may get this Mountain Valley pipeline now built because of the deal. But who knows? I hope they do. But we know that we can have midstream in our area. So, this midstream pipe that we're buying, In the Hainesville, they're becoming more and more valuable as demand for feed gas, you know, feedstock gas, LNG facilities grow. So we looked at it and we control it. I think our cost will be lower. And we thought it was a good buy for where we're drilling and the fact that all this is HPP. It's just a good, we thought it was a good way to spend $36 million versus, again, paying up and buying a company and adding locations if you have to buy PDP reserves.
spk07: I think on your question about would we look to do more of that, I think in specific situations where we see the opportunity to protect our cost structure and guarantee ourselves low transport costs and see that we control the gas behind it, it's something we'll consider as we end this year with a very strong balance sheet and a very substantial generation of cash flow. So I think that this is kind of, you know, one of the things we probably wouldn't have done, you know, three or four years ago when we wanted to spend every dollar we could on drilling. But it's something that I think is go forward and we see unique opportunities to create better markets for our gas in the Hainesville and also keep our transport rates low. You know, we'll consider it, you know, as opportunities come up.
spk05: Yeah, and again, I think it proves to you that we think our bedrock, which is our reserves and our technical group and our marketing group and our land group, I mean, the 209 people, we think the bedrock and our reserves, we like them. And we like the area and we like the fact that we've managed to extend this stuff into Caddo and Harrison and, you know, now into the Nacogdoches area. But that's really what we're doing. We're just staying to basics, except this time we're not digesting a big $2.2 billion acquisition. We took that, we grew it, and this is what has been the result of it. And we think any serious low-carbon outlook has to have natural gas as a fundamental resource in it. And we've got the natural gas, which just has low carbon.
spk02: Got it. Thanks for that. And then real quick as a follow-up, do you have an expected location count and average lateral length for the acquired acreage? We do not. That's it for me. Thank you.
spk04: Thank you. Our next question comes from the line of Noah Parks of Toy Brothers. Noah Parks, your line is open. Thank you.
spk03: Do you hear me? Yes, sir. Go ahead, Donald. You're loud and clear. Great. Sorry if you commented on this already. I missed it. But with your acquisition, you also got the 145 miles of pipeline infrastructure. I was just curious about what you thought the potential benefits of that were, and I'm just actually curious as to why the seller would sell that infrastructure.
spk05: Well, if you look at the whole maybe 3 million acres, whatever it is that the Hainesville-Bossier encompasses, and you look at midstream, midstream is becoming more and more and more valuable. I mean, we can build out and, you know, we deal, I guess, with every major midstream company within that footbridge, and we have for a long, long time. And we can build out where the Appalachian, they're restrained from building out. But we think midstream... particularly if it's long midstream, we think in the core area that's 145 miles long, it's high pressure, and it's underutilized for the most part. We think that it becomes more and more and more valuable. Again, as this demand for feedstock gas for LNG facilities grows, you're going to see the need for a lot more midstreaming. In fact, you know, one of the things we've been talking about during the call is the tightness of the market in the Hainesville. And most of the analysts write about how tight it is. You know, it's completely full in Appalachia. I mean, it's not a molecule more you can really produce in the midstream. And the Hainesville used to have four or five Bs of capacity. And now it's probably 90. The tightness of the market in the Hainesville. And most of the analysts write about how tight it is. You know, it's completely full in Appalachia. I mean, it's not a molecule more you can really produce in the midstream. And the Hainesville used to have four or five bees of capacity, and now it's probably 99, 95% full. So we're pushing on that. And at the same time, you've got, you know, tens of billions of dollars of commitments for LNG export terminals along the Gulf Coast. So if you add all that up, I think this midstream pipe is going to be very valuable.
spk07: Yeah, no, this was just a very unique opportunity of a company that's really being dissolved that had this asset that they weren't really utilizing. And I think that this was just a very unique opportunity that we identified a long time ago and stayed around this company that we knew was trying to dissolve and uh and found a way to actually uh buy this from them in the quarter yeah as far as treating plants you know we're already on one trading plan i'm sorry you said you already own one treating plant yeah we have a yeah we already have a we have 200 million a day aiming we have you know some some gathering systems and uh creating plant in our north wisconsin operations too okay so this this will be something we could add to our texas uh yeah okay great do you have any significant uh shutting quantities
spk03: now aside from just what you normally have for the delay before fracking?
spk07: No, I think our shut-in activity, you know, it's been around this 4%, you know, it's been kind of what we expect. Every now and then there's maintenance or something that can be, but it's not been of long duration for us so far and we don't foresee. We see kind of a similar, you know, for the rest of the year, just this We typically, you know, expect, you know, three to 5% shut in all the time from simultaneous simultaneous operations, a little bit of maintenance here and there. Um, and that's kind of what we averaged, you know, the first half of this year so far about 4%. Okay.
spk03: Okay.
spk07: We do, we do see, we have seen if anything longer to sales timeframes. Right. I think that's probably been the only thing that's a little different last year. Yeah, we were super efficient. There were a lot of, you know, last year there was, you know, setting all kinds of new efficiency records for drilling days and getting wells online. And this year, you know, with supply chain, very busy Hainesville area supply chain, you know, we've actually seen those timeframes stretch out. Just haven't been able, you know, just things, they get done, but, you know, not near as efficiently. given Hainesville is a very busy basin. One of the bigger rig increases, the Permian and the Hainesville account for most of the big increases in rigs. And that's just something we've had to deal with this year.
spk01: I'll add too that on the shut-in volumes, Jay mentioned the tightness on the pipelines being pretty full. We have seen a little bit higher incidence of really just high line pressure from all our pipes that we're connected to. Had been pretty prevalent this summer. It's not really a big number and a needle mover, but it's definitely something that's been pretty predominant this summer. And I'm sure it'll be, you know, we'll be looking at that, you know, as we go ahead in the next year.
spk07: And like we said earlier, there's a little bit of a, we'll see some expanded capacity in the Hainesville as we get into this fall. Yeah, that was not going to be available this summer. So there's a little bit of relief coming there.
spk03: Right. Thanks for the extra detail. It really helps. That's all for me.
spk04: Thank you. Thank you. Again, to ask a question, please press star 1 1 on your touch-tone telephone. Again, that's star 1 1 to ask a question. Thank you. Our next question comes from the line of Savannah Leonard of Bank of America. Savannah Leonard, your line is open.
spk06: Hey, guys. It's actually Greg Brody. I just picked up Savannah's phone line. How are you today?
spk07: Hey, Greg.
spk06: Just want to ask a couple of questions. So obviously buying back to 2029, I'm a bondholder. We love seeing that. It's a little bit of a surprise. So I'm curious, why did you go after the 2029s? Is there a philosophy about reducing senior debt further? And then just one other question. You reduced the amount of money you were talking about spending on leasing. I'm curious why you took the steps of reducing that amount and not leaving that open.
spk07: Okay, those are good questions. Yeah, on the 29s, I mean, basically now it's our most expensive debt since we've retired the 7.5%, so it's next in line. And we just saw the opportunity with kind of weak trading there. you know, during that to, you know, retire some extra debt, you know, with fewer dollars. And so that was just an opportunity. I think you saw other companies in our space, you know, took advantage of that same real weakness in the trading of the bonds, you know, at the time, you know, when companies like us have incredible free cash flow. So just an opportunity we saw and took advantage of and, you know, It's another question about the bolt-on acquisition and leasing amount that we targeted. I think the year's more than half over now, and we just don't see hitting that upper end of that other number. We do expect to have some more activity, but given what we just see ahead for the rest of this year, I don't think we'll hit the even upper range of the $75 million for that. we just wanted to signal kind of what we're seeing. Like we, we saw, we saw more deals that probably didn't happen, you know, back at the end of the first quarter who wanted to signal that. And so this is just kind of a adjustment to expectations there.
spk05: Yeah, we pulled a hundred billion in, we spent, you know, the dollars of 40 plus million. So there's another 20, 35 million or so that's kind of out there that's floating to spend.
spk06: Is it your assessment that those deals went away or did they trade someplace else?
spk05: They're still out there. Some are gone. Some are percolating. I mean, we don't expect any.
spk07: Yeah, a lot of it. You know, we're looking at only unique stuff that really adds to our current footprint, you know, that expands it in a way. So, you know, we're not out there just in the M&A market in general looking to find any kind of assets we can.
spk05: Well, historically, the greatest way to grow is to say no. You know, 99 out of 100 times you say no, that way when you say yes, you've really been chopping to find what you're looking for. So we said yes on this one, the 60,000 net acres and the pipeline and the treating. It took us a long time to say yes, and we said no on everything else.
spk07: That was a particular opportunity that we worked for two years. It wasn't like this came on the market or anything. unique assets that we thought could fit onto ours and we could utilize them differently than the purchaser. I mean, the seller was doing it and we knew they were, uh, you know, in the process of trying to liquidate the company. So that was a situation we've been working on a long time and we're excited to get it done in April.
spk06: You didn't happen to pick up any production with that. Is there?
spk07: No, no production at all. So it's all, uh, yeah, it's all, it's all, it's all HPP though. So that's very, yeah, that's, that's, that's the unique part. We actually, uh, We actually partnered with another company who wanted to own the production. And so instead of having to spend a lot of money on that, we were able to keep our expenditures, you know, just to buy the part that we wanted. So that was a very unique part of that deal.
spk05: I mean, think, 60,000 dead acres, HPP. 145-mile high-pressure pipeline and a natural gas trading plant for $36 million.
spk06: And just to follow up, so being optimistic about reducing debt if you see the opportunity in the market, is that something we should expect going forward, or is there an absolute debt target that you are targeting?
spk07: Well, I mean, I think, of course, if commodity prices stay as strong as they have, obviously we have a lot of extra free cash flow that's something that we'll consider in the future. If those two opportunities are there, we have the free cash flow and there's an opportunity to reduce debt at a good value. We do know that we'll pay the credit facility down, so that's front and center. I think we want to go ahead and just finish that off this year with the second half of the year's free cash flow.
spk05: I mean, a priority again, like Alden said, hopefully we can get the majority of the RBL paid off in the third quarter, probably a little dangling in the fourth. And then, you know, we want to continue. We'll add these two rigs. But we're not going to add any leverage. And our goal is to give the shareholders return, period. The next thing we need to do is we need to step up and give a dividend. And then we need to continue to, you know, test our inventory and become better at what we do. And that's on top of the ground. That's the people that are drilling and completing these wells. and marketing the guests.
spk06: Thank you very much for the time, guys.
spk04: Much appreciated. Thank you. At this time, I'd like to turn the call back over to Jay Allison for any closing remarks. Sir?
spk05: Okay, great. I love the questions. Thank you for your time. It's the most valuable thing you have. You know, as we look, the world LNG demands expect about 53 bees a day in 2022, and the U.S. provides about 22% of that, you know, 11, 12 bees a day. So we look at that backdrop worldwide because the commodity we have is a worldwide commodity, really effective as of 2016. And then if you look at the worldwide energy shortage, it shows up by what? Surging coal prices, natural gas prices, and oil prices. And then you look at the LNG market along the Gulf Coast. I mean, we added one LNG project in 2020, and times have changed in 2022, particularly after Russia, you know, invasion. So we look at the U.S. We've got the low-cost provider of LNG in the world. We have, you know, the natural gas is the world's fastest-growing fossil fuel and America's number one power source. And what we want to do is we want to continue to de-risk our footprint to continue to have really high margins, low cost, predictability, and continue to have a pristine balance sheet so that we can serve you. You know, you're the stakeholder. We work for you. We can serve you a return program that's predictable and have inventory that lasts for decades. So we want to be a pure company. So that's our goal. Thank you for your time.
spk04: This concludes today's conference call. Thank you for participating. You may now disconnect.
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