Thank you for joining us for Comstock Resources' earnings conference call for the second quarter of fiscal year 2022. All participants are currently in listen-only mode. Following the presentation, we will have a question-and-answer session. Now, I would like to turn the call over to Jay Allison, Chairman and CEO. Please proceed.

All right. Thank you. You've got a good tone this morning. You start everybody off right in the... Let me tell you we're thankful to be a natural gas producer in the Haynesville, which we think is the best basin 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 a presentation entitled second quarter 2022 results. I am 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 Investor Relations. If you’ll flip over to Slide 2, please refer to Slide 2 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 and such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Now let's start the real presentation Slide 3. The second quarter 2022 highlights. We'll cover the highlights for the second quarter on Slide 3. 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 7.5% senior notes, which 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 $1 per diluted share. Our Haynesville drilling program is going well as demonstrated by the 12.6 net operated wells that we reported on this quarter, with an average initial production rate of 26 million cubic feet per day. We completed a very attractive bolt-on acquisition, which included approximately 60,000 net acres prospective for the Haynesville and Bossier shale 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 our environmental stewardship. I will now turn the call over to Roland Burns to comment on our financial results. Roland?

All right. Thanks, Jay. On Slide 4, we recap the very strong financial results we had for the second quarter. Pro forma for the sale of our Bakken properties which we completed last October, our production increased by 1% to 1.4 billion cubic feet equivalent per day. On a pro forma basis, our adjusted EBITDAX for the quarter grew by 122% over the 2021 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 the 2021 second quarter on a pro forma basis. Our cash flow per share during the quarter was $1.65, up from $0.71 for the second quarter of 2021. Our adjusted net 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 $0.20 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 5. 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 realized price during the second quarter averaged $6.93, reflecting a $0.28 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 realized price to $4.85. We also generated $2 million of margin from third-party marketing in the quarter, which added $0.02 to our average price realization. On Slide 6, we detail our operating cost per mcfe and our EBITDAX margin. Our operating cost per mcfe averaged $0.74 in the second quarter, $0.05 higher than our first-quarter rate. The increase is directly related to the higher natural gas prices we are realizing, as production taxes increased by $0.06 in the second quarter. Our gathering cost increased by $0.02 for the quarter, which was primarily due to the impact of higher fuel costs of the higher value of natural gas that's used in transportation and that was offset by a $0.03 drop in our other lifting costs. Our G&A cost came in at $0.06, 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 7, we recap our first half of this year spending on drilling and other development activities. In the first six months of this year, we spent $487 million on development activities, including $426 million on our operated Haynesville 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 operated horizontal Haynesville 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 the revolver to fund part of the redemption of our 2025 senior notes on May 15. 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 our revolver later this year using free cash flow from operations. And then we ended the second quarter with financial liquidity of almost $1.1 billion. I'll now turn the call over to Dan to discuss the operations.

Okay. Thanks, Roland. Over to Slide 9, 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, we had five extra-long wells with laterals greater than 11,000 feet, with the longest lateral this quarter coming in at 12,237 feet. Today, we have drilled nine 15,000-foot laterals; four of these have been turned to sales, three are currently completing, and two 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 sales 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 are playing an increasing role in offsetting some of our cost increases we are experiencing in this inflationary cost environment. Slide 10 shows our latest D&C cost came 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 D&C 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 D&C cost. Our drilling costs were $478 a foot, a 6% quarter-to-quarter increase, while our completion costs 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 Haynesville acreage in Robertson County, Texas. The Circle M Number One H well was completed in the Bossier shale 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. Now I direct you to Slide 12, where we discuss our natural gas-powered completions with the BJ TITAN fleet. Back in April of this year, we deployed our first site fracturing fleet, which is fueled by 100% natural gas. On the first two pads that were completed using the site 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 tonnes 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 to minimize our completion cost as the cost of diesel has increased significantly. The completions cost on those first two pads were reduced by 15% compared to using one of our conventional diesel fleets. So 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.

Thank you, Dan, and thank you, Roland. If you go to Slide 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 million 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 re-initiate a return of capital program. We did redeem $244 million outstanding on our 2025 senior notes on May 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 borrowings 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 bolt-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 goals 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 specific guidance for the rest of the year.

Thanks, Jay. On Slide 14, we provide updated financial guidance for 2022. Third quarter production guidance is 1.37 bcfe to 1.44 bcfe per day, and the full year guidance remains unchanged at the 1.39 bcfe to 1.45 bcfe 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 million to $975 million, which incorporates the addition of two rigs and is up from $875 million 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 $0.20 to $0.25 both in the third quarter and the full year, while our gathering and transportation costs are expected to average $0.26 to $0.30 in both the third quarter and the full year. With the higher prices for natural gas, our production and ad valorem taxes are now expected to average $0.16 per mcfe to $0.18 per mcfe, while our DD&A rate is expected to average $0.90 per mcfe to $0.96 per mcfe for the year. Cash G&A is expected to be $7 million to $8 million in the third quarter and $29 million 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 million 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 that follow the company. Steve?

Thank you. Our first question comes from Austin Aucoin of Johnson Rice & Company. Austin, your line is open.

Hello. Good morning, Jay, and to your team. Congrats on a strong quarter.

Thank you.

My first question is for the second TITAN fleet expected to be in service in Q1 '23. Is that a good timeframe for the additional two rigs or should we think of EBITDA trying to come earlier?

We have two rigs; one has just started operations this month. The second rig will be arriving at the end of the month. The timeline for the next TITAN fleet in Q1 of 2023 is accurate.

Yeah. Remember the first TITAN fleet, we were supposed to receive in January of this year and we didn't get it till April. So that's the guesstimated date right now.

Thank you. I appreciate that. And as a follow-up, you showed impressive results in 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?

We took a step out on the Circle M. Our management style has involved similar moves throughout our history. For instance, in 2015, we drilled a Bossier well in Northern Sabine, which wasn't the common choice at the time. However, we had previously drilled eight successful Haynesville wells. We decided to explore the Bossier further, and five years ago, we established a presence in Caddo Parish, where we tested it and successfully drilled several wells. The same approach applied in Harrison County five years ago, which also proved effective. In the last quarter, we drilled three wells in Nacogdoches—one Bossier and two Haynesville—and we're bringing those online now, and the results look promising. Our team wanted to determine if we could technically drill a well at Circle M, and the initial results are encouraging. However, it's important to remember that one well is just the beginning, and we'll use this starter well to test our technology for future wells.

Thank you. I appreciate the color. That's all from me.

Thank you. Our next question comes from the line of Umang Choudhary of Goldman Sachs. Umang, your line is open.

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 the fourth quarter. Wanted to get your thoughts on the 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?

Yeah. And on production here, we see obviously more completions. I think we're kind of expecting around 19 or so wells coming online in the fourth quarter about 14 or so in the third quarter currently with a lot of it depends on when they come on in the quarter. So we have seen kind of longer kind of drill times just due to inefficiencies out there due to supply chain issues. 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 these wells online you know that we kind of planned for this year. Yeah. And it's early for us to start giving a lot of guidance for '23 production, but we are obviously adding more rigs. So as we get probably maybe a better outlook later out of the year, we'll give a clearer outlook to what we expect for next year.

Got it. That's really helpful. And acknowledging that you sell most of your 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 will be alleviated?

Yeah, I think you're talking about higher basis differentials there at the main regional hubs Perryville and Carthage. And I think those really reflect the tightness of transportation in the Haynesville that we've seen, as production has increased from there and there's also been a little bit more maintenance than normal going on, which has aggravated the situation. We see some of that loosening up as we get into October as far as the maintenance being over and some new capacity coming into the basin to alleviate a little bit of tightness. Given the tight market, that's why you've seen the differentials, especially at Perryville, be volatile and maybe elevated here. That's what we expect for years, and we really have moved to lock in a lot of our gas sales to Gulf Coast indexes and get more access to transportation to be able to deliver gas to the Gulf Coast index. So we still have somewhere around 10% of our base still is subject to the wider differentials even some of the gas we sell at Perryville. We've tried to do it under longer-term sales agreements where we've been able to lock that in closer to that 25 cents area that has been historical, and that has served us pretty well this summer.

And to Roland's point, we are selling gas directly to every LNG facility in Louisiana.

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 that, 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.

We marked it over 2 Bs a day and produced right at 1.4 Bs and if you look, we have about 1.7 Bs a day with direct access to, as Roland said, this premium Gulf Coast market in sales.

You noticed and could have this year, we've added some additional income through marketing third-party gas, and that's really because we do have some extra capacity in some of our Gulf Coast transport that we're not able to use yet for our 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, we will see that our equity gas first.

As Roland mentioned, I mean, we probably through David Terry and the marketing group and Whitney, etc., we got a pre-plan 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.

Great color. Thank you so much for your response. Thank you.

Thank you. Our next question comes from the line of Neal Dingmann of Truist Securities. Your question please, Neal Dingmann.

Good morning, guys. On the two rigs that you talked about later this year, Jay. Just wondering, I know it's early, any thoughts on the tenure of these rigs and what type of contracts you would walk into these rigs?

So this is Dan. All of our rigs now have either well-to-well contracts or six-month contracts. The rig companies have been hesitant to enter into long-term contracts in the past year. We're seeing rates that are likely up overall, approaching 50% compared to a year and a half ago, but we're monitoring where the market is headed. For now, we're going to maintain our current position and decide on long-term contracts later.

I think that makes a lot of sense. And then just lastly, next question on LNG specifically all continue to position very well. Jay, you pointed out early that given the basin on 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?

We again, we visited with all the major LNG exporters, period. I mean because I think we have more dedicated gas than any other Haynesville producer. But what we're trying to do, we're trying to have enough uncommitted current volumes to support transportation and long-term sales for the partnership, etc. We want to have, if an LNG company comes in, we want to show we had 1,600 net locations in the primary area we have takeaway. We have 400,000 net acres prospective. We do market a lot of gas. I mean we have said, one of the key things is, we've been in this basin 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? Are you exposed to shift international pricing, as the arbitrage is game? Do you do Henry Hub, 115%, etc., 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 grow. I mean we're looking at probably between now and maybe 2026, we expect LNG demand to increase off the Gulf Coast by maybe 6 or 7 Bcf. We know that the world demands more LNG. If you look at even the global deal, Russia exports more gas than anybody in the world, 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 Qatar, and then it's Australia. So if those are all facts, we want to be tied in with the biggest footprint with more locations for the most dedicated gas with relationships that we have to these users. We know them. So that's where we are. I think it's still early in the game, but you see all these commitments—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 areas. So we're right in the middle of this good storm as far as we want to stay and continue to derisk our footprints.

Well said, Jay. Thank you for your time.

Thank you.

Thank you. Our next question comes from Leo Mariani of MKM Partners. Your question please, Leo Mariani.

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, is that right? And it sounds like you're signaling that these two rigs would stay in place for all next year. So it sounds like a fairly good step-up in activity that the case, and it seems like that will lead to kind of much higher production growth. And are you guys have talked about kind of low to mid-single-digit growth? It looks like this could put you closer to double digits here. Any thoughts on that?

Leo, I think again we're going to add the two rigs as Dan answered the question earlier, which was the first question that was asked, we're going to add the two rigs. We do think there's going to be a demand in 2023 for more gas; this will not impact materially our production of gas in 2022. But you'll see it grow in 2023. We still have that 4% production growth that I think in 2022. We don't give a number for 2023 right now.

Now, Leo, we were at seven rigs. I mean, if you go back, we have been at seven rigs for a good part of the year. So this would increase our operated rig count to nine. Now one of these, of the nine rigs I would say, half of the entire rig during this entire year is doing third-party drilling for others. So we're probably really 8.5 rigs, kind of, where we end up. As far as the cadence for the company that we... That's the kind of activity we want to carry into '23.

Okay. So at the end of the day, like 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 we picked up in East Texas, and obviously, the Circle M wells only one well, but it looks good so far there? Plans to kind of drill a bunch of others in that area?

I think it's too early to tell. As we said, we've got a starter well in Caddo. We drilled for more; we had a starter well in Harrison County; we drilled some more. Rockcliff had a starter well in Panola; they drilled a bunch of them. We had a big footprint of acreage in Nacogdoches, and for 2019 and 2021, we didn't drill a well on that acreage; we just drilled three wells, two Haynesville, one Bossier, and they look really good. So it's too early to say what we'll do with that.

Okay. And then could you just comment on hedging real quick? Notice you didn't really hedge in versus the last update. Obviously, prices have been pretty strong here 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 making it after that.

Yes, that's right, Leo. We have hedges in place for the first half of next year. In 2023, our hedge strategy involves wide collars, with a floor around $3 and a ceiling just below $10. This means we are more exposed to full gas prices in 2023 than we were in 2022, where we had less exposure. For the latter half of the year, we are slightly below 50% hedged. When we implemented many of our hedges that are maturing this year, it was largely due to our high leverage following the acquisition of Covey Park and the low gas price environment of 2019 and 2020 amid COVID. Now that our balance sheet is improving and we aim to reduce leverage to under one times, we believe that a large percentage of gas hedging is no longer necessary. If we do hedge in the future, it will likely resemble the wide collars we used in the first half of 2023.

Okay. Thanks for the color.

And again, I think hopefully we can get our leverage below one this next quarter; that's our goal. Hopefully, we can pay off the majority of that $350 million drawn on that RBL in the next quarter. And on hedges, I think we would do the same thing again. When we bought Covey, we had to risk-adjust everything. I think all these companies did, but put in swaps initially, and then we put in the collars. If you look at '23, we are good or bad – I don't know what your opinion is – but for one of the late-stage natural gas companies on the planet, we have a $3 floor that is almost $10 for half of the production we have in the first half of the year, and we are completely open in the second half of 2023. But we are committed to getting our leverage ratio down; we got it down a quarter sooner than we thought that 1.2. We're 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 we told you last quarter that we're not looking to spend $3 billion, $4 billion, $5 billion buying PDP with inventory. We think we've got a lot of inventories; it's quality, and hopefully 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. At the same time, we want to show you that we love the environment as much as anybody, and so we've got the second TITAN BJ TITAN natural gas truck fleet coming our way.

Okay. Thanks, guys.

Thank you, Leo.

Thank you. Our next question comes from the line Fernando Zavala of Pickering Energy Partners. Your question please, Fernando Zavala.

Hey, good morning. I was curious about the bolton acquisition, specifically the infrastructure part. Are you planning to pursue more of that, or was it just a one-time opportunity that came with that deal?

You know what we did, and we kind of broadcasted that we were trying to do this in the last conference call, but towards the third and fourth quarters of last year, we added some deep core acreage that was held by production, and the shallow rights we didn't operate. We did a transaction that we reported on I think in the fourth quarter of 2021. So all we were able to do is we were able to kind of do the same thing, it's in a broader scope. We were able to come in the quarter of the deeper us on the acres that are held by production. So we don't have to put a rig in and start drilling out there immediately. It's a fee paid by another operator. But at the same time, we did buy this 145-mile high-pressure pipeline and the natural gas trading plant for not a lot of money, really $36 million. If you look at the future of LNG, and the U.S. is the lowest cost provider of LNG in the world. You can have the molecules, but you have to transport it. They're having trouble doing it in the Appalachian area. I mean they might get this Mountain Valley pipeline now built because of the Manchin 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 Haynesville is becoming more and more valuable as demand for feed gas and LNG facilities grows. 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 of this was held by production. It's just good; we thought it was a good way to spend $36 million instead of again paying up and buying a company and adding locations.

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 this is going to be one of the things we probably wouldn't have done three or four years ago when we wanted to spend every dollar we could on drilling, but it's something that I think is going forward. If we see unique opportunities to create better markets for our gas in the Haynesville and also keep our transport rates low, we will consider that as opportunities come up.

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 209 people, where we think the bedrock is in our reserves that we like them, and we like the area, and we like the fact that we've managed to extend the stuff in Caddo and Harrison and now into new areas. But that's really what we're doing; we're just staying the 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 is low in carbon.

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.

Thank you. Our next question comes from the line of Noel Parks of Tuohy Brothers. Noel Parks, your line is open.

Do you hear me?

Yes, sir. You're loud and clear.

Great. Sorry, if you commented on this already, I missed this. But with your acquisition, you also got 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 that would sell that.

So if you look at the whole maybe 3 million acres, whatever it is at the Haynesville Bossier encompasses, and you looked at midstream, midstream is becoming more and more valuable. I mean we could build out, and we deal, I guess, for therefore major midstream company within that footprint, and we have for a long, long time. We can build out where the Appalachian area is restrained from building out. But we think midstream, particularly in core areas, fits well. That said, the 145 miles long is high pressure, and it's under-utilized for the most part. We think that is becoming more and more valuable, again, as this demand for feedstock gas or LNG facilities grows. You're going to see the need for a lot more midstream. In fact, one of the things we've been talking about during the call is the tightness of the market in the Haynesville, and post the analyst has written about how tight it is; it’s completely full in Appalachia. I mean, you've just got to molecule more you can really produce, and the midstream market in the Haynesville used to have four, five Bcf of capacity and now is probably not in all as the tightness of the market in the Haynesville, and most of the analysts have written about how tight it is; it’s completely full in Appalachia. I mean, you’ve just got a molecule more you can really produce, and the midstream market in the Haynesville used to have four, five Bcf of capacity and now is probably 99%, 95% full. So we’re pushing on that, and at the same time, you've got tens of billions of dollars of commitments for LNG export terminals along the Gulf Coast. So if you add all that up, I think just take this midstream pipe; it's going to be very valuable.

Yeah. No, this was just a very unique opportunity of a company that's really being dissolved that had this asset that they were 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 found a way to actually buy this in the quarter.

Yeah. As far as treating plants, we already own one treating plant.

Yeah. We already own one treating plant.

200 million a day.

We have some gathering systems and a treating plant in our North Louisiana operations too.

Okay.

So this will be that we could add to our Texas.

Could you discuss any significant shut-in quantities we currently have, apart from the usual amounts we would see prior to fracking?

No. I think our shut-in activity has been around this 4%. It's been kind of what we expect there is every now and then there is maintenance or that’s going to be, but it has not been of long duration for us so far, and we don't foresee. We see it sounds kind of similar for the rest of the year. We just typically expect 3% to 5% shut in all the time from simultaneous operations, a little bit of maintenance here and there, and that's kind of what we average for the first half of this year so far about 4%.

I'll add too that on the shut-in volumes, as Jay mentioned, the tightness on the pipelines being pretty full. We have seen a little bit higher incidents of really just how on pressure from all our pipe that we're connected to have been pretty prevalent this summer. It's not really a big number in a needle mover, but it's definitely something that's been pretty predominant this summer, and I'm sure we'll be looking at that as we go ahead in the next year.

As we mentioned earlier, we expect to see some increased capacity in the Haynesville as we approach fall. That capacity was not going to be available this summer, so there is some relief coming.

Right. Thanks. Thanks for the extra detail. Really helps. That's all from me.

Thank you.

Thank you. Our next question comes from Savannah Leonard of Bank of America. Savannah Leonard, your line is open.

Hey, guys. I just picked Savannah's phone online. How are you today?

Hey, Gregg.

Just wanted to ask a couple of questions. So obviously, buying back the 2029 bonds was a little bit of a surprise. I'm curious, why did you have to 2029? Is there philosophy about reducing senior debt further? And then just one other question, you were just mentioning the 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?

That's a good question about the 2029 bonds. Essentially, it's now our most expensive debt since we've retired the 7.5%. It was the next in line, and we noticed an opportunity during a period of weak trading to eliminate some additional debt with available funds. We believed it was a chance worth taking. Other companies in our sector capitalized on similar weaknesses in bond trading at the time, especially since we have strong free cash flow. Regarding the bolt-on acquisition and the leasing targets, we're more than halfway through the year, and it seems unlikely that we'll reach the upper end of our previous expectations. While we do anticipate more activity, given the outlook for the remainder of the year, I don't think we'll reach even the upper limit of $75 million for that. We just wanted to update on our expectations as we've noticed fewer deals happening than anticipated at the end of the first quarter.

Yeah. We feel the $100 billion. We spent the dollars of $40 plus million. So there is another $20 million, 35 million or so that's got out there that's floating to spin.

Is it your assessment that those deals went away or that they trade someplace else?

They are still out there. Some are gone; some are percolating. I mean we don't expect any…

Yeah, a lot of it. We are looking at unique stuff that's really adds to our current footprint that expands it in a way. So we're not out there just in the M&A market in general looking to find any kind of assets we can.

Well, historically, the greatest way to grow is to say no. In nine out of 100 times say no that way. When you say yes, you've really been chopping to power to looking for. So we said yes on this one; there was 60,000 net acres in the pipeline and the trading. It takes a long time to say yes. And we've had to say no to everything else.

But that was a particular opportunity that we worked for two years and it wasn't like this one. This came on the market or anything. We saw unique assets that we thought could fit onto ours, and we could utilize them differently than the purchaser was doing, and we knew they were in the process of trying to liquidate the companies that had that was a situation. We've been working a long time, and we're excited to get it done in April.

You happen to pick up any production with that, is there?

No production at all. So that was all...

It's all of the acreage. So that's very…

Yeah. That's the unique part. 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 for just about the part that we wanted. So that was a very unique part of that deal.

I mean I think 60,000 net acreage held by production, the 145-mile high-pressure pipeline and the natural gas treating plant for $36 million.

I have a summer cold, but I did actually cough. I would like to follow up on the topic of being opportunistic about reducing debt. If you notice opportunities in the market, how should we expect that to play out in the future? Is there a specific debt target you are aiming for?

I believe that if commodity prices continue to be as strong as they have been, we will have significant extra free cash flow. This is something we will evaluate in the future if those opportunities arise. We have the free cash flow available, and there is a chance to reduce debt at a favorable value. We do intend to pay down the credit facility, which is a priority for us. Our plan is to complete that process this year using the free cash flow from the second half of the year.

Then a priority again, like Roland said, hopefully, we can get the majority of the RBL paid off in the third quarter, probably a little dangling in the fourth, then we want to continue to— we'll add these two rigs, but we're not going to add any leverage. Our goal is to get the shareholders return period, and that's something we need to do is we need to step up and give a dividend and then we need to continue to 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 gas.

All right. Thank you very much for the time, guys. Much appreciate it.

Yes, sir.

Thank you. At this time, I'd like to turn the call back over to Jay Allison for any closing remarks. Sir?

Okay. Great. I love the questions. Thank you for your time. It's the most valuable thing you have. As we look at the world LNG demand perspective our 5.3 Bcf a day in 2022 and the U.S. provides about 22% of that, 11 to 12 Bcf a day. So we look at that backdrop worldwide because the commodity we have is a worldwide commodity that really affects the visit in 2016. And then, if you look at the worldwide energy storage, it shows up by what charging coal prices, natural gas prices, and oil prices. If you look at the LNG market along the Gulf Coast, I mean we added one LNG project in 2020 and times have changed from 2020 to 2022, particularly after the Russia invasion. So we look at the U.S.; we've got the low cost, the provider of LNG in the world. We have – natural gas is the world's fastest growing fossil fuel, America's number one power source. What we want to do is continue to derisk our footprint to continue to have really high margins, low-cost predictability, and continue to have a pristine balance sheet so that we can share with our stakeholders. We work for you, and we can 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.

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