Comstock Resources, Inc. (CRK) Q2 2022 Earnings Report, Transcript and Summary

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. [Operator Instructions] I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.

All right. Thank you. You 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 the 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 two, 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 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, 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 14 or 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 perspective 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 recapped a 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 2021s 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 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 than 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 priced 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 tied 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 market 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 cost 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 cost. 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 activity. 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 wells 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 to 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 where 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 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 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 and 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 or 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 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 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 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 bolton 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. Ron?

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 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 bolton 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 analyst to follow the company. Steve?

Thank you. [Operator Instructions] Our first question comes from the line of Austin Aucoin of Johnson Rice & Company. Austin Aucoin, 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 1Q '23. Is that a good timeframe for the additional two rigs or should we think that EBITDA trying to come earlier?

So the two rigs we got one that's just started got underway in the second additional rig is coming later this month -- end of this month. Q1 of 2023 for the next TITAN fleet 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?

Yeah. Let me, 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, we drilled a Bossier well in the Norther Sabine -- it wasn't popular drill Bossier wells and we drilled eight successful Haynesville wells before that. So we wanted to test the Bossier that got kicked-off of those programs and then five years ago 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 want to form of our position there and that work and even if you go back even to this last quarter, we drilled three wells the Nacogdoches were one was at Bossier 2 or Haynesville and we're bringing those online today look really good. So we really stepped out on the same thing with the Circle M. Our team want to see if we could technically drill a well out there. It looks good. We reported it. But again a one well is only one well will test our technology on the next well and we call this starter well.

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 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, yeah, we see obviously more completions. I think we're kind of expecting around 19 or so wells being coming online in the fourth quarter about 14 or so in the third quarter currently with 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 just out there due to supply chain issues and so I think that's kind of push some of the production, a little bit later in the year this year, but we do see getting out these wells online you know that we kind of a plan for this year. Yeah. And it's, yeah, it's early for us to start given a lot of guidance for '23 production, but we are obviously adding more rigs. And so as we get probably maybe it was later out of the year will kind of give a really good outlook to what we expect for the next year.

Got it. That's really helpful. And acknowledging that you sell most of 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 are really reflect the tightness of transportation in the Haynesville that we've seen, as production has increased from there and there's also been more a little bit more maintenance than normal going on which is aggravated the situation. We see some of that loosening up as we get to into October as far as the maintenance being over and some new capacity come into the basin to alleviate little bit of tightness. We 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. And that's what we expect this for years and really have moved to lock in a lot of our gas sales to Gulf Coast indexes got 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 is still that 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 2025 cents area that has been historically and that 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 two Bs a day and produced right at 1.4 Bs and if you look we have about 1.7 B 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 and 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. What you see is that our equity gas first.

As Roland mentioned, I mean we probably through David Terry and the marketing group and Whitney et cetera. We got a pre-plan is 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. Yeah, we've -- all of our rigs, we've got now only either basically well to well contracts or six-month contracts. The rig companies have been reluctant to enter into long-term contracts just in the kind of recent past year. So we're looking at rates that are up probably overall. I mean you're approach in 50% from a year and a half ago though 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 we'll go from there as far as decided on long-term contracts.

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 think 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 on dedicated gas 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 et cetera. We want to have, if LNG company comes in and we want to show we had 1,600 net locations in the primary area we have takeaway. We have 400,000 net acres perspective. We do market a lot of gas. I mean we have said, one of the key things is, we've been in this various just 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're exposed to shift international pricing, as the arbitrage is 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 Boston. I mean we're looking is probably year numbers we between now and maybe 2026, we expect LNG for to increase off the Gulf Coast by maybe 6 or 7 Bs. We know that the world demand 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 gutter and then it's Australia. So if those were all facts and we want to be tied to end with the biggest footprint with more locations for the most and dedicated gas with relationships that we have to these users are 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 and the Gulf Coast areas. So we're right in the middle of this good storm as far 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 maybe you 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 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 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, I mean we've been at seven rig for a good later this year. So this would increase our operated rig count to nine. Now one of these of the nine rigs I would say half of entire rig during this entire year is doing third-party is drilling for the Jones. So it's -- we're probably really 8.5 rig, kind of, it's 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 is 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 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, we had a starter well, in Cada. We drilled for more we had a start well in Harrison County, we drilled some more. Rockcliff had started 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 an acre. 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 I'll just comment on hedging real quick notice you didn't really hedging versus the last update obviously prices have been pretty darn strong here. Thus far the 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 make it after that.

Yeah, that's correct, Leo. We are kind of hedged through the first half of next year. And in '23, our hedge position is more and wide collars 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, then 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 with. So I think -- we really looked at hedging when we put in a lot of the hedges that are paying out, we have to pay out on this year, it was because we had a lot of leverage and back-end after we bought Covey Park and into a low gas price world of 2019 and 2020 with had been a COVID. So now that we are kind of the balance sheet is really transforming and we're going to drive leverage under one times. We view that need to hedge a large percentage of our gas is not necessary and to the extent that we do hedge in the future. It's probably going to be more like the wide collars we did for the first half of '23.

Okay. Thanks for the color.

And 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 majority of that. I mean the vast majority in this 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 mean I think all these companies did, but put in swaps we have swaps initially and then we put it in the callers and 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. I mean we've $3 floor is almost $10 for half of the production we have in the first half year and they were completely open the second half of 2023, but we committed to get our leverage ratio down, we got it down a quarter sooner than we thought that 1.2. We're committed to give 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 the last quarter where 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 and 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, guys. Good morning. I was wondering if the -- on the bolton 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?

You know what we did and we kind of broadcast that we were trying to do this in the last conference call, but towards the third and fourth quarter of last year, we added some deep on acreage that was HBP and the shallow rights we didn't operate we did a transaction that we reported on I think is 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 the quarter of the deeper us on acres that are held by production. So we don't have to put a rig 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 with 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 Appalachia 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 pipes that we're buying in the Haynesville they are becoming more and more valuable as demand for feed gas -- feedstock gas LNG facilities growth. 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 HBP. It's just a good we thought is a good way just spend $36 million versus again paying up and bought a company and adding locations. If you have to buy PDP reserves.

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 guaranteed ourselves low transport cost 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 going to one of the things we probably wouldn't have done three or four years ago when we want 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 Haynesville and also keep our transport rates low, we will consider at yeah as opportunities come up.

Again I think it's just proves to you that we think are 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 and our reserves that we like them and we like the area and we like the fact that we've managed to extend the stuff and the Caddo and Harrison and now into new area. So, 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 as low 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.

Okay. That's it for me. Thank you.

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've 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 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. And we can build out where the Appalachian their restrained from building out. But we think midstream particularly fits if it's long midstream we think in the core area. That said the 145 miles long, it's high pressure and it's under-utilized for the most part, we think that is becomes more and more and more valuable again has this demand for feedstock gas or LNG facilities growth. 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 wrote about how tight it is. It’s completely fall in Appalachia, I mean you just got a molecule more you can really produce and the midstream and the Haynesville used to be used to have four, five Bs of capacity and now is probably not in all as the tightness of the market in the Haynesville and most of the analyst wrote about how tight it is, it’s completely fall in Appalachia. I mean you just got a molecule more you can really produce and the midstream and the Haynesville used to four, five Bs 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 is 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 that 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 from in the quarter.

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

I'm sorry you said you already own one treating plant?

Yeah. We have a -- we already have a, we have…

200 million a day.

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

Okay.

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

Okay. So we can add to the Texas. Okay, great. And could you talk about our -- do you have any significant shut in quantities now aside from just what you would normally have for the way before fracking?

No. I think our shut-in activity, it's 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 is 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. Just this we typically expect 3% to 5% shut in all the time from simultaneous operations 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%.

Okay. That’s all I have.

We do see -- we have seen a free thing longer to sales timeframes, right. I think that's probably been the only thing that's a little different. Last year, we were super-efficient there are a lot of it. Yeah, last year, there is said in all kinds of new efficiency records for drilling days and getting wells online and this year with supply chain is very busy Haynesville area, supply chain. We've actually seen those timeframe stretch out just haven't been able just things you get they get done, but not near as efficiently given its Haynesville is a very busy basin had one of the bigger rig increases the Permian and the Haynesville account for most of the big increases in rigs. Yeah, and that's just something we've had to deal with this year.

I'll add too that on the shut-in volumes, we've 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 the summer and I'm sure it we'll be looking at that as we go ahead in the next year.

Like we said earlier there is a little bit of a, there is, we'll see some expanded capacity in the Haynesville as we get into this fall. Yeah, that was not going to be available to summer. So there's a little bit of relief coming there.

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

Thank you.

Thank you. [Operator Instructions] Thank you. Our next question comes from the line of Savannah Leonard of Bank of America. Savannah Leonard, your line is open.

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

Hey, Gregg.

Just wanted to ask a couple of questions. So obviously, buying back to 29 (ph) on the bondholder. We've seen that, it's a little bit of a surprise. I'm curious, why did you have to 29 is there philosophy about reducing senior debt further. And then just one other question, you were just 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?

Okay. That's a good question, on the 29s, I mean basically, it's our 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 week trading during that to retire some extra debt with a fewer dollars and so that was just an opportunity. I think you saw other companies in our space took advantage of that same real weakness in the trading of the bonds, at the time, when companies like us have incredible free cash flow. So just an opportunity we saw and took advantage of. And as the another question about the bolton acquisition kind of leasing them out that we targeted. I think we, the years more than half over now and we just don't see hitting that upper end of that other number we still. So we don't -- we do expect to have some more activity, but given kind of what we just see ahead for the rest of this year. I don't think we'll hit even upper range of the 75 million for that. So we just wanted to signal kind of what we're seeing like we saw more deals that probably didn't happen back at the end of the first quarter, who wanted to signal that and so just kind of adjustment to expectations there.

Yeah. We feel the 100 billion, we spent the dollars of 40 plus million. So there is another 20 million, 35 million or so this 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 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 you've really been chop and to power to looking for. So we said, yes on this one, there is 60,000 net acres in the pipeline and the trading it takes long time to say, yes. And we've had no and everything else.

But that was particular opportunity that we worked for two years and wasn't like this one. This came on the market or anything. So unique assets that we thought could fit onto ours and we can utilize them differently than the purchaser. I mean the seller was doing it. And we knew they were in the process of trying to liquidate the companies have 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 want it. So that was a very unique part of that deal.

I mean I think 60,000 net acreage HBP. The 145-mile high pressure pipeline and the natural gas treating plant for $36 million. [Multiple Speakers]

I've got that summer cold, but I did legitimately cough. And just a follow-up. So being opportunistic about reducing debt. If you see the opportunity in the market. Does that -- how is that something we should expect going forward is or is there an absolute debt target that you are targeting?

Well, I mean, I think we course if commodity prices stay is 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 is opportunity to reduce debt at a good value. We do know that will pay the credit facility down, so that's front and center. I think we want to go ahead and just finish that off and this year with the second half of the years free cash flow.

Then a priority again like Roland said hopefully, we can get 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 and 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 what we do and that's on top of the ground that's the people that are drilling 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 whereas we look the world LNG demand perspective our 53 Bs a day in 2022 and the U.S. provides about 22% of that 11, 12 Bs a day. So we look at that backdrop worldwide because the commodity we have is a worldwide commodity really affect the visit 2016. And then, if you look at the world wide energy storage, it shows up by what charging coal prices natural gas prices and oil prices. And if you look at the LNG market along the Gulf Coast. I mean we added one LNG project in 2020 and times have changed to 2022, particularly after Russia invasion. So we look at the U.S., we've got the low cost, the provider of LNG in the world. We have -- the natural gas is the world's fastest growing fossil fuel. America's number one power source and what we want to do is, we want to 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 view and we are the stakeholder we work for you, but we can return program that's predictable and have inventory that last 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.