Comstock Resources Inc (CRK) 2022 Q2 法說會逐字稿

Thank you for standing by, and welcome to Comstock Resources Second Quarter Fiscal Year 2022 Earnings Conference Call. (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've got a good tone this morning. You start everybody off right. And 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 titled 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; Ronald Mills, our VP of Finance and Investor Relations.

And if you'll flip over to 2, please refer to Slide 2 in our presentation. Note that our session today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations and such statements to be reasonable, there can be no insurance that such expectations will prove to be correct.

Now start the real presentation, Slide 3, the second quarter 2022 highlights. We covered the highlights of 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 6.75% senior notes in the open market.

We brought our leverage down to 1.2x. 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 prospective for the Haynesville and Bossier Shale and a 145 mile high pressure pipeline and a 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 incremental 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 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 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 1.2x, down from 2.9x 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 the $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 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're realizing as production taxes increased by $0.06 in the second quarter.

Our gathering cost increased by $0.02 in the quarter, which was primarily due to the impact of higher fuel costs or 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 costs 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 6 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 1.2x in the quarter as compared to 2.9x 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 on Slide 9, so this just shows our average lateral length for the wells we drilled since 2017. Our lateral lengths averaged 9,612 feet in the second quarter, [for the] (corrected by company after the call) 16 wells that we turned to sales. Among the 16 new wells were 5 extra, long wells with laterals greater than 11,000 feet, but the longest lateral this quarter coming in at 12,237 feet.

To date, we have drilled 9 15,000-foot laterals. 4 of these have been turned to sales. We got 3 that are currently completing and 2 that are waiting on completion.

We're also in the process of drilling our 10th 15,000-foot lateral. The longest lateral drilled and completed to 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 9 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 are experiencing in this inflationary cost environment.

Slide 10 shows our latest D&C cost strength 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 costs. Our drilling costs were $478 a foot for 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 #1H 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 this year, we deployed our first TITAN fracturing fleet, which is fueled 100% by natural gas.

On the first 2 pads 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 2 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 will direct you to Slide 13, where we summarized 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 reinitiate a return of capital program.

We did redeem $244 million outstanding on our 2025 senior notes on May 15. 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 2 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 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 to provide some 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 to 1.44 Bcfe per day. And the full year guidance remains unchanged at the 1.39 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 2 rigs and is up from the $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 spent on our drilling program, we could spend up to a total of $50 million to $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 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 to $0.18 per Mcfe, while our DD&A rate is expected to average $0.90 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 noncash 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 who follow the company. Lateef?

(Operator Instructions) Our first question comes from the line of Austin Aucoin of Johnson Rice & Company.

Congrats on a strong quarter. My first question is with the second Titan fleet expected to be in service in 1Q '23? Is that a good time frame for the additional 2 rigs? Or should we think that they'd be all trying to get them earlier.

So the 2 rigs, we've got one that's just started, got underway and the second additional rig is coming later this month. Q1 of 2023 for the next Titan fleet is accurate.

Now remember, the first TITAN fleet, we were supposed to have received in January of this year and we didn't get it until April. So that's the guesstimate to date right now.

I appreciate that. 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 that exploration? And as a follow-up, how many locations do you see on the acreage?

Yes. 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 followed us a long time, if you go back to 2015, we drilled a Bossier well in the Norther Sabine -- it wasn't popular to drill Bossier wells.

We had drilled 8 successful Haynesville wells before that. So we wanted to test the Bossier. And that kind of kicked off Bossier. And then 5 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, 5 years ago, we wanted to firm up our position there. And that work, and even if you go back even to this last quarter, we drilled 3 wells in Nacogdoches where one was a Bossier, 2 were Haynesville and we're bringing those online today, and they looked really good.

So we've really stepped out on the same thing with Circle M. Our team wanted to see if we could technically drill a well out there, it looks good. We reported it. But again, one well is only 1 well. We'll test our technology on the next well and we call this starter well.

Our next question comes from the line of Umang Choudhary of Goldman Sachs.

My first question is on production outlook. Your guidance calls for a step-up in production in the fourth quarter. I wanted to get your thoughts on cadence of completions in the second half? And also, given you have added 2 rigs in 2023, any initial read on production next year would be really helpful.

Yes. On production, yes, we see obviously more completions. I think we're kind of expecting around [13.8](corrected by company after the call) or so wells being -- coming online in the fourth quarter at about [13](corrected by company after the call) or so in the third quarter currently. And of course, 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 just out there due to supply chain issues. And so I think that's going to push some of the production a little bit later in the year this year. But we do see getting all these wells online that we kind of planned for this year Yes.

And it's early for us to start giving a lot of guidance for '23 production, but we are obviously adding more rigs. And so as we get probably -- maybe it was later on in the year, we'll kind of give a really good 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 to be alleviated?

Yes. I think you're talking about a higher basis differentials there at the main regional hubs, Perryville and Carthage. And I think those are really reflects the tightness of transportation in the Haynesville that we've seen as production has increased some there.

And there's also been more -- a little bit of more maintenance than normal going on, which has 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 coming to the basin to alleviate a little bit of tightness.

But given the tight market and that's why you've seen the differentials, especially in Perryville, be volatile and may be elevated here. And that's what -- we 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.

So we still have somewhere around 10% of our base is still that's subject to the wider differentials. Even some of the gas, we sell at Perryville, we tried to do it under longer-term sales agreements where we've been able to lock that in closer to that $0.20, $0.25 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.

Yes, 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 the -- 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 market over 2 Bs a day and produce 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.

Yes, and you noticed in kind of this year, we've had -- we've added some additional income through marketing and 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 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'll just use it for equity gas first.

As Roland mentioned, I mean we probably, through operations and the marketing group, Whitney, et cetera. We try to preplan this for 1 year, 1.5 years 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.

Our next question comes from the line of Neal Dingmann of Truist Securities.

On the 2 rigs that you talked about arriving 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 lock into these rigs.

So this is Dan. Yes, we've -- all of our rigs we got now on either basically well-to-well contracts or 6-month contracts. The rig companies have been reluctant to enter any long-term contracts just in the kind of recent past here.

So we're looking at rates that are up probably overall. I mean you're approaching 50% from 1.5 years ago or so. So 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 go from there as far as deciding on long-term contracts.

I think that makes a lot of sense. And then just lastly, next question is on LNG. Specifically, you all continue to be positioned very well. Jay, you pointed out earlier, I think given the basin to benefit from potential LNG projects. I'm just wondering, again, I know it's early 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 undedicated gas than any other Haynesville-Bossier 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 an LNG Company come in and we want to show them we have 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 -- 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 international pricing as arbitrage as an end game? Well 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 at is probably your numbers between now and maybe 2026, we expect the LNG to increase off the Gulf Coast by maybe 6 or 7 Bcf/d.

We know that the world demands more LNG. If you look at even kind of the global deal, Russia exports more gas than anybody in the world, multiple of 2, multiple of 2, 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 those are all facts. And we want to be tied in with the biggest footprint with more locations for the most undedicated gas with relationships that we have with 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. The single largest financial investment in the world, I think we heard was Ventured Global $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.

Our next question comes from Leo Mariani of MKM Partners.

I wanted to follow up on the addition of the 2 rigs. I just wanted to kind of make sure I understand where we're at. Were you guys at 5 rigs prior to these 2 new rigs and that gets you to 7, is that right? And it sounds like you're signaling that these 2 rigs would stay in place 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. And now you guys have talked about kind of low to mid-single-digit growth. It looks like this maybe could put you closer to double digits here, any thoughts on that?

I think, again, we're going to add the 2 rigs as Dan answered the question earlier, which is the first question that was asked. We're going to add the 2 rigs. We do think there's going to be a demand in 2023 from 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, I think, in 2022. We don't give a number for 2023 right now.

And Leo, we were at 7 rigs. I mean, if you go back, I mean, we've been at 7 rigs for a good bit of this year. So this would increase our operated rig count to 9. Now one of these 9 rigs, I would say, half of our 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 -- 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 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 wells only 1 well, but it looks good so far.

Are 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 Caddo. We drill some more. We had a starter 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, 2021, we then drill [there](corrected by company after the call). We just drilled 3 wells, 2 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 all just comment on hedging real quick. I noticed you didn't really hedge anything versus the last update. Obviously, prices have been pretty darn strong here thus far this summer. Just any update on hedging philosophy? I know you got hedges that kind of last into the first half of next year and then you're sort of naked after that.

Yes, that's correct. We're kind of hedged through the first half of next year. And in '23, our hedge position is more in wide collars with kind of somewhere around a $3 floor, a little less than $10 ceilings. 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 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 in -- after we bought Covey Park and into a low gas price world of 2019 and 2020 with advent of COVID. So now that we're kind of -- the balance sheet is really transforming and we're going to drive leverage under 1x.

We view the 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.

And again, I think, hopefully, we can get our leverage below 1x 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 ought to 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 hedged natural gas companies on the planet. I mean we will have $3 floors 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 we committed to get our leverage ratio down. We got it down the quarter sooner than we thought to 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 the last quarter, we're not looking to spend $3 billion, $4 billion, $5 billion buying PDP with inventory. We think we've got a lot of inventory that'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 a BJ TITAN natural gas frac-fleet coming our way.

Our next question comes from the line of Fernando Zavala of Pickering Energy Partners.

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 onetime opportunity that came with that package?

Well, you know what we did, and we kind of broadcasted if we were trying to do this in the last conference call. But towards the third and fourth quarter of last year, we added some [inventory](corrected by company after the call) on acreage that was HBP and the shallow rides 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 and acquire the deep rights on acres that are held by production.

So we don't have to put a rig and start drilling out there immediately. It's HBP by another operator. But at the same time, we did buy this 145-mile high-pressure pipeline and the natural gas treating 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 can have the molecules which 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 Manchin deal, but who knows. I hope they do. But we know that we can have midstream in our areas. So this midstream pipe that we're buying in the Haynesville, they're becoming more and more valuable as demand for feed gas feed slot gas LNG facilities growth. So we look 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 is HBP. It's just a good -- we thought it's a good way to spend $36 million versus, again, paying up and buying that 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 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 don't think that this is kind of -- one of the things we probably wouldn't have done 3 or 4 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 Haynesville and also keep our transport rates low, we'll consider as opportunities come up.

Yes. And again, I think it just 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 that 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 now into the new area.

So -- but that's really what we're doing. We're just staying with 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 just has low carbon.

Got it. 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.

Our next question comes from the line of Noel Parks of Tuohy Brothers.

Sorry if you commented on this already, I missed this. 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 just actually curious as to why the seller would sell that?

Well, if you look at the whole maybe 3 million acres, whatever it is, at the Haynesville/Bossier encompasses and you look at midstream, midstream is becoming more and more and more valuable.

I mean we can build out and we deal, I guess, with whatever major midstream company within that footprint. And we have for a long, long time. And we can build out where the Appalachia, they're restrained from building out. But we think midstream, particularly if it's long midstream, we think in the core area that's at 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 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 most of the analysts wrote about how tight it is.

It's completely full in Appalachia. I mean, it's not a molecule more you can really produce in the midstream. And the Haynesville used to be usually have 4, 5 Bs of capacity. And now it's probably [90%](corrected by company after the call), 95% full. So we're pushing on that.

And at the same time, you got tens of billions of dollars of commitments for LNG export terminals, a lot of terminals along the Gulf Coast. So if you add all that up, I think this midstream [piece](corrected by company after the call), it's going to be very valuable.

Yes. 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 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 from them in the quarter.

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

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

Yes, we have. We already have -- we have.

200 million a day amine plant.

We have some gathering systems and treating plant in our North Louisiana operations, too. So this will be -- we could add to our Texas.

Okay, great. And -- and did you talk about our -- do you have any significant shut-in quantities now aside from just what you would normally have for the delay before fracking?

No. I think our shut-in activity it's been around the 4%. It's been kind of what we expect. There's -- every now and then, there's maintenance or that's going to be -- but it's not been a long duration for us so far. And we don't foresee -- we see kind of a similar for the rest of the year, just as 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 averaged for the first half of this year so far, about 4%. We do see -- we have seen, if anything, longer to sales time frames, right? I think that's probably been the only thing that's a little different.

Last year, we were super-efficient. There were a lot of -- last year, there was setting all kinds of new efficiency records for drilling days and getting wells online. And this year, with supply chain, very busy Haynesville area, supply chain, we've actually seen those time frames stretch out.

We just haven't been able -- just things they get done, but not near as efficiently given its -- Haynesville is a very busy basin. One of the bigger rig increases, the Permian, the Haynesville account for most of the big increases in rigs. And that's just something we've had to deal with this year.

I'll add to it and on the shut-in volumes, we've -- 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 have 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, we will be -- we'll be looking at that as we go ahead into next year.

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

(Operator Instructions) Our next question comes from the line of Savannah Leonard of Bank of America.

It's actually Gregg Brody, I just picked Savannah's phone online. Just wanted to ask a couple of questions, so obviously, buying back to 2029 on a bondholder, we love seeing that. It's a little bit of a surprise.

So I'm curious why did you got to 2029? 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?

Okay. That's a good question. Yes, on the 29s, I mean, basically, it's -- 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 a weak trading during that to retire some extra debt with 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 another question about the bolt-on acquisition kind of leasing amount that we targeted. I think -- yes, the year is more than half over now. And we just don't see hitting that upper end of that other number. We still -- so 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 the 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, we wanted to signal that and so this just kind of an adjustment to expectations there.

Yes. We pulled the $100 million and we spent the dollars of $40-plus million. So there's another $20 million, $30 million or so that's kind of out there that's floating to spend.

Is it -- is it your assessment that those deals went away? Or did they trade someplace else?

They're still out there. Some are done, some are percolating. I mean we don't expect any.

Yes, a lot of it. We're looking at unique stuff that 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, 99 out of 100 times just say no, that way when you say, yes, you've really been chopping the power you're looking for. So we said, yes, on this one, there's 60,000 net acres and the pipeline and the treating plant. It took us long time to say yes, and we said no on everything else.

But that was a particular opportunity that we've worked for 2 years. It wasn't like -- it wasn't just come on the market or anything. So unique assets that we thought could fit onto ours and we could use 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 company. So that was the situation we've been working on a long time and we decided to get it done in April.

Did it happen to pick up any production with that? Is there?

No production at all. That was all acreage.

It's all the acreage.

It's all HBP though. That's very important.

Yes. That's 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 just by buying the part that we wanted. So that was a very unique part of that deal.

I mean think 60,000 net acres, HBP, 145-mile high-pressure pipeline and a natural gas treating plant for $36 million.

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

Well, I mean, I think we -- 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 2 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, something we want to go ahead and just finish that off and this year with the second half of the year is free cash flow.

I mean the 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. And then, we want to continue, we'll add these 2 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 the 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 completing these wells and marketing the gas.

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. Thanks for your time. It's the most valuable thing you have. As we look at the world LNG demand expect about 53 Bcf/day in 2022. And the U.S. provides about 22% of that, 11-12 Bcf/day.

So we look at that backdrop worldwide because the commodity we have is a worldwide commodity, really effective into 2016. And then if you look at the worldwide energy storage, it shows up by what, surging coal prices, natural gas prices, in oil prices.

And then you look at the LNG market along the Gulf Coast, I mean, we added 1 LNG project in 2020 and times of change in 2022, particularly after Russia envision. So we look at the U.S. We've got the low-cost provider of LNG in the world.

We have the natural gas is the world's fastest-growing field, America's #1 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're the stakeholder. We work for you.

We can conserve your return program that's predictable and have the inventory that lasts for decades. So we want to be a pure [Haynesville](added by the company after the call) company. So that's our goal. So that's our goal. Thank you for your time.

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