Comstock Resources, Inc. (NYSE:CRK) Q4 2022 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q4 2022 Earnings Call Transcript February 15, 2023

Operator: Thank you for standing by, and welcome to Comstock Resources Fourth Quarter 2022 Earnings Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.

Jay Allison: Steve, I like your tone, you kicked it off right. So, thank you. Welcome to the Comstock Resources fourth 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 fourth quarter 2022 results. I am Jay Allison, Chief Executive Officer of Comstock. With me is, Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations. If you would, please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws.

While we believe the expectations of such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Now good morning, everyone are you all having fun yet? We see that smile I know you’re all out there. I hope you are. The world of natural gas is ever changing and we do recognize that at Comstock realizing that natural gas prices have fallen over 70% since September of last year. We made the call to drop two rigs or 22% of our operated nine rigs to ensure we are positioned for a rebound in natural gas prices in the future. Now most natural gas research analysts will tell you that they expect a substantial amount of the additional 11 Bcf of feed gas needed by LNG shippers starting in 2025 and 2026 to come from the Haynesville.

Well guess what, Comstock is the pure player in that region. Now, the question really is who will be able to supply that natural gas when it is needed the most. I believe Comstock will be one of those elite producers in that region. Now we increased our Haynesville/Bossier shale budget shelf footprint by almost 100,000 net acres in 2022 without paying billions and billions of dollars for an M&A transaction. Thus, we avoided issuing millions and millions of shares of stock or incurring debt to acquire additional drilling inventory. Instead, we paid $550 per acre to grow our Haynesville/Bossier shale footprint to 470,000 net acres, which provides us with thousands of future drilling locations. So how will we navigate the current natural gas market?

That’s the question. Well last year, we fortified our balance sheet. This year, we plan to protect our balance sheet by adjusting our drilling program to ensure that it is funded by operating cash flow. We have the lowest cost structure among our peers, giving us industry-leading high margins. We have been very successful so far in delineating our Western Haynesville play. Results so far on both wells put us among the best wells ever drilled in the entire basin. Our 2023 budget allows us to continue to prove up the Western Haynesville with eight new wells being drilled. Now, we will tip our hat to the stellar 2022 results we had, we will take our coats off and work toward achieving our 2023 goals. I know that everybody listening and those that listen to this recording, I know that you will all be cheering a sound to success.

Why? Because the world needs America’s natural gas to solve its energy needs. Now we’ll go back to the script, Slide 3. Our 2022 accomplishments on Slide 3, we highlight our major 2022 accomplishments. We significantly strengthened our balance sheet by using the $673 million of free cash flow we generated to what to retire $506 million of debt. In November, we entered into a new 5-year credit facility with 17 banks, which lowered our interest costs and increased our availability. We improved our leverage ratio to 1.1x down from 2.4x in 2021. And the $175 million in preferred stock that help fund the Covey Park acquisition was converted into common stock at the end of November. This is a key point. The conversion of the preferred by Jerry Jones is a statement demonstrating his confidence in the future of the company and his belief that ownership of Comstock Equity is the greatest potential for future appreciation.

With another strong year is the drill bit in the Haynesville/Bossier shale drilling 73 or 57 net wells. We drilled two very successful exploratory wells in our Western Haynesville play. The results so far on both wells put them among the best wells ever drilled in the Haynesville. We increased the average lateral length of the wells we drilled by 14% compared to 2021 to almost 10,000 feet. The wells we put on sales had an average IP rate of 26 million cubic feet per day, and our drilling activity added 1.1 Tcfe approved reserve additions at a low finding cost of $0.95 per Mcfe. Our SEC proved reserves grew 9% to 6.7 Tcfe and we replaced 216% of our 2022 production. Our 1P PV-10 value totaled $15.5 billion, highlighting our attractive cost structure we achieved an 83% EBITDAX margin, which is one of the highest in the industry.

In addition, we achieved a 28% return on average capital employed and a 62% return on average equity. In 2022, we added 98,000 net acres that is prospective for the Haynesville and Bossier shales for $54.1 million or $550 per acre. And we reinstated our quarterly common stock dividend at of $0.125 per quarter in the fourth quarter and on the environmental front, we achieved independent certification for 100% of our operated natural gas production under the MiQ methane standard for responsibly sourced gas. Next, we’ll go to Slide 4, the fourth quarter 2022 highlights. On Slide 4, we focus just on the fourth quarter highlights. During the quarter, we generated free cash flow from operations of $129 million. Our production increased 7% to 1.4 billion cubic feet of gas equivalent per day.

Our oil and gas sales were $558 million, 47% higher than the fourth quarter of 2021. Our operating cash flow was $434 million or $1.57 per diluted share. Adjusted EBITDAX increased to $478 million. Our net income for the fourth quarter was $288 million or $1.05 per share. In the fourth quarter, we drilled 21 or 14.8 net operated Haynesville/Bossier horizontal wells, which had an average lateral length of 9,903 feet. Since our last update, we have connected 19 or 13.1 net operated wells to shales with an average initial production rate of 25 million cubic feet per day. We also announced our second successful exploratory well in our Western Haynesville play, which had an initial production rate of 42 million cubic feet per day. We continue to further improve our balance sheet in the quarter with the additional retirement of $100 million of debt and the conversion of the preferred stock.

We initiated a return on capital program with the restatement of our quarterly common dividend of $0.125 per share in December of 2022. I will now turn it over to Roland to discuss the financial results. Roland?

Roland Burns: Thanks, Jay. On Slide 5, we highlight the financial results for our recently completed fourth quarter. Pro forma for the sale of our Bakken properties, which we completed in October of 2021, our production increased 9% in the quarter to 1.4 Bcfe per day as compared to the fourth quarter of ’21. Our EBITDAX in the quarter grew by 70% to $478 million, driven mainly by the stronger natural gas price environment and the production increase that we had. We generated $434 million of cash flow during the quarter an 86% increase over 2021’s fourth quarter, and our cash flow per share during the quarter was $1.57, up $0.67 from the fourth quarter of ’21. We reported adjusted net income of $288 million for the fourth quarter, a 191% increase from the fourth quarter of ’21, and our earnings per share came in at $1.05 as compared to $0.37 in the fourth quarter of ’21.

We generated $129 million of free cash flow from operations in the quarter. That’s 22% higher than we did in the fourth quarter of ’21. And as Jay mentioned, we retired $100 million of debt in the quarter, completely paying off our bank credit facility, which improved our leverage ratio for the year to 1.1x. On Slide 6, we highlight how much Comstock’s financial results have improved since 2019. Production growth has averaged 21% over the last three years. Our EBITDAX has gone from $614 million to $1.9 billion at an annual growth rate of 71%. The cash flow has grown from $468 million to $1.7 billion at an annual growth rate averaging 89% over the last three years. Our adjusted net income has grown from $122 million to $1 billion at an annual growth rate of 245%.

And free cash flow from operations grew to $673 million from really none that we generated in 2019, and our leverage ratio has improved from 3.8x in 2022 to 1.1x this year. On a per share basis, cash flow has increased from $2.50 to $6.21 and adjusted, earnings has increased from $0.75 per share to $3.73 per share. On Slide 7, we provide a breakdown of our natural gas price realizations in the quarter. On this slide, we show the NYMEX contract settlement price and the average NYMEX spot price for each quarter. So during the fourth quarter, the quarterly NYMEX settlement price averaged $6.26 per Mcf and the spot price averaged $5.60. During the quarter, we nominated 81% of our gas to be sold at index prices tied to that contract settlement price, and then we sold the remaining 19% of our gas in the daily spot market.

So the appropriate NYMEX reference price for our sales in the fourth quarter would have been $6.13. We realized $5.57 in the quarter, which reflects a $0.56 differential from the NYMEX benchmark. This differential was wider than normal due to the wider regional differentials that we had in the Haynesville and the much weaker Houston Ship Channel and Katy hub prices that we incurred – really since last summer due to the Freeport shutdown about 7% of our gas is tied to those Gulf Coast markets. In the fourth quarter, we were also 47% hedged, which reduced our realized gas price to $4.19 for the quarter. We have been using some of our excess transportation that we have available to us in the Haynesville to buy and resell third-party gas. This generated about $22 million of profits in the quarter, and this improved our average price realization by $0.17, make it up for some of that wider differential.

On Slide 8, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.76 in the fourth quarter, $0.06 lower than the third quarter rate driven mostly by lower production taxes. Production taxes decreased $0.07, primarily due to the lower gas prices that we had during the quarter, our gathering cost also decreased by 3% during the quarter, but our lifting costs increased by $0.02. G&A costs came in at $0.08 per Mcfe representing a $0.02 increase over the third quarter, but about the same rate that we had in the fourth quarter of ’21. We generated an EBITDAX margin after hedging at 82% in the fourth quarter. That’s down from the 85% margin we had in the third quarter where we had the very high gas prices.

On Slide 9, we recap our spending on our drilling activities and our other development activity for all of 2022. Last year, we spent $1 billion on development activities, including $919 million that we spent on our operated Haynesville and Bossier shale drilling program. We spent another $47 million on non-operated wells. $45 million of that was in the Haynesville, $2 million within the Eagle Ford. And we spent $66 million on other development activity, including infrastructure, installing production tubing, offset frac protection and then other workovers. In 2022, we drilled 73 or 57 net operated horizontal Haynesville wells, and we turned 66 or 53.6 net operated wells to sales. These wells had an average IP rate of 26 million cubic feet per day.

We also had an additional 1.8 net non-operated wells turned to sales. On Slide 10, we show our oil and gas reserves. We grew our SEC proved reserves 9% in 2022 to 6.7 Tcfe and replaced 216% of our ’22 production. Our drilling activity in 2022 added 1.1 Tcfe, which made up really substantially all of the reserve growth that we had in ’22. Our finding costs for 2022 came in at $0.95 per Mcfe. The present value at a 10% discount rate of our proved reserves was $15.5 billion based on the average first of the month prices that we had in 2022. In addition to the 6.7 Tcfe of SEC proved reserves, we have an additional 2.7 Tcfe of proved and developed reserves, which we don’t include in our SEC reported reserves as they are currently not expected to be drilled within the 5-year period required by SEC rules.

We also have another 3.5 Tcfe of 2P or probable reserves and 9.9 of Tcfe and 3P or possible reserves for total overall reserves of 22.8 Tcfe on a P3 basis. Slide 11 recaps our balance sheet at the end of last year. We fully repaid our revolving credit facility in the fourth quarter and ended the year with $2.2 billion in long-term debt. Our leverage ratio was 1.1x at the end of the year. And in November, we entered into a new revolving bank credit facility with a $2 billion borrowing base with $1.5 billion of alleged commitments from 17 banks. The maturity of the revolving credit facility was extended three years to 2027. So we ended 2022 with financial liquidity of more than $1.5 billion. I’ll now turn it over to Dan to discuss our operations in more detail.

Daniel Harrison: Okay. Thanks, Roland. If you look over on Slide 12, this is just a good overview of our current acreage footprint in the traditional Haynesville and Bossier shales. We’re the leading operator. Our acreage position now totals 618,000 gross acres and 470,000 net acres across Louisiana and Texas in the Haynesville and Bossier shale, which also includes our acreage located in the Western Haynesville. Slide 13 details our 2022 year-end drilling inventory. The drilling inventory is split between Haynesville and Bossier and is divided into four categories. Our short laterals are up to 5,000 foot, our medium laterals are at 5,000 to 8,000 foot long. Our long laterals are at 8,000 to 11,000 feet long. And then we have our – what we call our extra-long laterals for our wells greater than 11,000 feet.

Our total operated inventory currently stands at 1,826 gross locations in 1,387 net locations, which gives us a 76% average working interest across the operated inventory. On our non-operated inventory, we had 1,336 gross locations and 185 net locations, which represents, a 14% average working interest across the non-operated inventory. Based on the success of our new extra-long lateral wells, we’ve modified our drilling inventory to take advantage of our acreage position and where possible, we’ve extended our future laterals out further into the 10,000 to 15,000 foot range. And in 2022, our average operated lateral length averaged almost 10,000 feet longer than 2021, coming in at 10,000 feet, 2021, we’re at 8,800 feet. In our extra-long lateral bucket, we capture all our wells that now extend beyond 11,000 feet long.

In this bucket, we currently have 455 gross operated locations in 334 net operated locations. To recap our total gross operated inventory, we have 335 short laterals, 287 medium laterals, 749 long laterals and 455 extra-long laterals. Our total gross operated inventory has split 53% in the Haynesville and 47% in the Bossier. By extending our laterals, we have also increased the average lateral length in our inventory from 8,520 feet up to 8,870 feet or a 4% increase. In addition to the uplift in our economics, the longer laterals will help to reduce our surface footprint on future activity and further reduce our greenhouse gas and methane intensity levels. So to summarize where we’re at today, our current inventory provides us with over 25 years of future drilling locations, which is based on our planned 2023 activity level.

On Slide 14 is an update to our average lateral lengths we drilled since 2017. In 2022, our average lateral increased up to 9,989 feet based on the 66 wells that we turned to sales during the calendar year that is 14% longer than the previous year’s average lateral length of 8,800 feet. In 2022, 16 of our 66 total wells turned to sales were extra-long lateral wells greater than the 11,000 foot length. Included in these 16 extra-long lateral wells turned to sales were six wells that we completed with laterals longer than 15,000 feet. During the fourth quarter, we turned to sales our record longest lateral well to-date with a completed lateral of 15,726 feet and this well was drilled on our East Texas acreage. In 2023, we anticipate turning 69 gross wells to sales with an average lateral greater than 11,000 feet.

And we anticipate 31 of these in 2023 to be longer than 11,000 feet and 12 to be 15,000 foot laterals. Slide 15 is a summary of our new well activity for the fourth quarter. We’ve turned 19 new wells to sales since our last earnings call. We had strong well performance this quarter with the individual IPs ranging from 14 up to 42 million cubic feet a day and with an average test rate of 25 million cubic feet a day. The wells were drilled with lateral lengths at range from 6,769 feet up to 15,726 feet. The average lateral length came in at 10,186 feet. Included in the fourth quarter wells was our second well completed in our Western Haynesville area. The KZ Black number 1H well was completed in the Bossier with a 7,912 foot long lateral, and it was turned to sales in November.

The well was tested with an IP rate of 42 million a day. After we got the KZ well tested, our total field production exceeded the existing treating capacity in the field and the wells were curtailed to slightly below our treating capacity. Prior to being curtail, our first well completed in the field, our Circle M well was producing at a flat rate of 30 million a day since we turned it to sales back in April of last year with the exception of being shut in for the month of October, while the KZ Black well was being completed. The existing treater is currently being expanded. We expect to have additional treating capacity available basically by the beginning of the second quarter. We’re currently completing the third well on our Western Haynesville acreage, which is the Campbell B #2H well.

This well was drilled in the Bossier formation with a 12,700-foot long lateral. We anticipate turning this well to sales by the end of next month. We also have two rigs currently running on the Western Haynesville acreage that are drilling our fourth and fifth well. On Slide 16, Slide 16 is a recap of all our full year 2022 activity. For the full year, we turned a total of 66 wells to sales. The wells in this group were drilled with lateral lengths that range from 4,428 feet up to 15,726 feet, and the average lateral for the year was 9,989 feet. The IP rates for the year ranged from 12 million up to 42 million cubic feet a day with the average IP at 26 million a day. We’re currently running nine rigs in the play. We’ve got three full-time frac crews.

Over the next two to three months. We do have a plan in place to drop our rig count down to seven rigs and continue running a 7-rig program through the end of the year. On the completion side, for 10 months now, we’ve been working our first natural gas-powered frac fleet, along with our two conventional diesel fleets. We’ve been really pleased with the performance of the natural gas-powered frac fleet. This past summer, we executed a contract for a second natural gas powered frac fleet, and we are expecting the arrival of that fleet later in the second quarter. At that time, we are planning to run four frac fleets for just a short time through the summer, at which point we plan to drop back to three frac fleets for the remainder of the year and also into next year, once that change is made down to three frac fleets that will leave us operating two natural gas fleets and just on conventional diesel fleet.

Operating the two natural gas powered frac fleets will allow us to capture additional cost savings on our completions largely through the elimination of buying expense diesel – and as well significantly reducing our greenhouse gas emissions. Slide 17 shows our D&C cost trend through the fourth quarter and our full year 2022 performance for our benchmark long lateral wells. This is all of our wells that are longer than 8,000 feet. Of the 13 wells returned to sales during the fourth quarter, 11 of these fell into the category of our benchmark long lateral wells. Our fourth quarter D&C cost averaged $1,425 a foot. This is just a 1% increase compared to the third quarter. Our D&C cost for the full 2022 year averaged $1,329 a foot, and this represents a 28% year-to-year increase.

Our fourth quarter drilling cost was $582 a foot. This is a 3% decrease compared to the third quarter. And our 2022 full year drilling costs averaged $523 a foot, which is a 32% increase compared to our average 2021 drilling cost. On the completion side, our cost for the fourth quarter came in at $843 a feet, which represents a 4% increase compared to the third quarter. And for our 2022 full year, our completion costs came at $806 a foot which marks a 25% increase compared to our average 2021 full year completion costs. These cost increases are a reflection of the swift inflationary pressures we and the rest of the industry faced in 2022, while we face the same inflationary pressures in both our drilling and completion operations, our completion costs were somewhat buffeted through the deployment of our first natural gas frac fleet back in April of last year.

And as mentioned on the previous slide, we expect to capture more of these cost savings in 2023 and beyond through the deployment of our second natural gas-powered frac fleet, which is going to show up in the second quarter. As seen in the numbers, we did experience a flattening of both our service costs and pipe costs during the fourth quarter. And with the recent sharp drop in gas prices, we’re cautiously optimistic that we will see service costs begin to decline slightly throughout the rest of the year, along with the reduction in the rig activity. I’ll now turn it back over to Jay to summarize the outlook for 2023.

Jay Allison: Okay Roland and Dan, thank you for the report. And now we’ll jump into 2023 outlook. I would direct you to Slide 18 where we summarize our outlook for 2023. We will continue to derisk and delineate our Western Haynesville play with a two rig program in 2023. And we are managing our drilling activity levels to prudently respond to the lower gas prices environment we’ve had so far this year. We’re in the process of releasing two of our operated rigs on our legacy Haynesville footprint to pull in our activity in response to lower natural gas prices. We remain very, focused on maintaining the strong balance sheet we created last year. As a result, we will continue to evaluate our activity and plan to fund our drilling program with operating cash flow.

Our industry-leading low-cost structure provides acceptable drilling returns even at current natural gas prices as our cost structure is substantially lower than the other public natural gas producers. We plan to retain the quarterly dividend of $0.125 per common share. And lastly, we will continue to maintain our very strong financial liquidity, which totaled more than $1.5 billion at the end of 2022. I’ll now turn it over to Ron to provide some specific guidance for the rest of the year. Ron?

Ronald Mills: Thanks, Jay. On Slide 19, we provide our financial guidance for 2023. First quarter production guidance is 1.375 to 1.435 Bcfe per day, and the full year guidance is 1.425 to 1.55 Bcfe per day. During the first quarter, we do plan to turn to sales between nine to 12 net wells. On our first quarter development CapEx guidance, we’ve set it at $275 million to $325 million, and our full year development CapEx guidance is $1.05 billion to $1.15 billion. Our 2023 wells will have an average lateral length being approximately 10% longer than 2022, 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 $25 million to $35 million on additional bolt-on acquisitions and new leasing.

Our lease operating costs are expected to average $0.20 to $0.24 in both the first quarter and the full year, while our GTC costs are expected to be between $0.28 and $0.32 in both the first quarter and the full year. Production and other taxes are expected to average between $0.16 and $0.20 in both the first quarter and for the full year. This year, the DD&A rate is expected to remain in the $0.95 to $1.05 per Mcfe range. And our cash G&A is expected to total $7 million to $9 million in the first quarter and $30 million to $34 million for the full year. Non-cash G&A is expected to be about $2 million per quarter. Cash interest expense this year is expected to total $34 million to $36 million in the first quarter and $138 million to $140 million for the full year.

Effective tax rate is expected to remain 22% to 25%, and we expect to defer 75% to 80% of our taxes. We’ll now turn the call back over to the operator to answer questions from the analysts who cover the company. Please proceed.

Q&A Session

Operator: Our first question comes from the line of Derrick Whitfield of Stifel. Your line is open, Derrick

Derrick Whitfield: Thanks and good morning all.

Jay Allison: Good morning, I love this, nothing says I love you more than dropping gas rigs and announcing better than expected full year ’23 guidance?

Derrick Whitfield: It was a moment of elevated thinking, I must say.

Jay Allison: Well, it’s Valentine.

Derrick Whitfield: I think it’s safe to say that the operational plan and update are certainly welcome news, though. With my first question, I wanted to focus on the trajectory of your production profile for the year. While certainly sparring you guys the 2024 outlook question, given that you’re now just dropping rigs, I wanted to ask if you could perhaps elaborate on the facility constraints that are impacting your Q1 production? And if you could comment on your ability to hold production flat with seven rigs once the DUC cycle through?

Jay Allison: Yes so one, Derrick, I want to comment on your title. I think that just shows you that the whole world out there, is wanting companies like Comstock to drop rigs. And I think that was a tension valve that we want to be the first to say we’re going to do that. On takeaway, we think in our core areas, it’s probably 95% utilized. In other words, there’s not a lot of takeaway. Now we’ve worked with Trey Newell, who was our – he’s the new VP of Marketing to provide takeaway for the wells that we will be drilling in 2023 and through 2024, but I think our greater takeaway and Dan can address this in a moment, is our Western Haynesville. We had commented that we had a plant issue with the two wells that we brought online.

The plant didn’t expect that type of volumes. So our goal is to get that functioning properly with the expected production that we think we will have and then really by the end of 2023, whatever the takeaway that we think we might need – we’d like to have double that amount in case we need it in the future to prepare ourselves for 2025, 2026 takeaway when really these shippers will need more of this gas. So Dan, do you want to comment on the plant facility in the takeaway issue.

Daniel Harrison: Yes, so the Western Haynesville, Derrick, we – Jay mentioned they weren’t expecting these kind of volumes up. We had forecasted potentially having these volumes. But obviously, there was maybe a little bit of a doubt. They obviously like to see a little bit of gas show up before they spend a lot of money, investing a lot of money to upgrade their facilities. But they did – they have been working on it. What we had to circle in well on since April last year, we were fine when we put the case in and obviously, we exceeded that capacity, not by a whole lot, but we had the facility kind of max out. And in December, they were having a lot of up and downtime. So we basically curtail the wells back just a little bit more just to make sure we could keep the plant running full time, which they have.

But the plant is actually down today doing some of the upgrade work, and they’re going to have basically all their additional capacity that’s been planned will be basically up and on by April. We’ve got some of the capacity that’s being basically added right now. And so, we should be – for everything that we’ve got forecasted, all our production for the rest of this year, we’re going to be in good shape after these upgrades are completed.

Jay Allison: And Derrick, we’re drilling some of these wells we’ll be drilling along that Pinnacle pipeline, which we bought that plant and a 145-mile pipeline so, some of the wells that we’ll be drilling in the Western Haynesville will connect to our own pipeline. And I think right now, we think the capacity of that is about 300 million a day. And we have three other sources for takeaway that may double that amount. That’s what we’re working toward. We don’t think we’ll need that much. We’re working toward that. And that’s another reason Derrick production is a little softer in the first quarter versus second, third and fourth quarter. It’s the gathering plant.

Derrick Whitfield: Terrific. And then Jay is it safe to assume as we kind of look at these DUCs flowing through and as we’re modeling out the forecast with seven rigs, I mean, it looks to us that you guys can at least hold production flat with those seven rigs, five being in the legacy, two being in the Western Haynesville?

Jay Allison: We’ve – we’re one of the few that hadn’t had really any well degradation. In fact, if you look at our wells, our wells are performing nearly 20% better versus the 2020 and ’21 production. So if you look at that and you model it forward and then you look at the amount of pretty stable production we’re getting from Western Haynesville, we think we can have a 6% production growth within cash flow and give the dividend and have material reserve growth, at the same time, add material inventory without – having to go to the M&A market.

Derrick Whitfield: Yes. And maybe just as my follow-up, I wanted to lean into your last point there and congratulate you guys on what appears to be one of the better organic leasing programs across the industry in recent years. Regarding the Western Haynesville, now that your 3-ish wells into your delineation program, what can you tell us about how the wells are performing against your pre-drill expectations and the progress you’re making from a D&C learning curve perspective?

Daniel Harrison: So Derrick I’d say, I mean, as far as our expectations were – they basically have exceeded our expectations to-date. Now we haven’t had KZ Black on for very long, the Circle M. We’ve got basically still a 30 million a day well. It was flat as a pancake up through December, at which time we started having some of the plant capacity issues, and we had to basically pull everything back a little bit. It’s been pulled back through today to when the plant is – they’re doing the upgrades on the plant, but we totally expect that well to be basically backup to when the plant is back and running we’ll have it back up to that 30 million a day rate flat. So that well has obviously been really good. It has exceeded our expectations.

The KZ Black well line, we got it IP looks just as good, but obviously, with the – plant issues, the full capacity that we haven’t been able to basically flow that well at a full capacity for a length of time. So we’ll have to get the plant upgrades done and get everything back on to see how that one looks. The third well is coming on. And as soon as the upgrades are done, we’re going to have this Campbell well coming on. It’s actually plan to come on about mid-March if everything goes well on the completion. We’re currently fracking it now. So and then we really don’t have anything else coming on there until July, which time we got two wells coming on. We’ll have a big jump there and then early ’24. As Jay mentioned, we’ve got other wells we’re drilling, but they’ll go into our Pinnacle gathering system and not this existing treating facility we’re going in now.

Jay Allison: Yes, Derrick and I think the big question is, could you really drill at this depth, the lateral length of 6,000 feet, 8,000 feet, much less 12,700 feet, which is what we did on the Campbell. In other words, could you really do that? And I know in 2008 and ’09, in the core of the Haynesville, it took a consortium of companies, years to figure out how to drill long laterals, and we’re really – we’re one company out there trying to derisk this. And I think the operations group is a Tier 1 group. They’ve done a really good job at that.

Derrick Whitfield: It’s very helpful. Thanks for your time.

Jay Allison: Yes sir. Thank you.

Operator: Our next question comes from the line of Charles Meade of Johnson Rice. Your line is open, Charles.

Charles Meade: Good morning, Jay, Roland and the rest of the Comstock team there.

Jay Allison: Good morning, Charles.

Charles Meade: So Jay, I want to pick up on – pick up on the thread that you comment you made in your prepared remarks about drilling within cash flow. And I was just wondering you get you to elaborate your thought process there and about how you can navigate the company in that way? Because as I look at it, the strip has moved so far so fast that no company could, can maneuver on a quarterly granularity, it seems like – you couldn’t decelerate 2Q enough to drill within 2Q cash flow? So how is it that you’re looking at? Are you aiming to be within cash flow a couple – a few quarters out? And is that kind of the market that you try to hit or if you could just elaborate on how you think about that target and what you can do to hit it?

Roland Burns: Yes, that’s a great question, Charles. And it is a dynamic environment. And I think you saw some of the changes to our drilling program, was to try to achieve that. I mean we – commodity prices could go a lot of different directions for the rest of this year. So that’s a big unknown. And I think on the other side, the service costs are also – we’ve kind of budgeted for kind of the very high service cost environment that we had last year with a lot of inflation. So we hope to see some de-inflation of some of those costs, especially in the second half of this year. I think the one additional kind of source of cash that’s not as easy to model is the fact that we will have somewhere even about a couple of hundred million dollars of working capital that will – that was really earned in our great 22-year that gets received this year.

As you know, the way we had to settle hedges early. We don’t – et cetera, from last year and just the timing of gas receipts. There will be quite a bit of – if you’re just looking at the model, you don’t pick that up. But I think that’s a little bit of a cushion there too, that we see on – as we look ahead for this year. But it will be something that we’ll continue to monitor. We have tremendous liquidity and financial resources. So I think it’s not – it’s just our goal to say our overall goal is not to overspend cash flow and we’ll continue to try to change our program as the year progresses to do that.

Jay Allison: Yes, I think that’s the messaging. I mean, if you go back even probably on the 9th of this month, natural gas had dropped 46% this year. And as to your point, it’s all over the board. We do think that the Henry Hub sell-off is now overdone. We’ve accepted this seasonally warm weather. But we do think a big event changer in 2023 is the restart of the Freeport LNG. We looked at gas storage and you have all these numbers. I mean, storage today is about 11% above one year, about 5% above 5-year, but if you were to add back that 2 Bcf of lost demand related to Freeport, those numbers shares have changed dramatically, would be 11.5% below one year would be 16% below the five years. So we look at that too and then we look at all this flexibility we have, we tell you we have a 6% production growth in 2023.

And most of these companies have less than that. So we could flex down and have less production and still probably have more production than the peers. And then I think it always shows up and you always point this out, I mean, we’re a low-cost producer period, and we’ve been very – I think we have managed our money properly in the past, and we will exactly do the exact same thing. We’re going to manage our money just like we did in the past. We’re going to manage it, be that responsible in the future. So our goal is net net-net, to get quarter-by-quarter-by-quarter, if you get through 2023, and it’s a soft year, our goal is to not have borrowed net at the end of next year, $0.01 from our credit facility. So you can’t look at it on a 90-day basis it drives you crazy.

But that’s our goal.

Charles Meade: Right, right, it is. And thank you for that elaboration because it’s – you can’t affect it on a 90-day basis. And so that was a helpful exposition on the way you guys are approaching it. My second question, the Western Haynesville so it seems to me – I always like maps, but I understand you guys don’t want to put the maps in now because you say for competitive reasons? I look at that, you guys – as Derrick pointed out, a great job as you guys picked up this almost 100,000 acres. But it looks to me like you guys – if I look at that you don’t want to show map, but you’re also guiding to, I think, about $30 million of lease acquisition on the – no, I’m sorry, more closer to 100. So that suggests to me you’re not done building that position, but you’re probably more than half done building that position. Is that a fair way to characterize it or how would you characterize it?

Roland Burns: I think that we kind of – we talked about spending roughly the $30 million was the right number for lease acquisition in ’23. I think you’re looking at the infrastructure…

Charles Meade: Oh right, you’re right yes 30.

Roland Burns: Exactly structure investments that we probably want to make, which are separate from that. So I think this is – that we do feel like we will substantially complete capturing, we think the best part of this play this year. I would say that we’re more than half done, though.

Jay Allison: Charles, I would comment on this. We’ve disclosed the detail that in the Ks and Qs that we have to because we’re a public company. And then we don’t disclose the things that we don’t have to disclose as a public company because we’re still in that area. And then we disclosed the amount of money because you need to know that we think we’re going to spend kind of closing out the checked flag on our acreage. So we want to make sure that when you’re on the team and you own the stock, like the Jones is converting that $175 million preferred into equity, because that’s where the torque is. It’s the equity ownership. We want you to know as a prospective stakeholder and an analyst that we do have a checkered flag. We got to know where our parameter is.

We do have a budget for that spending. But we always do what it tells us to do, and that is how, is the drilling going? How are the lateral lengths going? Do we have any takeaway there? And we monitor that. And then I think that kind of the crescendo is, when will all this kind of really materialize and be extremely valuable, it’s in that 2025, 2026 timeframe, which is what – that’s when most of these companies need this natural gas. And if you need it as a shipper there’s, not many companies that can provide you decades upon decades of inventory and drilling. And that is our vision. We can’t fully explain it to you right now. We’re still kind of marking it up all on the sheet of paper, but we want to make sure you’re not left behind as we move in that direction.

Thanks, Charles.

Charles Meade: Thank you, Jay.

Jay Allison: Thanks, Charles.

Operator: Our next question comes from the line of Umang Choudhary of Goldman Sachs. Your line is open, Umang.

Jay Allison: Good morning.

Umang Choudhary: Hi, good morning, and thank you for taking the questions. Really appreciate all the color on your vision and how you’re shaping the activity levels both in the near term, but also setting the company up from a long-term perspective. I wanted to kind of focus a little bit more on the near term. It sounds like your completions and your production growth this year is going to be more back half weighted, consistent with higher gas prices that we see in the future curve today? You made a comment about tight oil field service market today. So I was wondering what kind of flexibility do you have with your rig and pressure pumping counterparties to add or drop activity if gas prices surprises to the upside or also to the downside?

Daniel Harrison: Yes, so we’re in really good shape there. We’ve got a few rigs on some just really kind of medium, short-term contracts. The majority of them are basically well-to-well contracts. So that’s one of the reasons we were able to basically kind of implement our plan to drop down to these seven rigs pretty quickly. I mean you can’t – we couldn’t really do it any quicker than we did because, obviously, they’re drilling on multi-well pads. And I mean, just even just on one multi-well pad, you’re there for two months. So we’re in great shape there. We do have the ability to drop additional rigs quickly if we need to. And we’re also very confident that we can add rigs pretty quickly in the back half of the year. We had a surprise to the upside, and that’s the path we wanted to take.

Same thing on the frac crews, we’ve got the one natural gas fleet that’s on a long-term contract. Other than that, our diesel fleet, our conventional fleets are just short-term contracts that we could think or turn south. We could obviously drop those pretty quick. And we’ve got – we can kind of – we’ve got, obviously, plans to go to the four frac fleet that I mentioned earlier when we picked up this new second gas fleet. So we’ve got the option to – we could drop one and basically just stay at 3. When the new fleet gets here or we can go to 4, which is what we have planned that basically kind of worked some of our DUCs down a little bit before we drop back to three at the end of the summer. And then obviously, we can go – we could just drop down to the two gas fleets.

So really, in summary, we’ve got really great flexibility to go up or down, rig and frac crews.

Umang Choudhary: That is really helpful. And I guess just a follow-up on this activity levels point. As you talk to some of your non-operated partners in the Haynesville, any real-time color you can provide in terms of what they are thinking about from an activity perspective. The rig counts so far has been fairly resilient if you look at some of the rig data?

Jay Allison: Well, they are definitely dropping rigs. We have talked to a few of them, not all of them, but everybody we have talked to is basically planning to drop rigs. We’ve already seen a few rigs dropped here just in the last two to three weeks. So I think that’s how many ultimately they drop remains to be seen. But definitely, everybody that we have talked to is dropping rigs, has dropped rigs.

Umang Choudhary: That’s really great color. Thank you so much guys.

Jay Allison: You bet. Thank you.

Operator: Our next question comes from the line of Bertrand Donnes of Truist. Your line is open, Bertrand.

Bertrand Donnes: Hi, guys. Jay, I’m sure you’re tired of talking about how good the Western Haynesville is, but maybe I could ask one more on it.

Jay Allison: I love it. Keep asking those questions.

Bertrand Donnes: All right, so the first one came on at 37 a day and then the next one came out even higher at 42. And it sounds like that you surprised your midstream guide a little bit. Were you guys expecting that level of consistency? I know it’s only two wells, but when you look at your core position, there’s kind of a much larger variation. So I’m just trying to find out if that was also a surprise to you guys or if there’s something different geologically that you knew this was going to happen?

Daniel Harrison: No I think the geology – I mean we, as far as variability, we expected the same out of both wells. We did both of these wells initially. We typically do flow our well completions of the casing for quite some time before we’ll tube them up down here in the Western Haynesville, both of these wells were basically tubed up from the get-go. We did run – we have two and 78s we ran in the Circle M. We ran 3.5-inch tubing in the KZ well. We wanted to run through 3.5-inch tubing in the Circle M well. We just basically couldn’t get our hands on a stream when we needed to. And so that’s one of the reasons why we didn’t really probably go to a higher IP rate on the Circle M was just – we’re just basically trying to manage technically critical velocities, erosional rates and all that. So that did let us – so the KZ with a bigger tube and allowed us to basically test at a little bit higher rate.

Jay Allison: I’ll tell you the well performance in our core area. Again, it’s provided us with a cash flow to derisk the Western Haynesville. It’s out of free cash flow that we bought all that acreage and to kind of your Western Haynesville questions, because the Western Haynesville has performed so well, I think that’s one reason why Jerry Jones and his family that own 66% of the company said, you know what, we’re going to demonstrate our confidence in the future of the company and the great potential is the upside in the equity. We’re going to convert our preferred into common what – maybe because the core is solid, but the real reason is we’ve got a lot of potential that we barely, barely talked about in the Western Haynesville.

We just have two wells. I mean, it’s a very beginning of the game. But if we can solidify that and continue to talk about it as brightly a year from now as we have today, then we will be the company that can provide this gas on a global basis because of where our footprint is where the LNG shippers are spending their money. That is the goal.

Bertrand Donnes: All right and just following up, the two rig program in the Western area is that just the best way to kind of not get over your skis. Is two rigs just the most efficient way to drill it? Why did you settle out on kind of two there and then five in the traditional?

Jay Allison: What – we did initially, we said, let’s let the play tell us how many rigs we need. And so you have to have the one rig, we drill the well, we moved the rig off and we produced the well for a while to see whether we should drill a second well. All of a sudden, the first well, like Dan said, we tubed it up not to produce as much gas as it could have produced. All of a sudden, we moved that rig back on, and we’re drilling, and it tells us to put a second rig on. Now you may look at the acreage footprint and say, well, at some point in time, you’re going to put a whole lot of rigs on and that answer is no either. We write-down our model, we had a rig a year to hold the acreage that we’ve leased. Now if all that acreage ends up being Tier 1 acreage, which who knows, but if it did, then that’s where we would have our drilling rigs anyhow.

Most of our core acreage is HBPed, so we can have the swing back and forth, we can tackle this back and forth that’s unusual, too. But that’s how we looked at this, Dan.

Daniel Harrison: Yes. I totally agree with that. Just one extra thing I would add is we knew this would be a little bit of a learning curve, drilling these wells down here versus our core. We’ve been drilling literally just the industry is thousands of wells up there pretty much very predictable and consistent. And so here in the Western Haynesville, we have seen some pretty good progress just on these first few wells that we’ve drilled as far as how fast we’re drilling them and where we feel like we can go in the future, obviously get much faster. And so kind of where we think we’re going to end up on speed, that’s also going to change the cadence of our activity down here in the Western Haynesville as we do speed up and drill these wells faster, then at some point, you can drill at a speed that’s essentially like adding another rig to the place. So we’re just kind of going to keep an eye on that, and that will also factor into when we add the additional rigs.

Bertrand Donnes: That’s great color, guys. And then really my last one, just depending on where the gas trip falls out, you could have some free cash flow, especially because you’re kind of committed to drilling within your cash flow. So you might have some free cash flow on top of it. With your revolver kind of paid down, is there a strategy that the rest of that cash would maybe fund an increase in the dividend, nice and slow or is it maybe you hold the cash or do you address the 29-30 notes a little ahead of schedule? I just – where does that excess cash go?

Roland Burns: Well, what we said publicly, and this is – our goal is like we would want to hold the cash. We’d want to – we kind of set a goal of creating at least $0.5 billion of a cash kind of reserve that could fund acquisitions, et cetera. So I think that’s kind of where we would – once we kind of have that established, then we kind of will look at other return of capital. So given the tighter environment we’re in now, obviously, the return of capital is probably push through all that out for the future, because I think we want to build this cash reserve first with additional free cash flow we generate this year.

Bertrand Donnes: Okay. Does that maybe look materialize into like a tender offer for debt after you get that cushion or is it – you’re comfortable with your free cash flow and by the time you get to ’25 and ’26 and the gas demand comes back that won’t really be a worry about notes?

Roland Burns: Well, I think those – I think as far as looking at the retirement additional debt, I think that we – really have to prioritize our free cash flow – of those things you mentioned, the dividend, share repurchases or bond repurchases. And I think to the extent we would – once we establish this cash reserve, I think then we will look at those three forms of return of capital and decide which one to pursue, which one is the best opportunity.

Jay Allison: Hi, you had to see where the bonds stayed at.

Roland Burns: Yes, so again, we have great maturity runway, great interest cost of debt that we really the balance sheet. We just – I think we got it in really great shape here in ’22. That was what the year afforded us to do. And so we’re able to navigate the lower prices because of our great cost structure, just like we navigated those low prices back when we didn’t even have the great balance sheet. So that’s how we’re viewing it.

Bertrand Donnes: Well, it sounds like you want to stay flexible and I think the markets reward you today for being flexible. So it sounds like you’ve good time guys.

Jay Allison: Thank you. Thank you. Good questions.

Bertrand Donnes: Thank you.

Operator: Our next question comes from the line of Jacob Roberts of Tudor Pickering Holt & Company. Your line is open, Jacob.

Jay Allison: Good morning.

Roland Burns: Good morning.

Jacob Roberts: Just curious, and I know it’s very early days, but if you could provide any guidepost on the Western Haynesville D&C costs that you’re seeing. And the comment you just made about the days to drill. Just curious if you could provide some context there and then maybe the trajectory that we might see from the Circle M and KZ Black to the 8th well?

Jay Allison: Yes, it’s a little too early to make any comments on that. Good question.

Jacob Roberts: Fair enough, I guess, for my second one, 25 years of inventory is certainly a long runway, just the appetite, maybe not in the near term of bringing some of that value forward in the market?

Jay Allison: I think any company needs to have a lot of inventory. I mean I think even during COVID, there was billions and tens of billions of dollars of M&A to high-grade inventory. I think what we’ve done, we just said we turn to sales 55 wells a year. We’ve got a lot of inventory. It doesn’t mean you have to drill a bunch of those wells. I think if we derisk our core areas, and we have thousands and thousands and thousands of locations. I mean, who knows, and that’s going to be worth a whole lot of money without having to drill all those wells. I’d like to have 40 years of inventory. I don’t feel I have a need to sell anybody, any of my inventory just because I have a lot of it.

Daniel Harrison: And one of the most effective way is to – which we’ve done to develop the Haynesville is – but given the fact that the wells have a high decline initially, there’s a lot – they need a lot of takeaway when they come on. And then five years later, they’re producing a lot less is the kind of space your development out over a long period of time. Otherwise, you have to make very, very large infrastructure investments, which are in a very prudent way to develop it. So I mean, given the nature of our play, I think the way we develop it over this longer time frame is the most cost-effective way to get the reserves even though you don’t get the net present value. But overall, you get, you don’t have to either over-commit to a massive infrastructure build that you won’t be able to use five years from now.

So I think that’s just the nature of the play we’re in, and I think we’ve been prudent in the way that we do that. And that’s why given our large footprint, we actually move around areas, not because we’re trying to – we don’t drill our very Tier-1 area all the time because we only have room for maybe a couple of wells a year to put into it based on the existing infrastructure. So we rotate the drilling program around to balance out the infrastructure needs. And given the activity level now is higher with, other operators that’s even more critical than it used to be because there’s only – there’s not a lot of extra capacity out there.

Jay Allison: I mean, again, I think we look at LNG build-out is going to run its course and this demand will pick up in the next several years, and we just want to be positioned to not oversupply the market to provide however much gas, the market needs we’d like to provide that in the Haynesville/Bossier.

Jake Roberts: Great. I appreciate the time guys.

Operator: Our next question comes from the line of Leo Mariani of MKM Partners. Your line is open, Leo.

Leo Mariani: Hi guys. Was hoping you could talk a little bit more about just confidence in the Western Haynesville. Like you said, you’ve got two wells out there, but it sounds like you are committing to a fair bit of infrastructure dollars. It sounds like a decent chunk of that $100 million that you’re spending on infrastructure in 2023. Are there other industry wells in and around you guys that have given you more confidence? Is there a geologic model where you look at the position and think that a lot of what you have in the acreage is more homogenous and can produce homogeneous results? Can you just provide a little bit more color around confidence and the willingness to run a couple of rigs there and spend these infrastructure dollars?

Jay Allison: Yes, I would comment, Leo, that we’ve done our own homework with our geological staff. We really, we had to see like in ’08, technically, have we advanced enough to technically drill these wells vertically and laterally like in ’08, ’09, 2010, we did when we deepened the Cotton Valley to hit what is now the Haynesville Bossier in the core area. We looked at our own geology. We looked at our own seismic, look at our own well logs for wells that have been deepened in this particular area. And then we have leased part of that acreage. And there is another company that has drilled a couple of wells, but we don’t go by what they’ve done or are doing. We’re really doing this with our own team and with our own information, and we like the results.

So that’s why we went ahead and bought the Pinnacle line at an acreage included in the Pinnacle line. So this is a kind of a self-created extension to the play that we think is going to provide the world with that extra gas that they need.

Leo Mariani: Yes, I appreciate that answer. And then just in terms of your D&C CapEx budget for 2023, it’s kind of fairly wide from the low end to the high end. Can you provide a little bit of color in terms of what gets you to the low end or the high end?

Roland Burns: I think the – it’s wide mainly because of the exactly inflation, how much – the high end, we assume inflation doesn’t just continue to run rapid like it has and the low end, we hope to see some improvements in prices. So it’s really service prices that are €“ it’s not activity level, we think is fairly mapped out, at least based on what we want to do today, but the cost of services is where you’re going to need a lot of maneuvering room, I think, to figure out what the ultimate CapEx is going to be?

Leo Mariani: Okay, that’s helpful for sure. And you guys alluded to this a little bit earlier in terms of flexibility and sort of add rigs or sort of drop rigs. But I’m just kind of curious as what would sort take for you guys to do that? And if we did get, let’s say, a spike in prices later this year, would you maybe elect to kind of hedge some of that before adding rigs? I mean, it seems like the gas market has been probably the least predictable it’s ever been, it feels like in the last year. It’s been very hard to see kind of where it’s been going here?

Daniel Harrison: Well, I think that’s – I think the next couple of years, there’s probably going to be a lot of volatility in gas and it’s very little things can drive it up or down, I think. And so – and you are assured just because you get a big spike in gas one month that it’s going to stay. In the shale development, committing to a rig and committing to a program like that and the way we drill wells on pads in the development mode because it’s much more cost effective, really is a longer-term decision. So you got to kind of get very comfortable with a 6-month to 8-month plus kind of time horizon to want to add that activity versus be very reactive to just one month’s spike. So because it takes – if you add them, then it can take that kind of time to un-add them.

So you have that flexibility, but they are – our contracts will allow us to do it, but they’re in the middle of drilling pads and all that. So it’s not very practical to remove a rig in the middle of a project or something. It’s got to wrap it up. So yes, so it’s a longer-term decision. So I think we kind of make those decisions kind of as we go into the year and then adjust as we have to. But that kind of try to overreact one way or the other, given our very strong balance sheet, great liquidity. I mean it’s just, wanting to prudently meet our goals as our objective not a worry that we’re going to outspend our resources.

Leo Mariani: Okay. Appreciate the color.

Jay Allison: Thank you, Leo.

Operator: Thank you. Our next question comes from the line of Paul Diamond of Citi. Your question please, Paul. Apologies, Paul, your line is open. Please go ahead.

Paul Diamond: Hello.

Jay Allison: These are buying stock that’s a good thing.

Paul Diamond: Hi sir, can you hear me?

Jay Allison: Yes.

Roland Burns: Yes, go ahead.

Paul Diamond: Okay. Thanks for taking the time. No, I kind of just want to just jump into – so there’s – you said you have flexibility to add and drop additional rigs. I just wonder if you could get into a bit of color on where your priorities would be if that – for that marginal rig or activity, whether that’s to that came out of core, should we expect that next marginal want to either come out of or go back into that same core acreage or does that priorities kind of shift more towards the Western Haynesville the closer we get to the long term?

Jay Allison: If we drop any rigs, they would come out of our core, not the Western Haynesville.

Paul Diamond: Understood. And then kind of the other point is, given the recent volatility we’ve talked about on the call today and kind of the longer-term view of much a much greater level of demand in the longer term. Has that shifted at all your guys’ strategy around hedging? You recently added some more in the last quarter or is it still – or is it still kind of a run rate to the kind of strategy you guys have been using for the last several quarters?

Jay Allison: Several months ago, we looked at, again, these two way collars with the Florida ceiling, and we did add another 250 million a day in the third quarter. I think we’re like 34% hedged for the whole year. And we did look at the $3 floor and whatever the ceiling might be. We added at $250 million a day. I think we always, in Ron’s in charge of that Ron Mills. We always look at putting some two way collar in. So we’ll keep looking at that. We don’t think that today is the day to do that. We did that a couple of months ago because when prices keep falling that’s not when you need to make those actions. We will throttle back and forth to maintain our fortified balance sheet, and we can do that with the election – to keep the rigs to have some DUCs et cetera. We’ve got a lot of controls on our panel. So we’ll look at hedging.

Paul Diamond: Understood. Thanks for the color.

Jay Allison: Thank you. Good question.

Operator: At this time, I’d like to turn the call back over to Jay Allison for closing remarks sir?

Jay Allison: Again, it’s – we’ve been on this an hour or 16. I think you’re still there after we hit for 16 minutes. I know they always say that your past actions probably predict your future actions. I think what we want to tell you is, that we have made responsible decisions in the past year-after-year-after-year, they’ve been responsible, and we will continue to make responsible decisions in the future why to protect our fortified balance sheet and to derisk the Western Haynesville. We thank you for supporting us in the past, and we thank you in advance for continued to support us in the future as we derisk the Western Haynesville and create the gas that the world needs and the spot that it needs in the United States. Thank all of you. Appreciate you.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.