Comstock Resources, Inc.

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. To ask a question during the session, you will need to press star 1-1 on your telephone. I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.

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 two 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. Good morning, everyone. Are you all having fun yet? Let me 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. You know, 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 Hainesville area. 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 Hainesville Bozier Shale footprint by almost 100,000 net acres in 2022 without paying billions and billions of dollars or 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 Hainesville-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 Hainesville 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 to Western Hainesville with eight new wells being drilled. Now, we will tip our hat to the stellar 2022 results we had. We'll 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 us on 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 three, our 2022 accomplishments. On slide three, we highlight our major 2022 accomplishments. We significantly strengthen 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 five-year credit facility with 17 banks, which lowered our interest costs and increased our availability. We improved our leverage ratio to 1.1 times down from 2.4 times in 2021. And the $175 million in preferred stock that helped 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, the drill bit in the Hainesville-Bossier shells, drilling 73 or 57 net wells. We drilled two very successful exploratory wells in our western Hainesville plate. The results so far on both wells put them among the best wells ever drilled in the Hainesville. 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 95 cents per MCFE. Our SEC approved reserves grew 9% to 6.7 TCFE, and we replaced 216% of our 2022 production. Our 1P PV10 value totaled $15.5 billion. Highlighting our attractive cost structure, we achieved an 83% AVIDAX 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 Hainesville and Bossier shells for $54.1 million or $550 per acre. And we reinstated our quarterly common stock dividend at 12.5 cents 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. Now if you'll go over to slide four, it's the fourth quarter 2022 highlights. On slide four, we focused 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-point net A operated Hainesville-Bossier horizontal wells, which had an average lateral length of 9,903 feet. Since our last update, we've connected 19 or 13.1 net operated wells to cells with an average initial production rate of 25 million cubic feet per day. We also announced our second successful exploratory well in our western Hainesville place, 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 reinstatement of our quarterly common dividend of 12.5 cents per share in December of 2022. I will now turn it over to Roland to discuss the financial results. Roland.

Thanks, Jay. On slide five, we highlight the financial results for our recently completed fourth quarter. Pro forma for the sale of our Balkan 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 EBITDA 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 67 cents 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 1.1 times. On slide six, 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 in an annual growth rate of 71%. Cash flow has grown from $468 million to $1.7 billion in 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 3.8 times in 2020 to 1.1 times 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 seven, we provide a breakdown of our natural gas price realizations in the quarter. On the 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 for 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 ourselves in the fourth quarter, it would have been $6.13. We realized $5.57 in the quarter, which reflects a 56-cent differential from the NYMEX benchmark. This differential was wider than normal due to the wider regional differentials that we had in the Hainesville and the much weaker Houston Ship Channel and KD 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 Hainesville 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 17 cents. Make it up for some of that wider differential. On slide eight, we detail our operating costs per MCFE and our EBITDAX margin. Our operating costs per MCFE averaged 76 cents in the fourth quarter, six cents lower than the third quarter rate, driven mostly by lower production taxes. Production taxes decreased seven cents, primarily due to the lower gas prices that we had during the quarter. Our gathering costs also decreased by 3% during the quarter, but our lifting costs increased by two cents. G and A costs came in at eight cents per MCFE, representing a two cent 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 percent 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 nine we recap our spending on our drilling activities and our other development activity for all of 2022. last year we spent one billion dollars on development activities including $919 million that we spent on our operated Hainesville and Bossier shale drilling program. We spent another $47 million on non-operated wells. $45 million of that was in the Hainesville, $2 million was in the Eagleford. And we spent $66 million on other development activity, including infrastructure, installing production tubing, offset frack protection, and then other workovers. In 2022, we drilled 73 or 57 net operated horizontal Hainesville 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. In slide 10, we show our oil and gas reserves. We grew our SEC proof 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 filing costs for 2022 came in at 95 cents per MCFE. The present value at a 10% discount rate of our approved 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-approved reserves, we have an additional 2.7 TCFE of approved undeveloped reserves, which we don't include in our SEC reported reserves as they are currently not expected to be drilled within the five-year period required by SEC rules. We also have another 3.5 TCFE of 2P or probable reserves and 9.9 TCFE of 3P or possible reserves for total overall reserves of 22.8 TCFE on a P3 basis. Lot 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 1.1 times 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 elected commitments from 17 banks. The maturity of the revolving craft 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.

Okay, thanks, Roland. If you look over on slide 12, this is just a good overview of our current acreage footprint in the traditional Hainesville and Bossier shells. where 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 Hainesville and Bossier Shales, which also includes our acreage located in the western Hainesville. Slide 13 details our 2022 year-end drilling inventory. The drilling inventory is split between Hainesville and Bossier, and it's 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 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 and 1,387 net locations, which gives us a 76% percent average working interest across the operated inventory. On our non-operated inventory, we have 1,336 gross locations and 185 net locations, which represents a 14 percent average working interest across the non-operated inventory. Based on the success of our new extra-long lateral wells, we 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 and 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 is 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 length we've 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 cells were extra-long lateral wells greater than the 11,000-foot length. Included in these 16 extra-long lateral wells turned to cells 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 links that ranged from 6,000 769 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 Hainesville area. The Casey Black number 182 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 Casey well tested, our total field production exceeded the existing treating capacity in the field and the wells were curtailed slightly below our treating capacity. Prior to being curtailed, 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 Casey 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 Hainesville Acreage, which is the Campbell B No. 2 H Well. This well was drilled into 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 Hainesville acreage that are drilling our fourth and fifth wells. 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 links that ranged 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 frack crews. Over the next two to three months, we do have a plan in place to drop a rig count down to seven rigs and continue running a seven-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 frack fleet along with our two conventional diesel fleets. We've been really pleased with the performance of the natural gas-powered frack fleet. This past summer, we executed a contract for a second after 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 one 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 expensive diesel, and as well significantly reducing our greenhouse gas emissions. Slide 17 shows our DNC cost trend through the fourth quarter and our full year 2022 performance for our benchmark long ladder wells. This is all of our wells that are longer than 8,000 feet. Of the 13 wells we turned to sales during the fourth quarter, 11 of these fell into the category of our benchmark long ladder wells. Our fourth quarter DNC cost averaged $1,425 a foot, This is just a 1% increase compared to the third quarter. Our DMC 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 cost 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 cost came in at $806 a foot, which marks a 25% increase compared to our average 2021 full-year completion cost. These cost increases are a reflection of the swift inflationary pressures we and the rest of the industry faced in 2022. While we faced 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 frack 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 in 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.

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 de-risk and delineate our Western rainfall 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. You know, we're in the process of releasing two of our operated rigs on our legacy rainfall 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 12.5 cents 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?

Thanks, Jay. On slide 19, we provide our financial guidance for 2023. The 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 9 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 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 to $35 million on additional bolt-on acquisitions and new leasing. Our lease operating costs are expected to average 20 to 24 cents in both the first quarter and the full year, while our GTC costs are expected to be between 28 and 32 cents in both the first quarter and the full year. Production and ad valorem taxes are expected to average between 16 and 20 cents in both the first quarter and for the full year. This year, the GD&A rate is expected to remain in the 95 cents to $1.05 per MCFE range, and our cash G&A is expected to total $7 to $9 million in the first quarter and $30 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 to $36 million in the first quarter and $138 to $140 million for the full year. Effective tax rate 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.

Thank you. As a reminder, to ask a question, you will need to press star 11 on your telephone. Again, that's star 11 on your telephone to ask a question. Our first question comes from the line of Derek Whitfield of Stiefel. Your line is open, Derek.

Thanks, and good morning, all.

Good morning. I love this. Nothing says I love you more than dropping gas rigs and announcing better than expected four-year 23 guidance.

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

Well, it's Valentine.

I think it's safe to say that the operational planning 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 sparing 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 duct cycles through.

Yes. So, one, Derek, 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 wanted to be the first to say we're going to do that. On takeaway, we think in our core area, it's probably 95% utilized. In other words, there's not a lot of takeaway. Now we've worked with Trey Newell, he's a 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 Hainesville. We had commented that we had a plant issue with the two wells that we bought online. The plant didn't expect that type of volume. 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, you want to comment on the plant facility and the takeaway issue?

Yeah, so the Western Hainesville, Derek, we, you know, Jay mentioned they weren't expecting these kind of volumes. You know, we had forecasted, you know, potentially having these volumes, but obviously, you know, there was maybe a little bit of doubt. You know, they obviously like to see a little bit of gas show up before they spend a lot of money, you know, invest a lot of money to upgrade their facilities. But they did, you know, they have been working on it while we had the circle in well on since April of 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 maxed out and, you know, in December they were having a lot of up and down time. So we basically curtailed 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's 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.

And, Derek, we're drilling, some of these wells we'll be drilling along that pinnacle pipeline, which we bought that plant, and that 145-mile pipeline. So some of the wells that we'll be drilling into Western Hainesville, we'll connect to our own pipeline. And I think right now we think the capacity of that is about 300 million a day. We have 300 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, Derek, production is a little softer in the first quarter versus second, third, and fourth quarter. It's the gathering plant.

Terrific.

Jay, is it safe to assume as we look at these ducks flowing through and as we're modeling out the forecast with seven rigs, 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 Hainesville?

You know, we're one of the few that hadn't had really any well degradation. In fact, if you look over 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 You look at the amount of pretty stable production we're getting from Western Ainsville. 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 markets.

Yeah, 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 industry in recent years. Regarding the Western Hainesville, now that you're three-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?

So, Derek, I'd say, I mean, as far as our expectations were, they basically have exceeded our expectations to date. Now, we haven't had Casey Black on for very long, the circle in. We've got basically still 30 million a day well. It was, you know, flat as a pancake up through December, which time, you know, we started having some of the plant capacity issues, and we had to basically pull everything back a little bit. uh it's been it's been pulled back through today to when the plant is uh you know they're doing the upgrades on the plant but we totally expect that well to be basically back up to when the plants back up and run and we'll we'll have it back up to that 30 million a day rate flat so you know that well has obviously been uh been really good it has exceeded our expectations the kz blackwell on you know we got it iped uh looks just as good but obviously with the plant uh the plant issues the full capacity. We haven't been able to basically flow that well at its 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 planned to come on about mid-March if everything goes well on the completion. We're currently fracking it now. And then we really don't have anything else coming on there until July, which time we've got two wells coming on, so 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.

Yeah, Derek, and I think the big question is, you know, 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 2009, in the core of the Hainesville, it took a consortium of companies years to figure out how to drill long laterals. And we're really, you know, we're one company out there trying to de-risk this. And I think the operations group is a tier one group. They've done a really good job at that.

That's very helpful. Thanks for your time.

Yes, sir. Thank you. Thank you.

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

Good morning, Jay, Roland, and the rest of the CompSoc team there.

Good morning, Charles.

So, Jay, I want to pick up on – pick up on the thread that you made in your prepared remarks about drilling within cash flow. And I just want to 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 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 it? Are you aiming to be within... within cash flow a few quarters out, and is that kind of the mark that you try to hit, or if you just elaborate on how you think about that target and what you can do to hit it.

Yeah, 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, commodity prices could go a lot of different directions for the rest of this year, you know, so that's a big unknown. And I think on the other side, you know, the service cost, you know, or also, you know, 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 thing The one additional kind of source of cash that's not as easy to model is the fact that we will have somewhere even up to about a couple of hundred million dollars of working capital that was really earned in our great 22 year that gets received this year as the way we had to settle hedges early. We don't, you know, et cetera, from last year and just the timing of gas receipts. You know, there will be quite a bit of, you know, if you're just looking at the model, you don't pick that up. But, you know, I think that's a little bit of a cushion there, too, that we see on, you know, as we look ahead, you know, for this year. But, you know, it will be something that we'll continue to monitor. You know, we have tremendous, you know, liquidity and financial resources. So I think it's not – It's just our goal to say, hey, our overall goal is not to overspend cash flow, and we'll continue to try to, you know, change our program, you know, as the year progresses to do that.

Yeah, 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 that's your point. It's all over the board. We do think that the Henry Hub sell-off is now overdone. We, you know, we've accepted this in seasonally warm weather. But, you know, we do think a big event changer in 2023 is the restart of the Freeport LNG. Now, we looked at the gas storage, and you have all these numbers. I mean, storage today is about 11% above one year, about 5% above five-year. But if you were to add back that two BCF of lost demand related to Freeport, Those numbers, Charles, have changed dramatically. We'd be 11.5% below one year. We'd be 16% below the five years. So, you know, we look at that, too, and then we look at all this flexibility we have. You know, 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 and be that responsible in the future. So our goal is net, net, net, you know, forget quarter by quarter by quarter. If you get through 2023 and it's a soft year, You know, our goal is to not have borrowed a net at the end of this year, a penny 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.

Right, right.

I think that's the point.

It is. And thank you for that elaboration because it's, you know, 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, Western Haynesville. So it seems to me, you know, I always like maps, but I understand you guys don't want to put the maps in now because, you know, you say for competitive reasons. I look at that. You guys, as Derek pointed out, great job that you guys picked up this, you know, almost 100,000 acres map. But it looks to me like you guys, if I look at that you don't want to show a map, but you're also guiding to I think about $30 million of lease acquisition. No, I'm sorry, closer to $100 million. 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?

I think that we talked about spending roughly the $30 million was the right number for lease acquisition in 23. I think you're looking at maybe infrastructure. Oh, right. You're right. Yeah, $30. We have infrastructure investments that we probably want to make, which are separate from that. So I think 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.

You know, Charles, I would comment on this. We've disclosed the detail that, you know, 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 disclose the amount of money because you need to know that we think we're going to spend kind of closing out the checkered flag on our acreage. So we wanna make sure that when you're on the team and you own the stock, like the Jones is converting that $175 million per part 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 kind of 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, you know, how's the drilling going? How are the lateral links 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 decade upon decades of inventory and drilling. And that is our vision. You know, we can't fully explain it to you right now. We're still kind of marking it up on the sheet of paper. But we want to make sure you're not left behind as we move in that direction.

Thank you, Jay. Thank you, Charles.

Thank you. Our next question comes from the line of Iman Chaudhary of Goldman Sachs. Your line is open, Iman.

Hi, good morning, and thank you for taking my questions. Good morning. 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 we see in the futures 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?

Yeah, 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, you know, that's one reason we were able to basically kind of implement our plan to drop down to these seven rigs pretty quickly. I mean, we couldn't really do it any quicker than we did because, obviously, they're drilling on multi-well pads. And, I mean, just on one multi-well pad, you know, 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. We're also very confident that we can add rigs pretty quickly in the back half of the year if 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, you know, our diesel fleet, our conventional fleets are just, you know, short-term contracts that we could, you know, that we could things 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, you know, frack fleet that I mentioned earlier when we picked up this new second gas fleet. So we, you know, we've got the option to, we could drop one and basically just stay at three when the new fleet gets here, or we can go to four, which is what we have planned. That basically kind of works some of our ducks down a little bit before we drop back to three at the end of the summer. And then obviously we could go to, you know, we could just drop down to the two gas fleets. So, you know, really in summary, we've got really great flexibility to go up or down, rigs and frack routes.

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

Well, they're definitely dropping rigs. We have talked to a few of them, you know, not all of them, but everybody we have talked to is basically planning to drop rigs. We've already seen, you know, a few rigs dropped here just in the last two to three weeks. So I think that's, you know, how many ultimately they drop remains to be seen, but definitely everybody that we have talked to is dropping rigs, has dropped rigs. That's really great.

Thank you so much, guys.

Thank you.

Thank you. Our next question comes from the line of Bertrand Duns of Truist. Your line is open, Bertrand.

Hey, guys. Jay, I'm sure you're tired of talking about how good the Western Hainesville is, but maybe I could ask one more on it.

I love it. Keep asking those questions.

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 you surprised your midstream guys 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.

No, I think the geology, as far as variability, we expected the same out of both wells. We did tube up both of these wells initially. We typically do flow our well completions up the casing for quite some time before we'll tube them up. Down here in the western Hainesville, both of these wells you know, we're basically tubed up from the get-go. We did run, we have two and seven-eighths tubing. We ran into the, in the Circle M, we ran three and a half inch tubing in the Casey well. We wanted to run three and a half inch tubing in the Circle M well. We just basically couldn't get our hands on a string when we needed to. And so that, that's one of the reasons why we didn't really probably go to a higher IP rate on the Circle M was just

know we're just basically trying to manage you know technically you know critical velocities erosional rates and all that so that did let us so the casey with the bigger tube and allowed us to basically test it a little bit higher rate i'll tell you the well performance in our core area again it's provided us with the cash flow to de-risk the western ainsville you know it's out of free cash flow that we bought all that acreage in and to kind of your western ainsville questions You know, because the Western Hainesville has performed so well, I think that's one reason why Jerry Johns 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, you know, the great potential is the upside in the equity. We're going to convert our part into common. Why? 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 Hainesville. We just have two wells. I mean, it's the 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, you know, we will be that 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.

right and and just following up the the two rig program in the in the western area is is that just the best way to kind of not get over your skis is is two rigs just the most efficient way to drill it why why did you settle out on you know kind of two there and then five in the traditional you know the 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 the one rig we drill the well we we move the rig off

And we produced the well for a while just 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, you know, 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 have to put a whole lot of rigs on. And that answer is no either. You know, we right now in our model, we add a rig a year to all 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. You know, most of our core acreage is HPP'd, so we can have the swing back and forth. We can toggle this back and forth. That's unusual, too. But that's how we looked at this, Dan.

Yeah, 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's thousands of wells up there, pretty much very predictable and consistent. So here in the western Hainesville, 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, you know, where we feel like we can go in the future, obviously get much faster. And so, you know, 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 Hainesville. And as we do speed up and drill these wells faster, then, you know, at some point you can drill at a speed that's essentially like adding another rig to the place. So, You know, we're just kind of going to keep an eye on that. And, you know, that'll also factor into when we add the additional rigs.

That's great color, guys. And then really my last one, just, you know, depending on where the gas strip falls out, you know, you could have some, you know, free cash flow, especially because you're kind of committed to drilling within your cash flow. So you might have some free cash 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, you know, maybe you hold the cash, or do you address the 2930 notes, you know, a little ahead of schedule? I just, where does that excess cash go?

Well, what we said publicly, and this is our goal, is that we would want to hold the cash. We'd want to kind of set a goal of creating, you know, at least a half a billion dollars of a cash kind of reserve, you know, that could fund acquisitions, etc., So, you know, I think that's kind of where we would, once we kind of have that established, then we kind of will look at, you know, other return of capital. So given the tighter environment we're in now, you know, obviously the other return of capital is probably pushed a little bit out, you know, for the future, because I think we want to build this cash reserve first with the additional free cash flow we generate this year.

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

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

Yeah, you'd have to see where the bonds fade out, etc.

Yeah. Again, we have great maturity runway, great interest cost of debt. The balance sheet, 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. Yeah. That's kind of how we're viewing this.

Well, it sounds like you want to stay flexible, and I think the markets reward you today for being flexible. So it sounds like a good plan, guys.

Thank you. Thank you. Good questions.

Thank you.

Thank you.

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

Good morning, guys.

Good morning.

Good morning. And I know it's very early days, but if you could provide any guideposts on the Western Haynesville DNC cost 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 Casey Black to the eighth well.

Yeah, it's a little too early to make any comments on that. Good question.

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.

You know, 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, you know, 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 de-risk our core areas and we have thousands and thousands and thousands of locations, I mean, who knows, then 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.

One of the most effective ways, which we've done in to develop the Hainesville is, you know, 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, you know, five years later, they, you know, they're producing a lot less, is to kind of space your development out over a long period of time. Otherwise, you have to make very, very large infrastructure investments, which, you know, aren't 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 timeframe 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 overcommit to a massive infrastructure bill 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, you know, we don't drill our very tier one 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 not a lot of extra capacity out there.

I mean, again, I think we look at LNG build-out. It's 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, but to provide however much gas the market needs. We'd like to provide that in the hands of Bossier.

Great. Appreciate the time, guys.

Thank you.

I'm sorry. Our next question comes from the line of Leo Mariani of MKM Partners. Your line is open, Leo.

Yeah, guys. I was hoping you could talk a little bit more about just confidence in the Western Hainesville. Like you said, you've got two wells out there, but it sounds like you are committing to a fair bit of infrastructure dollars. Sounds like a decent chunk of that $100 million that you're spending on infrastructure in, you know, 2023. You know, are there other industry wells in and around you guys that are giving you, you know, 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 homogenous results? Can you provide a little bit more color around confidence and the willingness to run a couple rigs there and spend these infrastructure dollars?

You know, I would comment, Leo, that we've done our own homework with our geological staff. 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, you know, 2010, we did when we deepened the Cotton Valley to hit what is now the Hainesville-Bossier and the Corps area. You know, we looked at our own geology. We looked at our own seismic, looked 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, you know, 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. That's why we went ahead and bought the Pinnacle Line and that 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.

Yes, I appreciate that answer. And then just in terms of your DNC CapEx budget for 2023, You know, 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?

I think it's wide mainly because of the, you know, exactly inflation, how much, you know, the high end, we assume inflation doesn't, just continues to run, you know, rampant like it has. And the low end, we hope to see some, you know, improvements in prices. So it's really service prices that are there. Because our 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 cap is going to be.

Okay, that's helpful for sure. And you guys alluded to this a little bit earlier in terms of flexibility and sort of, you know, add rigs or sort of drop rigs. But I'm just kind of curious is, you know, what would it sort of take, you know, for you guys to do that? And if we did get, let's say, a spike in prices, you know, later this year, would you maybe elect to kind of hedge some of that before, you know, 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.

Well, I think that's, you know, I think the next couple of years, you know, there's probably going to be a lot of volatility in gas. And, you know, very little things can drive it, you know, up or down, I think. And, you know, you aren't assured just because you get a big spike in gas one month that it's going to stay. So, you know, in the shale development, you know, committing to a rig, and committing to, you know, a program like that and the way we drill wells and pads in the development mode because it's much more cost effective, you know, really is a longer-term decision. So you've got to kind of get very comfortable with a six-month to eight-month plus kind of time horizon to want to add that activity versus, you know, be very reactive, you know, to just one month spike. So because it takes, you know, if you add them, then it can take that kind of time to So you have that flexibility, but they are, you know, our contracts will allow us to do it, but, you know, 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, you know, or something. It's got to wrap it up. So, yeah, 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, you know, adjust as we have to. but not 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 is our objective, not a worry that we're going to out, you know, spend our resources. Okay. Appreciate the call.

Thank you, Leo. 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. Hello? He's out buying stock. That's a good thing.

Hi, sir.

Can you hear me? Yes. Okay. Yes, go ahead. No, thanks for taking the time. No, I kind of just wanted to jump into, so 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 for that marginal rigger activity, whether that's the two that came out of core, should we expect that next marginal one to either come out of or go back into that same core acreage, or does that priority kind of shift more towards the western Hainesville, the closer we get to long term if we dropped any rigs they would come out of our core not the western haynesville understood thank you and then um kind of the other point is given the recent volatility we've talked about in the call today and kind of the longer term view of you know much um much greater level of demand in you know 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 kind of running to the kind of strategy you guys have been using for the last several quarters?

You know, several months ago, we looked at, again, these two-way collars with the floor to 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 that $250 million a day. I think we always, and 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's 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, you know, to keep the rigs, to have some ducts, et cetera. We've got a lot of controls on our panel. So, and we'll look at hedging.

Understood.

Thanks, McCulloch. Thank you. Good question.

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

Again, we've been on this an hour or 16. I think you're still there after the extra 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 de-risk the Western Hainesville. We thank you for supporting us in the past, and we thank you in advance for continuing to support us in the future as we de-risk the Western Hainesville and create the gas that the world needs and the spot that it needs in the United States. Thank all of you. Appreciate you.

This concludes today's conference call. Thank you for participating.

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