Thank you for standing by and welcome to the Comstock Resources first quarter 2023 earnings conference call. At this time, all participants are on a listen only mode. After the speaker's presentations, there'll be a question and answer session. To ask a question at that time, please press star one one on your telephone. As a reminder, today's call is being recorded. I will now turn the conference over to your host, Mr. Jay Allison, Chairman and CEO. Please go ahead. Perfect. Thank you. Good morning, everyone. I'd like to welcome all of you to the Comstock Resources first quarter 2023 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 First Quarter 2023 Results. I have 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'll flip over to slide two, please refer to slide two in our presentation to 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 can be no assurance that such expectations will prove to be correct. If you'll flip over to slide two, I wanna kind of address the issues. You know, I've read, I think all of the analyst reports that have been published and understand the concerns. You know, none are of no concerns. We understand them. If you look at where oil is today, plus yesterday, it's down $7. If you look at where natural gas is yesterday and today it's down $0.20. You know, we all know that we're experiencing pressure with low natural gas prices currently in the short term. However, we're extremely positive on the outlook for natural gas in the future. Looking ahead several years, we recognize the growing need for natural gas around the world. Our long-term goal is to be a significant supplier to the growing LNG market that is developing several hundred miles from our Haynesville Shale operations, including our emerging Western Haynesville area. Around the world today, over $1 trillion of natural gas infrastructure is being built. Over the next five years in the United States, we see more than $100 billion worth of new LNG plants being operational. We're currently in discussions to enter into long-term contracts with major LNG shippers who are following our new play with significant interest. To accomplish that goal, we must be great stewards of managing our dollars in this low gas price environment, while at the same time continuing to delineate our Western Haynesville assets. To that effect, we're continuing to run a two-rig program that should result in 14 drilled wells by year-end 2023. We also plan to wrap up our leasing efforts that we started almost three years ago. In the first quarter, we made great strides by materially adding to our acreage position, as you've noted. The well results in our traditional Haynesville area, where we had six- seven rigs running, continue to be very solid. We'll be down to five rigs in the next couple of weeks. The first quarter still has some inflation baked into the well cost, but we see that abating in the next several quarters. We're continuing to reevaluate our rig count in our traditional Haynesville area, as well as our completion timing, to be responsive to the weak price environment we're in, as we're very focused on maintaining the strong balance sheet that we've worked so hard to create last year. In summary, we are implementing a practical business plan focused on the longer term cycle to position Comstock to benefit from the future growth in the LNG market. We'll monitor our plan to delineate our Western Haynesville play. We'll adjust it based upon the results that we achieve. We'll continue to prioritize our longer term goals while being very proactive to protect our strong balance sheet, which is allowing us to weather the current short term headwinds we see. If you go to slide three, we'll include some of the first quarter highlights. Our production increased 11% to 1.4 billion cubic feet of gas equivalent per day. We had oil and gas sales of $390 million and operating cash flow of $255 million or $0.92 per diluted share. Adjusted EBITDAX for the quarter was $293 million. Our adjusted net income for the first quarter was $92 million or $0.33 per share. The financial results in the quarter reflect the weaker natural gas prices following the warm winter, the weather that we had. In the first quarter, we drilled 18 or 13.7 net operated Haynesville and Bossier horizontal wells, which had an average lateral length of 12,075 feet. Since our last update, we've connected 15 or 9.8 net operated wells to sales with an average initial production rate of 23 million cubic feet per day. These wells include six wells with lower IP rates in the liquid rich area of Panola County, which has associated liquid production. We also announced our third successful exploratory well in our Western Haynesville play, the Campbell Well. which had an initial production rate of 36 million cubic feet per day, which is a rate that we expect to produce it at. We had an active quarter acquiring additional acreage in our Western Haynesville play. Now I'll turn it over to Roland to discuss the financial results. Roland? Thanks, Jay. On slide four, we cover a quick summary of our financial results that we reported for the first quarter. As Jay said, our production in the first quarter increased 11% to 1.4 Bcf per day as compared to the first quarter of 2022. Oil and gas sales in the quarter, including hedging gains, decreased by 4% to $390 million as lower natural gas prices offset the production growth that we had in the quarter. Our EBITDAX decreased by 12% to $293 million. We generated $255 million of cash flow during the quarter, 14% less than 2022's first quarter. We reported adjusted net income, $92 million for the first quarter, and our earnings per share came in at $0.33 as compared to $0.51 in the first quarter of 2022. On slide five, we provide a breakdown of our natural gas price realizations in the quarter. During the first quarter, the quarterly NYMEX settlement price, which averaged $3.42, was substantially higher than the average Henry Hub spot price in the daily market of $2.67. During the quarter, we nominated 82% of our gas to be sold at the index prices tied to that contract settlement price, and we sold the other 18% of our gas in the daily spot market. The estimated NYMEX reference price for our sales in the first quarter would have been $3.29. Our realized gas price during the first quarter averaged $2.98, reflecting a $0.31 differential to the reference price. That differential is higher than our normal for us due to the continued weaker Houston Ship Channel and Katy hub prices that persisted during a good bit of the first quarter due to the Freeport LNG facility shutdown. With the Freeport startup late in the quarter, we've seen these price differentials along the Texas Gulf Coast tighten up somewhat. About 57% of our gas is tied to the Gulf Coast market indexes, and we are currently selling 21% of our gas directly to LNG shippers. In the first quarter, we were also 53% hedged, which improved our realized gas price to $3.07. We've been using some of our excess transportation in the Haynesville to buy and resell third-party gas. This generated about $9 million of profit and improved our average gas, our gas price realization by another $0.07. On slide six, we detail our operating costs per MCFe and our EBITDAX margin. Our operating cost for MCFe averaged $0.83 in the first quarter, $0.07 higher than our fourth quarter rate. The increased unit costs are related primarily to startup, the startup phase that we're having at our Western Haynesville area, where fixed costs are being spread over a lower production volumes. We expect them to come down as our production grows in that area. Our gathering cost increased by $0.04 during the quarter, and our lifting cost increased by $0.03. Our production taxes remained the same as we had in the fourth quarter. Our EBITDAX margin after hedging came in at 73% in the first quarter, down from the 82% we had in the fourth quarter, where we had substantially stronger gas prices. On slide seven, we recap our spending and our drilling and other development activity in the first quarter. During the quarter, we spent a total of $325 million on development activities, including $278 million spent on our operated Haynesville and Bossier Shale drilling program. We spent another $32 million on non-operated wells. Spending on other development activity, which includes installing production tubing, offset frack protection, and other workovers, totaled $14 million in the quarter. In the first quarter, we drilled 18 or 13.7 net to our interest, operated horizontal Haynesville Bossier wells, and we turned 19 wells or 11.6 net operated wells to sales. These wells had an average initial production rate of 24 MMCF/day. On slide eight, we recap our balance sheet at the end of the first quarter. We ended the quarter with no borrowings outstanding under our credit facility and with $2.2 billion in long-term debt. In April, the 17 banks at our bank group reaffirmed our $2 billion borrowing base with $1.5 billion of electric commitments. Our revolving credit facility matures in 2027. We ended the first quarter with financial liquidity of more than $1.5 billion. I'll now turn it over to Dan Harrison to discuss our operations in more detail. Okay. Thank you, Roland. Slide nine is the breakdown of our 2023 quarter end drilling inventory. Our drilling inventory is split between Haynesville and Bossier. We got it divided into 4 buckets. Our short laterals up to 5,000 feet, our medium laterals that run between 5,000 and 8,000 feet. Our long laterals run from 8,000 to 11,000 feet, and our recently created category of our extra long laterals, for our wells that exceed 11,000 feet laterals. Our total operated inventory currently stands at 1,810 gross locations, 1,364 net locations, which equates to a 75% average working interest on the operated inventory. Our non-operated inventory, we have 1,310 gross locations and 182 net locations, which represents a 14% average working interest on our non-operated inventory. Based on the success of our recent extra long lateral wells, we continue to leverage our acreage position where possible to modify our drilling inventory and extend our future laterals, specifically targeting the 10,000-15 foot range. In our extra long lateral bucket, we currently have 459 gross operated locations and 334 net operated locations. To recap our gross operated inventory, we have 313 short laterals, 298 medium laterals, 740 long laterals, and the 459 extra long laterals. The gross operated inventory is split 53% in the Haynesville and 47% in the Bossier. By extending our laterals, the average lateral length in our inventory now stands at 8,928 feet. This is up slightly from our 8,870 feet we had at the end of 2022. In addition to the economic uplift, the longer laterals reduce our surface footprint and help us to reduce our greenhouse gas and methane intensity levels. Based on our planned 2023 activity level, this inventory provides us with a 25-year runway of future drilling locations. On slide 10 is a chart. This outlines the average lateral length, we've drilled by year. During the first quarter, we turned 19 wells to sales with an average lateral length of 9,898 ft. The individual laterals range from 4,514 ft on the short end, up to a 15,584-foot long lateral on the long end. 15 of the 19 wells we turned to sales during the quarter were our benchmark long lateral wells that are greater than 8,000 ft long. Five of the wells were beyond 11-foot laterals. We had two of the laterals coming in longer than 15,000 ft. Our record long lateral well still stands at 15,726 ft. This is on our East Texas acreage, and that well was turned to sales during the fourth quarter of last year. Included in the group is the third well we recently completed on our Western Haynesville acreage, the Campbell EOB No. 2H well, which was completed in the Bossier Formation with a 12,763-foot long lateral. Based on our current schedule, we plan to turn another 52 wells to sales by year-end. 22 of these 52 future wells will be extra long laterals beyond 11,000 feet, and 12 of the wells will be 15,000-foot laterals. If successful, our 2023 year-end average lateral length will increase to approximately 10,855 feet. Slide 11 outlines our new well activity. We have turned to sales and tested 15 new wells since the time of our last call. We had really good well performance again on this group of wells, with the individual IP rates ranging from 13 million a day up to 37 million cubic feet a day, with an average test rate of 23 million a day. The average lateral length was 11,042 feet, with individual laterals ranged from 4,514 feet up to 15,584 feet. Included in this latest well activity are six wells that were completed on our liquids-rich Haynesville acreage in Panola County. The gas produced on this acreage represents 25- 30 barrels of natural gas liquids, which in turn enhances our economics 20%-30% versus a dry gas well. The average IP rate for our working interest ownership in the 15 wells for the quarter is 25 MMCF/day, which is comparable to prior quarters, even with the six low IP wells, as we have a lower working interest in those wells. Also included this quarter was our successful third well on our Western Haynesville acreage. The Campbell No. 2 well, which was completed in the Bossier with a 12,763-foot long lateral, was turned to sales in March. We tested the well with an IP rate of 36 MMCF/day, and we are currently flowing the well at this rate today and plan to produce the well at this same rate. In addition, we are currently completing our fourth well on the acreage and have a fifth well that is waiting on completion. We expect to turn both of these next two wells to sales within the next couple of months. Additionally, we're running two rigs on our Western Haynesville acreage that is currently drilling our sixth and seventh wells. Slide 12 summarizes our D&C costs through the first quarter for our benchmark long lateral wells, which covers all our wells greater than 8,000 feet on our legacy core East Texas, North Louisiana acreage position. 14 of the 19 wells we turned to sales during the quarter were these benchmark long lateral wells. In the first quarter, our D&C cost averaged $1,579 per foot, which is an 11% increase compared to the fourth quarter and a 19% increase over our full year 2022 D&C cost. Our first quarter drilling cost came in at $663 a foot, which is a 14% increase compared to the fourth quarter. A majority of the drilling cost increase is attributable to a shorter average lateral length for this quarter versus the last, along with inflation, as most of the wells we turned to sales were drilled in the third quarter and early fourth quarter. Our first quarter completion costs came in at $916 a foot, which is a 9% increase compared to the fourth quarter. The primary contributor to our higher completion costs during the first quarter was the fact that only 20% of our first quarter well completions were fracked with our TITAN natural gas fleet, as opposed to more than half of our fourth quarter wells were fracked using the TITAN natural gas fleet. As mentioned on the previous calls, we've been able to capture significant savings through the use of the TITAN natural gas fuel fleet compared to the conventional diesel fleet. With that being said, we are expecting the delivery of our second TITAN fleet within the next couple of months. To sum up where we stand on activity levels, we are currently running eight rigs. One of these will be released in a couple of weeks to bring us down to seven rigs. On slide 13, we highlight our continued improvement related to greenhouse gas and methane emissions. We reported a greenhouse gas intensity of 3.47 kilograms of CO2 equivalent per BOE of production. This is a 3% improvement versus 2021. Where we reported a methane emission intensity rate of 0.045%, which is a 16% improvement versus 2021. We achieved those emissions improvements despite our turn to sales lateral feet increasing by 10% in 2022. Adjusting for lateral length completed for our turn to sales wells, our greenhouse gas emissions per lateral foot turn to sales improved 10%, while our methane emissions per lateral foot turn to sales improved by 22%. We deployed optical gas imaging and aircraft leak monitoring technology at almost 100% of our production sites, which earned us the ability to certify our gas as responsibly sourced. A natural gas-powered frack fleet eliminated approximately five million gallons of diesel by utilizing natural gas, offsetting approximately 10,200 metric tons of CO2 equivalent. As a reminder, our first natural gas-powered frack fleet began operating in April, so that data reflects just nine months of contribution to our 2022 numbers. With our second natural gas-powered fleet arriving in the field by the end of the second quarter, we should see continued reductions in our emissions. Our dual fuel drilling rigs eliminated approximately 0.6 million gallons of diesel by utilizing natural gas, which offset approximately 1,900 metric tons of CO2 equivalent. We installed instrument air on approximately 65% of our newly constructed production facilities, mitigating approximately 4,000 metric tons of CO2 equivalent. I'm now gonna turn the call back over to Jay to sum up the 2023 outlook. Thank you, Dan, and I believe that we're the first Haynesville Bossier company to have 100% of our natural gas certified by MiQ standards, which tells you that, you know, all the gas we produced is responsibly sourced gas. In the future, that may create some additional value. Again, we're gonna be stewards of the environment. If you would, turn over to slide 14. I direct you to slide 14, where we summarize our outlook for 2023. You know, we will continue to de-risk and delineate our Western Haynesville play with the two rig program in 2023, which I'd mentioned. Our primary objective this year is to prove up our new play. At the same time, we're managing our drilling activity levels to prudently respond to the lower gas price environment as we continue to experience it. You know, we will be releasing the second of the two rigs on our legacy Haynesville footprint within the next couple of weeks, which we discussed at the last conference call, in order to pull our activity in, with to response to this low natural gas prices. In addition to evaluating additional changes to our rig count, you know, we are looking at delaying some completions. We remain focused on maintaining the strong balance sheet that we had created last year. Our industry leading lowest 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. If we do plan to retain the quarterly dividend of that twelve and a half cents per common share. Lastly, we'll continue to maintain our very strong financial liquidity, as Roland reported on, you know, which totaled more than $1.5 billion at the end of the first quarter. I'll turn it over to Roland now for specific guidance for the rest of the year. Roland? Thanks, Jay. On slide 15, we provide the financial guidance for 2023. Second quarter production guidance of 1.375-1.435 BCFE a day is consistent with our prior commentary that the second quarter production should be similar to that of the first quarter. Full year guidance remains unchanged from our initial guidance for the year of 1.425-1.55 BCFE per day. During the second quarter, we do plan to turn to sales between 11 and 14 net wells. As Jay mentioned, our 2023 wells, or Dan mentioned, will have an average lateral length of About 10,850 feet, which is 8.5%-9% longer than last year, which continues to help offset some of the cost inflation that we had experienced. Second quarter D&C CapEx is $260 million-$310 million. The full year D&C CapEx remains unchanged at that $950 million-$1.15 billion range. In terms of our infrastructure and other spending, we continue to budget $15 million-$30 million in spending during the second quarter and $75 million-$125 million for the full year. In addition to what we spend on the drilling program noted above, we now anticipate spending between $50 million and $60 million this year on leasing activity. That number has increased due to our robust leasing activity in the first quarter, when we spent almost $41 million on new leases. LOE is now expected to average $0.22-$0.26 in the second quarter and the full year, while our GTC costs are expected to be between $0.32 and $0.36 per unit, both in the second quarter and the full year. Production and ad valorem taxes are now expected to average $0.12-$0.16 in the second quarter and $0.14-$0.18 for the full year, primarily related to the impact of lower gas prices on production taxes. G&A rate remains unchanged between the $0.95 to $1.05 range. Our cash G&A is still expected to total $7 million-$9 million in the quarter and $32 million-$36 million for the year, while the non-cash G&A continues to be about $2 million per quarter. Cash interest expense is expected to be $34 million-$36 million in the second quarter and $150 million-$155 million for the year. Our effective tax rate remains unchanged in the 22%-25%, we now expect to be able to defer 95%-100% of our reported taxes this year, primarily related to the lower commodity prices as well as our activity level. We'll now turn the call back over to the operator to answer questions from analysts who follow the company. Valerie? Thank you. Thank you. Ladies and gentlemen, if you'd like to ask a question, please press star one one on your telephone. To ask a question, please press star one one. One moment for our first question. Our first question comes from the line of Derrick Whitfield of Stifel. Your line is open. Thanks, and good morning, all. Good morning. Before asking my questions, let me express that I understand the challenge of managing a business in the current environment. Really with that said, I wanted to ask if you could place some parameters around the potential flex in your capital program for 2023. Understanding that that decision is price dependent and there's a service cost feedback loop, what does a 5-10 well completion deferral do to your second half production and free cash flow profile? Is that a reasonable toggle if we see gas prices down in the $1.50 range? Derrick, that's a good question. I mean, yeah, I think that, yeah, that's something we certainly can look at as kind of, as delaying completions, especially if we see continued weakness in gas prices kind of stretching beyond the second quarter. You know, obviously we have, you know, I think our production, which is still kind of forecasted to grow some year-over-year, especially compared to last year, kinda at the... as you saw in the first quarter, you know, that it would just, you know, kind of flatten out. It depends on, you know, how quickly, you know, we put that in place and when we resume, you know, completions again. most of the activity that's gonna affect, you know, the this year, you know, you'd have to kind of put that in place pretty early. Otherwise, you know, you're really gonna be affecting next year's production levels. Terrific. Roland, perhaps staying with you, with the understanding, again, that it's a delicate balance between your near and long-term priorities, and it's not entirely within your control on the macro side, what degree of leverage are you comfortable operating with, knowing that it will likely inflect much lower in the following four quarters based on contango? Separately, how do you think the banks would likely view that scenario? Well, the company's it has such, you know, strong liquidity now and a great balance sheet kinda created by last year's, you know, debt pay downs. I still think we're, you know, based on the, you know, current gas prices and all that, I mean, you know, we may go backwards a step or two, but nothing to create any kind of concern for the, you know, the banks. I mean, we have a, you know, significant borrowing base that was just redetermined that's even beyond the commitment we have from them. I don't, I don't see the, you know, any, you know, significant, you know, real deterioration in the balance sheet, even if we don't change any of our plans. Yeah, it's really, yeah, as you look ahead to next year, do you have an environment that's as weak next year, or is it gonna kinda get back into the range what the futures prices are saying? You know, next year you've got, you know, gas closer to $3.50. It's really a short-term phenomena, you know, we recognize that. You know, look, we'll continue to manage it very proactively. You know, you saw this quarter you have kind of the convergence of, you know, low gas prices and high service costs, high costs created from last year's high prices. We do, you know, start to see be able to mitigate the cost side and, you know, get back into, you know, potentially if prices stay for a longer period, we would expect the cost structure to come back down to where, you know, where the strength of the company has always been that we have the lowest operating cost structure in the industry. You know, and we're still very profitable even with these low gas prices. Our, our break-even cost, you know, is, you know, almost $0.50, you know, per MCF lower than our peers, our public gas peers. That strength will be part of the things that help the company, you know, handle the, you know, the times that we're in now. You know, we've obviously had lots of experience doing that in the past. I think, you know, my initial comment would be we, you know, we run the strip for the, you know, the second half of 2023, all of 2024. As Roland said, the gas prices, they look pretty favorable, particularly with our cost structure. Our outlook on natural gas is extremely positive. We've looked at maybe looking into non-operated properties, how can we lower that commitment. We also, you know, really on a weekly basis, almost on a daily basis, look at hedging. You know, we haven't put any hedges into 2024, but we look at that. We look at that weekly. That's like we did in December of 2022. We put, you know, 25% collars in the second half of 2023, we added those. I think you as a stakeholder need to know that we do take looks at that. We do think there's gonna be some cost deflation in the future. They've kind of run up on us and gas prices have dropped. You are at that inflection point where there's a little bit more pain. What overrides all that is the fact that our 470,000 net Haynesville acres are within several hundred miles of the Gulf Corridor, where 95% of all the LNG shippers are building their export facilities. We look at that, and we look at the results that we've had in our new play, and that's why we wanna be very transparent in that we've got a little different business plan than most. You know, most of these companies maybe have issues with inventory. We don't. Some of them have degradation issues. We don't. Most of them, your option is to acquire a rival for M&A. We're not looking to do that either. It is a little different coloring book, a little different playbook, and we wanna make sure that those that support it know what they're supporting. I think it's based upon good judgment, and it's based upon the need for natural gas globally around the world in the future. Thanks, guys. I know we're really solving for three-six months and that the outlook is quite constructive. Certainly thank you for taking the more difficult questions. No, thank you. Great question. Thank you. One moment please. Our next question comes from the line of Jake Roberts of TPH&Co.. Your line is open. Morning, guys. Morning. I was hoping to hear more about the leasing program process in the Western Haynesville. In particular, how competitive has it been, maybe the size and scale of some of the deals you've done, and then perhaps thoughts on when you guys might be able to provide an acreage map and things like that to the market. Well, you know, we said at the very beginning that we started leasing there three years ago. We've been very cautious on what we've been doing at the drill bit, we've moved rigs on and off based upon the performance. We said at the very onset that it was a very beginning. Take a look at it, you know, quarter by quarter by quarter. You know, all that we can tell you now is that it did tell us to put a second rig there. It didn't tell us to put a third, fourth, fifth rig there. It told us to put a second one there. We've looked at the performance, which has been a little sporadic because of the takeaway facility, the Circle M has been stellar. I think the second well, you know, looks really strong. The third well, we just IP'd it, connected to sales, only as of last month. We're completing a well right now. We're waiting to complete a fifth well, and we're drilling two more. We have great hopes for it. Like all of these plays, you've got to be cautious. I think that's where we tell you that we took the majority of our dollars last year when we paid down our debt to get our balance sheet pristine. We looked at our long-term debt that's not due till 2029 at 2030, and that's at five and seven-eight and six and three-quarters debt. We looked at the amount of money that we had, and you noticed all the footprint that we own in the Western Haynesville. I mean, it was paid for out of cash flow. The wells that we're drilling, we think that they should be drilled. You know, we have really great expectations, which we should, but we'll see how this progresses. And I think by year-end, we'll have leased what we think is leasable at a very low cost, which I think that's the right price for the leases right now. We wanna make sure that you know that that is where we're looking. We're looking there cautiously, and we're keeping you updated quarterly. Great. Appreciate that. Then maybe if we could circle back to some of the prepared remarks on the longer-term LNG potential. I'm just curious, you know, what is perhaps the ideal structure you guys are after in those longer-term contracts and just how those discussions have been going? Thank you. Obviously, that, you know, for us, the ideal structure is to have a long-term market at the, you know, highest possible gas price that we can achieve, you know, and, you know, have certainty of markets and then certainty of price. I think that we expect to be able to do some big things in that area this year. I think, you know, the Western Haynesville hopefully plays a role in that. We already are a big supplier. We have done some 10-year contracts, I think as we can free up more gas that we're currently producing from other commitments, you know, we continue to want to power ourselves to the LNG shippers that are kind of driving, you know, the gas demand. Well, you know, we look, natural gas is a, it's a precious fossil fuel. If you've got $100 billion that you're spending for LNG exporters, you need that precious gas. If you can get it, you know, all the narratives will tell you that they'd really like to get it from the Haynesville. You're really not gonna get majority of it from Appalachia nor the Permian, in our opinion and in their opinion. If you could get it from the Haynesville Bossier, that's where you would rather get it. You know, we do treat it as the precious commodity, and we try to de-risk this Western Haynesville because they're really looking for commitments not for 2027, but for 2047. You know, who has the inventory that they can do business with that's predictable, that's got the balance sheet, and the management capability to deliver what they need and we need over decades. That is our longer term view of what we're doing with the company. Thank you very much. Appreciate the time, guys. Thank you. One moment, please. Our next question comes from the line of Bertrand Donnes of Truist. Your line is open. Hey, morning, guys. You added the well in the Western Haynesville, and, you know, it results in the top quartile of your results, but it, you know, it's still a little bit below that Cazey Black well. Was there anything geologically different between the two wells, or is the Cazey Black well just too high of a watermark to use as a comparison? Yeah, this is Dan. You're right. We did. We tested. We IP'd the Cazey Black well at 42 million a day. The lateral length, the Circle M and the Cazey Black had equivalent lateral lengths of just under 8,000 foot. You know, we're really longer on this Campbell Well. The Campbell Well looks really good. We're just trying to be real conservative on managing the drawdown. We certainly could have IP'd this Campbell Well a lot higher. We just chose not to. We IP'd it on a smaller choke. It's got really low drawdown. We just, you know, we basically wanna produce the well, you know, at this rate. We got the Circle M is still flowing at 30 million. We had it shut in for about 35 days for an offset frac here recently and just getting it back up to pace. We're, you know, the Cazey Black wells is flowing between 25 and 30 million a day, and then we're gonna flow this Campbell at 36 and just manage the drawdown. Okay, great. Maybe I missed it. How many, how much remaining inventory do you have in the Western Haynesville? Have you guys outlined that yet, or what are you thinking there, and just how many wells are coming on this year as well? No, we've just said, that we'll drill 14 total Western Haynesville wells by year-end and probably have eight or nine of those connected to sales. We haven't given any inventory, and all that's a little premature right now. Okay. That sounds good. Just shifting gears on the-- I wanna follow up on the LNG comments. You said you're trying to get the best, you know, gas price possible. You know, there's been two approaches, whether you want kind of a Henry Hub ship channel premium, or do you want to deduct to the international pricing? I just wasn't sure if you guys, how you viewed the two. You know, I'm sure, you know, you can get a higher price now, but it would come with some risk. I just wanna dive back to that answer. Yeah. That, we're still evaluating that. I think if you look at being a major supplier to the, at least the LNG shippers we're talking to, you know, 80%+ of their business is tied to NYMEX. They're gonna have to have their supply tied to NYMEX. If you wanna sell to them, if we wanna buy processing capacity and sell in international markets, you know, that's a, that's an option too. All those are being explored and partnerships with one particular large one is kinda being explored. You know, we're also like we could partner, you know, in the transport of the gas together versus, you know, have, you know, involving other midstream companies, you know, that, you know, are, you know, having high tariffs to move your gas to the Gulf. I think it's kind of all the above. I mean, the main thing we're focused on, let's make sure we're getting the absolute like a premium NYMEX gas contract with low transport to the Gulf. If we wanna explore participating in other markets, other indexes, you know, that's certainly a possibility too. You know, you have a better chance of doing that if you can prove that you have the quantity over the decades that everybody needs. That's, again, that's what we're advertising today, is that we're gonna stay the course, we're gonna manage our balance sheet, and we're gonna try to de-risk, you know, some inventory for the future. At the same time, you know, we'll give you the results of the Campbell, which is interesting that you put out an IP number, and you produce it at that same number. You know, over the 36 years I've been in this business, most people IP it at three times what they produce it at. It's a little different norm, what we're doing here. Yeah. I would say the Campbell is probably the strongest well, you know, potential right now. It may be producing at the highest level of the three. IPs are just a one day kinda number. Yeah. You know, and I'll just reiterate, the wells are obviously capable of flowing at higher rates. They got great pressures. The drawdown looks superb. The drawdown's much better than the drawdowns we see in our core, you know, East Texas, North Louisiana area. You know, we're just, we're managing the wells for longevity, for, you know, maximum value. You know, we put the asterisks on it, though. You don't know how many more Campbell wells are out there. You don't know the footprint, and it's gonna take, it's gonna take a long time to de-risk this. That's why we've taken the long road to do this, the slow road to do it. That's great color, guys. Then just the second part of that, LNG, was what about term? Are you scared of a 20-year commitment, or what's the limit to that? That's all I got. Thank you. No, we're not. I mean, we have done 10 years. I think that I think given our long inventory life is a big advantage we have over a lot of the other potential Haynesville suppliers. I think to the extent that we like the contract and wanna be a long-term partner, you know, that's something we're comfortable with. I think that'll be the trend of the future, will be continuing to wanna have, we wanna get a lot more of our gas sold direct to the end users, whether LNG or whether power generators or chemical, you know, other type of industrial users along the Gulf Coast and be a long-term reliable supplier of those and capture, you know, and capture the highest price possible by being able to be direct connected to them. You know, I would make a kinda global comment that if you look at our major stockholder, the Jerry Jones family, you know, he converted his preferred into common in November. He gets a dividend like everybody else. He gets equity appreciation like everybody else. He has a total of about $1.1 billion invested in the company. Because of that backstop, you know, we're able to maneuver the way we're maneuvering today, we're taking the longer term view, and we're showing you how precious we think natural gas is and how attractive we're trying to be for LNG shippers. That is the, that's the little different nuance that we have and why we have it. Also, you have to look at the judgment calls that we make, and see whether they've been good the last, you know, 15, 18 months, two years. I think they've been pretty good. We do want everybody to know that, you know, we do read all the analyst reports, and we're with you. We try to make changes when we need to, like the two rigs that we got rid of before anybody had a conference call last time. We got rid of those. We wanna advertise that we will toggle things around to make sure that, one, we always protect the balance sheet. Thank you. One moment, please. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is open. Good morning, Jay and Roland, and to the rest of the Comstock team there. Hello, Charles. Jay, I wanna ask a question about these upcoming Western Haynesville wells. My understanding is one of these upcoming two wells is gonna test the deeper part of the section, actually, the Haynesville section, as opposed to the, I guess, the previous four would all be Bossier wells. My understanding is you guys have a lot of, you know, vertical, you know, cores and logs through the section. What, if anything, should we be looking for that might be different from this Haynesville test? And are there any things that you, in particular, are looking for, would alert us to about whether it's higher pressure, more difficult drilling? Just any, you know, your thoughts about what could be different there. Hey, Charles, this is Dan. I'll try to answer your question. We have everything that we have put on so far have been Bossier wells, the three producers. We do have one that's fracking right now that's also another Bossier. The well that is waiting on completion was drilled as a Haynesville. We'll be starting to frack that well late this month, I should say, late May, and turning it to sales probably early July. That, you know, the reason we drilled the first wells as monobores, were simply we just looked at was trying to give ourselves, you know, the best chance of success. Because obviously, as you know, these wells are deeper, the temperatures are much, much warmer. We've, you know, been pretty pleased with the progress we've made in a short period of time drilling just a few wells. We, you know, we just basically look at where the sticks are, where we're gonna be drilling. We look at the TVDs, we look at what we think the temperatures are gonna be, and then we, you know, we just decide which one of the targets we need to pursue. There's a part of the field over where the Campbell is that's kind of down on the very far southwest end of our acreage. For geological reasons, you know, we only want to drill monobores there. You know, for the rest of the play, we, you know, kind of the Haynesville's our primary target. The Haynesville's the better rock based on all the work that's been done in the play, you know, we do expect superior results from our Haynesville completions. The other thing, you know, Charles, if you look at a competitive advantage, remember, in 2022, we bought the Pinnacle plant and then the 145-mile line. If we could drill these wells closer to the Pinnacle line, if they need to be drilled there, then we're gonna save a lot of money on gathering costs. We're gonna have a competitive advantage there, which you don't put in the cost structure till you do it. Some of the next wells we drill will go into our line that we own, that has probably $300 million of capacity, more or less. You don't think about that when we talk about the cost structure. You know, you look at the Western Haynesville and where we're producing that, even if we produce the five wells and called it quit, I mean, it would still be a very good play for us as far as dollars in, dollars out and reserve added. That is all helpful detail. That's it for me. Thank you, Jay. Thanks, Charles. Appreciate you. Thank you. One moment please. Our next question comes from the line of Phillips Johnston of Capital One Securities. Your line is open. Hey, guys. Thank you. Just to follow up on some of the factors that are coming into play around managing your activity levels, I wanted to ask you about single well economics in your traditional Haynesville play. Just curious as to what you estimate the current break-even flat gas price is at current well costs in order to generate a NPV break even. You know, the last time I ran that analysis a few months ago, I came up with roughly $2.50 flat. Does that sound about right to you guys? Well, we think it's low-bit lower than that for Comstock. I think that we're closer to $2.10-$2.15. It really depends on what EUR we're, what area are we drilling? What's the transportation cost? Because when you're talking about getting closer to break even, if you have a $0.15 transportation cost or a $0.35, it really makes a difference. I think last year with the high gas prices and the huge margins, a $0.10 difference in transportation costs really was a rounding error in returns. Now it kinda comes back into focus, and I think that's one thing, you know, we shift back to the areas that have the lower cost structure. You'll see, you know, even our gathering rates creep up on it 'cause we drilled in these other areas last year with the high gas price that have higher transportation. We can lean back in in our inventory on the areas with lower transportation. You know, our very best stuff, we can probably get that break-even level down to, it's much closer to where the, the current monthly price is now. If we, if we stray, you know, way out, you know, to other parts of our large footprint in the Haynesville, you know, it can be $0.30 difference. A lot of it is just the transportation. Some of it's EUR. Some of it is some areas cost. They're a little bit more expensive to drill certain parts of the Haynesville 'cause they're deeper, and some are easier. I think, yeah, now you can lean into... You go to your, you know, your very top players now, and I think that's kinda like what we did in, you know, 2020. It's kinda one thing you can shift to kind of overall improve, you know, you get to your best wells that can hit that are making money in this environment. Okay, great. That was really helpful. Thanks for that. I guess, in terms of what might trigger you guys to drop an incremental rig or two, I'm guessing it would just be sort of, you know, a matter of seeing that 24 strip price move significantly lower, but probably not as low as that sort of break-even price that you were referring to. Right. I think you obviously, if you look at really the reality is a lot of the wells that we're gonna be drilling in the second half of the year are not gonna even participate in this year's prices, you know. To the extent that, you know, that you don't have, you know, a good outlook, you know, post this summer, you know, and, you know, going into next year, yeah, that obviously changes maybe, you know, how you're drilling your inventory. I do think, you know, the big shift is like we need to drill our lowest cost kind of projects, and that's easier to do now that we reduced the rig count and pulled in the activity. really just kind of put the others back on hold until, you know, gas prices are strong again, and then we can drill some of those areas like we did last year, just to keep, you know, all parts of the inventory kind of, you know, moving. frankly, the Western Haynesville, you say, how does those come into play? Those are single wells, so they're, you know, they're not the pad drilling, which is a big cost saver. We still like to drill two- three wells on a pad because of the zipper frack capability and all that. The Haynesville well, yeah, based on the, they actually can compete, believe it or not, with our top low-cost wells, especially when we get them on our gathering system, and we save that transportation cost that we right now are, you know, the first wells are dedicated to a more higher cost system. If you look at the overall longer-term activity out there, a lot of it will be where we control the transportation cost on the Pinnacle system that Jay referenced. Okay, great. Thanks, Roland. Thank you. Thank you. One moment, please. Our next question comes from the line of Umang Choudhary of Goldman Sachs. Your line is open. Hi, good morning, thank you for taking my questions. Yes, sir. My first question was on activity levels in the Haynesville. Would love any color you can provide on any incremental Haynesville rig or crew reductions which you are expecting based on your conversations with other operators in the basin. Ron, what's your rig count right now? The rig count, according to Enverus, is in the upper 50s to 60. That's down from a peak of about 70. You know, between us, Chesapeake and Southwestern, that's five or six rigs that we've communicated to the Street that those three companies would be dropping. You know, you've had some of the larger privates that have already reduced the number of rigs, and I think there's more to go. When you think about starting point of 70 rigs, I think it's somewhat... You will end up seeing at least 15, maybe closer to 20 rigs being dropped between the three primary public operators and the private operators in the area. In terms of completion crews, I know a couple of companies have talked about potentially reducing or removing a completion crew at some point later this year. I haven't, I haven't heard very much about from private operators activity. But given the amount of rigs that the privates are dropping, it would surprise me if you don't see some of the completion count or crew, the frack fleet count go down related to private activity as well, especially since those are the type of companies that do drill directly out of cash flow. All right. That's really helpful. Thank you. I guess, I'm probably acknowledging that it's probably way too early to talk about this. Given your deep inventory and your proximity to LNG markets and your outlook on natural gas, as we look at the strip today and assuming that holds, especially in the back half of 2024 and heading into 2025, when would you like to add activity to grow into those kind of prices, as you look out to next year? I think that we're not thinking that we can really predict the future gas prices or be super comfortable with even what the futures market shows. I don't think that we're at all trying to time growing activity into that or trying to guess, you know. I think our priority is, you know, to which I really think is the most important part, is to kind of continue to delineate and prove out and get, you know, real grasp over the type curve and the productivity of our new play. I think over this period of time before this demand is needed, that's real critical. That way, they can rely on that source, and then we can develop that source based on that new market. That's what we see as the big priority. you know, our, what we call the traditional Haynesville, which is our other areas, that those are areas that we're toggling because, you know, that's just that we don't have to develop that inventory at any particular time. It's a deep inventory. We can go to different parts, like we said, to kind of improve the economics. That's more just to generate the cash flow to, you know, keep the company in great shape. There's really two different, kind of, two different priorities there that we're balancing in this market. Well, as we said earlier, you know, the United States should be the biggest beneficiary of the invasion by Moscow into Ukraine. Why? Because of our abundant natural gas and our LNG export capability. We at Gulfport want to make sure we provide our fair share of natural gas to Europe, to Japan, wherever it needs to go. Well, that's helpful. Thank you. Thank you so much for taking my questions. Thank you. One moment, please. Our next question comes from the line of Paul Diamond of Citi. Your line is open. Hi. Thank you. Good morning. Thanks for taking my call. Just wanted to touch base on kind of H2 cost structures. I know with the new TITAN asset coming online, we would expect a bit more utilization there. Just kind of curious how you guys saw that running through in H2. You know, given you included 20% or so in Q1 versus, like, 50% or so in Q4 of last year. Yeah, second half. I think that's, you know, as we get the TITAN in, you know, there's pretty much as we've tracked it, you know, measured it against our conventional diesel fleets, you know, it's almost given us a 15% consistent savings, you know, on the completion cost, which is the, you know, the largest part of the cost of the well. We're excited about that, about having that be a real driver to not only to help us score, you know, lower emissions, you know, this year and next year in 2024, but also just the cost savings that it provides and, you know, and it's an ideal location for it in the Haynesville because we have such an abundant gas supply that is drilling around. We've been very happy with the first one. That's kind of, you know, whether the second one comes in on time is probably the big question. Hopefully it's in working sometime in the second half, definitely by the fourth quarter, you know, you'll see a lot of our completions at a lower cost. We'll swap out some rigs with lower drilling rates too, that we're. There are some positives on the horizon for later this year to see in some well cost savings there. You know, I think they're mostly the earliest you start seeing those is second half versus, you know, second quarter. Okay, understood. Thanks for the clarity. Just one quick follow-up on the macro. You guys are currently selling 21% into LNG. Just kinda wanna get my head around where you thought that ideal level would be on the longer term? Yeah, probably closer to 50%. You know, I think we, you know, especially, you know, and a lot of it will depend on our new, our new area. You know, that's probably some of our best, highest realizations right now is on our 10-year contract now that we're doing. As, as we seek to maximize our gas price, you know, that market and potentially other markets that are, you know, industrial users, power generators, you know, to the extent that they're competitive or beat those rates, you know, we'll also wanna add that to our portfolio. Yeah, we would, we would like to see working our way toward over, you know, 50% plus. You know, that probably is more 2025, 2026 when all the, you know, a lot of new capacity comes on. Then a lot of our other commitments, you know, maybe roll off. Understood. Thanks for your time. Thank you. Thank you. One moment, please. Our next question comes from the line of Leo Mariani of Roth. Your line is open. Thanks. I just wanted to follow up briefly on the Western Haynesville here. You guys talked about these wells, even though it's early days, having kind of competitive returns, you know, with the Eastern. Can you kinda help us out there a little bit? I mean, just in terms of what the kind of parameters there. I mean, are you seeing kinda maybe twice the EURs or something on these wells? 'Cause my understanding is maybe they're roughly twice the costs early on, you know, at this point in time. Just trying to get a handle on sort of drill times and maybe what you think the early EURs are per foot on the first couple wells. Yeah. That's a good way to frame it because we said basically that kind of a... in order to make them competitive with the other wells, you know, yeah, you'll want twice the EUR. Yeah, but I think, you know, the cost is early cost, you know, so I think the future cost, the development cost will be significantly better. I mean, you know, if we drill single wells in our traditional Haynesville, they will be our most costly wells. You know, that, you know, that's why pad drilling is such a big important part of everybody's, you know, development plan now because the cost savings is so significant. That, that's for the future of this play, but then also just perfecting the drilling and completion will be the other part of getting the cost. Generally, you know, even out of the gate, you know, we're not starting out in a bad position. I think, Leo, you know, we're on the cutting edge of technology when we started doing it. Now, you know, we've been pretty successful with the wells that we've turned to sales from completing and drilling. As this kind of unfolds through 2023, 2024, then we can be, you know, give you a little more clarity on it. Yep. Okay. Just wanted to kind of ask a little bit around sort of production cadence and CapEx cadence as we move into the second half. Obviously, you've got first quarter behind you. You've got the second quarter guidance out there. Kind of flat on production in second quarter. Do we see like sequential growth in both 3 Q and 4Q, you know, assuming your plans don't change? Conversely, do we see CapEx kind of dropping in both 3Q and 4Q, you know, from 2Q levels? Just trying to kinda get a handle on those kind of moving parts. Well, clearly, since we had nine rigs for most of the first quarter and we're dropping down to seven over the course of the second quarter, the first quarter was gonna be the highest CapEx rate. The second quarter, you have our guidance. Your third and fourth quarters will probably be pretty similar 'cause we'll be down to the seven rig count by the end of the second quarter, and that's probably the way I would think about CapEx cadence. From a production standpoint, you're right, there's some sequential growth in both the third and fourth quarters to get to that full year production guidance. A lot of that is related to, if you think about the impact of the timing of completions in the Western Haynesville, where, you know, going forward with two rigs there, we'll have kind of two completions every quarter or so, and those come on at pretty high rates and flatter production profile. Your thoughts were correct. Okay. just to clarify though, on the CapEx third quarter and fourth quarter, pretty similar, but you think down versus kinda where second quarter shakes out a little bit just because of the activity reduction? Ye-yes. Okay. Yep. All right, no that's helpful. I guess just a, you know, a question just around cash taxes. Obviously you took your guidance down, you know, to call it fairly de minimis as a percentage of actual taxes in 2023. If we look at next year, like you said, $3.50 is roughly the futures price at this point. Do you see cash taxes up significantly next year? Any kind of ballpark in terms of what percentage of total taxes will be cash in 2024 based on what you see today? We're still evaluating that. I, you know, I think if you end up with a $3.50 gas price, then there's a chance that the cash or the deferral rate goes back down. I don't know if it goes all the way down to the 75%-80%, but it will go back down as gas prices move up. This year clearly is impacted by the such low gas price. You know, if you, if you wanna just conservatively go back to the, that 75%-80% deferred next year, and we're just gonna have to revisit that as we get closer to the year in terms of gas prices for next year. Okay. Thank you. Thank you, Leo. Thank you. This does conclude the conference for today. I'd like to turn the call back over to Jay Allison for any closing remarks. Sure. You know, we all know that time is a valuable commodity. We wanna thank each one of you for you know, giving us an hour and 10 minutes of your time. We're gonna be good stewards of the capital that we have. The future looks bright here. Thank you for your time. Thank you. Ladies and gentlemen, this does conclude today's conference. Thank you all for participating. You may now disconnect. Have a great day.