Thank you for joining us, and welcome to the Comstock Resources First Quarter 2023 Earnings Conference Call. All participants are currently in listen-only mode. Following the presentations, there will be a question-and-answer session. This call is being recorded. I would now like to hand over the conference to Mr. Jay Allison, Chairman and CEO. Please proceed.

Perfect, thank you, and good morning everyone. I would 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 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'll flip over to Slide 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. If you'll slip over to Slide 3, I want to address the issues. I've read, I think all of the analyst reports that have been published and understand the concerns. None are new 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, it is down $0.20. So, 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 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 asset. To that effect we're continuing to run a 2-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 to seven rigs running continue to be very solid now. 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're 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 5, 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 gas flow was $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 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. So now I'll turn it over to Roland to discuss the financial results. Roland?

Thanks, Jay. On Slide 4, we covered 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 and we generated $255 million of cash flow during the quarter, which is 14% less than 2022's first quarter. We reported adjusted net income of $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 5, 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. So 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 was higher than our normal 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're also 53% hedged, which improved our realized gas price to $3.07, and 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 price realization by another $0.07. On Slide 6, we detail our operating costs per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.83 in the first quarter, $0.07 higher than our fourth quarter rate. The increased unit costs are related primarily to the startup phase that we're having at our Western Haynesville area where fixed costs are being spread over 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, with our production taxes remaining 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. In Slide 7, 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/Bossier shale drilling program. We also spent another $32 million on non-operated wells. Spending on other development activities, which includes installing production tubing, offset frac 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 million cubic feet per day. On Slide 8, 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 in our bank group reaffirmed our $2 billion borrowing base with $1.5 billion of electric commitments. Our revolving credit facility matures in 2027, so we ended the first quarter 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, thank you, Roland. Slide 9 is the breakdown of our 2023 quarter-end drilling inventory. Our drilling inventory is split between Haynesville and Bossier, and we have it divided into four buckets. Our short laterals up to 5,000 feet, our medium laterals that run between 5,000 feet and 8,000 feet, our long laterals run from 8,000 feet 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 consists of 1,310 gross locations and 182 net locations, which represents a 14% average working interest. 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-foot to 15,000-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 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, as 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 feet. The individual laterals ranged from 4,514 feet 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 feet long. Five of the wells were beyond 11,000-foot laterals. We had two of the laterals coming in longer than 15,000 feet. Our record-long lateral well still stands at 15,726 feet. 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 #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, and with an average test rate of 23 million a day. The average lateral length was 11,042 feet with the individual laterals ranging 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 barrels to 30 barrels at natural gas liquids, which in turn enhances our economics by 20% to 30% versus the dry gas well. The average IP rate for our working interest ownership in the 15 wells for the quarter was 25 million a 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 #2 well was completed in the Bossier with a 12,763-foot-long lateral that was turned to sales in March. We tested the well with an IP rate of 36 million cubic feet a 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, 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 and 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 costs came in at $663 a foot, which is a 14% increase compared to the fourth quarter. The majority of the drilling cost increase is attributable to a shorter average lateral length of this quarter versus the last, along with inflation as most of the wells we turned to sales this quarter 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 that were fracked using the Titan natural gas fleet. As mentioned on 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.

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 all the gas we produce is responsibly sourced. In the future, that may create some additional value, but again, we're going to be stewards of the environment. If you would turn over to Slide 14, I'd direct you to Slide 14 where we summarize our outlook for 2023. We will continue to derisk and delineate our Western Haynesville play with the two-rig program in 2023, which I had 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, 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 response to this low natural gas prices. In addition to evaluating additional changes to our rig count, we are looking at delaying some completions. We are focused on maintaining the strong balance sheet that we had created last year, and 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 $0.205 for common shares. Lastly, we'll continue to maintain our very strong financial liquidity as Ron reported on, which totaled more than $1.5 billion at the end of the first quarter. I'll turn it over to Ron now for specific guidance for the rest of the year.

Thanks, Jay. On Slide 15, we provided the financial guidance for 2023. Second quarter production guidance of 1.375 Bcf to 1.435 Bcf 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 Bcf to 1.55 Bcf 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 will have an average lateral length of about 10,850 feet, which is 8.5% to 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 to $310 million and the full year D&C CapEx remains unchanged in the range of $950 million to $1.15 billion. In terms of our infrastructure and other spending, we continue to budget $15 million to $30 million of spending during the second quarter and $75 million to $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 to $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 for both the second quarter and the full year. Production and ad valorem taxes are now expected to average $0.12 to $0.16 in the second quarter and $0.14 to $0.18 for the full year, primarily related to the impact of lower gas prices on production taxes. The DD&A rate remains unchanged between the $0.95 and $1.05 range. Our cash G&A is still expected to total $7 million to $9 million in the quarter and $32 million to $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 to $36 million in the second quarter and $150 million to $155 million for the year, while our effective tax rate remains unchanged in the 22% to 25%. We now expect to be able to defer 95% to 100% of our reported taxes this year, primarily related to the lower commodity prices and our activity level. We'll now turn the call back over to the operator to answer questions from analysts who called to follow the company.

Thank you. Our first question comes from Derrick Whitfield from Stifel. Your line is open.

Thanks and good morning, all.

Good morning.

Good morning.

Before asking my questions, let me express that I understand the challenge of managing a business in the current environment and 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 is a service cost feedback loop, what does a 5 to 10 well completion deferral do to your second half production and free cash flow profile? And is that a reasonable toggle if we see gas prices down in the $1, $1.50 range?

Yes, Derrick, that's a good question. I mean, yes, I think that that's something we certainly can look at as kind of delaying completions, especially if we see continued weakness in gas prices stretching beyond the second quarter. Obviously, we have – I think our production, which is still kind of forecasted to grow some year-over-year, especially compared to last year kind of at the – as you saw in the first quarter, that it would just kind of flatten out. So it depends on how quickly we put that in place and when we resume completions again. Most of the activity that's going to affect the – this year, you'd have to kind of put that in place pretty early. Otherwise, you're really going to be affecting next year's production levels.

Terrific. And, 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 than the following four quarters based on Contango? And separately, how do you think the banks would likely view that scenario?

Well, other companies have such strong liquidity now and the great balance sheet kind of created by last year's debt pay downs. So I still think we – yes, we're – based on the current gas prices and all that, I mean, we may go backwards a step or two, but nothing to create any kind of concern for the banks. I mean, we have a significant borrowing base that was just redetermined that even beyond the commitment we have from them. So I don't see that any significant real deterioration in the balance sheet even if we don't change any of our plans. So yes, it's really – yes, as you look ahead to next year, do you have an environment that is weak next year or is it going to get back into the range of what the futures prices are saying? Next year you've got gas closer to $3.50. It's really a short-term phenomenon. And so we recognize that, and we'll continue to manage it very proactively. You saw this quarter, you have kind of the convergence of low gas prices and high service costs, high cost created from last year's high prices, but we do start to see be able to mitigate the cost side and get back into – potentially if prices stay longer for a longer period, we would expect the cost structure to come back down to where the strength of the company has always been, and we have the lowest operating cost structure in the industry. We're still very profitable even with these low gas prices. Our breakeven cost is almost $0.50 per Mcf lower than our peers, our gas –our public gas peers. So that strength will be part of the things that help the company handle the times that we're in now. And we've obviously had lots of experience doing that in the past.

And I think my initial comment would be we run the ship for the second half of 2023, all of 2024. And as Roland said, the gas prices look pretty favorable, particularly with our cost structure. So 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 really on a weekly basis, almost on a daily basis, look at hedging. We haven't put any hedges into 2024, but we look at that, we look at that weekly, just like we did in December of 2022. We put 25% collars in the second half of 2023. We added those. So I think you as a stakeholder need to know that we take – we do take looks at that. We do think there's going to be some cost deflation in the future. They've kind of run up on us and gas prices are dropped. So you are at that inflection point where there is a little bit more pain. But 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. So we look at that and we look at the results that we've had in our new play, and that's why we want to be very transparent in that. We've got a little different business plan than most. Most of these companies maybe have issues with inventory. We don't. Some of them have degradation issues. We don't. And most of them, you have to – your option is to acquire a rival for M&A. We are not looking to do that either. So it is a little different coloring book, a little different playbook, and we want to 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. And I know we're really solving for three to six months and that the outlook is quite constructive, so certainly thank you for taking the more difficult questions.

Thank you. One moment, please. Our next question comes from Jacob Roberts of TPHO. Your line is open.

Good morning, guys.

Good 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, 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. And we've moved rigs on and off based upon the performance. We said at the very onset that it was the very beginning. So take a look at it quarter by quarter by quarter. And 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 tells us to put a second one there. We've looked at the performance, which has been a little sporadic because of the takeaway facility, but the Circle M has been stellar. I think the second well looks really strong. The third well, we just IPed it, connected to shales only as of last month, and then we're completing a well right now, we're waiting to complete the fifth well and we're drilling two more. So we have great hopes for it, but 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 and we paid down our debt to get our balance sheet pristine. Then we looked at our long-term debt that's not due till 2029 at 10/2030, and that's at 5.875 and 6.75 debt. We looked at the amount of money that we had, and you noticed all the footprints that we owned in the Western Haynesville. I mean, it's paid for out of cash flow. The wells that we're drilling, we think that they should be drilled. We have great expectations, which we should, but we'll see how this progresses. I think by year-end, we'll have leased what we think is leaseable at a very low cost, which I think is the right price for the leases right now. But we want to make sure that – that is where we're looking, but we're looking there cautiously and we're keeping you updated quarterly.

Great. Appreciate that. And then maybe if we could circle back to some of the prepared remarks on the longer term LNG potential. I'm just curious 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.

Yes. Obviously, for us the ideal structure is to have a long-term market at the highest possible gas price that we can achieve and have one have certainty of markets and then certainty of price. So yes, I think that we expect to be able to do some big things in that area this year. I think the Western Haynesville hopefully plays a role in that. We already are a big supplier. We have done some 10-year contracts. I think that we could free up more gas that we're currently producing from other commitments; we want to continue to tie ourselves to the LNG shippers that are driving the gas demand.

Well, we look – natural gas is 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, all the narratives will tell you that they would really like to get it from the Haynesville. You're really not going to get the majority of it from Appalachia nor the Permian in our opinion and in their opinion. So if you could get it from the Haynesville/Bossier, that's where you would rather get it. So 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, who has the inventory that they can do business with that's predictable, who's got the balance sheet and the management capability to deliver what they need and we need over the decades, that is our longer-term view and what we're doing with the company.

Thank you very much. I 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.

Hi. Good morning, guys. You added a well in the Western Haynesville and the results are in the top quartile of your results, but it's still a little bit below that KZ Black well. Was there anything geologically different between the two wells? Or is the KZ Black well just too high a watermark to use as a comparison?

Hi. Yes, this is Dan. So you're right, we did, we tested, we IPed the KZ Black well at 42 million a day. The lateral length, the Circle M and the KZ Black had equivalent lateral lengths of just under 8,000 feet. We're really longer on this Campbell well, but the Campbell well looks really good. We're just trying to be real conservative on managing the drawdown. We certainly could have IPed this Campbell well a lot higher. We just chose not to; we IPed on a smaller choke. It's got really low drawdown. So we just – we basically want to produce the well at this rate. The Circle M is still flowing at 30 million. We had it shut in for about 35 days for an offset frac recently and just getting it back up to pace. The KZ Black wells are flowing between 25 million and 30 million a day, and we're going to flow this Campbell at 36 and just manage the drawdown.

Okay, great. And then I don't – maybe I missed it. Do you – 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 shales. So that – that we haven't given any inventory. And all that's all premature right now.

Okay, that sounds good. And then just shifting gears on the, I want to follow up on the LNG comment. You said you were trying to get the best gas price possible. There's been two approaches whether you want kind of a Henry Hub ship channel premium, or do you want to de-dock to the international pricing? I just wasn't sure if you guys, how you viewed the two. I'm sure you can get a higher price now, but it would come with some risk. So, I just want to dissect that answer.

Yes, no, we're still evaluating that. I think if you look at – if you look at being a major supplier to the, at least the LNG shippers we're talking to, 80%-plus of their business is tied to NYMEX. And so they need that – they're going to have to have their supply tied to NYMEX, and if you want to sell to them and if we want to buy processing capacity and sell in international markets, that's an option too. So all those are being explored and partnerships with one particular large one, it's kind of being explored. We're also, we could partner in the transport of the gas together versus involving other midstream companies that are having high tariffs to move your gas to the Gulf. So 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, and then if we want to explore participating in other markets, other indexes, that's certainly a possibility too.

And you have a better chance of doing that if you can prove that you have the quantity over the decades that everybody needs. And that's, again, that's what we're advertising today, is that we're going to stay the course, we're going to manage our balance sheet, and we're going to try to de-risk some inventory for the future. At the same time, we'll give you the results of the Campbell, which is, it is interesting that you put out an IP number and you produce it at that same number. Over the 36 years I've been in this business, most people IP it at three times what they produce it at. So it's a little different norm what we're doing here.

Yes, I would say the Campbell is probably the strongest well potential right now. And so, it's, and it may be producing at the highest level of the three. So IPs are just a one-day kind of number.

Yes. And I'll just reiterate, the wells are obviously capable of flowing at higher rates. They got great pressures. The drawdown looks superb, drawdowns much better than the drawdowns we see in our core, you know East Texas, North Louisiana area. So we're managing the wells for longevity for maximum value.

We put the asterisk on it, though you don't know how many more Campbell wells are out there, you don't know the footprint. And it's going to take, it's going to 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. And 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? And that's all I got. Thank you.

No, we're not. I mean, we definitely done; have done 10 years. And 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 want to be a long-term partner, that's something we're comfortable with. So, I think that'll be the trend of the future, would be continuing to want to have we want to get a lot more of our gas flow direct to the end users whether LNG or whether power generators or chemical, other type of industrial users along the Gulf Coast and be a long-term reliable supplier of those and capture, capture the highest price possible by being able to be direct connected to them.

And I would make a kind of global comment that, if you look at our major stockholder the Jerry Jones family, he converted his preferred into common in November. He gets a dividend like everybody else. He gets equity appreciation like everybody else, and he has a total of about $1.1 billion invested in the company because of that backstop, we're able to maneuver the way we're maneuvering today, and 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. So that is the, that's the little different nuance that we have and why we have it. But also, you have to look at the judgment calls that we make and see whether they've been good the last 15 months, 18 months, two years. I think they've been pretty good. But we do want everybody to know that 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 want to advertise that we are – we'll 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 want to ask a question about these upcoming Western Haynesville wells. My understanding is one of these upcoming two wells is going to 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 vertical, cores, and logs through the section. What, if anything, should we be looking for that might be different from this Haynesville test? 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 thoughts about what could be different there?

Hey, Charles, this is Dan, I'll try to answer your questions. So, 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. But the well that is waiting on completion was drilled as a Haynesville. We'll be starting to frac that well late next, late this month, I should say late May, and turning it into sales probably early July. The reason we drilled the first wells is Bossier’s were simply, we just looked at, was trying to give ourselves, the best chance of success. Because obviously, as you know, these wells are deeper, the temperatures are much warmer. But we've been pretty pleased with the progress we've made in a short period of time drilling just a few wells. We look at where the sticks are? Where we're going to be drilling? We look at the TVDs, we look at what we think the temperatures are going to be, and then we decide which one of the targets we need to pursue. So, and there's a part of the field over where the Campbell is, that's kind of down on the very far south, southwest end of our acreage for geological reasons. We only want to drill Bossier there. But for the rest of the play, we, kind of the Haynesville is our primary target, the Haynesville is the better rock based on all the work that's been done in the play. We expect superior results from our Haynesville completion.

The other thing, Charles, 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 going to save a lot of money on gathering costs. So we're going to have a competitive advantage there, which you don't put in the cost structure until you do it, but 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. So, you don't think about that when we talk about the cost structure. But you look at the Western Haynesville and where we're producing that, even if we produced the five wells and called Equip, I mean, it would still be a very good play for us as far as dollars in and dollars out and reserves.

That is all helpful detail. That's it for me. Thank you, Jay.

Thank you, Charles, appreciate you.

Thank you. One moment please. Our next question comes from the line of Phillips Johnston of Capital One Security. 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 about single well economics and your traditional Haynesville play. Just curious as to what you estimate the current breakeven flat gas price is at current well costs in order to generate a NPV break even at, 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 a little bit lower than that for Comstock. I mean, I think we're closer to $2 to $2.10 to $2.15. It really depends on what area we're drilling, what's the transportation cost? Because when you're talking about lower – if you're talking about getting closer to breakeven, if you have a $0.15 transportation cost or a $0.35, it really makes a difference. Last year with the high gas prices and the huge margins, a $0.10 or difference in transportation costs really was a rounding error in returns. Now it kind of comes back into focus. Yes, we shift back to the areas that have the lower cost structure, and you'll see even our gathering rates improve on that because 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 of lower transportation. So, our very best stuff we can probably get that breakeven level down to much closer to where the current monthly price is now. But if we stray out to other parts of our large footprint in the Haynesville, it can be a $0.30 difference. A lot of it is just the transportation. Some of it's EUR some of it is some areas costs. They're a little bit more expensive to drill certain parts of the Haynesville, because they're deeper. Some are easier. So, I think, yes, now you can lean into, you go to your very top players now, and I think that's kind of like what we did in 2020; it's kind of one thing you can shift to improve, 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. And just 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 a matter of seeing that 24 strip price move significantly lower, but probably not as low as that sort of breakeven price that you were referring to.

Right. I think you obviously, if you look at it, really the reality is a lot of the wells we're going to be drilling in the second half of the year are not going to even participate in this year's prices. To the extent that you don't have a good outlook, post this summer, and going into next year yes, that obviously changes maybe how you're drilling your inventory. But I do think the big shift is like we need to drill our low-cost, 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 other words back on hold until gas prices are strong again, then we can drill some of those areas like we did last year just to keep all parts of the inventory kind of moving. The Western Haynesville, we say, how does those come into play? But those are single wells, so they're not the pad drilling, which is a big cost saver. We still like to drill two to three wells on a pad because of the Zipper Frac capability and all that. But the Haynesville well, yes based on that 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 right now is dedicated to a more high-cost system.

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 and thank you for taking my questions.

Yes, sir.

My first question was on active delevers in the Haynesville. Would you love any color you can provide on any incremental Haynesville rig or crude reductions, which you are, which you're expecting based on your conversations with other operators in the basin?

Ron, what's the rig count right now?

The rig count according to inves is in the upper 50s to 60. That's down from a peak of about 70, 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'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 the starting point of 70 rigs, I think you'll 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 heard very much from private operators about activity, but given the number of rigs the privates are dropping, it would surprise me if you don't see some of the completion count or crew, the frac fleet count go down related to private activity as well, especially since those are the types of companies that drill directly out of cash flow.

That's really helpful. Thank you. I guess, and I'm probably acknowledging that it's probably way too early to talk about this, but 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 up to next year?

Well, 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. I think what we, our priority is, which we think is the most important part is to kind of continue to delineate and prove up and get a real grasp over the tight 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. So that's what we see as the big priority. The traditional Haynesville, which is our other areas that, those are areas that we're toggling. 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 improve the economics, but that's more just to generate the cash flow to keep the company in great shape.

Well, and as we said earlier, the United States should be the biggest beneficiary of the invasion by Moscow and to Ukraine. Why? Because of our abundant natural gas and our LNG export capability, we want to make sure we provide our fair share of natural gas to Europe, to Japan, wherever it needs to go.

That's helpful. 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 directs. I know the, 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, given included 20% or so in Q1 versus like 50% or so in Q4 of last year.

Yes, second half. I think that's, as we get the Titan in, there's pretty much as we've tracked it, measured it against our conventional diesel fleets, it's almost given us a 15% consistent savings on the completion cost, which is 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 lower emissions this year and next year in 2024, but also just the cost savings that it provides. 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, so that but that kind of, whether the second one comes in on time is probably the big question. But hopefully, it's in working sometime in the second half, definitely by the fourth quarter, then you'll see a lot of our completions at a lower cost. And we'll swap out some rigs with lower drilling rates too, so there are some positives on the horizon for later this year to see in some well cost savings there. But, I think they're mostly set, lucky, the earliest you start seeing those in the second half versus second quarter.

Okay. Understood. Thanks for the clarity and just one quick follow-up on the macro. Yes, we currently sell in 21% into LNG. Just kind of want to get my head around where you thought that ideal level would be on the longer term.

Yes, probably closer to 50%. I think we want to be, I think we, especially and a lot of it will depend on our new area, but that's probably some of our best highest realizations right now is on our 10-year contracts now that we're doing so, as we seek to maximize our gas price, that market, and potentially other markets that are industrial users, power generators, to the extent that they're competitive or beat those rates, we'll also want to add that to our portfolio. But yes, we would like to see working our way toward over 50% plus and that probably is more in 2025 or 2026 when all the, a lot of new capacity comes on. A lot of our other commitments 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 with the Eastern Can you kind of help us out there a little bit? I mean just in terms of what the kind of parameters there, I mean, are you seeing kind of maybe twice the EURs or something on these wells? Because my understanding is maybe they're roughly twice the costs early on. You know, at this point in time we're just trying to handle on sort of drill times and maybe what you think the early EURs are per foot on the first couple of wells.

Yes, that's a good way to frame it because we said basically that in order to make them competitive with the other wells, yes, you'll want twice the EUR. I think yes, the cost is early cost so I think the future cost of development will be significantly better. I mean, if we drill single wells in our traditional Haynesville, they will be our most costly wells because that’s why pad drilling is such a big important part of everybody's development plan now because the cost savings is so significant. That's the future of this play. But perfecting the drilling and completion will be the other part of getting the cost. Yes, generally, even out of the gate, we're not starting out in a bad position.

Yes. Okay. And then 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've got the second quarter guidance out there, so kind of flat on production and second quarter. So do we see like sequential growth in both 3Q and 4Q, assuming your plans don't change and conversely, do we see CapEx kind of dropping in both 3Q and 4Q from 2Q levels? We're trying to kind of get a handle on those kind of moving parts.

Yes, 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 going to be the highest CapEx. The second quarter you have our guidance, then your third and fourth quarters will probably be pretty similar because we'll be down to the seven rig count by the end of the second quarter. 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 the timing of completions in the Western Haynesville where 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 a flatter production profile. So your thoughts were correct.

Okay, but just to clarify though, on the CapEx third quarter and fourth quarter, pretty similar, but you think down versus kind of where the second quarter shakes out a little bit just because of the activity reduction?

Yes.

Okay. Yes. All right. No, that's helpful. And then I guess just a question just around cash taxes, obviously you took your guidance down, to call it fairly de minimus 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?

Well, we're still evaluating that. 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% to 80%, but it will continue to go back down as gas prices move up. This year clearly is impacted by such low gas price. If you want to just conservatively go back to that 75% to 80% deferred next year, we're just going to have to revisit that as we get closer to the year in terms of gas pricing 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. We all know that time is a valuable commodity and we want to thank each one of you for giving us an hour and 10 minutes of your time. We're going to be good stewards. So capital that we have and the future looks bright here. So 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.