Comstock Resources, Inc.

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 11 on your telephone. As a reminder, today's call is being recorded. I would now like to turn the conference over to your host, Mr. Jay Allison, Chairman and CEO. Please go ahead.

Perfect. Thank you, and 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 as Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer. 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 and note that our discussion today will include forward-looking statements. than 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 slip over to slide three, I want to 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 new concerns. We understand them. If you look at where oil is today plus yesterday, it's down $7. Look at where natural gas is yesterday and today, it's down 20 cents. So, 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 Hainesville Shield operations, including our emerging Western Hainesville area. Around the world today, over a trillion dollars 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, great stewards of managing our dollars in this low gas price environment. while at the same time continuing to delineate our Western Angel asset. 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 Hainesville 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 Hainesville 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 Hainesville 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 92 cents per diluted share. Adjusted EBITDAX for the quarter was $293 million. Our adjusted net income for the first quarter was $92 million, or 33 cents 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 Hainesville 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 cells 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 Hainesville play, the Gamble 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 requiring additional acreage in our Western Hainesville play. So now I'll turn it over to Roland to discuss the financial results. Roland?

Thanks, Jay. On slide four, 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 EVA DACs decreased by 12% to $293 million, and we generated $255 million of cash flow during the quarter, 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 33 cents as compared to 51 cents 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. So the estimated NYMEX reference price for our sales in the first quarter would have been $3.29. Our Realaz gas price during the first quarter averaged $2.98, reflecting a $0.31 differential to the reference price. That differential was higher than normal for us due to the continued weaker Houston ship channel and KD 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 Hainesville to buy and resell third-party gas. This generated about $9 million of profits and improved our average gas price realization by another $0.07. On slide six, we detail our operating costs per MCFE and our EBITDAX margin. Our operating costs for MCFE averaged 83 cents in the first quarter, seven cents higher than our fourth quarter rate. The increased unit costs are related probably to startup, the startup phase that we're having in our western Hainesville 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 costs increased by four cents during the quarter, and our lifting costs increased by three cents. 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. In slide seven, we recap our spending on 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 Hainesville and Bossier Shale drilling program. We also 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 interests, operated horizontal Hainesville-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 Hainesville and Bossier. We got it divided into four 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 to 15,000 foot range. In our extra long lateral bucket, we currently have 459 gross operated locations and 334 net operated locations. And 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 Hainesville 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 88 170 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 plan 2023 activity level, this inventory provides us with a 25-year runway of future drilling locations. On slide 10, there's a chart that outlines the average lateral length we've drilled by year. During the first quarter, we turned 19 wells to cells with an average lateral length of 9,898 feet. The individual laterals range 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 cells during the quarter were our mint smart 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 cells during the fourth quarter of last year. Included in the group is the third well we recently completed on our western Hainesville acreage, the Campbell EOB number 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 cells 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 Hainesville acreage in Panola County. The gas produced on this acreage represents 25 to 30 barrels of natural gas liquids, which in turn enhances our economics 20 to 30% versus a dry gas well. The average IP rate for our working interest ownership in the 15 wells for the quarter is 25 million a day, which is comparable to prior quarters, even with the six low IP wells as we have a lower lower working interest in those wells. Also included this quarter was our successful third well on our western Hainesville acreage, the Campbell No. 2 well, which was completed in the Bossier with a 12,763-foot-long lateral. It 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 Hainesville acreage that is currently drilling our sixth and seventh wells. Slide 12 summarizes our D&C cost 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 DNC cost. Our first quarter drilling cost 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 for this quarter versus the last, along with inflation, as most of the wells we turn to sales were drilled in the third quarter and early fourth quarter. Our first quarter completion cost came in at $916 a foot, which is a 9% increase compared to the fourth quarter. The primary contributor to our higher completion cost during the first quarter was the fact that only 20% of our first quarter well completions refract with our Titan natural gas fleet, as opposed to more than half of our fourth quarter wells refract using the Titan natural gas fleet. As I 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. 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 feed 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 gases responsibly sourced. Our natural gas-powered FRAC fleet eliminated approximately 5 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 frac 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 Hainesville 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 gas. 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'll direct you to slide 14, where we summarize our outlook for 2023. You know, we will continue to de-risk and delineate our western angel 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. You know, we will be releasing the second of the two rigs on our legacy footprint within the next couple of weeks. which we discussed at the last conference call in order to pull our activity in to 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 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 12.5 cents per common share, and lastly, we'll continue to maintain our very strong financial liquidity as Roland 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 provide the financial guidance for 2023. Second quarter production guidance of 1.375 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 1.425 to 1.55 BCFB 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, our Dan mentioned, 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 to $310 million and the full year DNC CapEx remains unchanged at that $950 to $1.15 billion range. In terms of our infrastructure and other spending, we continue to budget $15 to $30 million of spending during the second quarter and $75 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 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 22 to 26 cents in the second quarter and the full year, while our GTC costs are expected to be between 32 and 36 cents per unit both in 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. GD&A rate remains unchanged between the $0.95 to $1.05 range. Our cash G&A is still expected to total $7 to $9 million in the quarter and $32 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 to $36 million in the second quarter and $150 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 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. Again, ladies and gentlemen, if you'd like to ask a question, please press star 11 on your telephone. Again, to ask a question, please press star 11. One moment for our first question. Our first question comes from the line of Derek Whitfield of Spiegel. 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, 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's a service cost feedback loop. What does a five to 10 well completion deferral due to your second half production and free cashflow profile? And is that a reasonable toggle if we see gas prices down in the buck buck 50 range?

Yeah, Derek, that's a good question. I mean, um, Yeah, I think that's something we certainly can look at as delaying completions, especially if we see continued weakness in gas prices stretching beyond the second quarter. Obviously, I think our production, which is still forecasted to grow some year over year, especially compared to last year, as you saw in the first quarter, it would just flatten out. 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 this year, you'd have to put that in place pretty early. Otherwise, you're really going to 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? And separately, how do you think the banks would likely view that scenario?

Well, the company has such strong liquidity now, and a great balance sheet kind of created by last year's debt paydowns. So I still think 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's even beyond the commitment we have from them. So I don't see any significant real deterioration in the balance sheet, even if we don't change any of our plans. So it's really, as you look ahead to next year, do you have an environment that is weak next year, or is it gonna kind of get back into the range what the futures prices are saying? Next year you've got gas closer to 350, So it's really a short-term phenomena, you know, and so we recognize that. And, you know, 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. But we do, you know, start to see, be able to mitigate the cost side and, you know, get back into it. know potentially if prices stay longer for a longer period we would expect the cost structure to come back down um 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 even we're still very profitable even with these low gas prices our break-even cost you know is you know almost 50 cents you know for 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. We've obviously had lots of experience doing that in the past.

I think my initial comment would be we run the shift for the second half of 23, all of 24. 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 in into 2024, but we look at that. We look at that weekly. That's like we did in December of 22. We put 25% callers in the second half of 2023. We added those. So I think you as a stakeholder need to know that we do take a look 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 have dropped. So you are at that inflection point where there's a little bit more pain. But what overrides all that is the fact that our 470,000 net Tainesville 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. You know, 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're 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. 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.

Oh, thank you. Great question.

Thank you. One moment, please.

Our next question comes from the line of Jake 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 Hainesville. 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 markets?

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. And we've moved rigs on and off based upon the performance. We said at the very onset that it was a very beginning. So take a look at it, you know, quarter by quarter by quarter. And, 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. But 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 cells, only as of last month. then we're completing a well right now we're waiting to complete uh fifth well and we're drilling two more so um you know we have great hopes for it but like all of these plays uh you've got to be cautious and i think that's where we tell you that we took the majority of our dollars last year we paid down our debt did our balance sheet pristine And then we looked at our long-term debt that's not due until 29 and 2030, and that's at five and seven-eighths and six and three-quarters debt. Then we looked at the amount of money that we had, and you notice all the footprint that we own in the Western Hainesville. I mean, it was paid for out of cash flow. And the wells that we're drilling, we think that they should be drilled. And 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 leaseable at a very low cost, which I think that's the right price for the leases right now. But we want to make sure that you know 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.

Yeah. 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 certainty in markets and then certainly a price. So, yeah, I think that we expect to be able to do some big things in that area this year, and I think, you know, Western Hainesville hopefully plays a role in that, and we already are a big supplier. We have done some 10-year contracts, and I think that as we can free up more gas that we're currently producing from other commitments, you know, we continue to want to tie ourselves to the to the LNG shippers that are kind of driving, you know, the gas demand?

Well, you know, we look at natural gas as a precious fossil fuel. If you've got $100 billion that you're spending for LNG exporters, you need that precious gas. And if you can get it, you know, all the narratives will tell you that they'd really like to get it from the Hainesville. 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 Hainesville, Bossier, that's where you would rather get it. So, you know, we do treat it as the precious commodity and we try to de-risk this Western Hainesville 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 Donis of Truist. Your line is open.

Hey, morning, guys. You added the well in the western Hainesville, and, you know, it results in the top quartile of your results, but it's still a little bit below that Casey Blackwell. Was there anything geologically different between the two wells, or is the Casey Blackwell just too high of a watermark to use as a comparison?

Yeah, this is Dan. So we, you're right, we did, we tested, we IP'd the Casey Blackwell at 42 million a day. We, the lateral length, the Circle M and the Casey Black had equivalent lateral lengths of just under 8,000 foot. You know, we're really longer on this Campbellwell. But we, the Campbellwell looks really good. We're just trying to be real conservative on managing the drawdown. We certainly could have IP'd this Campbellwell a lot higher. We just chose not to. We IP'd it on a smaller choke. It's got really low drawdown, and so we just, you know, we basically want to 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 frack here recently, and just getting it back up to pace. And then, you know, the Casey Blackwells is flowing between 25 and 30 million a day, and then we're going to flow this Campbell at 36 and just manage the drawdown.

Okay, great. And then maybe I missed it. How many remaining inventory do you have in the Western Hainesville? Have you guys outlined that yet? Or what do you think in 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 Hainesville wells by year end and probably have eight or nine of those connected to cells. So we haven't given any inventory yet. And all that's a little premature right now.

Okay, that sounds good. And then just shifting gears, I want to follow up on the LNG comments. You said you're 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 deduct to the international pricing? And 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.

Yeah, we're still evaluating that. I think if you look at being a major supplier to at least the LNG shippers we're talking to, 80 plus percent of their business is tied to NYMEX. And so they're going to have to have their supply tied to NYMEX. And if you want to sell to them, if we want to buy processing capacity, and sell in international markets, that's an option too. So all of those are being explored and partnerships with one particular large one is kind of being explored where 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 NIMEX gas contract with low transport to the Gulf. And then if we want to explore participating in other markets, other indexes, you know, that's certainly a possibility too.

You know, and you have a better chance of doing that if you can prove that you have the quantity over the decades that 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. We're going to try to de-risk, you know, some inventory for the future. And 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. So it's a little different norm, what we're doing here.

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

Yeah, and I'll reiterate, the wells are obviously capable of flowing at higher rates. They've 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. So, 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 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 have done 10 years. And so 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, then 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. I think that will be the trend of the future. We'll be continuing to want to get a lot more of our gas sold direct to the end users, whether LNG or whether power generators or 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, capture the highest price possible by being able to be direct connected to them.

You know, and I would make a 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. 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 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, you know, 15, 18 months, two years. And I think they've been pretty good. But we do want everybody to know that, you know, we do read all the analyst reports and we're with you. And 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. So we want to 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 CompSoc team there.

Hello, Charles.

Jay, I want to ask a question about these upcoming Western Hainesville wells. My understanding is one of these upcoming two wells is going to test – The deeper part of the section, actually, the Hainesville 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 this section. What, if anything, should we be looking for that might be different from this Hainesville test? And are there any things that you in particular are looking 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. 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 Hainesville. We'll be starting to frack that well late next, late this month, I should say, late May and turning it to sales probably early July. But that, you know, the reason we drilled the first wells as mosers 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. But we've been pretty pleased with the progress we've made in a short period of time, drilling just a few wells. So we just basically look at where the sticks are, where we're going to be drilling. We look at the TBDs. We look at what we think the temperatures are going to be. And then we just decide which one of the targets we need to pursue. 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. You know, we only want to drill bozers there. But, you know, for the rest of the play, we, you know, kind of the Hainesville is our primary target. The Hainesville is the better rock based on all the work that's been done in the play. And that's, you know, we do expect superior results from our Hainesville completion.

The other thing, you know, Charles, if you look at a competitive advantage, remember in 22 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. You don't think about that when we talk about the cost structure, but, you know, you look at the Western Hainesville and where we're producing that. Even if we produced the five wells and called it quits, I mean, it would still be a very good play for us as far as dollars in, dollars out, and reserves added.

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

Thanks, Charles. Appreciate it.

Thank you. One moment, please. Our next question comes from the line of Philip 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 and 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 250 flat. Does that sound about right to you guys?

Well, we think it's a little bit lower than that for Comstock. I mean, you know, I think that we're, you know, closer to 210 to 215. It really depends on, you know, what area are we Drilling, what's the transportation cost? Because when you're talking about, you know, lower, if you're talking about getting closer to break even, you know, if you have a 15 cent transportation cost or a 35 cent, it really makes a difference. So I think, you know, what, you know, last year with the high gas prices and the huge margins, you know, a 10 cent or difference in transportation costs, you know, really was a rounding error in returns. But now it kind of 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. And you'll see, you know, even our gathering rates crap up only 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 with lower transportation. So, you know, our very best stuff, we can probably get that break-even level down to it's much closer to where the current monthly price is now. But if we stray, you know, way out, you know, to other parts of our large footprint in the Hainesville, you know, it can be 30 cents difference. And 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 Hainesville because they're deeper and some are easier. So I think, yeah, 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 kind of overall improve, you know, get to your best wells 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, 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 going to be drilling in the second half of the year are not going to even participate in this year's prices, you know, and 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. But 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've reduced the rig count and pulled in the activity and really just kind of put the other words 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. You know, and frankly, the Western Hainesville, you say, how does those come into play? But those are single wells, so they're, you know, they're not the pad drilling, which is a big, big cost saver. So we still like to drill two to three wells on a pad because of the zipper frack capability and all that. But the Hainesville well, yeah, based on the, they actually can compete, believe it or not, with the top, our top low cost wells. especially when we get them on our gathering system and we save that transportation cost that we right now, you know, the first wells are dedicated to a more higher cost system. But 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 Chaudhry of Goldman Sachs. Your line is open.

Hi, good morning, and thank you for taking my questions. Yes, sir. My first question was on activity levels in the Hainesville. Would love any color you can provide on any incremental Hainesville 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 Inveris, is in the upper 50s to 60. And 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 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. So when you think about a starting point of 70 rigs, I think it's – 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, Cruz, 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 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 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.

That's really helpful. Thank you. I guess 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 you look at the strip today and assuming that holds, especially in the back half of 24 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?

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. So I don't think that we're at all trying to time growing activity into that or trying to guess, you know. I think what we are – our priority is, you know, to – which we think is the most important part is to kind of continue to delineate and prove up and get, you know, real grasp over the tight curve and the productivity of our new play. And 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. And so that's what we see is the big priority. And then what we call the traditional Hainesville, which is our other areas. Those are the areas that we're toggling because 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. But that's more just to generate the cash flow to keep the company in great shape. So there's really two different priorities there that we're balancing in this market.

Well, as we said earlier, 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 Comstock 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. I 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, given you quoted 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 data, 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. And so 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 and 24, but also just the cost savings that it provides and, you It's an ideal location for it in the Hainesville because we have such an abundant gas supply that it's drilling around. We've been very happy with the first one. 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 some well-cost savings there. But, you know, I think they're mostly, like, the earliest you start seeing those is second half versus, you know, second quarter.

Okay, understood. Thanks for the clarity. And just one quick follow-up on the macro. Yes, we're currently selling 21%. Into LNG, just kind of want to 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 want to be, I think we, you know, especially, you know, and a lot of it will depend on our new area, but, you know, that's probably some of our best, highest realizations right now is on our 10-year contract now that we're doing. So as we seek to maximize our gas price, you know, That market and potentially other markets that are industrial users, power generators, you know, to the extent that they're competitive or beat those rates, you know, we'll also want to add that to our portfolio. But, yeah, we would like to see working our way toward over, you know, 50% plus. And, you know, that probably is more 25, 26 when all the, you know, a lot of new capacity comes on. And 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 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 cost early on, you know, at this point in time. Just trying to handle on sort of drill times and maybe what you think the early EURs are per foot on the first couple wells.

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'll want twice the EUR. But I think the cost is early cost, so I think the future cost, the development cost, will be significantly better. If we drill single wells in our traditional Hainesville, they will be our most costly wells because that's why I've had drilling as such a big important part of everybody's development plan now because the cost savings is so significant. So 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. But generally, even out of the gate, we're not starting out in a bad position.

I think we were on the cutting edge of technology when we started doing it, and now we've been pretty successful with the wells that we've turned ourselves in completing and drilling. So as this kind of unfolds through 2023-24, then we can be, you know, give you a little more clarity on it.

Yep. 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. You've got the second quarter guidance out there. So kind of flat on production in second quarter. So do we see, like, sequential growth in both 3Q and 4Q, you know, assuming your plans don't change? Yeah. Conversely, do we see CapEx kind of dropping in both 3Q and 4Q, you know, from 2Q levels? Just trying to kind of 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 going to be the highest CapEx rate. The second quarter, you have our guidance in 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, 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, and a lot of that is related to, if you think about the impact of the timing of completions in the western Hainesville 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. So your thoughts were correct.

Okay. But then just to clarify, though, on the CAPEX third quarter and fourth quarter, pretty similar, but you think down versus kind of where second quarter shakes out a little bit just because of the activity reduction. Yes. Yes. Okay. Yep. All right. Now 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 minimis as a percentage of actual taxes in 2023. If we look at next year, like you said, 350 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 350 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 – it will go back down as gas prices move up. This year clearly is impacted by the such low gas price. But, you know, if you want to just conservatively go back to that 75% to 80% deferred next year, and we're just going to have to revisit that as we get closer to the year in terms of gas pricing – 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, and we want to thank each one of you for, you know, giving us an hour and ten minutes of your time. We're going to be good stewards of the 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.