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Presentation

Operator: Thank you for standing by, and welcome to Comstock Resources First Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. 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.

Jay Allison: Perfect, thank you, and good morning everyone. I 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 kind of 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, so yesterday and today 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 the 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 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 5-rigs in the next couple of weeks. The first quarter still has some inflation baked into the well cost, but we see that abetting 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 were $255 million, or $0.92 per diluted share. Adjusted EBITDAX for the quarter was $293 million.

Our adjusted net income for the first quarter was $92 million, or $0.33 per share. The financial results in the quarter reflect the weaker natural gas prices following the warm winter, the weather that we had. In the first quarter, we drilled 18 or 13.7 net operated Haynesville and Bossier horizontal wells, which had an average lateral length of 12,075 feet. Since our last update, we’ve connected 15 or 9.8 net operated wells to shales 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 and our Western Haynesville play, the Campbell well, which had an initial production rate at 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?

Roland Burns: 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, 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. So 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 $0.31 differential to the reference price. That differential was higher than our – normal for us due to the continued weaker Houston Ship Channel and Katy hub prices that persisted during a good bit of the first quarter due to the Freeport LNG facility shutdown.

With the Freeport startup late in the quarter, we’ve seen these price differentials along the Texas Gulf Coast tightened 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 startup. The startup phase that we’re having at our Western Haynesville area we’re a fixed cost are being spread over a lower production volumes. We expect them to come down as our production grows in that area. Our gathering cost increased by $0.04 during the quarter, and our lifting cost increased by $0.03, our production taxes remain 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 another development activity, which includes installing production tubing, offset frac protection, and other workovers totaled $14 billion 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 details.

Dan Harrison: Okay, thank you, Roland. Slide 9 is the breakdown of our 2023 quarter end drilling inventory. A drilling inventory is split between Haynesville 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 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 we have 1,310 gross locations in 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 modifier our drilling inventory and extend our future laterals specifically targeting the 10,000 foot to 15,000 foot range. And our extra-long lateral bucket, we currently have 459 gross operated locations and 334 net operated locations. And to recap, to recap our gross operated inventory, we have 313 short laterals, 298 medium laterals, 740 long laterals, and the 459 extra-long laterals. The gross operated inventory is split 53% in the Haynesville and 47% in the Bossier. By extending our laterals, the average lateral length in our inventory now stands at 8,928 feet. This is up slightly from our 8,870 feet we had at the end of 2022.

In addition to the economic uplift, the longer laterals reduce our surface footprint and help us to reduce our greenhouse gas and methane intensity levels. Based on our plan 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 15,580 foot 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, a 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 ranged from 4,514 feet up to 15,584 feet. Included in this latest well activity our 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 20% to 30% versus the dry gas well. The average IP rate for our working interest ownership in the 15 wells for the quarters 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 which was completed in the Bossier with a 12,763 foot long lateral was turned to sales in March. We tested the well with an IP rate of 36 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 its 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 turn 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 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 fraced with our Titan natural gas fleet as opposed to more than half of our fourth quarter wells were frac used in the Titan natural gas fleet.

As mentioned on the previous calls, we’ve been able to capture significant savings through the use of the Titan natural gas fuel fleet compared to the conventional diesel fleet. With that being said, we are expecting the delivery of our second Titan fleet within the next couple of months. To sum up where we stand on activity levels, we are currently running eight rigs. One of these will be released in a couple of weeks to bring us down to seven rigs. On Slide of 13, we highlight our continued improvement related to greenhouse gas 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. Well, we reported a methane emission intensity rate of 0.045%, which is a 16% improvement versus 2021, and we achieved those emissions improvements despite our turn into sales lateral feet increasing by 10% in 2022, adjusting for lateral length completed for our turn to sales wells.

Our greenhouse gas emissions per lateral foot turn to sales improve 10% while our methane emissions per lateral foot turned to sales improved by 22%. We deployed optical gas imaging and aircraft leak monitoring technology at almost 100% of our production sites, which earned us the ability to certify our gas is responsibly sourced. Our natural gas-powered frac fleet eliminated approximately five million gallons of diesel by utilizing natural gas offsetting approximately 10,200 metric tons of CO2 equivalent. As a reminder, our first natural gas-powered frac fleet began operating in April. So that date 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 on approximately 65% of our newly constructed production facilities mitigating approximately 4,000 metric tons of CO2 equivalent. I’m now going to turn the call back over to Jay. You can sum up the 2023 outlook.

Jay Allison: Thank you, Dan and I believe that we’re the first Haynesville/Bossier company to have a 100% of our natural gas certified by MiQ standards, which tells you that, all the gas we produced is responsibly sourced gas in the future that may be 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 calls 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 are remain focused on maintaining the strong balance sheet that that we had created last year, or 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 $12.05 for common share.

And 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. Ron?

Ron Mills: 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 Bcfe to 1.55 Bcfe per day. During the second quarter, we do plan to turn to sales between 11 and 14 net wells. As Jay mentioned, our 2023 wells, our Dan mentioned our 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 at that $950 billion to $1.15 billion range.

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 to our, 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 at while our GTC costs are expected to be between $0.32 and $0.36 per unit both in the second quarter and the full year. Production and ad valorem taxes are now expected to average $0.12 to $0.16 in the second quarter and $0.14 to $0.18 in the, for the full year.

Primarily related to the impact of lower gas prices on production taxes. DD&A rate remains unchanged between the $0.95 to a $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 a 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 call follow the company.

Sally?

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

Derrick Whitfield: Thanks and good morning, all.

Jay Allison: Good morning.

Roland Burns: Good morning.

Derrick Whitfield: 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?

Jay Allison: Yes, Derrick, that’s a good question. I mean, yes, I think that that – that’s something we certainly can look at as kind of as delaying completions especially if we see continued weakness in gas price is kind of stretching beyond the second quarter. And 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. So 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.

Derrick Whitfield: 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?

Roland Burns: Well, other companies, it has 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, 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 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 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 cost, 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. And 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.

Jay Allison: And I think our – my initial comment would be we run the ship for the – the second half of 2023, all of 2024. And as Roland said, the gas prices, they 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 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.

Derrick Whitfield: 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.

Jay Allison: Thank you, great question.

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

Jacob Roberts: Good morning guys.

Jay Allison: Good morning.

Jacob Roberts: 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?

Jay Allison: 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 – 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 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. And 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. And 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. And then 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. And the wells that we’re drilling, we think that 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 – that is where we’re looking, but we’re looking there cautiously and we’re keeping you updated quarterly.

Jacob Roberts: 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.

Roland Burns: Yes. Obviously that – 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 that we expect to be able to do some big things in that area this year. And I think the Western Haynesville 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 could free up more gas that we’re currently producing from other commitments, we continue to want to tire ourselves to the LNG shippers that are kind of driving the gas demand.

Jay Allison: Well, we look – natural gas is a – it’s a precious fossil fuel. If you’ve got a $100 billion that you’re spending for LNG exporters, you need that precious gas. And if you can get it, all the narratives will tell you that they’d 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, 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 and what we’re doing with the company.

Jacob Roberts: Thank you very much. I appreciate the time, guys.

Operator: Thank you. One moment, please. Our next question comes from the line of Bertrand Donnes of Truist. Your line is open.

Bertrand Donnes: Hi. Good morning guys. You added a – the well in the Western Haynesville and it results 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 it the KZ Black well just too high of a watermark to use as a comparison?

Dan Harrison: Hi. Yes, this is Dan. So we – you’re right, we did, we tested, we IPed the KZ Black well at 42 million today. We – the lateral length, the Circle M and the KZ Black had equivalent lateral lengths of just under 8,000 foot. We’re really longer on this Campbell well, but we – 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. And so we just – we basically want to produce the well at this rate. We got – the Circle M is still flowing at 30 million. We had it shut in for about 35 days for an offset frac here recently. And just getting it back up to pace. And then we’re – the KZ Black wells is flowing between 25 million and 30 million a day and then we’re going to flow this Campbell at 36 and just manage the drawdown.

Bertrand Donnes: Okay, great. And then I don’t – maybe I missed it. Do you – how many 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?

Jay Allison: 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.

Bertrand Donnes: 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? 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.

Jay Allison: 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, 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, they could – 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.

Dan Harrison: 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. And 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.

Jay Allison: 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.

Dan Harrison: Yes. And I’ll just reiterate, the wells are obviously capable of flowing at higher rates. They got great pressures. The drawdown looks superbs, 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.

Jay Allison: 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, 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.

Bertrand Donnes: 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.

Roland Burns: No, we’re not, I mean, we definitely done, have done 10 years. And so I think 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. And I think the extent that that we like the contract and want to be a long-term partner, that’s something we’re comfortable with. So, I think, we’ll, I think that’ll be the trend of the future, would be continuing to, 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 him.

Dan Harrison: 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.

And 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. 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 are – we’ll toggle things around to make sure that one, we always protect the balance sheet.

Operator: Thank you. One moment, please. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is open.

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

Jay Allison: Hello, Charles.

Charles Meade: Jay, I want to ask a question about these upcoming Western Haynesville wells. My understanding is one of these up two 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. And 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? And are there any things that you, in particular are looking for, would alert us to about whether it’s higher pressure, more difficult drilling, just any your thoughts about what could be different there?

Dan Harrison: 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. And 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 into sales probably early July. But that, 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, 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, we just basically 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 – we just 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. And that’s you know, we do expect superior results from our Haynesville completion.

Jay Allison: 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 call, 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 and dollars out and reserve that it.

Charles Meade: That is all helpful detail. That’s it for me. Thank you, Jay.

Jay Allison: Thank Charles, appreciate you.

Operator: Thank you. One moment please. Our next question comes from the line of Phillips Johnston of Capital One Security. Your line is open.

Phillips Johnston: 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 break even 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 250 flat. Does that sound about right to you guys?

Jay Allison: Well we think it’s, low bit lower than that for Comstock. I mean I think that we’re closer to two to 10 to 215, it really depends on, what – what area are we 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. So, I think, 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. But now it kind of comes back into focus. And I think that’s one thing. Yes, we shift back to the areas that have the lower cost structure and you’ll see, even our gathering rates crap up on it 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, it’s much closer to where the current monthly price is now. But if we stray, way out to other parts of the, of our large footprint in the Haynesville, it can be $0.30 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 Haynesville, because they’re deeper. And some are easier. So, I think yes, now you can lean in to, 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 get to your best wells that can hit that are making money in this environment.

Phillips Johnston: 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.

Jay Allison: Right. I think you obviously, if you look at really the reality is a lot of the wells or we’re going to be drilling in the second half of the year are not going to even participate in this year’s prices. And to the extent that 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. And really just kind of put the other words back on hold until, gas prices are strong again and then we can drill some of those areas like we did last year just to keep, all parts of the inventory kind of moving.

And frankly the Western Haynesville, we say, how does those come into play? But those are single wells, so they’re, 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 Frac capability and all that. But the Haynesville well, yes 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 are, the first wells are dedicated to a more higher cost system. But the – 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.

Phillips Johnston: Okay. Great. Thanks Roland.

Roland Burns: Thank you.

Operator: Thank you. One moment please. Our next question comes from the line of Umang Choudhary of Goldman Sachs. Your line is open.

Umang Choudhary: Hi, good morning and thank you for taking my questions.

Roland Burns: Yes, sir.

Umang Choudhary: 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?

Roland Burns: Ron, what’s the rig count right now?

Ron Mills: The rig count according to inves 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’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 starting point of 70 rigs, I think it’s some, 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 are re 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, the completion count or crew, the frac fleet count go down related to private activity as well, especially since those are the type companies that, that do drill directly out of cash flow.

Umang Choudhary: 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?

Roland Burns: 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 that we’re at all trying to time growing activity into that, or trying to guess I think what we, our priority is, to which we think is the most important part is to kind of continue to delineate and prove up and get, 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 as the big priority. And then – the – what we call the traditional Haynesville, which is our other areas that, those are areas that we’re toggling because, so that’s just that we don’t have to develop that inventory at any particular time.

It’s a deep inventory. We can go to different parts like we said to kind of improve the economics, but that’s more just to generate the cash flow to, keep the company in great shape. So there’s really two different, kind of two different priorities there that we’re balancing in this market.

Jay Allison: 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.

Umang Choudhary: That’s helpful. Thank you so much for taking my questions.

Operator: Thank you. One moment please. Our next question comes from the line of Paul Diamond of Citi. Your line is open.

Paul Diamond: 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 tighten 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.

Roland Burns: Yes, second half. I think that’s, as we get the, the tighten 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, the largest part of the, 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, lower emissions this year and next year in 2024, but also just the cost savings that it provides. And it’s an ideal location for it in the Haynesville because we have such an abundant gas supply that is drilling around. So 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’re, we’ll swap out some rigs with lower drilling rates too, that were so there’s, 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 second half versus second quarter.

Paul Diamond: 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.

Roland Burns: 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 contract 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 25, 26 when all the, a lot of new capacity comes on. And then a lot of our other commitments maybe roll off.

Paul Diamond: Understood. Thanks for your time.

Jay Allison: Thank you.

Operator: Thank you. One moment please. Our next question comes from the line of Leo Mariani of Roth. Your line is open.

Leo Mariani: 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 wells.

Dan Harrison: Yes. That’s a good way to frame it because we said basically that that kind of a, that’s what that in order to make them competitive with the other wells, yes, you’ll want twice the EUR and but I think, yes the cost is early cost, so I think the, the future cost of development costs will be significantly better. I mean, if we drill single wells in our traditional Haynesville, they will be our most costly wells because you know that, that’s why I’ve pad drilling is 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, the drilling and completion will be the other part of getting the cost. So but generally, even out of the gate, we’re not starting out in a bad position

Jay Allison: That’s actually a unit. We we’re 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 to sales from completing and drilling. So as this kind of unfolds through 2023, 2024, then we can be, give you a little more clarity on it.

Leo Mariani: 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?

Roland Burns: 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. Great. 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. 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, fourth quarters to get to that, 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 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 flatter production profile. So your thoughts were correct.

Leo Mariani: 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?

Roland Burns: Yes.

Leo Mariani: 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, of actual taxes in 2023. If we look at next year, like you said, 350 is roughly the future’s 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?

Roland Burns: Well, we’re still evaluating that. I think if you end up with a 350 gas price, then there’s a chance that, that the cash or the, 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 if you want to just conservatively go back to the, 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.

Leo Mariani: Okay. Thank you.

Jay Allison: Thank you, Leo.

Operator: Thank you. This does could conclude the conference for today. I’d like to turn the call back over to Jay Allison for any closing remarks.

Jay Allison: 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, that we have and the future looks brought here. So thank you for your time.

Operator: Thank you. Ladies and gentlemen, this does conclude today’s conference. Thank you all for participating. You may now disconnect. Have a great day.