Comstock (CRK) Q1 2026 Earnings Call Transcript

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Date

Wednesday, May 6, 2026 at 11 a.m. ET

Call participants

• Chairman and Chief Executive Officer — Miles Jay Allison
• President and Chief Financial Officer — Roland O. Burns
• Chief Operating Officer — Daniel S. Harrison

Takeaways

• Natural Gas and Oil Sales -- $339 million, reflecting lower production partially due to significant winter weather impact.
• Operating Cash Flow -- $192 million, equaling $0.66 per share.
• Adjusted EBITDAX -- $251 million for the quarter.
• Adjusted Net Income -- $44 million, or $0.15 per diluted share, after excluding an $83 million pre-tax unrealized gain from hedge mark-to-market and other nonrecurring items.
• Production Volume -- Averaged 1.1 billion cubic feet equivalent per day, lowered by winter storm-induced disruptions.
• Well Turn‑In and Performance -- Six new Western Haynesville wells averaged 29 million cubic feet per day initial production rate; 10 legacy Haynesville wells averaged 31 million cubic feet per day.
• Weighted Average Realized Gas Price -- $4.27, reflecting a $0.69 basis differential to the NYMEX settlement price; 72% of volume was hedged, reducing realized price to $3.45.
• Operating Cost per Mcfe -- $0.93, up $0.16 from the prior quarter due mostly to fixed field costs spread over lower production.
• EBITDAX Margin -- 73% for the quarter.
• Drilling and Development Capital Expenditure -- $343 million, funding 17 total new wells (15.3 net) and 13 wells turned to sales (11.7 net).
• Total Liquidity -- Almost $1.3 billion, comprised of available borrowing base and recently added midstream credit facility.
• Leverage Ratio -- Last-twelve-months ratio at 2.9 times.
• Power Generation Hub Agreement -- Announced selection of Western Haynesville site for a 5.2 gigawatt natural gas-fired facility operated by NextEra Energy Resources with Comstock Resources (NYSE:CRK) to supply gas volumes potentially reaching nearly 1 billion cubic feet per day by 2031.
• Legacy Haynesville Inventory -- 955 gross (740 net) operated locations; 819 gross (98 net) nonoperated locations; average working interest of 78% operated and 12% nonoperated.
• Western Haynesville Inventory -- 3,331 gross (2,546 net) locations with most locations in Bossier shale; approximately 76% average working interest.
• Drilling Performance -- Legacy Haynesville averaged 26 days to total depth and 921 feet per day, up 3%; Western Haynesville averaged 57 days and 478 feet per day, down 4% from the previous quarter.
• Drilling and Completion Cost Trends -- Legacy Haynesville drilling cost rose 3% to $700 per foot; completion cost fell 9% to $652 per foot; Western Haynesville drilling cost rose 3% to $1,534 per foot, with completion cost flat at $1,537 per foot.
• Performance Initiatives -- Rotary steerable drilling, higher-pressure rig upgrades, and big-hole lateral designs being adopted for further cost reductions and performance predictability.
• Horseshoe Well Program -- 114 Horseshoe locations added to inventory with average 35% drilling cost savings on long lateral wells; 16 Horseshoe wells planned for the year.
• Midstream Strategy -- Pinnacle Gas Services now independently financed through a $150 million credit facility with $47 million outstanding and in process of securing an equity partner.
• Guidance for Second Quarter -- "Production should be up 13% to 15% for the second quarter," according to Allison.

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Risks

• Allison acknowledged, "we did miss production in the quarter by about 13%, and our CapEx was higher," framing both as consequences of prior rig-laydowns and balance-sheet preservation.
• The company explicitly addressed "cash burn and the slow pace of resource delineation testing investor patience," as acknowledged in both management commentary and investor questions.
• Western Haynesville drilling and completion performance was described as highly variable, dependent on "vertical depth, temperatures, and lateral lengths," with drilling efficiency in the area down 4% sequentially and well costs remaining high relative to the legacy play.
• Harrison cited certain Western Haynesville wells with significantly lower initial production rates due to high water production during flowback and complex geology, noting, "three out of the 36 with really high water volumes that affected IP rates."

Summary

Comstock Resources (NYSE:CRK) reported reduced quarterly production volume and increased operating costs, directly affected by winter storm disruptions and the company’s ongoing focus on balance-sheet stability through conservative M&A and rig decisions. Management confirmed that 13% production shortfall and higher capital expenditures resulted from strategic reductions in drilling activity in 2025 and outlined expectations for a 13%-15% sequential production rebound. The company emphasized a long-term growth strategy centered on expanding and optimizing the Western Haynesville acreage, reserving capital for high-return well designs such as Horseshoe wells, and capturing significant commercial potential via the announced 5.2-gigawatt NextEra-operated power generation hub, which may demand up to 1 billion cubic feet per day of supplied gas. The addition of a dedicated midstream credit facility and the ongoing process to secure an equity partner for Pinnacle Gas Services reflects continued efforts to vertically integrate and create long-term infrastructure value. Management acknowledged drilling variability and cost pressures in Western Haynesville as an explicit operational challenge but highlighted technical initiatives—such as rotary steerable systems and advanced lateral designs—as underpinnings for future efficiency gains.

• Harrison separately confirmed, "Western Haynesville will yield significantly more resource potential per section than our legacy Haynesville," suggesting focused future capital allocation.
• In response to drilling underperformance, management detailed that steep gradient and high water flowback were identified as key contributors to select Western Haynesville wells’ lower initial output, and that ongoing pad-specific testing will inform future geotechnical decisions.
• The company specified that outspending, in the range of "$400 million to $450 million," is anticipated and linked primarily to natural gas pricing.
• Management clarified that no major acquisitions or equity issuances are planned, and acknowledged that acreage accumulation will slow, with ongoing additions expected at a rate of "1,000 to 2,000 acres every month."

Industry glossary

• Horseshoe Well: A horizontal well design that combines two separate shorter laterals into a single long lateral, efficiently tapping reserves and reducing per-foot drilling costs.
• Basis Differential: The difference between a local or regional commodity price and a standard benchmark price, such as NYMEX for natural gas.
• EBITDAX: Earnings before interest, taxes, depreciation, amortization, and exploration expense; a profitability metric tailored for the exploration and production sector.
• Mcfe: Thousand cubic feet equivalent; measurement standard converting all hydrocarbons to a natural gas equivalent for reserve and cost comparisons.
• TD (Total Depth): The final depth reached in drilling a wellbore.

Full Conference Call Transcript

On Slide 3, we summarize the highlights for the first quarter. Lower production, partially driven by production impact from significant winter weather in the first quarter, drove the lower financial results in the quarter compared to 2025. Our natural gas and oil sales were $339 million. We generated $192 million of operating cash flow, or $0.66 per share. Adjusted EBITDAX for the quarter was $251 million, and we reported adjusted net income of $44 million, or $0.15 per share. During the quarter, we had very strong drilling results which will drive production back up for the remainder of the year. Almost all the wells returned to sales in the first quarter were very late in the quarter. Since our last update, we put six new Western Haynesville wells online with an average per-well initial production rate of 29 million cubic feet per day. In our legacy Haynesville, we turned 10 wells to sales with an average lateral length of 12,312 feet and a per-well initial production rate of 31 million cubic feet per day. Now, the power generation hub: On March 19, 2026, the United States Department of Commerce selected our Western Haynesville site to host a new 5.2 gigawatt natural gas-fired power generation hub to be located in Anderson County, Texas, as shown on Slide 4. We are very excited about this development and what it means to have a large commercial customer in our backyard. The project is part of Japan's $550 billion investment commitment in the United States as part of the U.S.-Japanese trade deal. The U.S. and Japan would own the projects while NextEra Energy Resources will develop, build, and operate it.

NextEra is actively developing the project, advancing site development, procurement, permitting, and commercial structuring as they work toward definitive agreements with the U.S. and Japan. This project takes advantage of our abundant natural gas supply and a strong transmission infrastructure in the area. The Anderson County facility will have up to 5.2 gigawatts of natural gas-fired generation capable of serving up to 5 gigawatts of large-load demand. Comstock Resources, Inc. will provide the natural gas supply for the facility, which could reach almost 1 billion cubic feet per day by 2031. We will now provide some more details on the financial results we reported yesterday. Roland?

Roland O. Burns: Alright. Thanks, Jay. On Slide 5, we cover the first quarter financial results. Our production in the first quarter averaged 1.1 Bcfe per day. Oil and gas sales after hedging in the quarter were $339 million, reflecting the lower production level we had in the quarter. EBITDAX came in at $251 million, and we generated $192 million of cash flow during the first quarter. We reported a $107 million profit for the quarter, or $0.38 per share, but included in that number was a pretax $83 million mark-to-market unrealized gain related to our hedge book.

So excluding the mark-to-market gain, exploration expense (which is related to seismic that we are shooting in our Western Haynesville play), and other nonrecurring items and the related income tax effect of those items, we reported adjusted net income of $44 million, or $0.15 per diluted share for the quarter. On Slide 6, we break down our natural gas price realizations in the quarter. The quarterly weighted average NYMEX settlement price averaged $4.96 in the first quarter, and the weighted average Henry Hub spot price was $4.90. Twenty-six percent of our gas was sold in the spot market, so the appropriate NYMEX reference price would have been $4.94 for our production.

Our realized gas price during the quarter averaged $4.27, reflecting a $0.69 basis differential compared to the NYMEX settlement price and a $0.67 differential compared to that reference price. Significant disconnect existed during the quarter between the regional hub prices and NYMEX, which drove the higher differentials in the quarter. We also had to purchase higher-priced gas to make up for shut-in production during the winter storm event. In the quarter, we were also 72% hedged, which reduced our realized price down to $3.45. We did improve the overall price realizations by $0.05, to $3.50, with our third-party gas sales during the quarter. On Slide 7, we detail our operating cost per Mcfe and our EBITDAX per-unit cost.

These were negatively impacted by the lower production level in the quarter, as much of our field costs are fixed. Our operating cost per Mcfe averaged $0.93 in the quarter, up $0.16 from the fourth-quarter rate. Both lifting cost and G&A were up $0.04, attributable to the lower production level. Production ad valorem taxes increased $0.03 due to the higher gas prices in the quarter, and our gathering costs were up $0.05 mainly due to some prior-period adjustments we recognized. Overall, our EBITDAX margin in the quarter was 73%. On Slide 8, we recap spending on our drilling and other development activity in the quarter. We spent a total of $343 million on our drilling program.

We drilled 11, or 9.3 net, horizontal Haynesville wells and 6, or 6 net, Bossier wells for a total of 17 wells in the quarter, or 15.3 net wells. We turned 13 wells to sales, or 11.7 net wells, which had an overall average per-well IP rate of 31 million cubic feet per day. Slide 9 summarizes our capitalization at the end of the first quarter. We ended the quarter with $350 million of borrowings outstanding under our upstream credit facility. Our upstream borrowing base is $2 billion, and our elected commitment under our facility is $1.5 billion. In March, we entered into a new $150 million midstream credit facility for Pinnacle Gas Services.

The midstream credit facility had $47 million outstanding as of March. Our last-twelve-months leverage ratio was 2.9 times. At the end of the first quarter, we had almost $1.3 billion of liquidity. I will now turn it over to Dan to discuss our operations for the quarter.

Daniel S. Harrison: Okay. Thanks, Roland. Over on Slide 10, this is our updated overview of our acreage footprint in the Haynesville and Bossier shales across East Texas and North Louisiana. We now have 874,868 gross acres and 806,980 net acres that are prospective for commercial development of the Haynesville and Bossier shales. On the left is our Western Haynesville footprint, which we have now grown to over 540,000 net acres. On the right is our 266,570 net acres within our legacy Haynesville area. We currently have 36 wells producing on our Western Haynesville acreage, which is relatively undeveloped compared to the legacy Haynesville area.

With the higher pay thicknesses and the very high pressures we encounter in the Western Haynesville versus the legacy core, we expect the Western Haynesville will yield significantly more resource potential per section than our legacy Haynesville. On Slide 11 is our current drilling inventory in our legacy Haynesville area at the end of the first quarter. Our operated inventory in the legacy Haynesville now consists of 955 gross locations and 740 net locations, which equates to an average working interest of 78%. On our nonoperated inventory in the legacy Haynesville, we have 819 gross locations with 98 net locations, which is a 12% average working interest. Our drilling inventory is split into four buckets.

We have our short laterals (less than 5,000 feet), our medium-length laterals (5,000 to 8,500 feet), our long laterals (8,500 to 10,000 feet), and our extra-long laterals (over 10,000 feet). In our gross operated inventory in the legacy Haynesville, we now have 30 short laterals, 141 medium laterals, 337 long laterals, and 447 extra-long laterals. The gross operated inventory is split 52% in the Haynesville and 48% in the Bossier. Legacy Haynesville inventory also includes 114 gross Horseshoe locations with 53% of those being in the Haynesville and 47% in the Bossier.

Over 80% of our gross operated inventory has laterals longer than 8,500 feet, and as of today our average lateral length in legacy Haynesville inventory has climbed to 10,019 feet. This inventory provides us with decades of future drilling locations based on our current activity levels. On Slide 12, we show our estimated drilling inventory in the Western Haynesville. Our Western Haynesville inventory currently consists of 3,331 gross locations and 2,546 net locations, which equates to an average working interest of approximately 76%. The number of our net locations is estimated since much of our Western Haynesville acreage has not yet been unitized.

Our Western Haynesville inventory is more weighted to the Bossier formation, with nearly two-thirds of the inventory in the Bossier shale and one-third of the inventory in the Haynesville shale. We also have our Western Haynesville inventory divided into the same four groups by lateral length. In our Western Haynesville gross operated inventory, we do not have any short laterals today. We have 1,319 medium laterals, 646 long laterals, and 1,366 extra-long laterals. Sixty percent of our Western Haynesville gross operated inventory has laterals greater than 8,500 feet. On Slide 13, this is an update to our new Horseshoe development program.

The Horseshoe well design combines two separate and adjacent shorter laterals into a longer single lateral, which results in a much more efficient use of our capital. On average, we realize 35% savings in our drilling costs when we drill a 10,000-foot Horseshoe well compared to two 5,000-foot sectional lateral wells. Our drilling inventory in our legacy Haynesville area now includes 114 Horseshoe locations. The Camp Tech 29-14-9 No. 2 was turned to sales in the first quarter with a 41 million cubic feet per day IP rate, and we plan to drill a total of 16 Horseshoe wells in 2026.

On Slide 14, there is a chart outlining our average lateral lengths drilled based on when the wells have been drilled to total depth. Average lateral lengths are shown separately for the legacy Haynesville and for the Western Haynesville areas. In the first quarter, we drilled 12 wells to total depth in our legacy Haynesville area, and these wells had an average lateral length of 10,872 feet. The individual laterals ranged from 8,497 feet up to 15,772 feet. Our longest lateral drilled to date on our legacy Haynesville acreage still stands at 17,409 feet.

In the first quarter, we also drilled five wells to total depth in the Western Haynesville, and these wells had an average lateral length of 10,356 feet. The individual lengths ranged from 9,400 feet up to 11,393 feet. Through the first quarter, our longest lateral drilled in the Western Haynesville stood at 12,763 feet. As of last month, we have since exceeded that length in the Western Haynesville with a new record lateral length of approximately 14,800 feet. The well, which is the Dolly Jones RP No. 1H, reached total depth in mid-April, and we have it scheduled for completion later this summer.

To date, we have drilled 47 wells to total depth in the Western Haynesville, including 21 wells with laterals over 10,000 feet and seven wells with laterals over 12,000 feet. On Slide 15, this outlines the 10 wells that we turned to sales on our legacy Haynesville acreage since our last call. The average lateral length on these was 12,312 feet, and the individual laterals ranged from 9,465 feet up to 15,143 feet. The individual IP rates on these wells ranged from 15 million cubic feet per day up to 41 million cubic feet per day. The average IP was 31 million cubic feet per day. Five of our nine rigs are drilling on the legacy Haynesville acreage.

Slide 16 outlines the six wells that we have turned to sales on our Western Haynesville acreage since the last call. These six wells had an average lateral length of 10,874 feet, with an average initial production rate of 29 million cubic feet per day. We have four of our nine rigs currently drilling on our Western Haynesville acreage. On Slide 17, this highlights the average drilling days and our average footage drilled per day in the legacy Haynesville area for our benchmark long lateral wells greater than 8,500 feet. In the first quarter, we drilled 12 of our benchmark long lateral wells to total depth in the legacy Haynesville area and we averaged 26 days to TD.

In the first quarter, we averaged 921 feet drilled per day in our legacy acreage, which represents a 3% increase versus 2025. Four of the wells drilled in the first quarter were our Horseshoe wells, which do take a few extra days compared to our normal straight laterals. Slide 18 highlights our drilling progress in the Western Haynesville. During the first quarter, we drilled five wells to total depth in the Western Haynesville. This now gives us a total of 44 wells that we have drilled to total depth through the end of the first quarter. We averaged 57 days for the five wells drilled to total depth during the first quarter.

This is an increase of three days compared to the fourth quarter. You can see this is also reflected in the drilling speed of 478 feet per day during the first quarter, which is 4% lower than the fourth quarter. Aside from drilling issues, our quarter-to-quarter drilling performance in the Western Haynesville is mainly dictated by vertical depth, temperatures, and lateral lengths, and this varies considerably across our acreage footprint. Where the wells are being drilled has a big impact on our drilling performance numbers quarter to quarter. Our fastest well drilled to date in the Western Haynesville still stands at 37 days, and it was drilled with a 12,045-foot lateral.

On Slide 19, this is a summary of our D&C cost through the first quarter for our benchmark long lateral wells in our legacy Haynesville acreage position (laterals greater than 8,500 feet). These costs reflect all of our legacy area wells with greater than 8,500 feet. The drilling costs are based on when the wells reach TD, and the completion costs are based on when the wells are turned to sales. During the first quarter, we drilled 12 of our benchmark long lateral wells to total depth. First-quarter drilling cost averaged $700 per foot, a 3% increase compared to the fourth quarter.

The increase in first-quarter drilling cost is the result of a combination of factors, mainly a shorter average lateral length in the first quarter, a higher number of wells drilled, and more wells drilled in our East Texas area, which require an additional casing string to isolate localized over-pressured SWD zones in that area. During the first quarter, we also turned eight of our benchmark long lateral wells to sales on our legacy Haynesville acreage. First-quarter completion cost came in at $652 per foot, a 9% decrease compared to the fourth quarter. This lower completion cost is due to a combination of using less horsepower, having higher frac efficiency, and slightly lower drill-out cost.

We are currently running three full-time frac fleets. After we added our third frac fleet in January, we are adding a fourth frac fleet this month, and we are planning to maintain running four frac fleets through the end of the year. On the drilling side in the legacy Haynesville area, we have continued field testing with our rotary steerable drilling BHAs and are continuing to make good progress. As we accumulate more data and make refinements, we expect this rotary steerable technology to play a larger role in our future drilling program to help drive more cost reductions.

On Slide 20, this is a summary of our D&C cost through the first quarter for all wells drilled in the Western Haynesville. During the first quarter, we drilled five wells to total depth in the Western Haynesville with an average lateral length of 10,356 feet. Our first-quarter drilling cost averaged $1,534 per foot, representing a 3% increase compared to the fourth quarter. During the first quarter, we also turned five wells to sales in the Western Haynesville that had an average lateral length of 11,177 feet. First-quarter completion cost averaged $1,537 per foot, which is basically unchanged compared to the fourth quarter.

As mentioned earlier, our drilling and completion performance in the Western Haynesville is greatly affected by where the wells are being drilled on the acreage, given variability in vertical depths, formation temperatures, and lateral lengths. We are implementing performance initiatives that we expect will lead to further time savings and cost reductions. We have one of our existing Western Haynesville rigs being upgraded to a 10,000 PSI rating that will be available to us by late summer. With this upgrade, we will be able to increase our drilling speeds in both the vertical and horizontal hole sections, further reducing our cost.

We also intend to test some new higher-temperature-rated drilling motors later this year, which we expect will lead to faster drill times and longer runs. Once we get more successful and consistent runs of the rotary steerable drilling system in our legacy Haynesville area, we will look to deploy this technology into our Western Haynesville area. I also mentioned earlier we drilled our record-longest lateral to date in the Western Haynesville with a 14,800-foot lateral, and the well surpassed our initial performance expectations. The well was drilled with a larger hole size in the lateral, which allowed us to use larger insulated drill pipe.

That leads to lower downhole temperatures, more reliable motor performance from the downhole drilling assemblies, and longer motor life. We plan to implement this new well design in more of our future wells, which, along with the other performance initiatives being undertaken, are going to lead to a significantly lower and more predictable cost structure for our future wells. I will now turn the call back over to Jay.

Miles Jay Allison: Alright, Dan. Thank you. Roland, thank you. If everyone would please turn to Slide 21. I know we are dealing in a 90-day capsule on this call; I understand that. But the Comstock Resources, Inc. story over the past five years has been defined by our quest to add substantial drilling opportunities in the Western Haynesville, not just the last 90 days. Over that period, we have leased or acquired drilling rights on 728,000 gross acres, comprised of approximately 30,000 individual leases. Overall, our leases have favorable terms supporting our development program. As a result of that program over five years—not the last 90 days—we now have 2,546 net locations identified on our acreage.

We have been joined by three other companies now who are actively drilling and working in the Western Haynesville basin. The Haynesville shale is viewed, in our opinion, as the most important basin to supply natural gas to Gulf Coast LNG facilities and now the data centers being built in Texas and Louisiana. The arrival of the Western Haynesville is the game changer as the market looks into the future to where the needed natural gas will come from. Now our relationship with NextEra, which goes back to 2015, combined with our ideal locations and the drilling results that Dan just discussed in the Western Haynesville, led to the 03/19/2026 announcement that the U.S.

Department of Commerce selected our Western Haynesville site to host a new 5.2 gigawatt natural gas-fired power generation hub to be located in Anderson County, Texas. Our current goals for the company are fivefold. Number one, enhance our legacy Haynesville drilling program, which we accomplished by adding 114 Horseshoe wells to our near-term drilling program, which Dan talked about. They are fantastic performing wells. Currently, three of our five rigs deployed in our legacy Haynesville area are drilling Horseshoe wells. Two, strive to continue to be the low-cost operator. The combination of having the lowest cost and an abundance of drilling inventory closest to the growing natural gas demand will drive the market value for Comstock Resources, Inc.

Third, continue to protect the balance sheet, which was greatly helped by the divestitures we made in 2025 and by our robust hedging program as outlined on Slide 22, as well as our strong financial liquidity of almost $1.3 billion. Four, support the build-out of our midstream company, Pinnacle Gas Services (PGS). The formation of PGS by us in 2023 to gather and treat our natural gas in the Western Haynesville not only supports our drilling program, but also led to the power generation hub opportunities. By controlling our midstream, we will be able to keep our producing cost low and capture future value by owning the infrastructure.

PGS is now in a position to have its separate credit facility, and we believe we are nearing the end of a very strong process finding an equity partner to allow us to continue to grow our midstream footprint and to take advantage of future opportunities to connect Western Haynesville to premium markets. And finally, number five, optimize the drilling and completion of our wells in the Western Haynesville. Of the 44 wells we have drilled through the first quarter, many have different vertical designs and were drilled to various depths with laterals of various lengths, and were drilled and completed with different methods and tools, as Dan has discussed.

We have also produced the wells by employing different drawdown levels. The well performance has varied, which should be expected in a new shale play. That is the good news, as we are very encouraged that we are cracking the code on the best way to drill and complete the wells to unlock tremendous natural gas value and wealth in the future. I want to thank you for your time today. There will be questions, and we will turn it over to Ron if you want to call in and ask Ron questions. I also want to make one more comment.

As an initial founder or developer in the legacy Haynesville in 2008, we learned from mistakes that were made there. We did learn, and we understand. The thing that we did not want to do in our 700,000-plus acres in the Western Haynesville, which might have unprecedented wealth, is make the mistakes that were made in the legacy starting in 02/2010. That is 4 million acres in the legacy. We have about 800,000 acres that we think are in the Western Haynesville. The mistakes that were made were drilling too fast because leases were expiring, and you destroyed value. The rocks are established; they cannot move. What we have to do as a company is make those rocks valuable.

The way we do that—and I understand cash burn and slow pace of resource delineation is a little taxing—is to create the value that we already possess. With that, we will now open the call for questions.

Operator: We will now open the call for questions. Please limit to one question and one follow-up. To ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please standby while we compile the Q&A roster. Our first question comes from the line of Carlos Escalante from Wolfe Research. Carlos, your line is now open.

Carlos Escalante: Hey. Good morning, guys. Thank you for having us on. I appreciate the headline around cash burn and the slow pace of resource delineation testing investor patience.

Miles Jay Allison: Thank you for headlining cash burn and slow pace of resource delineation risk to investor patience. I love that headline. That is why I brought it up in my narrative because I think that is exactly right. That is not a negative; it is a positive, but it is not a positive for everybody. I just want you to know that. Thank you for being honest and coming up with that headline. It helped me.

Carlos Escalante: Sure, and I appreciate you saying that and giving an overview on how you feel about the long-term value proposition. Let us start there. You are dealing with a tough gas tape, as are your peers. On your current plan, as you mentioned, you may extend the period of that cash burn. How patient do you expect investors to be, acknowledging that there is a long-term value proposition, but that you still have to get through a number of quarters where your production and capital at times have not been aligned with what you stated the quarter prior? If you can frame that for us, that would be tremendously helpful.

Miles Jay Allison: Well, Carlos, number one—this is hard. It is like going into the first day of advanced math and not understanding anything and barely remembering your teacher's name when you walk out because it is so confusing. If you look at our business plan, yes, we did miss production in the quarter by about 13%, and our CapEx was higher. If you have our business plan, which is no M&A—if you throw M&A in here, you issue equity typically, you add production and inventory, and you stir up the pot every quarter or every year. We have not had M&A.

If you do not have M&A, the only way you can increase production—there will be a time lapse, maybe 90 to 120 days—is because if you are trying to protect your balance sheet last year and you lay down one, two, three, four rigs, you are going to lose that production a year later. It is a day of reckoning. We laid down the rigs. We did not do M&A. We kept adding a couple of thousand to 3,000 acres every month to our Western Haynesville, and most of that is the best acreage. We kept spending that money.

To turn the cycle, we sold $445 million of assets that in our business plan were not important to us in the next 15 years. When you do that, you pay down debt. Then what happens? You are going to have to lever up a little bit. We did say that we would outspend maybe $400 million to $450 million. That depends on the price of natural gas. In this quarter, production was down—yes, we missed it—and CapEx was up a bit. If you do not do M&A and you do not issue equity all the time, you have a quarter like we have. We protect every share of equity that everybody has.

Production is down, but now you see production up. Our production should be up 13% to 15% for the second quarter. I think we have turned the corner. The corner is hard because you have to spend money on those four new rigs, you have to have these Horseshoe wells really work, and you have to have Daniel S. Harrison have the freedom to figure out the best way to drill and complete repeatable Western Haynesville wells in both the Bossier and the Haynesville that can be very different from each other, much less 20 miles apart. I think we have turned the corner.

Maybe in the second quarter, because we did add that fourth frac fleet, the dollars that we took last year paid down our debt. We are not doing anything radical to destroy value in the Western Haynesville. The acreage that we have—if you keep the four rigs busy that we have right now in our Western Haynesville—every acre that we own will be HBP. We do not even have to have all four. The plan works. In the past, you might say, “You bought another 15,000 to 20,000 acres; there is another $200 million to $300 million,” and it kind of hit us in the quarter. We do not plan on that. We do not see that out there.

We see 1,000 to 2,000 acres every month. If we could get more, we would, but it is not there to be taken. We have crossed the bridge we are talking about. It was a hard bridge to cross. Now let us look at where the future is going.

Carlos Escalante: Sounds great to me, Jay. Appreciate the answer on that. My follow-up is for Dan. Can you talk briefly about the Hutto-Rodell IP? It looks like it underperformed the broad group and the initial production rates of all the wells that you brought online in the basin. Can you qualify the root cause—completion design, geology? What specific changes can you make on your next pad to prevent whatever drove this underperformance relative to your solid IP rates on the Western Haynesville?

Daniel S. Harrison: That is a good question. I will give you the quick answer and then a bit more. Of the 36 Western Haynesville wells we have on production, we have seven that we drilled “uphill,” meaning the laterals go updip instead of downdip. Most go down due to the geology. The Hutto-Rodell is the furthest by far as to the TVD difference between heel and toe—nearly 1,400 feet from heel to toe. The main reason we did not get a good IP on this well was it made a lot of loadwater during flowback—really high water volumes throughout flowback. Same as in the core—if you are making a lot of water, it is hard to get a high IP rate.

We are still triangulating whether it is more than geometry; it may include geology. We had our Brown Trueheart BB well about a mile away; both were Haynesville targets and both drilled uphill. The Brown Trueheart did not go as far uphill but also made a lot of water during flowback. It got a slightly better IP because the water was not as high. Those two wells are in deeper pay, roughly 17,500 to 18,800 feet TVD. Both made a lot of water during flowback. We have drilled five “uphill” wells on shallower acreage (14,000 to 17,000 feet TVD). Those also made a little more water in initial flowback, but by release from flowback, the water volumes were down.

So I will not hang 100% of the cause on drilling uphill; it contributes, but may not be the sole reason. We are fracking another well right next to those as we speak, the Jones No. 1—not to be confused with the Dolly Jones No. 1 I mentioned as the long lateral we just drilled. This Jones No. 1 is a Bossier, as opposed to those two being Haynesville. We will see how it responds to help determine whether it is geometry or Haynesville versus Bossier geology. The short answer: if you make a lot of loadwater during flowback, it is hard to get high IPs.

We probably had three out of the 36 with really high water volumes that affected IP rates.

Miles Jay Allison: And that is loadwater, not formation water.

Daniel S. Harrison: That is correct. Across the area, we are testing wells over a 50- to 60-mile spread—from East Texas to the deep inactive fault zone in Louisiana. That is a huge distance with a lot of variability in performance and water volumes. Also, comparing Western Haynesville to the core, the core does not have many wells that go significantly downdip or updip; they are mostly near-horizontal. In the Western Haynesville, we have more dip, and with two-well pads, one goes south (downdip), one goes north or northwest (updip). More structural dip leads to higher-angled wellbores.

Carlos Escalante: Understood. I will turn it back. Thank you, team.

Miles Jay Allison: Great question. Thank you.

Operator: Thank you. Our next question comes from the line of Charles Arthur Meade from Johnson Rice. Charles, your line is now open.

Charles Arthur Meade: Good morning, Jay, Dan, Roland, Ron, and all the other Comstock Resources, Inc. people on the call. Jay, forgive me if this is basic, but could you give us the whole picture from your point of view on this Texas power generation hub? You have made announcements about it; from my point of view, it looks like you are the surface owner for where this site is going to be—I think that seems to be the case. You are going to supply gas to the power gen facility, but I guess that is not finalized yet. Could you outline what roles Comstock Resources, Inc. is playing and how close you are to finalizing commercial terms for gas sales?

Miles Jay Allison: That is a great question. If you look at all the noise about AI, hyperscalers, and things that are not funded—you can treat that as background. What has happened here is if you have a hyperscaler in your office, most will say they really like Texas. It is a state that has a lot of natural gas, and we need it to power the generation that the NextEras of the world see. They like it, but you have to have a location that works. If you are in a really great geographic location, and you do have a big footprint, the sky is the limit. The federal government, under an agreement with the Japanese, has Japan’s $550 billion commitment.

The federal government then chooses NextEra, and NextEra chooses where their basin might be. This goes back to our 2015 relationship with NextEra. They said, “We have done a lot of business in the past. We love the Western Haynesville. We have been out there. This is where we would like the power generation hub.” We do not own the surface. Our role is to provide the gas. The obligations to build are not ours. We provide them the volumes—up to 5 gigawatts of power load, nearly 1 Bcf/d of gas, and it may grow higher—to feed the turbines.

It is a great event because it is at the United States government level, then at NextEra’s level, and it is our gas. We are a natural gas company. Whatever the benefits are, you open those when everyone else has discussed terms and when you have your first power needed. It is significant that we captured the acreage and have the midstream. You have to have the midstream to provide that gas to serve what NextEra sees as a huge role for U.S. shale gas to power AI hyperscalers and data centers.

Charles Arthur Meade: Got it. Thank you for that overview. As a follow-up about the Western Haynesville, I really like the maps on page 16 with the red dots of your well results. It looks like you had two wells that are further updip. Can you talk about how the play changes as you move updip? I am guessing you have lower D&C because of less vertical depth, but what are you seeing with productivity on those wells as you move up there?

Miles Jay Allison: I will let Dan take that, and I will add one asterisk. If you were to go where we drilled several wells and infill drill, you could drill dozens and dozens of wells and have gathering nearby on that pad site to get cost down. That is not part of our business plan either. That is why we went 40 to 50 miles to the north to drill the Elijah well. We had seismic, we had well control—we have about 1,000 penetrations across this footprint—and now we have cores. Before cores, we would still go north because the plan was to delineate quickly while holding acreage. Jumping 40 to 50 miles in one year is pretty quick delineation.

Our goal is to keep rigs busy; more than 90% of the time, it is to continue to hold acreage, not infill drill around known repeatable locations. It is a different business plan. Dan?

Daniel S. Harrison: Those two dots are two pads—the two Bumpers wells and two Pollard wells. On each pad, we drilled one north (updip) and one south (downdip). After reviewing performance, we concluded we were likely understimulating these wells and needed bigger fracs. All four of those wells were pumped with bigger fracs than offsets in that area, and all four look really good. Two of those went uphill by about 600 to 700 feet from heel to toe. We did not see big water volumes by the time we were off flowback, and the wells “dried up” appropriately. They are roughly 14,000 to 16,500 feet TVD; the toes of the downdip wells may be closer to 17,000.

Less pressure makes them cheaper to D&C. Our record fastest and cheapest well to date—TD in 37 days—was a direct offset to one of those pads (the Jennings FSRA), which was updip. We had great motor runs. The EUR will be a little less because of lower pressure and shallower depth, but we offset that with faster drilling and lower D&C cost.

Charles Arthur Meade: That is great color, Dan. Thank you.

Daniel S. Harrison: You bet. Great question. Thank you.

Operator: Our next question comes from the line of Derrick Lee Whitfield from Texas Capital. Derrick, your line is now open.

Derrick Lee Whitfield: Good morning, all, and thanks for your time.

Miles Jay Allison: Morning, Derrick.

Derrick Lee Whitfield: Jay, I appreciate your bigger-picture comments to open up the call. Maybe, Dan, I will start with you. As you think about the new concepts you are testing, you highlighted the use of rotary steerable drilling systems and your first well with a big-hole design. What could these developments mean in cost if successful?

Daniel S. Harrison: On rotary steerables, we will deploy those later in the Western Haynesville. We have had several runs so far in the legacy Haynesville. We started five to six months ago and are still making tweaks. We have had some fantastic runs and some that did not make it far due to tool issues being refined. When they rolled out similar tech in the Permian a few years ago, it took 18 to 24 months to get the tool humming. The Haynesville is usually the last basin due to depth and temperature. We are excited about the great runs but need more of them with consistency; then we will roll it into the Western Haynesville, which is more challenging thermally.

We have run several on Horseshoe wells and are pleased. The 10k-PSI rig coming at the end of the summer will let us pump faster, put more horsepower on bottom, improve ROPs, and knock days off. On the big-hole lateral we just drilled—8.5-inch bit size instead of 6-3/4—we needed a project with a long lateral because you spend more before reaching the lateral (larger hole sizes and casing), so you start “in the red.” You need a longer lateral drilled faster to break even or come out cheaper. We came out even cheaper than expected.

Our drill cost on that well was lower than any of the bars you see on Slide 20 on cost per foot—slightly lower—and the approach looks more predictable than slim-hole. We can slide and turn more effectively than in the slim hole. We need to drill more of them, but early results are very encouraging. We thought we might need 14,000 to 15,000 feet to break even versus slim hole, but now it looks like we may only need 11,000 to 12,000 feet to be cost competitive.

Miles Jay Allison: And remember, some of these are Bossier and some are Haynesville. When Dan talks about a particular well, we may have another Haynesville 80 miles away, but it is not exactly the same. They are all a little different, and that is why we saw value destroyed in the legacy Haynesville back in 2008–2011—too many rigs drilling with leases expiring, and then natural gas prices collapsed. We look at all of that. We are planting seeds around the basin, and these trees are starting to grow. You cannot do it too fast.

We are in front of an unprecedented bull market opportunity for LNG and data centers, and I think our timing is going to be perfect because we are in the correct geographical location. If you own the basin—and yes, there are other companies drilling—but they do not own what we own. If it is valuable and precious, you have to treat it that way. That is exactly what we are doing. Every share is precious; we treat it like it is precious. Production should go up, and we should have really great growth for the rest of this year, particularly in the third and fourth quarters. We did add that extra frac fleet. I see big sunshine out there.

Daniel S. Harrison: Derrick, did that answer your question?

Derrick Lee Whitfield: All good. And, Jay, I agree with you on NextEra. When you think about that development—how meaningful and differentiated it is for you within the sector on the scale and nearness of development—I agree it is a big development that probably is not getting enough attention this morning. Back to Dan on another topic: on restricted flowback testing to date, is that an optimization lever you are likely to turn as you progress development in the Western Haynesville?

Daniel S. Harrison: Absolutely. We need to be pumping bigger fracs—better stimulation—and with those bigger stimulations, the volume of rock you are touching needs to be kept open. To keep it open, you need a very conservative drawdown. We are probably moving to an even slightly more conservative drawdown this year than in the last six months. You get bigger EURs and better PV-10 values, and if you still get the volumes within the first couple of years, your rate of return should be about the same. That is the answer: significant resource in the ground due to thickness and pressures—you are touching a lot of reserves—and you must keep those fracs open to extract the volumes and value.

So, bigger fracs and very conservative drawdown going forward.

Miles Jay Allison: And we put boots on the ground. Two weeks ago, Dan and our top drilling team went to Germany to the Baker plant—see it, touch it—so we can tweak to make it better, quicker, faster. If a partner is spending money developing what we need, we will be there. We give you our best—38 years of doing this—and we do not tell a weird story. It is a hard story, but it is a great story, and every share of equity is precious.

Derrick Lee Whitfield: One more, philosophically on guidance: when you provide guidance, should we think of that as a P50 with a little bit of risking—call it P45 to P55?

Daniel S. Harrison: We give you our best estimate based on expectations for drilling and completion time frames. The legacy Haynesville has been a little more predictable to date than the Western Haynesville, but with bigger fracs and more conservative drawdown, it will make Western Haynesville volumes more predictable looking forward than looking backward.

Miles Jay Allison: And pure volume in the Western Haynesville will take out some of the lumpiness.

Derrick Lee Whitfield: All makes sense. Thanks for your time, guys.

Miles Jay Allison: Great questions. Thank you, Derrick.

Operator: Our next question comes from the line of Leo Mariani from Roth. Leo, your line is now open.

Leo Mariani: Hey, wanted to turn to the funding side a bit here. You secured the Pinnacle credit facility, which you mentioned briefly. It looks like you are consolidating that; it is on your balance sheet. Is that debt recourse to Comstock Resources, Inc.? Additionally, you have spoken about other financing needed at the Pinnacle level. I know you are attempting to take Quantum out, which supposedly pays them. Is there additional equity you are looking to raise at the Pinnacle level, or do you think you are going to be good with this credit facility for the near future?

Roland O. Burns: That is a good question, Leo. We are running a process [inaudible].

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