On Wednesday, Comstock Resources (NYSE:CRK) discussed first-quarter financial results during its earnings call. The full transcript is provided below.
This content is powered by Benzinga APIs. For comprehensive financial data and transcripts, visit https://www.benzinga.com/apis/.
View the webcast at https://edge.media-server.com/mmc/p/p77w7mi4/
Summary
Comstock Resources Inc reported lower production and financial results in Q1 2026 due to winter weather impacts, with natural gas and oil sales at $339 million.
The company highlighted strong drilling results, with new wells in Western and Legacy Haynesville showing promising initial production rates.
The U.S. Department of Commerce selected the company’s Western Haynesville site for a 5.2 gigawatt natural gas power generation hub, enhancing strategic growth prospects.
Adjusted net income for the quarter was $44 million, or $0.15 per share, excluding a significant unrealized hedge gain.
Comstock Resources Inc is focused on optimizing drilling and completion techniques in the Western Haynesville, emphasizing careful resource management to avoid past mistakes made in other shale plays.
The company is pursuing a new equity partner for its midstream company, Pinnacle Gas Services, to support infrastructure growth.
Management expressed confidence in turning around production declines and maintaining financial stability without resorting to M&A or equity dilution.
Full Transcript
Jay Allison (Chairman and CEO)
Thank you everyone. Thank you for joining us. Welcome to The Comstock Resources First Quarter 2026 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 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock. Here 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. 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 in such statements to be reasonable, there can be no assurance that such expectations will prove that to be correct. If everyone would please go to slide 3. On slide 3 we summarize the highlights of the first quarter. Lower production Partially driven by production impacts from significant winter weather in the first quarter drove the lower financial results in the quarter compared to the first quarter of 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 we turned 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 12,312ft and a per well initial production rate of 31 million cubic feet per day. Now the power generation hub. On March 19th, 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. Next year is actively developing the project, advancing site development, procurement, permitting and commercial structuring as they work toward definitive agreements with the US And Japan. This project takes advantage of our abundant natural gas supply and a strong transmission of infrastructure in the area. The Henderson county facility will have up to 5.2 gigawatt of natural gas fire generation capable of serving up to 5 gigawatt of large load demand. Comstock will provide the natural gas supply for the facility which could reach almost 1 billion cubic feet per day by 2031. Roland will now provide some more details on the financial results we reported yesterday.
Roland Burns (President and Chief Financial Officer)
Roland all right, 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’re shooting in our western Haynesville play and other non recurring 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 at $4.90. 26% 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 69 cent basis differential compared to the NYMEX settlement price and a 67 cent differential compared to the reference price. Significant disconnects existed during the quarter between the regional hub prices and and NYMEX kind of 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 margin per unit costs 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 costs and G and a were up 4 cents attributed 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 the quarter was 73%. On slide 8 we recapped the 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 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 per day. Slide 9 We summarize our capitalization at the end of the first quarter. We ended the quarter with $350 million of borrowings outstanding at our upstream credit facility. Our upstream borrowing base is $2 billion and our electric commitment under our facility is 1.5 billion. In March we entered into a new $150 million midstream credit facility for Pinnacle Gas Services. At the end of March, the Midstream Credit Facility had 47 million outstanding. Our last 12 months ratio was 2.9 times. At the end of the first quarter we had almost $1.3 billion of liquidity. I’ll now turn it over to Dan to discuss our operations in the quarter.
Dan Harrison (Chief Operating Officer)
Okay, thanks Roland over on slide 10 this is just our updated overview of our acreage footprint in the Haynesville and Bossier shales across East Texas and North Louisiana. We now have one 174,868 gross acres and 806,980 net acres that are prospective for commercial development of the Haynesville and Bossier shells. On the left is our western Haynesville footprint which we have now grown over 540,000 net acres. On the right is our 266,570 net acres that’s in 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. Of course, with the higher pay thicknesses and the very high pressures we encountered 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 operating inventory in the Legacy Haynesville now consists of 955 gross locations, 740 net locations which equates to average working interest of 78%. On our non operated inventory, the Legacy Haynesville, we have 819 gross locations with 98 net locations which is a 12% average working interest. Our drilling inventory we split into four buckets. We have our short laterals less than 5,000ft. We have our medium length laterals that are from 5,000 to 8,500ft. Our long laterals are between 8,500 and 10,000ft and our extra long laterals are everything over 10,000ft. 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 pretty much split 52% in the Haynesville and 48% of our locations in the Bossier. Our 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 have laterals that are longer than 8,500ft long. As of today, our average lateral length in Legacy Haynesville inventory has climbed up to 10,019ft. So 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, 2,546 net locations which equates to an average working interest 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 is in the Haynesville shell. We also have our western Haynesville inventory divided into the four separate groups by length with our short laterals less than 5,000, the medium laterals between 5 and 8,500ft, the long laterals between 8,500 and 10,000ft and the extra long laterals over 10,000ft. So in our western Haynesville gross operated inventory we don’t have any short laterals. Today we got 13 1,319 medium laterals. We have 646 long laterals and 1,366 extra long laterals. So 60% of our Western Haynesville gross operated inventory has the laterals greater than 8,500ft on slide 13. This is just an update to our new horseshoe development program. The horseshoe well design of course combines the 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 10k horseshoe well compared to 25000 foot sectional lateral wells. Our drilling inventory in our legacy Haynesville area Now includes the 114 horseshoe locations. The Camp Tech2914 9 number 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 total in 2026. On slide 14 there’s a chart outlining our average lateral lengths drilled that are based on when the wells have been drilled to total depth. The 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 10,872ft. The individual laterals range from 8,497ft up to 15,772ft. Our longest lateral drill to date on our legacy Haynesville acreage still stands at 17,409ft 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 10,356ft. The individual lengths range from 9,400ft up to 11,393ft through the first quarter. Our longest lateral drilled in the western Haynesville stood at 12,763ft as of last month. We have since exceeded that length in the western Haynesville with a new record lateral length of approximately 14,800ft. The well, which is the Dolly Jones RP1H reached total depth in mid April and we have it scheduled for completion later this summer. So to date we have drilled 47 wells to total depth in the western Haynesville. That includes 21 wells with laterals over 10,000ft and seven of the wells had laterals over 12,000ft. 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 12,312ft and the individual laterals range from the low end of 9,465ft up to a high of 15,143ft. The individual IP rates on these wells range from a low of 15 million a day up to a high of 41 million a day and the average IP was 31 million. Today and five of our nine rigs are drilling on the Legacy Haynesville acreage. Slide 16 this one outlines the six wells that we have turned to cells on our western Haynesville acreage since the last call. So these six wells had an average lateral length of 10,874ft with an average initial production rate of 29 million cubic feet per day. And we have four of our nine rigs are 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. And this is for our benchmark long lateral wells that are greater than 8,500ft long. 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 921ft drill per day in our Legacy Haynesville acreage which represents a 3% increase versus the fourth quarter of 2025. Four of the wells drilled in the first quarter were our horseshoe wells which do take takes a few extra days compared to our normal straight levels. Slide 18 this 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 5 wells drilled to total depth during the first quarter. This is an increase of 3 days compared to the fourth quarter. You can see this is also reflected in the drilling speed of 478ft per day during the first quarter which is 4% lower than the fourth quarter. Aside from drilling issues we have our quarter to quarter drilling performance in the Western Haynesville is mainly dictated by our vertical depth, our temperatures and our 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 DNC cost through the first quarter for our benchmark long lateral wells that are located on our legacy Hazel acreage position. These are laterals greater than 8,500ft. These costs reflect all of our legacy area wells greater than 8,500ft. 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. The first quarter drilling cost averaged $700 a foot. This is a 3% increase compared to the fourth quarter. The increase in the first quarter drilling cost is the result of a combination of factors mainly being overall short average lateral length in the first quarter had a higher number of horseshoe wells drilled and we also had more wells drilled in our East Texas area which does require additional casing stream that we used to isolate the localized over pressured SWD zones in that area. During the first quarter we also turned 8 of our benchmark long lateral wells to sales on our legacy Haynesville acreage. The first quarter completion cost came in at $652 a foot. This is a 9% decrease compared to the fourth quarter. This lower completion cost is due to a combination of using less horsepower and having higher frac efficiency and with a slightly lower drill out cost. We’re currently running three full time frac fleets. This is after we added our third frac fleet in January. We are adding a fourth frac fleet this month and we’re 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 we’re really continuing to make good progress there. So as we accumulate more data and we make further refinements there, we do expect this rotary steerable technology is going 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 DNC cost through the first quarter. This is for all our wells drilled in the western Haynesville. During the first quarter we drilled five wells to total depth in the western Haynesville. This is with an average lateral length of 10,356ft. Our first quarter drilling cost average $1,534 a foot. This represents 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 11,177ft. Our first quarter completion cost average $1,537 a foot, which is basically unchanged compared to the fourth quarter and kind of also to reiterate what was mentioned earlier, our drilling and completion performance in the western Haynesville is greatly affected by where the wells are being drilled on the acreage as there’s much variability in the vertical depths and formation temps along with the lateral lengths. We’re also implementing our new performance initiatives that we expect will lead to further time savings and cost reductions. We do have one of our existing western Haynesville rigs being upgraded to a 10,000 psi rating that’s going to 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 temp rated drilling motors later this year which we expect will lead to faster drill times and some longer runs. Once we get more successful and consistent runs of the rotary steerable drilling system in our legacy Haynesville area, we will be looking to deploy this technology into our western Haynesville area. I also mentioned it earlier, but we also 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 with allowed us to use larger insulated drill pipe which leads to lower downhole temperatures, more reliable motor performance from the downhole drilling assemblies and longer motor life. So 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 significantly lower more predictable cost structure for our future wells. I’ll now turn the call back over to Jay.
Jay Allison (Chairman and CEO)
All right, Dan, thank you Roland, thank you. If everyone would please turn to slide 21. You know, I know we are dealing in a 90 day capsule on this call I understand that, but the Comstock 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. Capsule over that period we have leased or acquired drilling rights on 728,000 gross acres comprised of approximately 30,000 individual leases over that five year period. Overall, our leases have favorable terms supporting our development program and 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’ve 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 to data centers being built in Texas, 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. They all ask that question now. Our relationship with NextEra which goes back to 2015 combined with our ideal locations and the drilling results that Dan has just talked about in the western Haynesville. It led to the March 19, 2026 announcement of what 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 where in Anderson County, Texas. So our current goals for the company, they’re fivefold and the fifth one you’ll really want to hear. 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’re 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. Third, obvious 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 has our strong financial liquidity of almost $1.3 billion. 4. Support the build out of our midstream company Pinnacle Gas Services. The formation of Pinnacle Gas Service by us in 2023 together and treat our natural gas in the western Haynesville not only supports our drilling program but but also led the power generation of opportunities by controlling our midstream we’ll be able to keep our producing cost low and capture the future value by owning the infrastructure. PGS is now in a position to have its separate credit facility and we believe we’re nearing the end of a very, very strong process of finding an equity partner to allow us to continue to grow our midstream footprint and to take advantage of future opportunities to connect the Western Haynesville to premium markets. And finally, number five, which is what most of this conversation has been on 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 they were drilled to various depths with laterals of various lengths which were drilled and completed with different methods and tools. As Dan has gone on and on about, we’ve also produced the wells by employing different drawdown levels. …
This post was originally published here
