管理層發言
Good day, and thank you for standing by. Welcome to the Second Quarter 2026 Comstock Resources 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. To ask a question during the session, you will need to press *11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press *11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and Chief Executive Officer. Please go ahead.
Thank you for the introduction. I want to welcome everyone to the Comstock Resources second 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 will find a presentation entitled Second Quarter 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland O. Burns, our President and Chief Financial Officer; Daniel S. Harrison, our Chief Operating Officer; and Ronald Eugene Mills, our VP of Finance & 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 of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. On Slide 3, if you turn there, we summarize the highlights of the second quarter. We did see the return of production growth in the quarter. Production increased 16% over the first quarter of 2026 and 1% over the second quarter of 2025. However, lower natural gas prices drove lower financial results in the quarter. Natural gas and oil sales, including realized hedging gains, were $332 million. Operating cash flow excluding working capital changes was $189 million, or $0.65 per share. Adjusted EBITDAX for the quarter was $245 million. Our legacy Haynesville, Horseshoe and Western Haynesville drilling results are driving future production and reserve growth. Eleven Western Haynesville wells turned to sales so far in 2026 with an average lateral length of 10,300 feet and a per-well initial production rate of 31 million cubic feet per day. Twenty-two legacy Haynesville wells turned to sales with an average lateral length of 12,100 feet and a per-well initial production rate of 31 million cubic feet per day. Eight of the legacy Haynesville wells were Horseshoe wells. On June 15, we completed our midstream equity placement by selling a 27% stake in Pinnacle Gas Services for $600 million, which we used to retire Pinnacle's preferred equity and all of Pinnacle's outstanding debt. I will discuss this in more detail on the next couple of slides if you turn over to Slide 4. On June 15, 2026, we sold a minority equity interest in our midstream subsidiary, Pinnacle Gas Services, to certain funds managed by Sixth Street. Sixth Street invested $600 million in Pinnacle to acquire a 27% non-controlling common equity interest. This transaction is another validation of the future potential of our Western Haynesville acreage, which is well positioned to service the growing demand for natural gas in our region. The Western Haynesville represents one of the largest undeveloped natural gas resources with access to the growing demand along the Gulf Coast. It will also serve the recently announced Texas Power Generation Hub in Anderson County, Texas. The transaction with Sixth Street represents an important milestone for Comstock and a strong validation of the value we have created in the Western Haynesville. With Sixth Street's investment, we strengthened our balance sheet by reducing debt and simplified Pinnacle's capital structure. If you will turn to Slide 5, Sixth Street's investment of $600 million in Pinnacle Gas Services for a 27% stake implies a $2.2 billion enterprise value for Pinnacle. We retained a 73% controlling common equity interest in Pinnacle, which implies a $1.6 billion value for our stake. The strong valuation reflects the expected future production growth from our Western Haynesville drilling program. After the transaction, Pinnacle is now debt-free and is saving $40 million in fixed charges annually. Comstock retained a 73% controlling equity interest in Pinnacle and, after certain return hurdles are met, our ownership increases to 80.5%. We also maintained operational control and key decision-making of the Pinnacle system critical to supporting our growing Western Haynesville asset. I will now have Roland Burns review the financial results for the quarter. Roland?
Alright. Thanks, Jay. On Slide 6, we cover the second quarter financial results. Our production in the second quarter averaged 1.2 Bcfe per day, which was up 16% from the first quarter this year and slightly higher than the second quarter of last year. Our oil and gas sales after hedging were $332 million, reflecting the lower natural gas prices we experienced in the quarter. EBITDAX came in at $245 million, and we generated $189 million of cash flow in the quarter. We reported a $9 million profit for the quarter, or $0.03 per share. Included in that number was a $1 million mark-to-market unrealized gain related to our hedge book. If you exclude the mark-to-market gain and exploration expense, which is solely related to seismic shooting in the Western Haynesville, and other nonrecurring items such as a gain on sales and the related income taxes to those items, we reported an adjusted net income of $8 million for the quarter, or $0.03 per share. On Slide 7 is the year-to-date financial results. Production in the first half of the year averaged about 1.2 Bcfe per day as well. Our oil and gas sales for the six months were $670 million. EBITDAX was $496 million, and we had $380 million of cash flow. We reported a profit of $116 million for the first six months, or $0.40 per share. That includes a pretax $84 million mark-to-market unrealized gain on our hedge book. So if you exclude that gain, exploration expense, and other nonrecurring items, and the related income tax effect of those, our adjusted net income would have been $48 million for the first six months of this year, or $0.16 per share. Slide 8 breaks down the natural gas price realizations. In the quarter, the weighted average NYMEX settlement price averaged $2.89, and the weighted average Henry Hub spot price for the quarter was $2.93. Thirty-two percent of our gas was sold in the spot market, so the approximate NYMEX reference price would have been about $2.91 for our production. Our realized gas price during the second quarter averaged $2.54, reflecting a $0.35 basis differential compared to the NYMEX settlement price and a $0.37 differential compared to the reference price. In the second quarter, we were 63% hedged, which increased our realized gas price for the quarter to $2.93. Slide 9 details our operating cost per Mcfe and our EBITDAX margin. Our unit operating cost returned to normal levels in the quarter compared to where they were in the first quarter of this year. Our operating cost per Mcfe averaged $0.77 in the second quarter, which improved $0.16 from the first quarter rate, and was in line with where we were in the second half of last year. Lifting cost was down $0.04 per Mcfe. G&A was down $0.03 per Mcfe. Both of those improvements were due to the higher production level in the quarter. Production and ad valorem taxes were also down by $0.04 in the quarter. Some of that was due to the lower gas prices we had, and the divestitures that we completed last year helped reduce our ad valorem taxes in the quarter. Gathering costs were down $0.05 in the quarter; that is also due to the higher production level and utilizing more of our firm transportation. Our EBITDAX margin in the quarter improved to 74%. On Slide 10, we recap our spending on our drilling and other development activity in the quarter and for the first half of this year. We spent a total of $390 million on development activities in the second quarter and $734 million during the first half of this year. In the first six months of this year, we have drilled 22, or 19.4 net horizontal Haynesville wells and 12, or 11.5 net Bossier wells for a total of 34, or 30.9 net wells. We have returned 29, or 24.4 net operated wells to sales, which had an average initial production rate of 30 million cubic feet per day overall. Slide 11 summarizes our capitalization at the end of the second quarter. We ended the quarter with $545 million of borrowings outstanding under our upstream credit facility. Our upstream borrowing base is $2 billion and our elected commitment under that facility is $1.5 billion. At the end of June, the midstream credit facility had no borrowings outstanding following the Pinnacle transaction with Sixth Street. Our last 12 months leverage ratio has averaged exactly 3x. At the end of the second quarter, we have almost $1.2 billion of liquidity. So I will turn it over to Daniel to talk about the operating results for the quarter.
Okay. Thank you, Roland. If you look on Slide 12, this is our latest overall acreage footprint in the Haynesville-Bossier shale in East Texas and North Louisiana. We now have 1.08 million gross acres and 809,000 net acres that are prospective for commercial development of the Haynesville and Bossier shales. Our Western Haynesville footprint has grown to just over 545,000 net acres. We currently have just over 264,000 net acres located in our legacy Haynesville area. We have 41 wells currently producing on our Western Haynesville acreage, and another 13 wells that are in various stages of development. Slide 13 outlines the drilling inventory in our legacy Haynesville area. At the end of the second quarter, we had 926 gross operated locations with a 77% average working interest. This is 717 net locations. We have 779 gross non-operated locations with a 13% average working interest, or 99 net locations. The drilling inventory is divided into our four different groups based on lateral length. Four hundred forty-nine of our 926 gross operated locations, nearly 50% of the inventory, have laterals surpassing 10,000 feet. The average lateral length in the inventory now stands at 10,200 feet. The gross operated inventory is evenly split with 51% of our locations in the Haynesville and 49% in the Bossier shale. Our legacy Haynesville inventory also includes 113 gross Horseshoe locations, with 53% of those in the Haynesville and 47% in the Bossier. We are currently running five rigs on our legacy Haynesville area. This inventory provides a long runway for future drilling locations. Slide 14 outlines our estimated drilling inventory in the Western Haynesville. We have 3,280 gross operated locations and 2,530 net locations in the Western Haynesville, which equates to an average working interest of 77%. Our total net locations are estimated since most of our Western Haynesville acreage has not yet been unitized. The Western Haynesville inventory is also divided into our four groups based on different lateral lengths, and in this inventory we do not have any short laterals less than 5,000 feet. One thousand three hundred twenty of the 3,280 gross operated locations, 40%, have a lateral surpassing 10,000 feet. Sixty-one percent of our gross operated locations have laterals surpassing 8,500 feet. The average lateral length in our Western Haynesville inventory is 8,880 feet. The Western Haynesville inventory is weighted more to the Bossier formation with nearly two-thirds of the inventory in the Bossier and one-third in the Haynesville. We are currently running four rigs on our Western Haynesville acreage. Slide 15 recaps our ongoing Horseshoe well development activity within our legacy Haynesville area. To date, we have drilled a total of 19 Horseshoe wells to total depth and 11 of these Horseshoe wells have been turned to sales. We continue to realize significant cost savings with Horseshoe development compared to drilling the shorter 5,000-foot laterals. Our well performance has also met expectations, with an average of 31 million cubic feet per day for all 11 Horseshoe wells that we have turned to sales. For 2026, we plan to drill a total of 16 Horseshoe wells and turn 17 of those to sales. Our drilling inventory includes the 113 Horseshoe locations. Slide 16 outlines our average lateral lengths drilled based on the wells that have been drilled to total depth. The average lateral lengths are shown separately for the legacy Haynesville and the Western Haynesville. In the second quarter, we drilled 13 wells to total depth in the legacy Haynesville area. Those had an average lateral length of 11,500 feet, and the individual laterals ranged from 9,490 feet up to 15,600 feet. Our longest drill to date in the legacy area is 15,409 feet. In the second quarter, we also drilled four wells to total depth in the Western Haynesville with an average length of 10,300 feet. The individual laterals ranged from 7,870 feet up to 14,800 feet. The longest lateral drilled to date in the Western Haynesville is 14,800 feet. To date, we have drilled a total of 50 wells to total depth in the Western Haynesville; 21 of these wells have laterals exceeding 10,000 feet. Slide 17 summarizes the 22 wells that turned to sales in our legacy Haynesville area so far in 2026. The average lateral length was 12,100 feet, with individual laterals ranging from a low of 9,300 feet up to a high of 15,800 feet. The average IP for the 22 wells was 31 million cubic feet per day, and included in these results are eight of our Horseshoe wells. Slide 18 outlines the 11 wells that we have turned to sales on our Western Haynesville acreage so far this year. These 11 wells had an average lateral length of 10,300 feet and an average initial production rate of 31 million cubic feet per day. The last five wells we have turned to sales since our first quarter update have ranged from 30 million to 35 million cubic feet per day. We have a total of 41 wells currently producing on the Western Haynesville area. Slide 19 highlights our drilling efficiency in the legacy Haynesville area for our benchmark long-lateral wells, all wells greater than 8,500 feet long. In the second quarter, we drilled 13 of these benchmark long-lateral wells to total depth in the legacy Haynesville area and averaged 24 days to total depth. Correspondingly, we averaged 817 feet drilled per day in our legacy Haynesville area, which represents a 10% increase versus the first quarter of 2026. Six of the 13 wells we drilled in the second quarter were Horseshoe wells. Slide 20 highlights our drilling progress in the Western Haynesville area. During the second quarter, we drilled four wells to total depth in the Western. This gives us a total of 48 wells drilled to total depth through the end of the second quarter. We averaged 59 drilling days for the four wells drilled to total depth during the quarter. This is an increase of two days compared to the first quarter. This is also reflected in the drilling speed of 769 feet per day during the second quarter, which is 2% lower than the first quarter. The main driver affecting the lower drilling efficiency in the second quarter was the deeper depths, which mean higher temperatures. The average true vertical depth for the four wells drilled in the second quarter was approximately 1,200 feet deeper than the average TVDs of the five wells we drilled in the first quarter. Slide 21 details our D&C cost through the second quarter for the benchmark long-lateral wells in the legacy Haynesville area. These costs reflect all legacy Haynesville wells with laterals greater than 8,500 feet. The drilling costs are based on the quarter in which the wells reached TD, and the completion cost for the quarter is based on the quarter in which the wells were turned to sales. During the second quarter, we drilled 13 benchmark long-lateral wells to total depth. The second quarter drilling cost averaged $710 per foot, which is a 1% increase compared to the first quarter. Although we drilled six Horseshoe wells in the second quarter compared to four in the first quarter, we were able to keep our drilling costs nearly flat due to better drilling performance on our Horseshoe wells in the second quarter. During the second quarter, we also turned 12 of our benchmark long-lateral wells to sales on our legacy Haynesville acreage, and five of these were Horseshoe wells. The second quarter completion cost came in at $608 per foot, which represents a 4% increase compared to the first quarter. The higher completion costs in the second quarter were the result of slightly higher costs associated with some longer drillouts and slightly higher flowback costs. On the drilling side in the legacy Haynesville, we continue to deploy rotary steerable drilling technology, particularly on our Horseshoe wells, making good progress in improved repeatability. On Slide 22 is a summary of our D&C cost through the second quarter for all wells drilled in the Western Haynesville. During the second quarter, we drilled four wells to total depth in the Western Haynesville with an average lateral length of 10,300 feet. Our second quarter drilling cost averaged $1,070 per foot. This represents a 13% increase compared to the first quarter. Higher drilling costs in the second quarter were attributable to the wells encountering some steering difficulties in the laterals, resulting in additional trips and BHA runs. Higher drilling costs for these wells were partially offset by the lower drilling cost associated with our first big-hole record long lateral drilled in the second quarter. That well was drilled at an attractive cost of $1,310 per lateral foot, which is 25% lower than our quarterly average. During the second quarter, we also turned four wells to sales in our Western Haynesville acreage that had an average lateral length of 9,440 feet. The second quarter completion cost averaged $1,610 per foot, a 5% increase compared to the first quarter. Higher completion costs in the second quarter can be attributed to higher proppant loading. We had a lower average lateral length in the second quarter compared to the first quarter, and we had a higher percentage of single-well pads that we completed in the second quarter. Based on the successful results of our first big-hole long lateral drilled in the quarter, we are now in the process of drilling our second and third big-hole laterals to confirm repeatability. The big-hole lateral creates lower downhole temperatures, which leads to longer, more reliable runs from our downhole drilling assemblies. This fall, we will be deploying our first 10,000-psi rig in the Western Haynesville. This will increase our drilling speeds in both the vertical and horizontal sections. Near-term, we will be testing new higher-temperature-rated drilling motors, which we expect to lead to longer runs and better drill times. On a longer timeline, we are continuing discussions with industry partners regarding the development of a 20,000-horsepower frac spread, which would allow us to significantly increase frac efficiencies and generate superior performing wells with higher EURs. This would be a 2027 event. I will now turn the call back over to Jay.
Excellent report, Daniel. Thank you, Roland. If you will turn to Slide 23, we will summarize our outlook for 2026. As you can tell, our primary goal continues to be advancing our Western Haynesville, which will position Comstock to benefit from a longer-term growth in natural gas demand. We have four operated rigs drilling in the Western Haynesville to continue to delineate the new play. We expect to drill 22 wells and turn 21 wells to sales in 2026. We expect drilling efficiencies and changes to our completion design to continue to drive up productivity and drive down drilling and completion cost. We have five operated rigs drilling in our legacy Haynesville to support production growth in 2026 and 2027. We expect to drill 48 wells and turn 48 wells to sales in 2026. Lastly, we continue to have strong financial liquidity of almost $1.2 billion. To everyone listening, I want to thank you for your time today. Slide 25 provides guidance for the rest of 2026, which Ronald can discuss with you directly. If you have any questions, for the rest of the call I will take questions from analysts who follow the company.
分析師問答
As a reminder, to ask a question, please press *11 on your telephone. Wait for your name to be announced. To withdraw your question, please press *11 again. In the interest of time, we ask that you please limit yourself to one question and one follow-up. Please stand by while we compile the Q&A roster. Our first question comes from Derrick Whitfield with Texas Capital. Your line is open.
Good morning, all, and thanks for your time. I wanted to start with your D&C optimization efforts in the Western Haynesville. While we are still very early in optimizing this trend, the steps you are taking are clearly important to value extraction over time. With that said, if we assume you move forward with the tangible changes, including the big-hole design and higher-spec rigs, where do you see well cost per foot trending? And as a tack-on to that, if you assume the use of more leading-edge technologies like the higher-temperature-rated drilling motors you talked about and a higher-horsepower frac spread, where do you see cost trending when all the drivers are working together?
That is a really good question, Derrick. On the drilling side, we definitely see cost coming down. We are excited about the big-hole lateral that we drilled, albeit we have only drilled the one so far. We are drilling the second and third ones now. We have five on our drilling schedule slated to be drilled with the bigger lateral and probably another dozen or so targeted for the bigger hole. We need to get results on the second and third wells, but the first well, the Dolly Jones, at $1,360 per lateral foot is a good bit cheaper than any other well we have drilled at a similar TVD. That well had about a 16,400-foot TVD average and is by far the cheapest well of any well we have at that depth or deeper. We did not have the exact motors we wanted on the first well; we used more off-the-shelf tools because we had not done any big-hole work in the Western Haynesville. We hope to have better performance on the second and third wells because we have had time to dial in and get something better fitted. I think the majority of future wells will probably be with this bigger lateral. Not only are they cheaper, but there are intangible benefits as well. We had a lot better steering ability in the first big-hole well versus the slim-hole wells. If you want to make course corrections, it is a lot easier and quicker. You get better yields and you are not fighting and sliding for longer periods of time trying to get the well to turn. So I think big-holes will be more predictable on performance, cheaper, and more predictable. On the completion side, we are pretty efficient. We had a couple of wells last quarter where we left motors in the hole, but we have gone to drilling out all of our wells, and we have quit running motors on our drillouts. We now do everything with stick pipe in the Western Haynesville, which eliminates a lot of risk and does not add time. That is possible because of modern dissolvable plugs and technology. We are essentially washing to the bottom and occasionally drilling through a spot, but the overall risk is lower. We are pumping larger fracs. For most wells completed in the second quarter, we are either 25% or 50% higher proppant loading than before. We are seeing really good pressures at the rates we are flowing at initially, and we think the higher proppant loading will bear fruit in higher EURs. We have to wait to prove it out, of course. So for costs, I see drilling costs going down and completion costs increasing due to larger fracs. Overall D&C costs, depending on which factor weighs more, should be similar to or a little cheaper than where we have been, because drilling costs will come down with big-hole laterals while completion costs rise for larger fracs.
Our next question comes from Charles Meade with Johnson Rice. Your line is open.
Good morning, Jay, Roland, Daniel and the rest of your team at Comstock. Jay, maybe this is for you, maybe it is for Daniel. You have done a great job explaining why the big-hole design is helping on the drilling side. I am curious if you would offer any opinion on what it might ultimately mean for well productivity once you complete the well. With the larger internal diameter, you will have an easier time getting your fracs off; can you talk about what it might mean on the cost side of the completion and, importantly, on well productivity?
I think it will allow us to drill longer laterals on average, and the longer the lateral, the more toe stages and the more horsepower needed. Running the bigger pipe generally gives lower treating pressure because of lower pipe friction, which lets you get more rate and better frac efficiency, pump faster, and shorten pump time. Those things all help. The biggest difference for us has been on the drilling side. We beat expectations on the first big-hole well and now need to show repeatability on the second and third wells.
Well, like Daniel said, we do have a line of sight through drilling techniques we have implemented on these 50 wells and tweaking completion designs. The changes should materially drive down drilling cost and enhance well productivity. Charles, you have known us a long time; you are seeing the build-out of a major natural gas field. Every 90 days we provide updated results. We are 50 wells into it and pleased with where we are and where we are going. Everything is driven by demand for natural gas, inventory depletion, and our focus on drilling and completion spend rather than buying inventory. We want you to look at that and understand the opportunity. Thank you.
Got it. Thank you. If I could ask about these U-turn, or Horseshoe, wells in the legacy Haynesville: for the second quarter in a row now, your highest IP rate has come from a Horseshoe well in the legacy Haynesville. I believe part of that is because you have stranded single-section units in some of the best parts of the Haynesville that were developed early. Other than that, is there something else going on—maybe with your frac recipe—that is still breaking new ground as far as productivity in the legacy Haynesville with these wells?
We do not pump a different frac design on the Horseshoe wells; it is the same proppant and fluid loading we pump in the other wells. Execution has been pretty flawless. You cannot tell the difference when completing a Horseshoe if you do not know it is a Horseshoe well. The rotary steerable work we started a few quarters ago has helped a lot on Horseshoe wells because we can rotate while drilling the curve instead of sliding with a conventional assembly. That has shaved time off what we expected originally. A lot of the Horseshoe wells were in good curve areas because they were stranded, and they have performed well. All Horseshoe wells to date have been in Louisiana; we have drilled three Horseshoe wells in Texas, completed our first of those, and it is on flowback now, so we will see how those look on the next call.
Charles, the industry has advanced dramatically in lateral length and technology over the years. Rotary steerable and other technologies have opened up many new locations that were not economic before. What we are doing is applying that technology to the Western Haynesville. We think the demand drivers—LNG, data centers, and local power—will require another major gas field. We are trying to de-risk and deliver that. Thank you.
Thank you. Our next question comes from Kevin McCurdy with Pickering Energy Partners. Your line is open.
Hey, thanks for taking my question. I wanted to ask about production cadence. Last quarter you talked about the exit rate this year could bring you back to the peak levels experienced in early 2024. Is that still the case, or are there changes to your cadence?
Kevin, this is Ronald. Historically, we have said that we think fourth quarter can get back to where we were in the first half of 2024. We are still on track to get to that level. In terms of relative cadence between the third and fourth quarters, both quarters should grow by a similar amount sequentially, which you can back into via the guidance.
Thanks, Ronald. Then a different direction on my follow-up: some competitors have shown interest in the southern end of the Haynesville. You have acreage in Sabine Parish. What has your experience been drilling in that region and your thoughts on the extent of the Louisiana Haynesville?
We like that acreage down there and have drilled a few wells on the south end. The meat of our acreage is not really in that area, but we have a couple of Horseshoe wells planned later this year or early next year for the south end. The Bossier and Hazle zones have performed well down there, so we're not against it; it’s a matter of how it layers into the drill schedule and other opportunities.
Our next question comes from Jacob Roberts with TPH and Co. Your line is open.
Good morning. I wanted to start on leasing: with the increase to the overall Western Haynesville position by about 5,000 acres, can you speak about what is compelling about some of these smaller transactions relative to your overall position, how they fit into the program going forward, and what you look for in these types of transactions?
As we put together units in the Western Haynesville, we have leased a lot of large tracts and blocked up acreage well. There is a continual maintenance of picking up remaining acres before we want to drill the well. Part of that program is twofold: completing building out units—typically we end up with 100% of the well for the most part—and capturing extensional areas based on reprocessing seismic. We monitor and pick up gaps as leases become available; it is not very large acreage additions, but those cleanups matter.
When we lease to clean up acreage, mineral owners who see we have drilled 50 wells and expect many more are inclined to lease to us because they want a well drilled. On a quarterly basis we add a little acreage here and there to make the existing acreage better.
And about 2027: if you think of a nine-rig program and four frac crews continuing into next year, can you give a point of reference on growth rate? Also, if prices remain where they are and forward curves don't reflect a demand wave, might you hold back activity until demand is clearer?
We have been disappointed with gas prices this summer and will continue to watch that. We will look at our 2027 activity late in the year and base decisions on the view then. We would want to see stronger prices—especially ones we could hedge into—to support that activity into next year.
Our growth goal is to derisk the asset and be ready to respond when demand arrives. LNG demand growth is expected, and there's a lag between project sanction and gas demand. Much of our exposure in the Bossier is easier to develop and held by production, so we are positioning to respond quickly. We will continue what we've been doing to be ready.
Our next question comes from Noel Parks with Tuohy Brothers Investment Research. Your line is open.
Hi, good morning. I apologize if you already touched on this, but regarding the experimentation with motors that have better heat resistance: if you make a transition to those more widely, what might that look like in terms of cost or time savings?
We have been working with a vendor to make higher-temperature motors available. We expect to take delivery in the next two to three months and deploy them in wells. The benefit is staying on bottom longer because the elastomer in the motor is rated for higher temperature. Staying on bottom longer means longer runs, fewer trips, and fewer days to drill the well. Eliminating one trip can cut one to two days; eliminating two trips can cut four to five days. That is the potential time saving.
Daniel covered the expectations for motors. We are always focused on what will improve costs and time.
The big-hole lateral—8.5-inch bit versus 6.75-inch slim-hole—lets you circulate mud faster, keeping the hole cooler and helping tools last longer. Will the higher-temperature motor also be fitted for the big-hole motors? Also, thinking back a few years there was a wave of improvement around downhole tools; are there other similar improvements you expect in the next couple of years?
Yes, the higher-temperature elastomer can be used in the bigger motors for big-hole wells, and we get the same benefit. A few years ago we began using coated or insulated drill pipe, which reduced circulating temperatures by 20 to 30 degrees and made a big difference. We now use insulated drill pipe for big-hole laterals as well. The big-hole is the next step change to drive cost down. We expect to get higher-temperature motors in the next two to three months. Additionally, we have a 10,000-psi upgraded rig coming in October, which should increase drilling speed. We are in talks to upgrade a second rig to 10,000 psi and, if successful, all Western rigs would be 10,000 psi. On the frac side, we continue to evaluate a 20,000-horsepower frac fleet with partners; it is a significant capital investment and we're working through how to make it work for us.
Great. Thanks a lot.
Our next question comes from Carlos Escalante with Wolfe. Your line is open.
Hey, good morning, team. Thank you for taking my question today. Daniel, I would like to ask about the completion side and help parse through the headline D&C cost trend, particularly as you've been ramping up the pounds per foot on the proppant side and fracturing with tighter stages. Can you walk us through which batch of wells we should use as a proxy to think about your ultimate completion design? It feels like you are confident about larger fracs. Which wells across the last three to four quarters should we look to assess if larger fracs are meeting expectations on EURs?
All the wells we turned to sales in Q2 are the first batch we systematically increased proppant loading on. We did enlarge one earlier well, but Q2 was the first systemic ramp to larger proppant loading. Those wells have been on for two to three months since turning to sales in March. We pumped some at around 5,000 pounds per foot and some at 6,000 pounds per foot. It will take time to see how they decline, but initial results look good: flowing pressures and IP behaviors are promising. We are managing drawdown conservatively to maintain high flow and pressure.
To clarify: did you ramp proppant loading at the same time you started doing tighter frac stages, or were those independent?
They were independent. We adopted tighter cluster spacing and smaller stages last year while still pumping our standard frac design of about 4,000 pounds per foot. We maintained the smaller stage spacing as we increased proppant loading.
And regarding HBP (held-by-production) campaign effects: many of your initial leases were signed under different unitization and optimization parameters. Is it fair that because you are working on older leases you were constrained to drilling shorter laterals than you would choose if you were doing a greenfield, HBP-free optimization campaign?
Yes, the drilling program has been influenced by holding acreage and by lease age. You cannot always drill the most optimal place initially; you use the program to put leases into held-by-production status. Over time, that will shift and allow for more infill drilling, but that is the nature of the program.
Lateral length considerations reflect that we have not yet drilled large multiwell pads for infill development; we have been cautious, leaned into technology, managed debt, and focused on improving execution. Over time you will see cost benefits from pad development and greater efficiencies as the program matures.
Pad development and synergies will reduce overall costs compared to single-well development. Comparing to a mature legacy Haynesville where pads have been funded over years, the future costs in Western Haynesville should be significantly lower as we prove up and perfect drilling and completion design. Additionally, the reservoir pressures and formation quality support higher proppant fracs that we believe will yield larger EURs. We need time to prove that out, but early pressure data looks favorable.
To drive the point home: Dolly Jones big-hole success demonstrates the potential of the design. Sixth Street's investment in Pinnacle should also give confidence—those managers manage substantial capital and validated Pinnacle's value. Our infrastructure and location between Dallas, Houston and Austin are compelling for demand growth, and we're focused on not wasting capital. Thank you.
This concludes the question-and-answer session. I would now like to turn it back to Jay Allison for closing remarks.
They say that if you are worthy, the less you say, the less you have to be accountable for. So my closing is thank you for having your ears tuned to a definitely pure-play natural gas company. Thank you.
This concludes today's conference call. Thank you for participating. You may now disconnect.