Earnings Call Transcript - CRK Q3 2024

Operator, Operator

Good day, and thank you for standing by. Welcome to the Third Quarter 2024 Comstock Resources Earnings Call. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Jay Allison, Chairman and CEO

Perfect. And welcome everyone listening in. Welcome to the Comstock Resources third quarter 2024 financial and operating results conference call. You can view a slide presentation during or after this call by going through our website at www.comresources.com and downloading the quarterly results presentation. There you'll find a presentation entitled third quarter 2024 results. I am Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer and Ron Mills, our VP of Finance and Investor Relations. If you would please refer to slide 2 in our presentations 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 could be no assurance that such expectations will prove to be correct. If you would turn to slide 3, before we start going over this slide, I do want to make a few comments. On Tuesday, I was watching Bloomberg News and the headline was, 'Big Oil sees AI Boom Driving Crazy Demand for U.S. Natural Gas.' Now by the way, I love that word crazy. Then on Wednesday I read in the Journal, 'Wall Street' giants to make a $50 billion bet on AI and power projects with the quote, 'Gas is going to be at the forefront of this.' Natural gas can back up those intermittent renewables very nicely, and natural gas fired plants will be critical in supplying round the clock power to data centers. Now since those headlines came out on Tuesday and Wednesday, I know they're not trick or treat headlines. So today is Halloween everyone. So happy Halloween. It does make you smile a little bit having a pure natural gas company report results on Halloween. I told someone I was hoping tonight I'd see a kid in my front door dressed as a flame or either as a horseshoe. Either one's good with me. Anyhow, the good news or the treat for natural gas companies is that America and the world needs more natural gas in the very near future as demand for an additional 15 BCF of LNG feed gas gets nearer along with growth in power demand being driven by the growth in data centers and AI. The question is, where does Comstock fit into this puzzle and how did we position ourselves over the past four years to be a difference maker in the U.S. natural gas market? As one analyst stated on Monday, 'The producing basins are facing inventory exhaustion.' You either add inventory by M&A or exploratory drilling. Comstock has chosen four years ago to grow inventory through exploration in our new Western Haynesville play. Since 2020, we have secured 450,000 net acres in a Western Haynesville and we've drilled 18 wells over an area of 26 miles to give birth to a major natural gas field close to the LNG demand corridor, which could potentially add decades of additional drilling inventory. I told someone that it's like a dog chasing a car and catching it. That's what we did in Western Haynesville. We caught the 450,000 net acres and now we're learning how to drive the car or in our case develop the Western Haynesville well by well. The results to date look very, very promising. So the future looks very bright. In fact, today Dan Harrison, our COO, will report on our 13th Western Haynesville and give you cost per foot. And yes, number 13 is a lucky number for us today even on Halloween, that kind of makes you smile too. So on this Halloween day, we're thankful to be the treat as a corner of being is being turned for natural gas demand. So now let me go back to the presentation on slide 3. On slide 3 we summarize the highlights of the third quarter. Our financial results continue to be heavily impacted by the continued weak natural gas prices as our average realized gas price before hedging was $1.90 for the quarter. As a result, our oil and gas sales including hedging were $305 million in the quarter, and we generated cash flow from operations of $152 million or $0.52 per share in adjusted EBITDAX of $202 million. Our adjusted net loss was $0.17 per share for the quarter. Given the lower completion activity that was planned for this quarter, we had only eight operated wells turned to sale since the company's last update. These wells had an average initial production of 21 million cubic feet per day. One of those was our first horseshoe Haynesville well, which had an initial IP rate of 31 million per day, which Dan will talk about later. We're continuing to advance our Western Haynesville exploratory. Our acreage in the emerging play is now up to 453,881 net acres. Most importantly, we have substantially reduced the well cost in the Western Haynesville with our 13th well recently completed at a cost of approximately $2,814 per lateral foot. This was a single well with an 11,400 foot lateral, which did not get the cost savings that we see on a two well pad. The next five wells in the Western Haynesville are expected to be turned to sales in late 2024 to early 2025. I'll give it over to Roland to go to third quarter financial results. Roland?

Roland Burns, President and CFO

All right, thanks, Jay. On Slide 4, we cover our third quarter financial results. Our production in the third quarter averaged 1.4 Bcfe per day, which was 2% higher than the third quarter of 2023. Continued low natural gas prices resulted in our oil and gas sales in the quarter declining 3% to $305 million. EBITDAX for the quarter was $202 million and we generated $152 million of cash flow in the third quarter. We reported an adjusted loss of $49 million for the third quarter of $0.17 per share. Higher depreciation, depletion and amortization in the quarter really accounted for the loss. The higher amortization rate driving the increase in our DD&A was caused by a decrease in improved undeveloped reserves, which had to be determined under SEC rules based on the low natural gas prices we've had over the last 12 months. On slide 5, we cover our year-to-date financial results. Production in this period averaged 1.5 Bcfe per day, and that was 5% higher than the same period in 2023. Again, low natural gas prices caused our oil and gas sales in the first nine months of the year to decrease 7% to $919 million as compared to 2023. Our EBITDAX for the first nine months of this year is $598 million, and we generated $452 million of cash flow. We reported a net loss of $121 million for the first nine months of this year or $0.42 per share as compared to income of $105 million in the same period in 2023. On Slide 6, we break down our natural gas price realizations in the quarter. The quarterly NYMEX settlement price averaged $2.16 in the third quarter, and the average Henry Hub spot price averaged $2.09. Our realized gas price during the third quarter averaged $1.90, reflecting a $0.26 differential to the settlement price and a $0.23 differential to the reference price. In the third quarter, we were 28% hedged, which improved our realized gas price to $2.28. As we look ahead to the fourth quarter, we will be 50% hedged. On Slide 7, we detail our operating cost per Mcfe in our EBITDAX margin. Our operating cost per Mcfe averaged $0.77 in the third quarter, that's a $0.07 improvement from the second quarter rate, and our margin improved 67% in the third quarter as compared to 61% in the second quarter. A lot of that was driven by lower production and ad valorem taxes, which were down $0.05, reflecting a reduction in the statutory rate in Louisiana. Our lifting costs were also down $0.05 in the quarter. Our gathering costs were up $0.03 in the quarter, but this is solely due to some prior period adjustments from some of our transport agreements. So we expect to see that back to kind of normal rate in the fourth quarter. Our G&A costs were unchanged from the second quarter. On Slide 8, we recap our spending on our drilling and other development activity. We spent a total of $184 million on development activities in the third quarter. And for all of the first nine months of this year, we've drilled 23 or 18.6 net Haynesville wells and 12 or 11.1 closer well. We've also turned 41 or 35.9 net operated wells to sales so far this year that had an average IP rate of 24 million per day. Slide 9 recaps our capitalization at the end of the third quarter. We ended the quarter with $415 million of borrowings outstanding under our credit facility, giving us $3 billion of total debt, including our outstanding senior notes. Yesterday, our bank group unanimously reaffirmed our borrowing base of $2 billion, and our electric commitment still remains at $1.5 million under the bank credit facility. And given the extended period of low natural gas prices that we've had, our bank group approved an amendment to loosen the covenant leverage ratio that we have. The new leverage ratio under the amendment increases to less than 4 times through the first quarter of next year then steps back down to 3.75 times in the second quarter of 2025 and then to less than 3.5 times by the third quarter of 2025. At the end of the third quarter, we ended the quarter with $1.1 billion of liquidity. I'll now turn the call over to Dan to discuss the operations.

Daniel Harrison, Chief Operating Officer

Okay. Thanks, Roland. If you look over on Slide 10, this is an updated slide from our last call, which outlines the new development plan we have utilizing the horseshoe lateral concept. To test the concept, we have successfully drilled and completed our first single horseshoe well, the Sebastian 11 #5. This is located in DeSoto Parish, Louisiana and it's located in one of our isolated single section acreage blocks. We turned the well to sales early last week. We just recently reached an IP rate of 31 million cubic feet a day from a 9,382 foot completed lateral that is in the Haynesville Shale. Building upon this successful test, we will be pursuing additional horseshoe well projects in the future. The technology allows us to develop acreage that before presented more challenging economics by being limited to drilling short laterals. The section we have depicted on this slide represents a project we have scheduled for late next year. This section would have originally been developed by drilling 4,000, 5,000-foot laterals from 2 well pads with a $40 million capital cost. The same section will now be developed from a single 2-well pad drilling 2 horseshoe laterals with a $32 million capital cost. And this is based on the D&C cost of $1,740 a foot, and our recently completed Sebastian well costs came in slightly lower than this. The project will deliver cost savings of 23% or $8 million, which substantially improves all our key economic performance metrics. We expect the well performance from the horseshoe wells will match that of our regular 10,000-foot laterals. With this success, we have also optimized our drilling inventory by converting 57% of our short Haynesville locations to 64 future horseshoe locations. We're still in the process of evaluating our short Bossier locations for additional horseshoe view locations. On Slide 11 is our current drilling inventory as it stands at the end of the third quarter. Our total operated inventory now stands at 1,607 gross locations. And so 1,252 net locations, which equates to a 78% average working interest. The non-operated inventory now stands at 1,199 of those locations and 158 net locations, which represents a 28% average working interest. The drilling inventory split between Haynesville and Bossier locations is broken down into 4 different categories: bilateral length, the short laterals less than 5,000 feet, the medium laterals up to 25,000 and 8,500 feet. Our long laterals come in at 8,500 and 10,000 feet, and our extra-long laterals that go past 10,000 feet. In our gross operated inventory, we now have 180 short laterals, 331 medium laterals, 482 long laterals, and 614 extra-long laterals. The updated inventory numbers include the impact of identifying 64 horseshoe locations in the Haynesville Shale. Two-thirds or 68% of the gross operated inventory has laterals longer than 8,500 feet, and 38% of the gross operated inventory have laterals longer than 10,000 feet. The average lateral length now stands at 9,261 feet, and this is up slightly from our 9,077 feet, which we had at the end of the second quarter. This inventory provides us with over 30 years of future drilling locations based on this year's activity. On Slide 12 is the chart outlining our average lateral length drilled based on wells that we turned to sales. During the third quarter, we turned 11 wells to sales with an average length of 12,586. Individual lengths ranged from 8,912 feet to 15,303 feet. Our record longest laterals will still say is at 15,726 feet. All the wells we turned to sales during the third quarter had laterals longer than 8,500 feet. Furthermore, 9 of the 11 wells that turned to sales during the quarter were extra-long laterals that were over 10,000 feet. As we mentioned earlier, we did not turn to sales any wells on our Western Haynesville acreage during the third quarter. However, we do have 6 additional wells in the Western Haynesville that we plan to turn to sales by the end of the year or early January 2025. The first of these 6 wells was turned to sales last week, and it's currently being flow-tested. Looking ahead, we have several extra-long laterals slated to turn to sales over the remainder of the year, and we expect our average lateral length for all of 2024 will be approximately 10,100 feet on a total of 48 wells turned to sales. To recap on our long lateral activity to date, we've now drilled 109 wells with laterals longer than 10,000 feet, and we have drilled 40 wells with laterals over 14,000 feet. Slide 13 outlines our new well activity since we last provided the well results at the end of July. Since our last call, we have 8 new wells that have turned to sales. The individual IP rates on these range from 10 million cubic feet a day up to 31 million cubic feet a day with an average test rate of 21 million cubic feet a day. The average lateral weight was 12,391 feet with the individual laterals that range from 9,382 feet up to 15,272 feet. This list includes our first horseshoe well, the Sebastian 11 #5, turned to sales last week that achieved an IP rate of 31 million cubic feet a day. Recapping our activity levels, we're currently running 5 rigs and 2 frac crews, our second frac crew returned in late September following a 70-day frac holiday during the third quarter. We currently have 2 of the 5 rigs drilling in the Western Haynesville. We also have both of our frac fleets currently working in the Western Haynesville where we're in the process of fracking our first 2-well pads. Most of our pads will be completed in the fourth quarter and turn to sales at year-end. In addition to these 2 well pads, we also have 2 single wells that will turn to sales by year-end, which generates a total of 6 Western Haynesville wells turning to sales between now and year end. On Slide 14 is the summary of our D&C costs through the third quarter for our benchmark long lateral wells that are located on our core East Texas and North Louisiana acreage. This covers our wells with laterals greater than 8,500 feet long. During the quarter, all 11 wells that we turned to sales were located on our core East Texas, North Louisiana acreage; all 11 wells fell into our benchmark long-lateral group. We're now providing the drilling cost per foot based on the date the wells reached TD. This provides a better view of the current drilling environment and the growing cost environment and just to be better aligned with the timing of when we spend the drilling dollars. The completion cost per foot continues to use the turn to sales date. So in the third quarter, our drilling costs averaged $642 a foot. This is a 3% increase compared to the second quarter. Our third quarter completion costs came in at $776 per foot, which represents a 6% decrease compared to the second quarter. When we look out ahead to the next couple of quarters, we do see our D&C cost remaining flat or going slightly lower. I'll now turn the call back over to Jay to summarize the 2024 outlook.

Jay Allison, Chairman and CEO

Okay, Roland. Thank you, Dan. Thank you, if you would, I'll direct you to Slide 15, where we summarize our outlook for 2024. As we stated last quarter, we've taken a number of steps in response to the significantly low natural gas prices this year. During the first quarter, we released 2 of our operated drilling rigs, reducing our rig count to 5 rigs, and we also released 1 of our frac spreads, reducing our frac fleet to 2 spreads. We no longer have any long-term commitments for our pressure pumping services. With those steps, our 2024 CapEx is expected to be down 25% to 35% from the 2023 level. We suspended our quarterly dividend, saving approximately $140 million of dividend payments. In late March, our majority shareholder, Jerry Jones, invested an additional $100.5 million into the company through an equity private placement. Starting in late February, we have added significantly to our hedge position starting in the fourth quarter of 2024 and extending through the end of 2026. We're targeting a hedge level of 50% of our expected production level. In early April, we further enhanced our liquidity position with a $400 million senior notes offering. We are evaluating our planned activity level in 2025 based upon the outlook for natural gas demand and we'll adjust our drilling program as needed to respond to the natural gas prices. We'll continue to maintain our very strong financial liquidity, which totaled just under $1.1 billion at the end of the third quarter. Our industry-leading lowest cost structure is an asset in the current low natural gas price environment as our cost structure is substantially lower than the other public natural gas producers. We remain very focused on proving up our Western Haynesville play and continuing to add to our extensive acreage position in this exciting play. Our Western Haynesville acreage position totals over 450,000 net acres. We believe that we are building a great asset in the Western Haynesville that will be well-positioned to benefit from the substantial growth in demand for natural gas in a region that is on the horizon, driven by the growth in LNG exports that begins to show up in the second half of next year. I will now have Ron to provide some specific guidance for the rest of the year. Ron?

Ronald Mills, VP of Finance and Investor Relations

Thanks, Jay. On Slide 16, we provide our fourth quarter guidance. The fourth quarter production is expected to remain in the 1,325 to 1,375 million cubic feet per day range, which is down approximately 10% from the fourth quarter of 2023 as expected and as has been discussed on prior calls, that's related to the impact of the timing of dropping the 2 rigs late in the first quarter. The D&C CapEx guidance for the quarter is $225 million to $275 million due to the timing of bringing wells online. We now expect 43 net wells to be turned to sales in 2024 versus the original expectation of 38 to 39 wells when we provided our original guidance. Those wells are coming on at the very end of the year, so there's not much production impact, but we do bear the full brunt of that capital expenditure. We continue to anticipate leasing CapEx of $2 million to $5 million per quarter, and CapEx related to Pinnacle Gas Services, which is funded by our partner, Quantum, is expected to be $50 million to $90 million during the quarter. On the cost side, LOE is expected to average $0.24 to $0.28 per Mcfe, while GTC costs are expected to average $0.34 to $0.40 per Mcfe. Production and ad valorem taxes are expected to average $0.14 to $0.18, while the DD&A is expected to remain in the $1.40 to $1.55 range. G&A side, cash G&A remains in the $6 million to $8 million per quarter range with about $3 million to $4 million of noncash G&A expenses expected. With the current SOFA rates in the April notes offering, we now anticipate our cash interest expense to be $54 million to $56 million during the quarter, and our noncash interest in the quarter will be $3 million to $4 million. Effective tax rate remains in the 22% to 25% range, and we still expect to defer roughly almost 100% of those taxes. I'll now turn the call back over to Jill to answer questions.

Operator, Operator

The first question comes from an unnamed analyst at Bank of America. Please go ahead; your line is open.

Unnamed Analyst, Analyst

Hey good morning guys. Thanks for getting me on. I guess I'd like to start with the elephant in the room, which is the planned outspend for 4Q. To bring it up a little bit, I think we're all pleased to see that you guys have the waiver. But I think some of the market to that tripping the coming in will lead you back to more of a free cash priority. From our perspective, I think we get it, we see you trying to stabilize production and division for maybe a better 2025. Just hoping that you can kind of talk through your motivations to outspend through this soft pricing and then maybe articulate your plans to manage the balance sheet in 2025?

Roland Burns, President and CFO

Yes, that's a good question. When we initially developed the plan and began executing it, prices were slightly higher than anticipated, which we believed would cover our projected expenditures for this year. The only reason for a modest increase in expenditure is that drilling days in the Western Haynesville have been quicker, leading to some of the completion work initially expected to extend into 2025 being completed within this quarter. If you consider a longer timeframe rather than just individual quarters, there hasn't really been much change in our overall plans; it’s mainly a matter of how we report costs. In 2025, our aim is to balance the capital invested with the cash flow generated from our operations, especially with a higher hedge level, which should help reduce the risks associated with gas prices.

Unnamed Analyst, Analyst

Got it. So it's really timing and your plan to keep activity continue to progress forward. Maybe my next question is really on the Western Haynesville. Maybe this is for Dan. Cost per foot on the Hodges is better than our high-end estimate. And it's just one well. You've got a 2-well pad coming up, so maybe those costs are getting better. Maybe I have been aside if you can discuss those drilling costs, we'll take that. But more broadly, with the amount of wells that you have online, the data points on cost, maybe you have an event path ahead. When can we expect a more fulsome update on the Western Haynesville in 2025?

Daniel Harrison, Chief Operating Officer

We expect to provide more detailed information on the Western Haynesville early next year during our next call. You’re correct that the 2,814-foot depth milestone was achieved with a single well. The well we drilled recently, which has been labeled the important one, was turned to sales and took only 51 days to reach total depth. This marks a significant improvement compared to a few years ago when we began drilling these wells in 70 to 80 days. We’ve made impressive progress, and we're still refining a few days off our drilling time. The execution on the Hodges #1 well was very successful, with all phases of operations going smoothly. We currently have favorable frac pricing, and the well completion also performed well. A key factor in our success is the lateral length, which exceeds 11,400 feet. This is crucial for our cost per foot calculations. Typically, our cost targets are normalized to a 10,000-foot lateral, so lateral lengths between 11,000 to 12,000 feet will yield better costs per foot, while shorter laterals around 8,500 to 9,000 feet will exhibit higher costs.

Unnamed Analyst, Analyst

Thanks for that. We are watching with interest guys.

Operator, Operator

Thank you. One moment for our next question. The next question comes from Carlos Escalante with Wolfe Research. Go ahead, Carlos. Your line is open.

Carlos Escalante, Analyst

Good morning. Thank you for taking my call. I'd like to start with the horseshoe results because they are certainly encouraging, and I believe this is what the investment community wants to see. However, we need to understand how this translates into free cash flow generation. My question is regarding the geographical spread of the 64 locations you believe are candidates for this across your Haynesville locations, considering that not all acreage is created equal. Thank you.

Daniel Harrison, Chief Operating Officer

Good question. There are 64 locations just in the Haynesville, and we are very pleased with the results of the Sebastian well. We didn’t encounter any issues while drilling the well. It took maybe two extra days compared to just drilling a straight 10,000-foot lateral, but everything went smoothly. The fracking process went well; if you didn’t know it was a horseshoe well, you wouldn’t notice any difference between fracking the straight 10,000-foot lateral and the horseshoe. The well performed excellently in terms of fracking, so we’re very excited about that. Regarding the distribution of the locations, they are quite evenly spread across the acreage position from south to north within the basin. We have them in the 16 B per thousand and the type curve areas up to the 2. So, the summary is that they are spread out across all the acreage and not concentrated in any specific area.

Carlos Escalante, Analyst

Sure. That certainly helps. I guess your answer provided me with another question, if you will, on that same topic. And maybe this is a bit too early because the Western Haynesville is still, by all means, an exploration play. But do you feel like you will come across the geometry, lease line issues that you have in the Haynesville and the traditional Haynesville in the Western Haynesville? And then just to finish up my second question, which is also in the Western Haynesville. What do you expect to be the average lateral length for your program going forward, bearing in mind that you have a hard reservoir and it's more difficult to drill?

Daniel Harrison, Chief Operating Officer

I think your first question pertains to lease lines in the Western Haynesville compared to Louisiana. The main difference is that in Louisiana, we work with square mile sections, where each section is treated as a unit. This means we typically drill well lengths of 5,000 to 10,000 feet, 15,000 feet, or, as we progressed, 7,500-foot laterals. We can also turn the wellbore and use horseshoe techniques. In this case, lease lines follow the section lines. Conversely, in Texas, there are no strict sections. Instead, abstract surveys allow for more flexible and customized unit construction, resulting in laterals that can have varying lengths, such as 5,000 to 10,000 feet and even other lengths like 9, 8, 6,500, or 11,500 feet. In Louisiana, we are restricted to specific lengths of 5,000, 10,000, 15,000, or 7,500 feet. This highlights the differences in drilling practices between the two states. Regarding the average lateral length in the Western Haynesville, we’re looking at around 10,000 feet on average, as we have better temperature management at the bottom. The major challenge is not temperature but minor faults and geo hazards in certain areas that require us to stop drilling. We aim to drill the longest laterals possible as we hold acreage, and I believe that 10,000 feet is a solid target for our average length moving forward. We've already drilled a maximum of 12,700 feet, and our shortest lateral is about 700 to 800 feet. We are successfully drilling these longer laterals, with limitations mainly due to hazards or other factors.

Carlos Escalante, Analyst

Wonderful. Thank you guys.

Operator, Operator

Thank you. Stand by for our next question. The next question comes from Charles Meade with Johnson Rice. Go ahead, Charles. Your line is open.

Charles Meade, Analyst

Good morning, Jay, Roland and the whole Comstock team there. I want to go back to the Sebastian well. You can't help but notice that it's the shortest lateral with the highest IP on the quarter. So I know it's early, but do you think this is just luck of the draw? Or is there something else going on here perhaps?

Daniel Harrison, Chief Operating Officer

It's not just a matter of chance. I believe all the horseshoe drilling we do in Louisiana will generally have similar lateral lengths unless we eventually decide to attempt a well that reaches about 7,500 feet in depth and back. That's a long way off, and we might be getting ahead of ourselves. However, this performance aligns with what we expect from a well in this area based on the oil we drill on this land. So, we are not surprised at all.

Charles Meade, Analyst

Understood. It's great to have your insights on this. Regarding the Western Haynesville, you've mentioned this previously. I'm pleased to hear about the progress made with Hodge. As you consider replicating that success, aside from the lateral length, what specific aspects of the well construction and completion process will you prioritize to achieve a similar dollar per foot efficiency?

Daniel Harrison, Chief Operating Officer

I believe we need to recognize that we have become more consistent in our performance. Initially, we experienced some inconsistency in our early wells, but now we are achieving much more reliable results. We expect a cost reduction of 5% to 7% when using pad drilling compared to drilling a single well pad. This is a solid figure for a single well pad. The well with the longer lateral that I mentioned earlier contributes to better cost efficiency. As we increase the lateral length beyond 10,000 feet, the costs tend to decrease slightly. In this case, the well was 11,400 feet. If it had been a 9,000-foot lateral, the cost per foot would have been higher, while at 12,000 feet, it would have been lower. With pad drilling and this level of performance, we anticipate costs will be lower than the current $2,800 per foot.

Charles Meade, Analyst

That’s great. Thank you.

Operator, Operator

Thank you. Stand by for our next question. The next question comes from Jacob Roberts with TPH & Co. Jacob, go ahead. Your line is open.

Jacob Roberts, Analyst

Good morning. I believe you've all previously contemplated adding a few rigs next year. And I understand it might be a little bit early to talk about 2025. But given where the commodity price is today, how are you thinking about the timing of those rig adds, if at all? And then maybe as well, if I could tack on what you might consider a balanced program in terms of those rigs at current commodity prices?

Roland Burns, President and CFO

It's an important question. It's somewhat early to tell since we will be closely monitoring the gas market, including whether we experience a winter, which will greatly influence gas prices in the first half of 2025. We anticipate an increase in demand in the latter half of 2025. This is a key factor as we decide when to bring back the two rigs we paused in the first quarter of this year. We have significant flexibility regarding the timing of that decision, and we believe we can align our services as needed, with several options available at short notice. We want to be responsive to whatever the market conditions are in 2025. Our goal is to increase our hedge percentage to about 50% in 2025; we're currently around 40% hedged. There’s some work ahead, but this strategy should help us perform better than this year, where we were just under 30% hedged for the first three quarters.

Jacob Roberts, Analyst

Thanks. I appreciate the color. Maybe if we could look at the Western Haynesville and particularly the midstream. Can you frame the current runway you have what the Q2 2025 addition will add to that runway maybe in terms of quarters or wells that you ultimately see being able to handle being able to be handled?

Ronald Mills, VP of Finance and Investor Relations

Yes, that's a good question. With the six wells being added to our Pinnacle system, we expect to reach a significant rate by January. We will start to approach the treating capacity—though not the pipeline capacity—of our Bethel treating plant. We have sufficient backup capacity to offload to several other midstream companies with which we have contracted arrangements at favorable rates. While we could pursue that option, our preference is to utilize our own facility. A significant portion of our expenditures now, particularly in the fourth quarter and early next year, is aimed at opening a new gas treating plant at Marquee, which will enhance our capacity in the Western Haynesville area by adding 400 million a day of treating capacity. This will enable us to manage growth effectively. Once this facility is operational, we will have the capability to offload and process according to our arrangements, ensuring we won't face any limitations regarding our production levels. As we assess the program and consider adding more rigs, we will also evaluate the need for expanding our capacity for the play.

Jacob Roberts, Analyst

Great. Appreciate the time.

Operator, Operator

Thank you. Stand by for our next question. The next question comes from Greta Droshky with Goldman Sachs. Greta, go ahead. Your line is open.

Unnamed Analyst, Analyst

Hi, good morning and thank you for taking my question. I was just wondering if you could spend a bit more time on the Horseshoe wells. And the benefits you're realizing there. Is there a proportion of your overall operations that you hope to apply this technique to over time? And do you see potential for any upside to your 64 horseshoe locations that you've outlined? Thank you.

Daniel Harrison, Chief Operating Officer

Good question. We definitely see potential for more locations to be converted. The 64 we've converted so far is only on the Haynesville side, and we're still working through the Bossier. We expect to have numbers on that in the first quarter. Regarding the horseshoe developments, this news is quite new, and we intend to pursue more in our drilling program. We have several things prepared, but getting drill-ready takes time and planning. Our next project is a single horseshoe well coming up early next summer. We also have a 2-well pad project planned for later next year and a triple well pad set for 2026. We are pleased with the results, but it's challenging to fast-track additional wells into our existing drilling program without advance notice. However, as we gather more data on this well, there's a possibility that we might incorporate more into our program with some adjustments, which will require effort.

Jay Allison, Chairman and CEO

My comment would be that we always prioritize our inventory across our 1,400 locations. The horseshoe will now be expedited to the forefront, as Dan mentioned. This is a positive development based on our recent results from this challenging well. Additionally, we may have the same number or even more in the Bossier as we continue to integrate that into the first quarter of 2025.

Roland Burns, President and CFO

Some indirect benefits from the horseshoe, particularly as we deplete the Bossier inventory in our reserves, will lead to significantly improved economic outcomes. Even at low prices, some of these can be very economical. We expect the internal rates of return for the horseshoe wells to be three times better than that of a short lateral Haynesville well, as noted by Dan Harrison. This makes much more of our inventory economically viable at lower gas prices. Therefore, you will see an impact that allows us to classify a larger portion of our inventory as proved undeveloped reserves.

Daniel Harrison, Chief Operating Officer

Yes. I think I didn't really answer that part of your question. So I mean, as far as the performance versus the single 500, our return rate is basically it triples the return on the wells. Our payouts will be less than half. If you just look at the 2 single 500 versus the horseshoe, we're going to generate $5.5 million to $6 million additional PV-10 value. And so pretty substantial.

Unnamed Analyst, Analyst

That's really helpful. And then my second question is I was wondering if you could speak about the outlook for M&A in the Haynesville. Do you expect consolidation to continue more broadly? And do you see opportunities for bolt-on M&A either in the Western or legacy Haynesville for Comstock from here?

Daniel Harrison, Chief Operating Officer

We are actively monitoring opportunities, particularly in the Western Haynesville. We've partnered with various companies interested in shallow and existing production while acquiring deep rights and securing acreage held by production. This area presents numerous opportunities for us, especially as mature older vertical wells are being sold by larger companies. We are engaged in the M&A landscape, and we anticipate that private operators will continue to seek divestment. Over the next several years, we expect these private companies to consolidate. As gas prices reach more favorable levels, we believe this could spark renewed activity in the market.

Unnamed Analyst, Analyst

Thanks, all of you. Thank you.

Operator, Operator

Thank you. One moment for our next question. The next question comes from Noel Parks with Tuohy Brothers Investment Research. Go ahead, your line is open.

Noel Parks, Analyst

Hi, good morning. Just had a couple. I was just wondering, you mentioned it being important to avoid faulting in the Western Haynesville. I was wondering to what degree you can anticipate those, I don't know if it's seismic or legacy penetrations or anything. So just curious in how you're handling that.

Daniel Harrison, Chief Operating Officer

We have 3D seismic data covering almost all of our acreage, which allows us to effectively map and identify our resources. Therefore, we don't see this as a concern. It plays a crucial role in our planning for development, but we have reliable 3D data, giving us a clear understanding of the area.

Noel Parks, Analyst

Thank you. I have a macro-level question. I heard a gas producer confirm a point you've mentioned before, which is that prolonged lower natural gas prices and reduced activity levels will likely lead to a more challenging recovery in industry activity. This could result in higher peaking gas prices when they return. Considering we've completed another quarter and some areas are performing better as we approach winter, I'm curious about your thoughts on this and how you see a potentially mild winter affecting the peak prices.

Roland Burns, President and CFO

That's an excellent question. The natural gas industry faces the challenge of significant demand on the horizon that arrives in large increments, but it's not present at the moment. Therefore, near-term gas prices will primarily depend on the demand for heating during the winter, and we need to see how that unfolds. The first half of 2025 will be closely linked to this winter, though we have two factors working in our favor. Firstly, there is a new demand starting on the LNG side, which positions us well even at current high rates. Secondly, the rig count is quite low, leading to production declines that will help tighten supply. As we’ve observed at Comstock, despite reducing our activity in the first quarter, we will really start to see the decline manifest only in the fourth quarter. We were early in scaling back activity in the Haynesville, and many private operators followed suit a few months later; thus, we can expect the first quarter to show a significant drop in activity there. This situation should help us balance supply and demand compared to last year, which had high activity levels and a warm winter. Those two factors contributed to the significant drop in gas prices we've experienced this year. Going forward, I anticipate a more volatile gas market, with price fluctuations serving as a balancing mechanism. If there is excess gas, prices will drop significantly; if there is a shortage, prices will rise sharply. I expect considerable volatility in 2025 as various factors interact.

Jay Allison, Chairman and CEO

And then, Noel, I comment on the defaulting question. I mean, we have major control points for almost all of our 450,000 net acres. I mean, we do have those points. And as Dan said, we've got 3D seismic on the majority of it. And if you look at M&A, a lot of M&A was done at $4 to $5 gas prices and the Holy Grail is inventory you typically do M&A or inventory ever now in its size, if you're small, but a lot of the M&A is inventory. The Holy Grail is inventory. So I think what we were able to do, we were able to go take an old gas field, which is now we call the Western Haynesville, we went deeper, just like we did in the core of the Haynesville/Bossier. And we figured out that technically that we can drill to complete these wells and make it competitive with our core. So it's all about the right geographic spot it's about the right drill bit performance is about the right EUR. And then all of a sudden, you throw in our horseshoe that makes it a little bit more exciting because, as Dan and Roland said, the IRR on the horseshoes is 3 times better than your typical Haynesville well. So then you get to the banks, the 17 banks looking at us and they look at the whole company and they look at the future, and that's why we had unanimous approval. It all makes a lot of sense. Just to your point, you have to weather this storm in order to be there when the broad light and sun comes back out, and we are more than well-positioned to do that.

Operator, Operator

Thank you. One moment for our next question. Next question comes from Bertrand Donnes with Truist. Please go ahead. Your line is open.

Bertrand Donnes, Analyst

Hey team. I wanted to follow up on the rig count discussion. You did a great job notifying your rigs late last year to have them dropped by the end of the first quarter. It seems like you have quite a bit of flexibility there. Do you have an updated estimate on that? How many months would it take for you to drop or pick up rigs? And logistically, do you have to do it around December, or is it just as easy to do it in the summer or fall?

Roland Burns, President and CFO

Yes, there's no room time frame. Typically, we've got about half the rigs that are in our fleet that really just require a 45-day notice. So we have to plan around that. And then obviously, logistics of moving the rig out. Obviously, you're not going to just pull it out in the middle of a project or a middle of a multi-well pad. So it's really all about planning for it. So that's obviously something we're looking at very hard as we're pondering our 2025 budget in the right activity level and kind of see how things play out. But it's typically December when we really make these final decisions like we did last year and then hopefully have a good plan to get it in place quickly like we're able to do for the 2024 year.

Jay Allison, Chairman and CEO

The one thing that we've tried to do is we try to have all of our rigs be capable of drilling in the Western Haynesville. So even if they're drilling in the legacy area, we want them to be qualified, if you need to move them over to the Western Haynesville.

Bertrand Donnes, Analyst

That makes sense. And then switching gears to the land leasing program. It seems to continue to be strong. It seems like every time you think you have an idea of how much is out there, you keep finding more attractive opportunities. Is that because of the movement in gas prices? Or is the leasing team just kind of hitting their stride? Or is your view on the long-term value changing? Just why do you keep surprising to the upside on that?

Jay Allison, Chairman and CEO

Well, if you spent 4 years looking at 3D and at long and well results, and you have an area kind of like I said, it's like we were chasing this big footprint, and we actually caught it. So if there's a little bit extra out there, I mean, you keep your land group busy to clean up around where you're already leased. If there's anything else that you would need to add to expand a little bit. But I'd give you is 90% of our leasing program is in a rearview mirror. And I think if you look at our balance sheet, the debt that we've incurred, that's like a big M&A event. I mean, we have acquired the acreage. We're now drilling it. We control the midstream with Pinnacle and you see the well costs are coming down. And as I said, the Holy Grail is inventory. If we've got 14 other locations, the majority of those in our legacy, I mean just think of the upside they would have on the 450,000 net acres in the Western Haynesville. That is the goal. So we just keep cleaning it up. But you shouldn't expect any quarter where we spend this $50 million, $100 million like we had done in the past. Those days are behind us. And the reason we were successful at acquiring that acreage is because gas was low. Nobody was out there doing it.

Bertrand Donnes, Analyst

Very well said. And then I just wanted to clarify something. I think I heard a triple horseshoe pad in 2026. Is that 3 horseshoe wells? Or is that 3 sets of 2 horseshoe wells for a total of 6? Thanks guys.

Daniel Harrison, Chief Operating Officer

So that is 3 horseshoe wells, which would be prior to that would have been 6, 5000-foot laterals.

Operator, Operator

Thank you. One moment for our next question. The next question comes from Geoff Jay with Daniel Energy Partners. Please go ahead. Your line is open.

Geoff Jay, Analyst

Hey everyone. I appreciate you taking the questions. Quick question from me. Looking at the Horseshoe drilling and completing cost of about $1,700 per foot compared to traditional laterals of that length at around $1,400 to $1,500. Is there any reason why, as you gain more experience with these, the costs couldn't converge? Or is there something inherent to horseshoe drilling that will always keep it slightly more expensive? Thank you.

Daniel Harrison, Chief Operating Officer

On the completion side, there isn't really an increase in cost. If you execute well, the only expense comes from making a 180-degree turn. Comparing that distance to drilling straight, it will take longer to drill because you are constantly sliding and turning. Since we are using conventional tools, this will add an extra day or two, and that's the main difference.

Roland Burns, President and CFO

Potentially after that number that's kind of reported on that slot. So I think that's a fairly conservative estimate too.

Daniel Harrison, Chief Operating Officer

It is. We previously projected this before drilling the Sebastian well. Currently, we expect the Sebastian well to come in slightly under 1,700 feet, while we had initially modeled it at 1,740 feet as shown in this slide deck.

Geoff Jay, Analyst

Got it. Thank you guys.

Daniel Harrison, Chief Operating Officer

And that was a single. I mean, that's a single horse you well. So really, if you do 2 horsewells, you get that 5% to 7% additional savings from pad drilling, really, that were, say, 1,680 a foot on the Sebastian, if you do a 2-well pad, we should be able to drop that cost even lower.

Operator, Operator

Thank you. One moment for our last question. The question comes from the line of Paul Diamond with Citi. Go ahead. Your line is open.

Paul Diamond, Analyst

Thank you good morning. Thanks for taking the call. Just a quick question for you on the 2025 hedging book. It's currently breaking down pretty evenly per quarter and with the curve currently sitting at around low 3s. I guess how do you guys think about the timing and opportunity of kind of trenching in those last little bit to bring you up to the 50% target?

Roland Burns, President and CFO

We will work diligently to reach the $0.50 target. That's our goal, and we will make some adjustments after the third quarter. Gas prices have been weaker recently, so it's important to identify the right opportunities. We have the right structures in place to do this. While our production next year may not be evenly distributed, it will likely be more concentrated in the latter half of the year. This gives us a chance to focus on the latter part of 2025 to meet our objectives when pricing is expected to be stronger.

Jay Allison, Chairman and CEO

I think what we do, we advertise to you whether you're a bank or a bondholder, an equity owner analysts that our goal if that window opens up before we can hedge 50%, that's our goal and we'll be leaning into that window. So...

Paul Diamond, Analyst

Understood. I appreciate the clarity. Dan, I have another quick question. You mentioned the 57% conversion of Haynesville locations to horseshoe. I'm curious about the status of the remaining 43%. Have those locations been rolled out, or are they still in the evaluation stage?

Daniel Harrison, Chief Operating Officer

They are always under evaluation, but we can’t convert all of them to horseshoe wells because certain conditions need to be met for the conversion. First, you need to have two sticks together. In many places, we only have one stick, which means we can’t do anything with that. Additionally, a lot of this is on isolated sections where we still have some remaining sticks, often in areas that are mostly developed, leaving a few sticks for infill. The spacing also needs to be appropriate; you cannot have two sticks on opposite sides of the section that are too far apart to achieve the horseshoe configuration. Considering all of these factors, we ended up converting just 57% of that inventory.

Paul Diamond, Analyst

Got it. So it would be a reasonable read-through that you probably run into similar types of issues in the Bossier acreage as well?

Daniel Harrison, Chief Operating Officer

That would be correct. And on the Bossier side, if you just look at the acreage and you lay out nothing but Bossier sticks, we've got a little bit more of a clean slate to work with, obviously, because it's not as drilled up as the Haynesville. So we'll still have a lot of ability to drill the long laterals in the Bossier whereas in the Haynesville, we've got a lot of those drilled and some of these horses are connecting the short. We skipped over and then drill the short laterals, and we were doing the development because just because of the economics. And so now that we can come back and you've got 2 of them there, you can hook them up. So maybe in the future, we get a little bit more comfortable with maybe how wide we can space the horseshoe. We can maybe convert a few. We just need to get a little bit further down the road on what our abilities are going to be.

Paul Diamond, Analyst

Got it. Appreciate the color.

Operator, Operator

Thank you. I'm showing no further questions at this time. I would now like to turn it back to Jay Allison for closing remarks.

Jay Allison, Chairman and CEO

First of all, I want to thank everybody for staying on the line for a little over an hour. With natural gas prices ranging between $1.65 and $1.90 for the last 6 months, it's a difficult time for pure natural gas company. That's just the fact. But what happens in those months really tests our resolve, I want to acknowledge three groups over the past 6 months that consistently have stood for first our 255 employees who create the exceptional results in both our legacy and Western Haynesville area. Second, our 17 banks we reaffirmed our $2 billion borrowing base and gave us unanimous approval on our bank amendment to loosen the leverage covenants. Third, the Jones family through in the month of August made open market purchases of 13.5 million shares of our stock for $138 million. I want to thank each of you as well as our bond and our equity owners. I can assure you we are on the exact right path to be positioned for the growth in natural gas demand that is just around the corner. Thank you for your time.

Operator, Operator

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.