Good morning, everyone. In Frisco, Texas, this morning, it's 34 degrees. The Texas Rangers took a lead in the World Series, and I saw natural gas prices were up about $0.20 this morning. So we're all smiles here. We started out the day the right way. The world of natural gas is something that is a big part of our business. Reported profitable third quarter with a realized gas price of only $2.41 with only 18% of our gas hedged highlights our extremely low operating cost structure and our high margins. The 18 net operated wells returned to sales since our last update on our extensive Haynesville/Bossier acreage position continued to deliver solid results from our legacy area as well as the emerging Western Haynesville. The 2 Western Haynesville wells we recently turned to sales were 'top-of-the-class' wells as were the other 5 that we turned to sell starting with our Western Haynesville well, the Circle M, which started production in April of 2022. And make no mistake about it, we're extremely pleased with the results of all the Western Haynesville wells we have turned to sell so far. This year, we are focused on proving up the Western Haynesville and continuing to build our extensive acreage position. During this time of weak natural gas prices, we're providing a dividend to our stakeholders, holding our legacy production steady while being accountable to our bank lending group who have just reaffirmed our $2 billion borrowing base and proving up a much-needed new resource near the expanding LNG export facilities along the Texas and Louisiana Gulf Coast. A major step in the development of our Western Haynesville play is finding the right partner for the midstream build-out needed to support our Western Haynesville drilling program, and we are excited to partner with Quantum Capital Solutions to that end. We want to publicly thank them for entering into this new adventure with us. If you'll go to the main slides, we welcome you to the Comstock Resources third quarter 2023 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com or downloading the quarterly results presentation. There, you'll find a presentation titled 'Third Quarter 2023 results'. I am Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our President and CFO; Dan Harrison, our COO; and Ron Mills, our VP of Finance and Investor Relations. If you go to Slide 2, please refer to Slide 2 in our presentations and note that our discussions today 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 to be correct. Now if you'll flip to Slide 3. What we'll do is summarize the highlights of the third quarter. The financial results were heavily impacted by the continued low natural gas prices we realized in the quarter. Oil and gas sales, including hedging were $316 million in the quarter. We generated cash flow from operations of $167 million or $0.60 per share and adjusted EBITDAX was $209 million. Our adjusted net income was $0.04 for the quarter. We continue to have strong results from our drilling program. We drilled 13 or 10.2 net successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 11,644 feet. Since the last conference call, we've connected 21 or 18.1 net operated wells to sales with an average initial production rate of 29 million cubic feet per day. We're having great success in our Western Haynesville exploratory play. Our sixth and seventh wells were recently turned to sales with strong initial production rates, both of which were drilled in the Bossier shale. We recently entered into a new venture with Quantum Capital Solutions to fund the midstream build-out to support our Western Haynesville drilling program, which I'll expand on the next slide. If everyone would turn to Slide 4, this visibly shows our Bethel plant, which is part of the Pinnacle gathering and treating system we acquired last year. Pinnacle combined with our processing in the area will allow us to grow our Western Haynesville production up to 500 million cubic feet per day. Given how prolific these wells have been, we see running out of capacity in this area by 2025. We're excited to partner with Quantum Capital Solutions, an affiliate of Quantum Capital Group to build out this system to handle future growth. To that effect, we have set up a midstream partnership to build out the system to increase the capacity fourfold, and Pinnacle will contribute to that partnership, while QL will contribute 100% of the capital required, up to $300 million, for the build-out of the gathering and treating system. We'll operate the partnership, which will be called Pinnacle Gas Services and will direct its activities. Quantum will receive a preferred return and 80% of distributions until the investment hurdle is achieved, and then that reduces to 30%. I'll now turn it over to Roland to cover the third quarter financial results.

All right. Thanks, Jay. On Slide 5, we covered the third quarter financial results. Our production in the third quarter was $1.4 Bcfe per day, which was 1% higher as compared to the third quarter of last year and 3% higher than the second quarter. Low natural gas prices significantly impacted our oil and gas sales in the quarter, which came in at $316 million, which is 54% lower than the third quarter of 2022. EBITDAX was $209 million, and we generated $167 million of cash flow during the quarter. We reported adjusted net income of $12 million for the third quarter as compared to only $1 million in the second quarter of this year and then $326 million in the third quarter of last year. Slide 6, we have our financial results for the first 9 months of this year. Production for the first 9 months averaged 1.4 Bcfe per day, which is 4% higher as compared to the same period in 2022. Oil and gas sales in the first 9 months of this year totaled $991 million, which is 42% lower than last year's sales in the same period and EBITDAX was $685 million, and we generated $568 million of cash flow for the first 3 quarters of this year. We reported adjusted net income of $105 million for the first 3 quarters of this year as compared to $735 million for the same period in '22. On Slide 7, we detail our natural gas price realizations that we had in the third quarter. The quarterly NYMEX settlement price in the third quarter averaged $2.55. It was very close to the average spot price in the quarter, which averaged $2.58. Our realized gas price during the third quarter averaged $2.33, reflecting that $0.22 differential to the settlement price and a $0.23 differential to the reference price. The differential this quarter returned to more normal levels due to improvements in the Houston Ship Channel and Katy Hub prices following the restart of the Freeport LNG facility. In the third quarter, we were 18% hedged, which improved our realized gas price to $2.41. We've been using some of our excess transportation in the Haynesville to buy and resell third-party gas. We generated about $2.5 million in profits from this activity, which improved our average gas price realization by another $0.02. On Slide 8, we detail our operating cost per Mcfe produced in our EBITDAX margin. Our operating cost averaged $0.85 per Mcfe in the third quarter. It's 1% higher than our second quarter rate. The increased unit costs relate to higher production taxes and higher ad valorem taxes imposed in the state of Louisiana. Our gathering costs were flat this quarter at $0.36 and our other lifting costs were 3% lower than the second quarter rate at $0.24. Our production in ad valorem taxes increased $0.05 this quarter compared to the second quarter level. G&A came at $0.05 per Mcfe. That was $0.01 lower than the rate we had in the second quarter. And our EBITDAX margin after hedging came in at 65% in the third quarter as compared to 63% in the second quarter of this year. On Slide 9, we recap our spending on drilling and other development activity for the first 9 months of this year. So far, we spent $958 million on our development activities, including $919 million on our operated Haynesville and Bossier shale drilling program. Spending on other development activity has totaled $38 million so far this year. In the first 9 months of this year, we drilled 52 wells or 41.3 wells net to our interest in our operated drilling program, and we've turned 57 or 43 net operated wells to sales. The wells we turned to sales had an average IP rate of 25 million cubic feet per day. On Slide 10, we recap our balance sheet at the end of the third quarter. We ended the quarter with $345 million of borrowings outstanding under our credit facility, giving us a total of $2.5 billion in total debt. Our $2 billion borrowing base was recently reaffirmed by our bank group this month, and we ended the third quarter with financial liquidity of almost $1.2 billion.

Okay. Thank you, Roland. So Slide 11 is a breakdown of our current drilling inventory at the end of the third quarter. The drilling inventory split between the Haynesville and the Bossier and is divided into 4 categories: short laterals that are up to 5,000 feet; medium laterals that run from 5,000 to 8,000 feet; our long laterals at 8,000 to 11,000 feet; and our extra long laterals, beyond 11,000. The total operated inventory currently stands at 1,760 gross locations in 1,338 net locations. This equates to a 76% average working interest across the operated inventory. Our non-operated inventory has 1,265 gross locations and 153 net locations, which represents a 12% average working interest across the non-op inventory. Breaking down our gross operated inventory, we have 307 short laterals, 286 medium laterals, 712 long laterals, and 455 extra long laterals. The gross operated inventory is split 52% in the Haynesville and 48% in the Bossier. 26% of the gross operated inventory for the 455 locations have the lateral lengths greater than 11,000 feet, 66 or 2/3 of the gross operated inventory has laterals exceeding 8,000 feet. The average lateral length in the inventory stands now at 8,949 feet, which is up slightly from 8,947 feet at the end of the second quarter. The inventory provides us with 25 years of future drilling locations. On Slide 12 is the chart, which outlines our progress to date on our average lateral length drilled based on the wells that we've turned to sales. During the third quarter, we turned 21 wells to sales with an average lateral length of 10,460 feet, thanks to the continued success of our long lateral drilling program. The individual lengths range from 6,789 feet up to 15,333 feet, and our record longest lateral still stands at 15,726 feet. During the third quarter, 6 of the 21 wells we turned to sales had laterals that exceeded 11,000 feet, and 5 of these exceeded 14,000 feet. To date, we've drilled a total of 64 wells with laterals over 11,000 feet and 33 wells with laterals over 14,000 feet. During the third quarter, we also had 2 additional wells that turned to sales on our new Western Haynesville acreage. The Cazey MS #1 and the Lanier #1 wells were both completed in the Bossier shale. These wells represent the sixth and seventh new vintage wells now producing in the Western Haynesville. Based on our current schedule, we plan to turn another 17 wells to sales by year-end, 13 of these will be longer than 11,000 feet and 8 of the wells longer than 14,000 feet. We expect by year-end 2023, our average lateral length will be approximately 11,000 feet. Slide 13 outlines our new well activity. We've turned to sales and tested 21 new wells since the time of the last call. The individual IP rates ranged from 18 million a day, up to 39 million a day at an average test rate of 29 million cubic feet a day. The average lateral length was 10,460 feet with individual laterals from 6,789 up to 15,333 feet. Included in the quarter again are the sixth and seventh new vintage wells in our Western Haynesville acreage. The Cazey MS, which was completed in the Bossier had a lateral length of 10,028 feet and was turned to sales in August. We tested the well with an IP rate of 34 million cubic feet a day. The Lanier #1 well, which was also completed in the Bossier, is completed with a 9,577-foot lateral and this well was turned to sales in September. We tested this well with an IP rate of 35 million cubic feet a day. In addition to the first 7 producing wells, we have 1 well that is currently waiting on completion, and we do expect to turn that well to sales in January. We currently have 2 rigs actively running on our Western Haynesville acreage that are drilling our ninth and tenth wells.

Okay. Thank you, Dan. Thank you, Roland. For everyone, we'll turn to Slide 15. I will direct you to Slide 15, where we summarize our outlook for the rest of 2023. We remain very focused on proving up our Western Haynesville play, continuing to add to our extensive acreage position in this prolific play. We believe that we are building a great asset in the Western Haynesville that we'll be well positioned to benefit from the substantial growth in demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports, which begins to show up in the second half of next year. Our new Western Haynesville midstream partnership will reduce 2024 capital expenditures that would otherwise be required to support the growth in production that we expect. Our industry-leading lowest cost structure is an asset in the current natural gas price environment as our cost structure is substantially lower than the other public natural gas producers. We plan to retain the quarterly dividend of $0.125 per common share. Lastly, we'll continue to maintain our very strong financial liquidity, which totaled almost $1.2 billion at the end of the quarter. I'll now have Ron provide some specific guidance for the rest of the year.

Thanks, Jay. On Slide 16, we provide the financial guidance for the fourth quarter of 2023. Fourth quarter D&C CapEx guidance is $240 million to $280 million. We've seen some signs of deflationary pressures on service costs relative to earlier this year. We believe most of those improvements will be seen in 2024. In terms of infrastructure and other spending, we continue to budget $15 million to $25 million of spending during the fourth quarter. On a combined basis, our D&C and infrastructure plus other CapEx should remain within our past annual guidance of $1.02 billion to $1.28 billion. In addition to what we spent on our drilling program noted above, we now anticipate spending $30 million to $40 million in the fourth quarter for additional leasing activity. Our LOE costs are expected to average $0.24 to $0.28 per Mcfe in the fourth quarter, while our gathering and transportation costs are expected to be $0.32 to $0.36 per Mcfe in the fourth quarter. Production in ad valorem taxes are expected to average $0.16 to $0.20 per unit in the fourth quarter, which is higher due to higher ad valorem taxes in Louisiana to go along with the higher production tax rate that Louisiana put into effect at the beginning of the third quarter. DD&A rate is expected to remain in the $1.05 to $1.15 per Mcfe range, while our cash G&A is expected to remain in the $7 million to $9 million range for the quarter with an additional plus roughly $2 million of non-cash G&A. Due to the increase in SOFR rates, our cash interest expense is now expected to total $42 million to $46 million in the fourth quarter, while our non-cash interest will remain roughly $2 million per quarter. On taxes, the effective tax rate is still expected to be in the 22% to 25% range, and we still expect to defer 95% to 100% of our reported taxes this year. Now I'll turn the call back over to the operator to answer questions.

And our first question comes from Derrick Whitfield from Stifel.

Regarding the Quantum partnership, I wanted to confirm a comment you made in your prepared remarks. If my numbers are correct, a fourfold increase suggests you're solving for 2 Bcf per day of capacity in the Western Haynesville. If that's correct, could you comment on how you're thinking about mainline egress as well?

Well, I think when we looked at our footprint in the Western Haynesville, when we look at our inventory, and we looked at the wells that we'll be drilling between now and maybe 2028, and we look around the corner to see what type of production we may have between now and then. A lot of that depends upon what the market needs, and we think in the latter part of '24, you're going to need another 4.5 to 5 Bs. Every year after that, you're probably going to need another B a day. That's just for LNG, exportable gas as feed gas. So when we looked around at Quantum, which is a Blue Ribbon financing source, when we started visiting with them months ago, they looked at our footprint and the well performance. We evaluated all that. We looked at the rig count, which, again, we will add. Our goal is to add a rig in the Western Haynesville next year. So we go from 2 rigs to 3, and then we would add another rig in 2025, and we think that's the goal for our footprint. If you look at that model for 5 years, we would have the capacity with the takeaway, both for transportation and the gathering, with the financing from Quantum to have at least 2 Bcf a day available to serve America and the globe. That's where we come up with this fourfold number.

Appreciate it, Jay. Thanks for all the color, too. In the past, you guys have talked about the Western Haynesville and the asset seeing similar returns to the legacy Haynesville at current operating conditions. With the understanding that you're still in the early stages of your learning curve in the Western Haynesville, could you speak to what you're seeing in operational efficiency gains and the degree cost could improve over time?

Yes, this is Dan. We have made significant progress in our cost structure in the Western Haynesville. As you mentioned, it’s still early, and we are on the steep part of the learning curve. We have reduced our drill times by approximately 20 days from when we drilled the first Circle M well to where we stand today. We also have plans that will allow us to further reduce costs in the future, so we feel confident about that. On the completion side, there isn't much potential for cost savings, as we follow the same processes regularly. There is a slightly higher cost for the horsepower needed to frac these wells here. Our efficiency improvements in completion will primarily come from using multi-well pads and making typical operational enhancements.

I would comment on looking at Dan and the group, things that were once really complex when we drilled the Circle M. Some of those things become a little simpler. If you drilled your seventh well and turned it to sales, now you're drilling your eighth and ninth and tenth well, and now we started focusing on the Haynesville, not so much on Bossier. Some of the hand-wringing that would require us to drill the first Circle M well isn't as pronounced anymore. We do have it going forward, but this shows you where Quantum comes in, having seen the well results and performance and what the future looks like in our inventory, and that kind of answers your question. We think the cost can come down. Our focus is on lasting worth, not near-term wealth. It's more of a lasting long-term goal, as we continue to build this company.

Good morning Jay, to you, Roland, Dan, Ron, and the whole crew there.

It's always good to hear from you. You should be here with us with the 34-degree weather. You'd be happier.

I would be happier. We were in the 50s down here this morning. I like it. But anyway, Jay, I want to ask a question about your business decisions here. $300 million from outside capital. That's great that you've got a high-quality partner like Quantum willing to put that kind of money into JV. I'm curious about what you can share about the way they looked at this. I'm imagining that for them to put that much money to work, they have to have some kind of commitment to the amount of volumes that you're going to put through the system? Maybe it's not a firm commitment, but some kind of commitment? And can you talk about the rate that you're going to pay per Mcf?

Yes, Charles, that's a good question. I think that we're going to continue to charge the same rate that we've been charging since the first wells went onto the system that we acquired last year. For all processing and transportation, we charge about $0.54 per Mcf. So there's really no change in the rate. It's the same rate that we historically have had. Yes, we have a very small MVC that's back to our own subsidiary here, and it's far less than half of what we project the production to be. So that kind of just supports the new midstream entity.

Just with the existing production that we have, Charles, so I think we start out with a big risk adjustment day 1. I think it provides what we need for the short term, but we keep an eye out on the long-term for natural gas. It gives us flexibility for the longer term too. That's what a Tier 1 partner does for you.

My question was on third-party volumes as well, but it does sound like this ramp from the 500 and then ultimately up to 2 Bcf a day by '28 is mostly, if not all, Comstock volumes. Are you able to say approximately what your gross volumes are in the play today?

No. Phillips, I think if you ask me if I'm going to do a big M&A and double the size of my company, then I'd do a big M&A. And I don't know what the M&A would be. If I'm out here derisking the Western Haynesville and you know we're going to add a third rig next year, we have to see how these wells hold up. We have to see how the new wells perform. That's where we try to keep it simple. We try to show you that if these volumes do grow between now and 2028, we think we have the type of geology that allows us to have about 2 Bcf a day. We throw that out there because it is in the model that we have with Quantum, but that is not something anyone should focus on between now and then. That's a long way down the road.

In the first half of the year, you guys were helped by some sizable working capital cash inflows and some of that, of course, reversed here in Q3. Just wondering what that might look like in Q4? And if we assume you continue to run 7 rigs throughout next year, would you expect working capital will either be a material source or use of cash next year?

Well, there are 2 elements of the working capital change. One of them is spending levels, and I think the spending levels have come down from where they were earlier in the year. So you see that it lags, it's like a 2-month lag between cash numbers. I think you've seen that impact of spending. I've got working capital that will stay from spending not as a source or use of cash kind of going forward because we're now kind of at the 7 rig level for a while. The second element of that is gas prices, if gas prices are higher now and we're still receiving gas from 2 months ago that's lower priced, that lag will be part of working capital change. We're hoping that gas prices keep going up and that you'll continue to see a little bit of a negative effect of working capital adjustment as you continue to see higher gas prices from the previous quarter, and that's what you're seeing.

I think that we'll go into the hedging position. We did add $100 million a day of hedges, which were swapped at $3.55. We're, I think, 22% hedged for 2024. If you look at the perfect world of Comstock, we'd like to be in the 40%-plus. We want to add those extra hedges just to mitigate some risk as we go through 2024. We think the demand for gas will appear in the latter part of '24 and then '25 on, and you should see it pretty consistent.

Could you talk a little bit to what you're seeing in terms of leading-edge service costs and the traditional kind of Eastern core Haynesville? I think you alluded earlier that maybe those have come in some. Could you give us a sense? I mean, just looking at your third-quarter D&C was up 1%. What do you see the service cost doing in the leading edge, and when do you think that starts to show up in the financials?

So Leo, this is Dan. We have seen the service costs come down. They've been easing down probably earlier this year, but we've seen the biggest decrease on the rig rates that are down about 10% since the earlier part of this year. On the completion side, probably not quite as much. That's driven by our frac cost, more like a 5%, 6%, 7% decrease since earlier in the year. I think we'll see that continue to trend down into this fourth quarter and into next year. We'll just have to wait and see really what these gas prices how they materialize next year.

The one comment I may add is, Leo, when you're looking at that cost per completed well, there's a significant time difference. Drilling costs are the oldest costs in there. And so because these wells were drilled probably back a couple of quarters ago or at least a quarter ago. Completion costs are more relevant in the quarter, but even all of them lag because we can't report this until the well is completed. When the drilling costs come down last, I think what we would expect to see is as you get kind of out over the future, that current cost will show up in scores.

Just a quick one for me. With the plan to move 1 rig from your legacy Haynesville into the Western Haynesville next year. Do you think your legacy Haynesville production can be held flat with that rate cadence? Or do you think it declines a little bit with a 4 rig program?

I think it's a good chance that it will be hard to hold it flat with just 4 rigs. We are going to look at high grade to maybe hold the most prolific part. As the Western Haynesville starts to build a production base, it has a much lower decline rate. I think longer term, we can lower our corporate decline rate as the Western Haynesville takes over a more meaningful part of that production base. In the short term, we'll have to see how to balance the two.

Our next question comes from Gregg Brody from Bank of America.

You mentioned the $300 million of capital coming from Quantum. About $100 million to $200 million you said will be spent next year. Is there a need to raise more capital? Is the $300 million enough? Or are there plans to raise a revolver down to that facility?

The entity will become self-financing after it gets going. We think that the amount of equity capital is adequate based on how we're seeing it build up. We see flexibility with this partnership and that will exist and will kind of have its own potential financing base. In terms of guarantees, Comstock is not guaranteeing anything that's in that subsidiary, and Quantum's commitment will be equity dollars.

I again want to thank everyone for spending time. Your time is probably your most valuable asset. As I was listening to the Q&A and our presentation, even with weak natural gas prices, we reported solid results for the Western Haynesville shale drilling program. Our goal is to keep the dividend, manage the balance sheet, and be a great partner to Quantum as we build the midstream in the Western Haynesville. We want to maintain an eye on appraising all of our Western Haynesville wells. Thank you for your participation today.

This concludes today's conference call. Thank you for participating. You may now disconnect.