Comstock Resources, Inc.

Thank you for standing by and welcome to the CompStock Resources fourth quarter 2023 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during this session, you'll need to press star 11 on your telephone. If your question has been answered and you'd like to remove yourself from the queue, simply press star 11 again. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Jay Ellison.

chairman and ceo please go ahead sir all right jonathan i love that broadcasting voice uh kind of starts the day off right uh our corporate team of 255 strong i want to thank you for joining the call this morning and we wish you a happy valentine's day being a pure play natural gas company in a sub two dollar natural gas market calls for decisive actions to weather the volatility and at the same time continue positioning CompSoc to benefit from the longer-term growth in natural gas demand in the foreseeable future. America will need to deliver an additional 10 billion cubic feet of natural gas per day to the LNG facilities currently under construction in the next few years, actions taken so far as we batten down the hatches to protect our balance sheet. Number one, In January, we released a frack crew. Number two. Several months ago, we gave notice to release two rigs, and they will both be finished, their work, by the end of this month. Number three. We suspended our quarterly dividend until natural gas prices improved. Number four. We continually evaluate our activity level as we plan to fund our drilling program within operating cash flow, if possible. Number five. We formed our midstream joint venture last year that allows us to build out the Western Hainesville midstream assets to be funded by the midstream partnership and not burden our operating cash flow at Comstock. Number six, we're positioned Comstock to have very few rigs needed to hold all of our corporate acres, including the 250 plus thousand net acres in the Western Hainesville. Number seven, We're bullish on the long-term outlook for natural gas and are growing our resource base in the advantage proximity to the Gulf Coast market. Number eight, lastly, our Western Hainesville, quote, box of chocolate on its Valentine's Day allows us to maturely grow our drilling inventory organically versus through the M&A market. I can also assure you that our majority stockholder The Jerry Jones family is in 100% approval of all of our prior actions, as well as our recent moves to protect our balance sheet in this volatile natural gas market. They are in the cockpit with us, helping fly this plane with a steady hand on the throttle, looking into the future where global natural gas markets are counting on our U.S. gas to provide needed clean energy. Our goal is to look back on this point in time in the future years and say we handled it well and continue to create corporate value in a weak period for natural gas. Now I'll go over to the corporate script. Welcome to the Comstock Resources Fourth 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 and downloading the quarterly results presentation. There you will find a presentation entitled Fourth Quarter 2023 Results. I'm Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer. And Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within a meeting 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. Fourth quarter 2023 highlights. On slide three, we summarize the highlights of the fourth quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and gas sales, including hedging, were $354 million in the quarter. We generated cash flow from operations of $207 million, or $0.75 per share, and adjusted EBITDAX was $244 million. Our adjusted net income was $0.10 for the quarter. We continue to have very strong results from our drilling program. In the fourth quarter, we drilled 13.3 net successful operated Hainesville and Bossier Shell horizontal wells in the quarter with an average lateral length of 8,994 feet since the last conference call. We've connected 22 or 16.5 net operated Welsh to cells with an average initial production rate of 24 million cubic feet per day and an average lateral length of 11,966 feet. Our 2023 drilling program replaced 109% of our 2023 production with new approved reserves ads. We are continuing to make progress in our Western Angel exploratory plate We added 23,000 net acres to our expensive Western Hainesville acreage position in the fourth quarter alone, increasing our total acreage position in the play to over 250,000 net acres. We recently turned our H well to cells. The Nela well was completed in the Hainesville formation and is currently producing at 31 million cubic feet per day. Three additional wells, the Harrison, Glass, and Farley wells, are expected to come on production by the end of the first quarter. I'll now have Roland go over the fourth quarter and the annual financial results. Roland?

Thanks, Jay. On slide four, we cover our fourth quarter financial results. Our production in the fourth quarter of 1.5 BCFE per day increased 6% for the fourth quarter of 2022 and grew 8% from the third quarter. Low natural gas prices resulted in our oil and gas sales in the quarter coming in at $354 million, declining 37% from 2022's fourth quarter, despite the higher production level. EBITDAX for the quarter came in at $244 million, and we generated $207 million of cash flow in the fourth quarter. We reported adjusted net income of $28 million for the fourth quarter, or 10 cents per share, as compared to a net income of $12 million in the third quarter of 2023, and $288 million in the fourth quarter of 2022. Slide 5, we show the financial results for the full year, 2023. Our production averaged 1.4 BCFE per day, which was a 5% increase from the prior year. Oil and gas sales in 2023 totaled $1.3 billion, and we're 41% lower than our sales in 2022 due to the lower gas prices we realized. Our EBITDA in 2023 was $928 million and we generated $774 million of cash flow for the year. We reported net income of $133 million for 2023 as compared to net income of $1 billion in 2022. Slide six, we show our natural gas price realizations that we had in the quarter. During the fourth quarter, the quarterly NYMEX settlement gas price averaged $2.88, which was 14 cents higher than the average Henry Hemp spot price in the quarter of $2.74. Our realized gas price during the fourth quarter averaged $2.48, reflecting a 40 cent differential to the settlement price and a 32 cent differential to our reference price. The differentials were a little wider in the quarter starting in October, which normally occurs as we reach the end of storage injection period. In the fourth quarter, we were 16% hedged, and that improved our realized gas price for the quarter to $2.51. We've also been using some of our excess transportation in the Hainesville to buy and resell third-party gas. We generated about $4.4 million of profits in the fourth quarter, and that approved our gas price realization by another $0.03 in the quarter. On slide seven, we detail the operating cost per MCFE and our EBITDAX margin. Our operating cost per MCFE averaged $0.81 in the fourth quarter, 4% lower than the third quarter. Lower gathering costs were offset though by higher production and ad valorem taxes. Our gathering costs were down $0.03 to $0.33 during the quarter, And our lifting costs were also one cent lower than the third quarter rate at 23 cents. Our production ad valorem taxes increased three cents from the third quarter level. And G&A came in at two cents per MCFE, which was three cents lower than the third quarter. Our EBITDAX margin after hedging came in at 68% in the fourth quarter, up from the 65% level we had in the previous quarter. On slide 8, we recap our spending on drilling and other development activity in 2023. We spent a total of $1.3 billion on our development activities, including $1.2 billion on our Hainesville and Bossier Shale drilling program. Spending on other development activity, including installing production tubing, offset frack protection, and other workovers, totaled $54 million. In 2023, we drilled 67 wells or 55.5 wells net to our interest. In turn, 74 or 55.7 net operated wells to sales. These wells had an overall average IP rate of 25 million cubic feet per day per well. On slide nine, we cover our natural gas and oil reserves that were determined using the required SEC prices. Our SEC-approved reserves decreased 26% in 2023 to 4.9 TCFE due to the low gas price used in that determination. The required SEC gas price decreased 60% for 2023 to $2.39 per MCF, down from the $6.03 that was used in 2022. Our 2023 drilling activity added 571 BCFE approved reserves to our year end reserves, which replaced 109% of our 2023 production. But we also had 1.8 TCFE of negative revisions due to the lower approved undeveloped reserves caused by our reduction in drilling activity and the low natural gas price that was used to determine which undrilled locations we would drill. In addition to the total 4.9 TCFE of SEC-approved reserves that we had at the end of the year, we have another half of TCFE-approved undeveloped reserves that aren't included as they are not expected to be drilled within the five-year required time period required by the SEC rules. We also have another almost TCFE of 2P or probable reserves and 4.6 TCFE of 3P or possible reserves for a total reserve base of around 10.9 TCFE on a P3 basis, all determined at the low SEC pricing. On slot 10, we've used a NYMEX gas price of $3.50 per MCF to determine the reserves to show the impact of the low prices on the year-end reserves. Using this price, our approved reserves would have been similar to last year at 6.6 TCFE. In addition, our overall reserves, we would have had an additional of another two TCFE-approved undeveloped reserves that are outside the five-year period. And then we would have 2.5 TCFE of 2P, or probable reserves, and another 8.7 TCFE of 3P, or possible reserves, for a total overall reserve base of 19.8 TCFE on a P3 basis, all determined at a 350 NYMEX gas price, which and our view lined up closer to the long-term futures prices for natural gas. On slide 11, we recap our balance sheet at the end of 2023. We did end the quarter with $580 million of borrowings under our credit facility, giving us a total of $2.7 billion in debt, including our outstanding senior notes. Our borrowing base for our bank credit facility is currently at $2 billion, of which we have an elected commitment of $1.5 billion of that amount. So we ended the year with overall financial liquidity of just over a billion dollars. I'll now turn it over to Dan to kind of discuss our operations in more detail.

Okay. Thank you, Roland. Overall slide 12, this shows where our current drilling inventory stands at the end of the year, end of the fourth quarter. Our inventory is split between our Hainesville and Boser locations. We have it divided up into four buckets. Our short laterals run up to 5,000 feet. Our medium laterals run between 5,000 and 8,500 feet. We have our long laterals between 8,500 and 10,000 feet. And then our extra long laterals extending out beyond 10,000 feet. Our total operated inventory currently stands at 1,706 gross locations and 1,303 net locations. This equates to a 76% average working interest across our operated inventory. Our non-operated inventory has 1,253 gross locations and 160 net locations. This represents a 13% average working interest across the non-operated inventory. If you break down our gross operated inventory, we have 291 short laterals, 347 medium link laterals, 438 long laterals, and 630 extra long laterals. The gross operated inventory is split 51% in the Huntsville and 49% in the Bossier. 37% of our gross operated inventory or 630 locations have laterals greater than 10,000 feet, and 63% of the gross operating inventory has laterals exceeding 8,500 feet. The average lateral length of our inventory now stands at 8,971 feet, and this is up slightly from 8,949 at the end of the third quarter. Our inventory provides us with 25 years of future drilling locations. On slide 13 is a chart outlining our progress to date on our average lateral length drilled based on the wells that we've turned to cells. During the fourth quarter, we turned 17 wells to cells with an average length of 11,870 foot. And this is thanks to the continued success of our long lateral drilling program. The individual lengths ranged from 5,736 feet up to 15,243 feet. while our record longest lateral still stands at 15,726 feet. During the fourth quarter, 12 of the 17 wells we turned to sales had laterals exceeding 10,000 feet, including seven of those wells longer than 14,000 feet. To date, we have drilled a total of 80 wells with laterals over 10,000 feet long and 28 wells with laterals over 14,000 feet. During the fourth quarter, we didn't turn any wells to cells on our new Western Hainesville acreage. Today, in 2024, we have turned one well to cells in the Western Hainesville, and we do expect a total of four wells to be turned to cells by the end of the first quarter. In 2023, we turned a total of 74 wells to cells with an average lateral length of 10,820 feet. And this is up 8% from our 2022 average lateral length of 9,989 feet. Slide 14 outlines our new well activity. We have turned the sales and tested 22 new wells since the time of our last call. The individual IP rates range from 9 million a day up to 42 million a day with an average test rate of 24 million cubic feet a day. The average lateral length was 11,966 feet with the individual laterals ranging from 5,736 feet up to a 15,243 foot lateral. The Hamilton Verhalen B number two well located in East Texas which had a nine million a day IP rate suffered a mechanical casing failure during completion which resulted in this well producing from only half of the completed lateral. In addition to the first seven wells producing in the Western Hainesville at the end of 2023, we recently placed our eighth well online. The Neyland number one was drilled in the Hainesville and to date it's currently producing 31 million cubic feet a day. This well is still in the process of being tested and cleaning up. We do anticipate three additional wells being turned to sales by the end of the first quarter. We currently have two rigs running on our Western Hainesville acreage. and we are currently planning to keep two rigs running in the western hazel for the remainder of the year. On slide 15, this summarizes our D&C costs through the fourth quarter for our Mitchmark long lateral wells that are located on our legacy core East Texas and North Louisiana acreage. This covers all our wells having laterals greater than 8,500 feet long. During the quarter, we turned 17 wells to sales that were on our core East Texas and North Louisiana acreage. 13 of the 17 wells were our benchmark long-ladder wells. In the fourth quarter, our DNC cost averaged $1,482 a foot on the 13 benchmark long-ladder wells. And this reflects a 5% decrease compared to the third quarter. Our fourth quarter drilling cost averaged $610 a foot, which is a 15% decrease compared to the third quarter. The lower drilling cost reflects a slight downward trend on pricing we've experienced throughout 2023, and also our drilling cost in the third quarter was abnormally higher due to some drilling issues we had in that quarter. Our fourth quarter completion cost came in at $871 a foot, which is a 3% increase compared to the third quarter. The increase in completion costs were primarily attributable to some slightly higher plug drill out cost in the fourth quarter due to the longer laterals. We currently have seven rigs running. We are in the process of releasing one rig this weekend, and end of the month, early next month, we'll be releasing a second rig. We currently expect to run five rigs for the rest of 2024. On the completion side, we are currently running two frac crews. We do expect to maintain one to two frac crews running for the remainder of the year. I'll now hand the call back over to Jake.

Thank you, Dan. Thank you, Roland. If you'll turn to slide 16, we'll summarize our outlook for 2024. We remain very focused on on proving up our Western Hainesville play and continuing to add to our extensive acreage position in this exciting play. At the end of 2023, our Western Hainesville acreage position totaled over 250,000 net acres. Following the creation of our mid-spring joint venture late last year, the capital costs associated with the build-out of the mid-spring assets in Western Hainesville will be funded by the Mid-Spring Partnership and will not be a burden on our operating cash flow. We believe that we are building a great asset in the Western Hainesville that will 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 that begins to show up in the second half of next year. We're actively managing our drilling activity level to prudently respond to the current low gas price environment. We have already released one of our three completion crews, as Dan said, and two of our operated rigs on our legacy Hainesville footprint, bringing our total operated rig count to five rigs, of which two are drilling in the western Hainesville. We are focused on preserving our balance sheet in this gas price environment. We'll continue to evaluate our activity level as we plan to fund our drilling program within operating cash flow. We are going to suspend our quarterly dividend until natural gas prices improve. 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. And lastly, We'll continue to maintain our very strong financial liquidity, which totaled around a billion dollars at the end of the fourth quarter. I'll now have Ron provide some specific guidance for the rest of the year. Ron? Thanks, Jay.

On slide 17, we provide the updated financial guidance for the first quarter of this year and the full year. First quarter, DNC CapEx. Guidance is $225 to $275 million, and the full-year DNC CapEx guidance is $750 to $850 million. The lower spending versus last year is related to the announced release of two drilling rigs in our press release last night in response to low gas prices. We've continued to see signs of some deficientary pressures on service costs, including an improvement in our completion costs per stage. We anticipate spending an additional $30 to $40 million on lease acquisitions in the first quarter and $40 to $50 million over the course of the year. Capital expenditures related to Pinnacle Cast Services will be funded by our midstream partner and are expected to total $30 to $40 million in the first quarter and $125 to $150 million for the full year. For both the First quarter and the full year, our LOE is expected to be in a range of $0.24 to $0.28 per MCFE. GTC are expected to be $0.32 to $0.36 per MCFE. And production and ad valorem taxes are expected to average $0.16 to $0.20 per MCFE. DG&A rate is expected to average $1.30 to $1.40 per MCF this year. In the first quarter, our cash GNA is expected to total $7 to $9 million and $30 to $34 million for the full year. In addition, we'll have non-cash GNA in the first quarter of $2.7 to $3 million and $10 to $12 million for the full year. With the increase in SOFA rates and our current debt levels, Cash interest expense is now expected to total $43 to $47 million in the first quarter and $195 to $205 million for the year, while non-cash interest will remain approximately $2 million per quarter. Effective tax rate will remain in the 22 to 25% range, and we continue to expect to defer 95 to 100% of our reported taxes this year. We'll now turn the call back over to the operator. to answer questions from analysts who follow the company.

Certainly. One moment for our first question. And our first question for today comes from the line of Derek Whitfield from Steeple Financial. Your question, please.

Good morning, all, and thanks for your time. Yes, sir.

Let me first commend you on a strong year end in your decision to reduce capital outflows in the current depressed gas price environment. With respect to your 2024 outlook, could you speak to the average gas price that underpins your spending within cash flow view? Any additional steps you'd likely take to further produce capital if gas continues to deteriorate?

Yeah, Derek. I mean, of course, that's a moving target where gas prices are. And I think that probably where the gas price was in the market maybe about two or three weeks ago is probably exactly where that's in balance. It's going to be a volatile deal, but I think the things that we'll continue to monitor are what are our service costs. They're trending down a little bit as far as some deflationary actions happening on that side. The other levers that we can pull are continue to look at dropping another rig. That's the most effective way to reduce capital expenditures that has the most impact on creating net operating cash flow. And so that's what we'll continue to monitor the activity like we do each year and look to tighten up the ship wherever we can to kind of maximize the operating dollars that we have.

That's my follow-up. I wanted to shift over to the Western Hainesville with the understanding that it's a long game resource. Could you speak to the gains you're experiencing in operational efficiency, the degree you're expecting your break even to improve over time, and if you're expecting a meaningful difference in the break even between the Hainesville and Bossier intervals?

This is Dan. I'd say we're definitely gaining ground and going up the curve still faster on our Western Hainesville wells. We are, you know, we're drilling our first two-well pad actually currently. We got to know what the second rig is going to its first two-well pad next. That's going to definitely help our efficiency there. We still have had some things that we've gained on on the drilling front that's still increasing our drill times. And we still see a little bit more running room there to get faster. So I think, you know, we definitely are seeing an increase there in the western Hainesville wells and we're seeing those costs come down. In the core area, you know, probably as far as the moving the needle on efficiency, probably not as much. I mean, we've been there for a long time and got everything pretty streamlined. But, you know, down to the two frack crews, same vendor, we see some kind of some savings there. Just really, really good solid performance. We brought in some three, you know, three new rigs, new build rigs. So just, I think we're going to have some better performance there just kind of overall. So I think we will, and of course we're seeing the cost savings come down with the activity levels. We're probably down 10% or so this year since the beginning of last year. And, you know, obviously difficult times, you know, we, I think everybody gets pretty streamlined and pretty efficient and the costs come down, but Obviously, we'd like to see maybe prices be a lot higher, you know, and be battling some of those things. But, yes, that's where we're at.

Very helpful. Thanks for your time.

Thank you. One moment for our next question. And our next question comes from the line of Charles Mead from Johnson Rice. Your question, please.

Good morning, Jay. To you and your whole team there, Comstock.

Good morning.

Dan, I'm going to start with just a really quick clarifying question with you. I think I heard you say in your pair of comments that you're planning on running between one and two completion crews for the remainder of the year. Did I catch that right?

That's right. If you just do the math, we've got two dedicated fleets to us, but if you do the math with the number of wells we're going to turn to sales, it comes out to like 1.7 is what we'll need this year. Got it. Got it. One running full-time and one, you know, with some gaps in between.

Got it. And then my follow-up, Jay, and I recognize that this is kind of a maybe simplistic way to start this, but, you know, I recognize you guys look at a lot more data and have a lot more considerations than somebody sitting in my chair does. So, but in my chair, you know, I look at the... the futures curve here, and we don't get above two bucks until July. And so for my seat, it looks to me like the right number of completion crews to be running right now for at least the next several months is zero. And, you know, I recognize that's not a realistic case, but can you bridge the pieces to, you know, kind of bridge the view for, you know, it looks like the right number is zero, but why the right number for you guys is zero? is 1.7 or 1 to 2 for the next several months?

Well, I think that's a really good question. Number one, I think if you look at how proactive we've been, typically on a conference call like this, you're going to release a FRAC crew. We've already done that. Second of all, maybe you have contracted to have that FRAC crew and you have to use them. We don't have any contracts. It's a will by will. Now, I think the other thing, just as far as cost, I mean, usually in a conference call like this, you're going to release two rigs, and it takes two or three, four months to release those rigs. And we were proactive back in December to give notice. And as Dan has said, we'll have both of those released by the beginning of March is our goal. So then, you know, Roland was asked a question about the price of natural gas to save it in operating cash flow, which is kind of your question. I think what we tell you is that that is our goal, is to tell you that, you know, we don't plan on spending as much money on acreage procurement as we have in the past. It tells you that, you know, probably half of our acreage that we own right now is Western Haines where the other half is a core. And it tells you that, you know, we're not inventory starved. So we don't have to do deals in the market whether gas prices are high or low in order to buy inventory. So then you come and you look at the cost, and we look at deflation. I mean, Dan goes over some of the cost savings that we've had from the FRAC company so far, and some of the cost savings we've had in drilling and completing the wells. I think all we can do is tell you that we've looked at those numbers. We've looked at hedging. You know, we've hedged about 28% of our production in 24 to 355 swaps. I think that we need to be in the 50% range. Now, you know, when will we get there? I don't know. But I think you and the market need to know that it is a corporate goal that we have. And the reason that we use kind of batting down the hatch as a theme is because if we need to delay some practice, we see that in the next month or so, then I think we can do that. If we need to lay down another rig, we'll have the optionality to do that. So again, I think your goal is, you know, how are you going to protect this thing? And that's one reason I always say, if you look at the major shareholder who owns 65% of this, if anybody's trying to protect it, the Jones family is, and they're well involved with what we do. And then I think you have to look at any minimum volume commitments or farm transportation agreements that you have and say, Are we impacted by reducing the recount? And the answer is we're not. So you have to look at all those things too when you ask that question. But we're going to continue to manage this just like we've managed it for a while. We as a group, you know, we recognize pain. I mean, some groups haven't recognized it because they haven't experienced it. We do. So it's a good thing. It's an indicator. And whatever we need to do to right this ship, that's what we plan on doing. So that's a great question.

Thank you for that elaboration. That was helpful, Jeb.

Yes, sir.

Thank you. One moment for our next question. And our next question comes from the line of Fernando Zavala from Pickering Energy Partners. Your question, please.

Hey guys, good morning. Kind of going back to your comments around evaluating dropping another rig. Where would that rig come from? Would it come from the Western Hainesville or the core Hainesville?

If we dropped another rig, it would be in the core. It would not be the Western Hainesville.

OK, got it. And then can you talk a little bit about the, as my follow up, the trajectory of production in 2024? You know, it seems like the implied 2024 guidance is in line with first quarter, so just a little bit more color there.

Yeah, if you think about the timeframe related to dropping a rig and starting to show up in terms of impacting production, Dan mentioned we were dropping the first of those two rigs here this weekend and the second rig within the next within the next two to three weeks, I think he said. And so just like when you add a rig, when you drop a rig, there's plus or minus a six or seven month lag between the timing of changing your activity level and having it flow through to production. So that's why the first half of the year production should remain relatively flat and you start to see a little bit of a decline in the third quarter and a little bit larger decline in the fourth quarter as you start to feel the full brunt of running five rigs. Okay, that's helpful.

Thank you. Thank you. One moment for our next question. And our next question. comes from the line of Jacob Roberts from TPH and Company. Your question, please.

Morning.

Morning. Morning. Morning.

I think previously you've had some commentary about drilling commitments and HPP provisions on the Western Hainesville. Can you speak to the impact of running those two rigs for 2024 and any needed extensions or perhaps capture provisions to be needed in 2025 plus?

No, we feel like that, you know, that not running the three rigs like we originally anticipated this year, that that's not going to put us that far behind, and we won't really have to alter, you know, our future plans, you know, by taking this, you know, a little bit slower approach in 24. You know, but over a longer period of time, you know, we have a lot of acres to term acreage that, you know, has to be, we have to drill to hold, so. But given the actions we're taking this year, we're not really changing, you know, having to know that we have to extend leases, et cetera. We still can keep all these kind of on track.

You know, in fact, I think the slowdown is a positive in that in the Western Hainesville, as Dan said earlier, most of the wells we'll be drilling now will be two wells per pad. We have been drilling one well per pad. I think it lets our land group now get ahead a little bit for 25 and 26 because we have added a lot of acreage within a small window. I think it lets us position our wells better in 24 and 25 to de-risk a lot greater swath of acreage with fewer wells. So it really has been, the slowdown has served our land group And as Roland said, and Dan will tell you, it has not impacted really the drilling. I do think we'll add another rig in 2025, like we were going to do in 2024. But, you know, the results will speak for themselves. And so far, the results have been really good. They've been stellar for the acreage that we have and the area that we de-risk. which is probably from the hill to our northern well, probably 20, three or four miles. We've said that publicly. We've got a lot of acreage we de-risked there. So it looks good, and I think this environment is favorable for us to slow that down.

Thanks for that. My second question is around the leasing program that seems to have bled over from 2013 to 2024 and is pretty heavily focused in the first quarter of the year. Can you just provide any detail on what caused some of those conversations to fall into this year? Has the process become more competitive? And then maybe if you can, a sense of the scale of the remaining transactions in the pipeline. Thank you.

The process definitely has not become more competitive with the weak gas price environment. We're leasing from lots of different parties. There's lots of reasons why you don't actually close something you're working on. I don't think there's any significant trend there. We are rounding up where we've captured a lot of the acreage in the areas that we think are the most prospective for the play. That's really driving the program forward. More than anything else, it's just we're finishing up.

Great, appreciate the time.

Well, you know, Luke stated that we average about $550 an acre, and in fact, at $1.61 gas, which is where we are right now, which I don't think I've read that we hadn't been this low since spring of 2016, so eight years, I can promise you there's no competition out there at $1.61 at all.

Thank you. One moment for our next question. And our next question comes to the line of Bertrand Dawn from Truist. Your question, please.

Hey, good morning, guys. Morning.

Morning.

This one might be a little bit weird, and I'm not saying it's necessary, but if it did become necessary, is there any ability to negotiate with Quantum on the minimum volumes? It seems like you guys have a mutual interest, and even when they revert to 30%, there's probably a an interest in properly managing the asset instead of just kind of hitting a number that was inked at a different gas price. But it was purely out of curiosity.

Well, that level is set so much – far, far lower than our forecast and even our production level now. It's just not even a question to give any thoughts to.

Sounds good. Very succinct. Another one, just to keep them a little bit weird, was there any consideration instead of technically suspending the dividend, instead going to a kind of variable dividend? I just don't know if management has a view on whether or not that has a place or no place, or maybe it just doesn't mesh with the corporate view.

No, we didn't consider that.

Sounds good. I appreciate the answers. Thanks.

Great questions.

Thank you. One moment for our next question.

And our next question comes from the line of Phillips Johnson from Capital One Securities. Your question, please.

Hey, guys. Thanks. My first question is on your three and a half times max leverage ratio covenant. At current strip prices, our model shows that you might be close to reaching that later this year. Would you also see that as a possible risk? And if so, How easy would it be to get a waiver from the banks?

We don't see that. So we don't think that we come that close to that, Phillip. So I think we just continue to monitor our spending level and not use much more of the credit facility.

OK, sounds good. And just to make sure our models are calibrated, as we think about the FIBRED program, what would you expect in that well count to look like for the year in terms of both wells drilled and wells turned to sales?

Rod's got that number.

It's in the press release, too. Yeah, it's in the press release. You can read it there, yeah.

I guess 40. Oh, I don't have that email. Hang on. Give me two seconds.

So, as it says in the press release, we plan to drill 46 gross and that's about 36 net wells and turn to sales 44 gross, 38 net.

Okay. Sorry about that. I completely missed that. Thank you.

Thank you. One moment for our next question.

And our next question comes from the line of Leo Marinari from Roth. Your question, please.

I just wanted to quickly follow up on some of the prepared, you know, answers here that you guys had given here. You know, Ron, you talked about production, you know, kind of flattish in the first half of the year, a little bit of a third quarter decline, and then more of a fourth quarter, you know, decline. And, of course, I'm sure it's, you know, pretty obvious to you folks that that's a bit inverse to what the futures curve is suggesting, where clearly prices are expected to be lower early in 24 and then higher as you get towards those winter months in 24. So you certainly expressed the belief that you want to be kind of flexible and sort of do what you can to kind of maximize the cash flow. So is there some some thought to pushing some of those turn-in lines out towards those later quarters and perhaps trying to shift the production a bit so it's a little bit lower this summer and maybe higher next winter? And is there any operational reasons maybe why you couldn't do that?

Maybe some of the western Hainesville stuff has provisions or wells have to come online at a certain point in time, but any color you have there would be great.

Well, you know, I think it's difficult to, you know, under shale if you don't understand that timing of shell production and the way that the wells are drilled and all that to try to be, you know, super precise and bring production on, you know, within what the futures curve says it could be now, which it could be different when you get there. I mean, it's not something, I mean, you obviously can give consideration to it and we can give consideration in the field if we have low, you know, spot prices that we, you know, not turn a well on that day, definitely. So you can manage these kind of around that, but, you know, I don't know that you can think that you can direct it, you know, a real precise level because, you know, you could, your assumptions could be wrong and too, plus it takes like, it takes a lot of resources to, you know, to, in preparation to bring these on and you don't have all those available, you know, at the, you know, you can't snap your fingers and get all the wells turned on in one day and, So it's just really balancing all that and balancing it with what you have, you know, the facts you have at the time. So just because we present a plan and budget doesn't mean it's going to happen exactly that way. So, you know, we'll adjust as we go through the year to, you know, what's going on, you know, in the markets and what's available in the spot market or the index market, et cetera.

And I'll add specifically to the Western Hainesville. Our two frack crews are actually fracking wells there now in the Western Hainesville. So there's really only one other well right behind those. And we don't have anything else coming on in the Western Hainesville until the end of the year because, like I mentioned earlier, we got one rig that just started a two-well pad a couple of weeks ago. And our other rig is getting ready to move to a two-well pad. And obviously, you know, the Western Hanes will take more days to drill. So with two-well pads, you know, they'll be drilling all through the spring and summer and fall.

Got it. Okay, that's helpful color, guys. And I know you can't snap your fingers like you said, Roland, but it sounds like maybe there is. some flexibility to kind of, you know, manage this, you know, a little bit on y'all's end, and I'm sure you're going to be watching it very closely as the year progresses here. Okay, maybe just a follow-up on the Western Haynesville. You obviously had your reserve report out. Can you give any color around, like, what some of these Western Haynesville wells were getting booked at, maybe, like, in terms of, you know, reserves per thousand feet or however you guys want to present it here?

Yeah, and generally, you know, we don't have a lot of bookings because we're We're not trying to get beyond a direct offset as far as booking anything in the western Hainesville. It's still early, and we only had the seven producing wells in total in the play. So there's a limited number of locations in the reserve report, but I would say overall the average kind of reserve bookings are in that 3.5 BCF per 1,000 feet of completed laterals. Only really one well has a pretty significant track record of performance, which is the first one, the Circle M. And, you know, it was upwardly revised, you know, with this. It's kind of outperformed that. The rest of the wells, you know, don't have near the number of months after production. So kind of left them, you know, where they are. But, you know, the reserves are trending nicely in the play for the first wells that we've drilled.

Okay. No, that's a great color and certainly appreciate that. And just lastly for me here, just obviously I don't think gas has turned out like anyone expected, you know, in 2024 here. It sounds like the plan is to really not kind of add debt from what I'm hearing, you know, from you here, Roland. And I guess just to the extent that, you know, for whatever reason, let's say next winter's warm and it's kind of a weaker start, you know, to the year, hopefully that's not the case. But, you know, if that is, I mean... you know, are you still in a position where you don't want to add debt or do you have to have maybe a little bit more activity next year because of holding some of the western Haynesville and were there any consideration of maybe putting in some, I'll call it near-term funding to kind of get you over the gap here until markets improve, you know, later in 25 and 26?

I think we position ourselves right now so that the things that we've done allow us to protect our balance sheet. I mean, if you just segregated and you look at the Western Hainesville, like Dan said, these wells will be slower to reach production. So even though we didn't add a third rig, I mean, as Raul mentioned, we're not going to have any issues with our midstream quantities. So I don't see an issue there. And then I think as far as any obligations we have to drill the complete wells, we don't have any obligations there. And we, as we said, we were very, very proactive even in December, much less January, February, to cut some costs. So I think we're just monitored like that. If we need to lay down another rig, if we need to defer completions, all of those things, those are all in the hopper that we'll look at to do. So even in a very tough market, I think we've got a lot of switches to pull to protect where we are. And the bottom line is we're just so rich in inventory that we just have to protect what we already own period we don't have to breach the 10th commandment and covet everybody everybody else's inventory we just have to continue to perform uh in the western angel uh like roland said i mean the eur's look solid dan said the costs are coming down it's still early innings But we've captured a lot of acreage, and we'll just see what the storybook tells us in the future.

Okay.

Appreciate the caller. Yes, sir. Thank you. One moment for our next question. And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Your question, please.

Hey, good morning. I love Noel. I just wanted to touch again on the Western Hainesville. I just wondered, can you talk a little bit about what kind of science you're doing on the latest Western Hainesville wells? Sort of like what are you most interested in learning about next as far as just your drilling practices, for instance?

Well, I mean, so we've, you know, I think we've stated before, you know, probably the biggest – difference between the Western Hainesville and our core is the temperature, you know, in the depth. I mean, obviously, they're a little bit deeper. If you just look at the TVDs of the wells, and, of course, with that comes temperature, and we've just really done a really good job at managing the temperature. When I say that, manage it, getting our, you know, bottom hole assemblies to perform and stay on bottom longer. Faster ROPs, less trips in and out of the hole to get the lateral drill. So we've made a lot of gains there. And then just up top, you've got obviously a longer vertical section to drill. We've made some modifications to our casing design. We've seen our penetration rates pick up up top also. So you just kind of got to attack everything. And we don't have all of those things. you know, just totally, you know, kind of maxed out like we do in the core. I mean, in the core, we just kind of make some tweaks a little bit here and there, and you pick up a day or two. But, you know, we're picking up bigger chunks down here in the western Hainesville, just figuring this thing out.

And are you at a point where productivity of the rock is pretty much not a surprise anymore, or are you still learning things there?

I'd say the rocks turned out, I mean, we knew, everybody knows that the gas is there. There were two old wells drilled back in like 2010 and 2011 that we got data on. They had all kinds of problems, had very inferior completions put on them. But, you know, still with that, you know, they still ate a decent amount of gas. So we knew the gas was there. You know, it's really a matter of economics. And the wells... They do treat at higher pressures when they frack, but they also frack very consistently. The pressures don't just go up and down and go all over the place. That would obviously make it a lot more difficult. So they frack very consistently, which makes it easier to frack them at the high pressures. So we've had pretty good costs there. Not cost fluctuation, I mean consistent on the cost also on the completion side. We also have, a few years ago, we started drilling out these long laterals with snubbing units using a stick pipe. You can basically handle higher pressured wells with that than with coil tubing. And so we've had great success in that regard also that's helped us out with these wells. So really, I mean, the completion side, everything's just clicking along really good. We'll get some cost savings from our vendor there. And then really on the drilling side, it's just the gains we're seeing, just basically shaving days off these wells.

Great. Thanks a lot.

Yes, sir. Good question.

Thank you. One moment for our next question.

And our next question comes from the line of Paul Diamond from Citi. Your question, please.

Thank you. Good morning. Thanks for taking the call. Just a quick, I want to touch base on some of the DNC costs in slide 15. Just wanted to get an idea of your guys' view on how much of that shipped in, shipped out and drilling is deflationary or how much should we think about that as sticky and kind of inverse for completions? How much should we expect that to be sticky going forward?

I think, so going forward this year, I think we're still, obviously with the activity, we're going to still see the deflation occurring. I mean, we still are seeing maybe another 10% cost into this, you know, this year versus the last year. I'd say more on the, you know, the completion side is a little bit more predictable, I would say. Just need to get, you know, it's just going to basically be lower prices from everybody. The drilling side, because the Western Hainesville is going to be a big component of our program this year, you know, it's also going to be on the drilling side, just the

increased performance less days to td you know for for the uh cost savings along with just the you know vendor pricing coming down understood and just kind of circle back on that towards the western haynesville the as far as like drilling days and this operational improvements are we towards you guys view are we towards the end of those or that improvement trend or is this kind of just the beginning

Oh, no. Well, we've made some pretty good improvements, but we've still got a lot of them in the pipeline coming. I mean, we're in the middle of some of those right now, and we definitely see a lot more days getting cut off these wells from even where we're at today. So, I mean, as far as trying to say in the middle, I'd say maybe that's probably maybe somewhere in there in the middle. I mean, we've probably shaved off 20 days off these things since the first couple of wells we drilled, and we still see You know, that kind of potential going forward.

Got it. So another potential 20 days decline in the drilling time.

Yes, sir. Good.

Thanks for your time. Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to Jay Ellis and Freddie for the remarks.

First of all, I'd like to thank all of you for your questions. They make us better managers. Hopefully we have shown you that we've started and I think we've been very proactive to batten down the hatch to protect our balance sheet. You know, we were very proactive on our operations arena to release the frack crew and the two rigs. You know, the underlying denominator of everything is stellar drilling performance and stellar inventory in our core area and that area we operate. And you look at the Western Angel, I mean, almost half our footprint corporately is in the Western Angel. Those wells look very promising. So, again, we know that it's a stressful time, but we do want to assure you that we're going to continue to manage this company with a steady hand, and we want to wish you all a happy Valentine's Day. So thank you for your time.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day. Hello. Thank you. Thank you. Thank you. Thank you for standing by and welcome to the CompStock Resources fourth quarter 2023 earnings conference call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during this session, you'll need to press star 1-1 on your telephone. If your question has been answered and you'd like to remove yourself from the queue, simply press star 1-1 again. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Jay Ellison.

chairman and ceo please go ahead sir all right jonathan i love that broadcasting voice uh kind of starts the day off right uh our corporate team of 255 strong i want to thank you for joining the call this morning and we wish you a happy valentine's day being a pure play natural gas company in a sub two dollar natural gas market calls for decisive actions to weather the volatility and at the same time continue positioning Comstock to benefit from the longer-term growth in natural gas demand in the foreseeable future. America will need to deliver an additional 10 billion cubic feet of natural gas per day to the LNG facilities currently under construction in the next few years, actions taken so far as we batten down the hatches to protect our balance sheet. Number one, In January, we released a frack crew. Number two. Several months ago, we gave notice to release two rigs, and they will both be finished, their work, by the end of this month. Number three. We suspended our quarterly dividend until natural gas prices improved. Number four. We continually evaluate our activity level as we plan to fund our drilling program within operating cash flow, if possible. Number five. We formed our midstream joint venture last year that allows us to build out the Western Hainesville midstream assets to be funded by the midstream partnership and not burden our operating cash flow at Comstock. Number six, we're positioned Comstock to have very few rigs needed to hold all of our corporate acres, including the 250 plus thousand net acres in the Western Hainesville. Number seven, We're bullish on the long-term outlook for natural gas and are growing our resource base in the advantage proximity to the Gulf Coast market. Number eight, lastly, our Western Hainesville, quote, box of chocolate on its Valentine's Day allows us to maturely grow our drilling inventory organically versus through the M&A market. I can also assure you that our majority stockholder The Jerry Jones family is in 100% approval of all of our prior actions, as well as our recent moves to protect our balance sheet in this volatile natural gas market. They are in the cockpit with us, helping fly this plane with a steady hand on the throttle, looking into the future where global natural gas markets are counting on our U.S. gas to provide needed clean energy. Our goal is to look back on this point in time in the future years and say we handled it well and continue to create corporate value in a weak period for natural gas. Now I'll go over to the corporate script. Welcome to the Comstock Resources Fourth 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 and downloading the quarterly results presentation. There you will find a presentation entitled Fourth Quarter 2023 Results. I'm Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer. And Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within a meeting 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. Fourth quarter 2023 highlights. On slide three, we summarize the highlights of the fourth quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and gas sales, including hedging, were $354 million in the quarter. We generated cash flow from operations of $207 million, or $0.75 per share, and adjusted EBITDAX was $244 million. Our adjusted net income was $0.10 for the quarter. We continue to have very strong results from our drilling program. In the fourth quarter, we drilled 13.3 net successful operated Hainesville and Bossier Shell horizontal wells in the quarter with an average lateral length of 8,994 feet since the last conference call. We've connected 22 or 16.5 net operated Welsh to cells with an average initial production rate of 24 million cubic feet per day and an average lateral length of 11,966 feet. Our 2023 drilling program replaced 109% of our 2023 production with new approved reserves ads. We are continuing to make progress in our Western Angel exploratory plate We added 23,000 net acres to our expensive Western Hainesville acreage position in the fourth quarter alone, increasing our total acreage position in the play to over 250,000 net acres. We recently turned our eighth well to sales. The needle well was completed in the Hainesville formation and is currently producing at 31 million cubic feet per day. Three additional wells, the Harrison, Glass, and Farley wells, are expected to come on production by the end of the first quarter. I'll now have Roland go over the fourth quarter and the annual financial results. Roland?

Thanks, Jay. On slide four, we cover our fourth quarter financial results. Our production in the fourth quarter of 1.5 BCFA per day increased 6% for the fourth quarter of 2022 and grew 8% from the third quarter. Low natural gas prices resulted in our oil and gas sales in the quarter coming in at $354 million, declining 37% from 2022's fourth quarter despite the higher production level. EBITDAX for the quarter came in at $244 million, and we generated $207 million of cash flow in the fourth quarter. We reported adjusted net income of $28 million for the fourth quarter, or $0.10 per share, as compared to a net income of $12 million in the third quarter of 2023, and $288 million in the fourth quarter of 2022. Slide 5, we show the financial results for the full year, 2023. Our production averaged 1.4 BCFE per day, which was a 5% increase from the prior year. Oil and gas sales in 2023 totaled $1.3 billion, and we're 41% lower than our sales in 2022 due to the lower gas prices we realized. Our EBITDA in 2023 was $928 million and we generated $774 million of cash flow for the year. We reported net income of $133 million for 2023 as compared to net income of $1 billion in 2022. Slide six, we show our natural gas price realizations that we had in the quarter. During the fourth quarter, the quarterly NYMEX settlement gas price averaged $2.88, which was 14 cents higher than the average Henry Hemp spot price in the quarter of $2.74. Our realized gas price during the fourth quarter averaged $2.48, reflecting a 40 cent differential to the settlement price and a 32 cent differential to our reference price. The differentials were a little wider in the quarter starting in October, which normally occurs as we reach the end of storage injection period. In the fourth quarter, we were 16% hedged, and that improved our realized gas price for the quarter to $2.51. We've also been using some of our excess transportation in the Hainesville to buy and resell third-party gas. We generated about $4.4 million of profits in the fourth quarter, and that approved our gas price realization by another 3 cents in the quarter. On slide 7, we detail the operating cost per MCFE and our EBITDAX margin. Our operating cost per MCFE averaged 81 cents in the fourth quarter, 4% lower than the third quarter. Lower gathering costs were offset, though, by higher production and ad valorem taxes. Our gathering costs were down 3 cents to 33 cents during the quarter, and our lifting costs were also one cent lower than the third quarter rate at 23 cents. Our production ad valorem taxes increased three cents from the third quarter level, and G&A came in at two cents per MCFE, which was three cents lower than the third quarter. Our EBITDAX margin after hedging came in at 68% in the fourth quarter, up from the 65% level we had in the previous quarter. On slide 8, we recap our spending on drilling and other development activity in 2023. We spent a total of $1.3 billion on our development activities, including $1.2 billion on our Hainesville and Bossier Shale drilling program. Spending on other development activity, including installing production tubing, offset frack protection, and other workovers, totaled $54 million. In 2023, we drilled 67 wells or 55.5 wells net to our interest. In turn, 74 or 55.7 net operated wells to sales. These wells had an overall average IP rate of 25 million pbp per day per well. On slide 9, we cover our natural gas and oil reserves that were determined using the required SEC prices. Our SEC-approved reserves decreased 26% in 2023 to 4.9 TCFE due to the low gas price used in that determination. The required SEC gas price decreased 60% for 2023 to $2.39 per MCF, down from the $6.03 that was used in 2022. Our 2023 drilling activity added 571 BCFE approved reserves to our year end reserves, which replaced 109% of our 2023 production. But we also had 1.8 TCFE of negative revisions due to the lower proved undeveloped reserves caused by our reduction in drilling activity and the low natural gas price that was used to determine which undrilled locations we would drill. In addition to the total 4.9 TCFE of SEC-approved reserves that we had at the end of the year, we have another half of TCFE-approved undeveloped reserves that aren't included as they are not expected to be drilled within the five-year required time period required by the SEC rules. We also have another almost TCFE of 2P or probable reserves and 4.6 TCFE of 3P or possible reserves for a total reserve base of around 10.9 TCFE on a P3 basis, all determined at the low SEC pricing. On Slot 10, we've used a NYMEX gas price of $3.50 per MCF to determine the reserves to show the impact of the low prices on the year-end reserves. Using this price, our approved reserves would have been similar to last year at 6.6 TCFE. In addition, our overall reserves, we would have had an additional of another two TCFE-approved undeveloped reserves that are outside the five-year period. And then we would have 2.5 TCFE of 2P of probable reserves and another 8.7 TCFE of 3P or possible reserves for a total overall reserve base of 19.8 TCFE on a P3 basis, all determined at a 350 NYMEX gas price, which and our view lined up closer to the long-term futures prices for natural gas. On slide 11, we recap our balance sheet at the end of 2023. We did end the quarter with $580 million of borrowings under our credit facility, giving us a total of $2.7 billion in debt, including our outstanding senior notes. Our borrowing base for our bank credit facility is currently at $2 billion, of which we have an elected commitment of 1.5 billion of that amount. So we ended the year with overall financial liquidity of just over a billion dollars. I'll now turn it over to Dan to kind of discuss our operations in more detail.

Okay. Thank you, Roland. Overall slide 12, this shows where our current drilling inventory stands at the end of the year, end of the fourth quarter. Our inventory is split between our Hainesville and Bossier locations. We have it divided up into four buckets. Our short laterals run up to 5,000 feet. Our medium laterals run between 5,000 and 8,500 feet. We have our long laterals between 8,500 and 10,000 feet. And then our extra long laterals extending out beyond 10,000 feet. Our total operated inventory currently stands at 1,706 gross locations and 1,303 net locations. This equates to a 76% average working interest across our operated inventory. Our non-operated inventory has 1,253 gross locations and 160 net locations. This represents a 13% average working interest across the non-operated inventory. If you break down our gross operated inventory, we have 291 short laterals, 347 medium-length laterals, 438 long laterals, and 630 extra long laterals. The gross operated inventory is split 51% in the Hounsville and 49% in the Bossier. 37% of our gross operated inventory or 630 locations have laterals greater than 10,000 feet, and 63% of the gross operating inventory has laterals exceeding 8,500 feet. The average lateral length in our inventory now stands at 8,971 feet, and this is up slightly from 8,949 at the end of the third quarter. Our inventory provides us with 25 years of future drilling locations. On slide 13 is a chart outlining our progress to date on our average lateral length drilled based on the wells that we turned to cells. During the fourth quarter, we turned 17 wells to cells with an average length of 11,870 foot. And this is thanks to the continued success of our long lateral drilling program. The individual lengths ranged from 5,736 feet up to 15,243 feet. while our record longest lateral still stands at 15,726 feet. During the fourth quarter, 12 of the 17 wells we turned to sales had laterals exceeding 10,000 feet, including seven of those wells longer than 14,000 feet. To date, we have drilled a total of 80 wells with laterals over 10,000 feet long and 28 wells with laterals over 14,000 feet. During the fourth quarter, we didn't turn any wells to cells on our new Western Hainesville acreage. Today, in 2024, we have turned one well to cells in the Western Hainesville and we do expect a total of four wells to be turned to cells by the end of the first quarter. In 2023, we turned a total of 74 wells to cells with an average lateral length of 10,820 feet. And this is up 8% from our 2022 average lateral length of 9,989 feet. Slide 14 outlines our new well activity. We have turned the sales and tested 22 new wells since the time of our last call. The individual IP rates range from 9 million a day up to 42 million a day with an average test rate of 24 million cubic feet a day. The average lateral length was 11,966 feet with the individual laterals ranging from 5,736 feet up to a 15,243 foot lateral. The Hamilton Verhalen B number two well located in East Texas which had a nine million a day IP rate suffered a mechanical casing failure during completion which resulted in this well producing from only half of the completed lateral. In addition to the first seven wells producing in the Western Hainesville at the end of 2023, we recently placed our eighth well online. The Neyland number one was drilled in the Hainesville and today it's currently producing 31 million cubic feet a day. This well is still in the process of being tested and cleaning up. We do anticipate three additional wells being turned to sales by the end of the first quarter. We currently have two rigs running on our Western Hainesville acreage. and we are currently planning to keep two rigs running in the western hazel for the remainder of the year. On slide 15, this summarizes our D&C costs through the fourth quarter for our Mitchmark long lateral wells that are located on our legacy core East Texas and North Louisiana acreage. This covers all our wells having laterals greater than 8,500 feet long. During the quarter, we turned 17 wells to sales that were on our core East Texas and North Louisiana acreage. 13 of the 17 wells were our benchmark long-ladder wells. In the fourth quarter, our DNC cost averaged $1,482 a foot on the 13 benchmark long-ladder wells. And this reflects a 5% decrease compared to the third quarter. Our fourth quarter drilling cost averaged $610 a foot, which is a 15% decrease compared to the third quarter. The lower drilling cost reflects a slight downward trend on pricing we've experienced throughout 2023, and also our drilling cost in the third quarter was abnormally higher due to some drilling issues we had in that quarter. Our fourth quarter completion cost came in at $871 a foot, which is a 3% increase compared to the third quarter. The increase in completion costs were primarily attributable to some slightly higher plug drill out cost in the fourth quarter due to the longer laterals. We currently have seven rigs running. We are in the process of releasing one rig this weekend, and end of the month, early next month, we'll be releasing a second rig. We currently expect to run five rigs for the rest of 2024. On the completion side, we are currently running two frac crews. We do expect to maintain one to two frac crews running for the remainder of the year. I'll now hand the call back over to Jake.

Thank you, Dan. Thank you, Roland. If you'll turn to slide 16, we'll summarize our outlook for 2024. We remain very focused on proving up our Western Hainesville play and continuing to add to our extensive acreage position in this exciting play. At the end of 2023, our Western Hainesville acreage position totaled over 250,000 net acres. Following the creation of our mid-spring joint venture late last year, the capital costs associated with the build-out of the mid-spring assets in Western Hainesville will be funded by the Mid-Spring Partnership and will not be a burden on our operating cash flow. We believe that we are building a great asset in the Western Angle that will 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 that begins to show up in the second half of next year. We're actively managing our drilling activity level to prudently respond to the current low gas price environment. We have already released one of our three completion crews, as Dan said, and two of our operated rigs on our legacy Hainesville footprint, bringing our total operated rig count to five rigs, of which two are drilling in the western Hainesville. We are focused on preserving our balance sheet in this gas price environment. We'll continue to evaluate our activity level as we plan to fund our drilling program within operating cash flow. We are going to suspend our quarterly dividend until natural gas prices improve. 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. And lastly, We'll continue to maintain our very strong financial liquidity, which totaled around a billion dollars at the end of the fourth quarter. I'll now have Ron provide some specific guidance for the rest of the year. Ron? Thanks, Jay.

On slide 17, we provide the updated financial guidance for the first quarter of this year and the full year. First quarter, DNC CapEx. Guidance is $225 to $275 million, and the full-year E&C CapEx guidance is $750 to $850 million. The lower spending versus last year is related to the announced release of two drilling rigs in our press release last night in response to low gas prices. We've continued to see signs of some deflationary pressures on service costs, including an improvement in our completion costs per stage. We anticipate spending an additional $30 to $40 million on lease acquisitions in the first quarter and $40 to $50 million over the course of the year. Capital expenditures related to Pinnacle Cast Services will be funded by our midstream partner and are expected to total $30 to $40 million in the first quarter and $125 to $150 million for the full year. For both the First quarter and the full year, our LOE is expected to be in a range of $0.24 to $0.28 per MCFE. GTC are expected to be $0.32 to $0.36 per MCFE. And production and ad valorem taxes are expected to average $0.16 to $0.20 per MCFE. DG&A rate is expected to average $1.30 to $1.40 per MCF this year. In the first quarter, our cash GNA is expected to total $7 to $9 million and $30 to $34 million for the full year. In addition, we'll have non-cash GNA in the first quarter of $2.7 to $3 million and $10 to $12 million for the full year. With the increase in SOFA rates and our current debt levels, Cash interest expense is now expected to total $43 to $47 million in the first quarter and $195 to $205 million for the year, while non-cash interest will remain approximately $2 million per quarter. Effective tax rate will remain in the 22 to 25% range, and we continue to expect to defer 95 to 100% of our reported taxes this year. We'll now turn the call back over to the operator. to answer questions from analysts who follow the company.

Certainly. One moment for our first question. And our first question for today comes from the line of Derek Whitfield from Steeple Financial. Your question, please. Good morning, all, and thanks for your time.

Yes, sir.

Let me first commend you on a strong year end in your decision to reduce capital outflows in the current depressed gas price environment. With respect to your 2024 outlook, could you speak to the average gas price that underpins your spending within cash flow view? Any additional steps you'd likely take to further reduce capital if gas continues to deteriorate?

Yeah, Derek. I mean, of course, that's a moving target where gas prices are. And I think that probably where the gas price was in the market maybe about two or three weeks ago is probably exactly where that's in balance. It's going to be a volatile deal, but I think the things that we'll continue to monitor are what are our service costs. They are trending down a little bit as far as some deflationary actions happening on that side. The other levers that we can pull are continue to look at dropping another rig. That's the most effective way to reduce capital expenditures that has the most impact on creating net operating cash flow. And so that's what we'll continue to monitor the activity like we do each year and look to tighten up the ship wherever we can to kind of maximize the operating dollars that we have.

That's my follow-up. I wanted to shift over to the Western Hainesville with the understanding that it's a long game resource. Could you speak to the gains you're experiencing in operational efficiency, the degree you're expecting your break even to improve over time, and if you're expecting a meaningful difference in the break even between the Hainesville and Bossier intervals?

This is Dan. I'd say we're definitely gaining ground and going up the curve still faster on our Western Hainesville wells. We are, you know, we're drilling our first two-well pad actually currently. We got to know what the second rig is going to its first two-well pad next. That's going to definitely help our efficiency there. We still have had some things that we've gained on on the drilling front that's still increasing our drill times. And we still see a little bit more running room there to get faster. So I think, you know, we definitely are seeing an increase there in the western Hainesville wells, and we're seeing those costs come down. In the core area, you know, probably as far as the moving the needle on efficiency, probably not as much. I mean, we've been there for a long time and got everything pretty streamlined. But, you know, down to the two frack crews, same vendor, we see some kind of some savings there, just really, really good solid performance. We brought in some three, you know, three new rigs, new build rigs. So just, I think we're going to have some better performance there just kind of overall. So I think we will, and of course we're seeing the cost savings come down with the activity levels. We're probably down 10% or so this year since the beginning of last year. And, you know, obviously difficult times, you know, we, I think everybody gets pretty streamlined and pretty efficient and the costs come down, but Obviously, we'd like to see maybe prices be a lot higher, you know, and be battling some of those things. But, yes, that's where we're at.

Very helpful. Thanks for your time. Thank you. One moment for our next question. And our next question comes from the line of Charles Mead from Johnson Rice. Your question, please.

Good morning, Jay. To you and your whole team there, Comstock.

Good morning.

Dan, I'm going to start with just a really quick clarifying question with you. I think I heard you say in your pair of comments that you're planning on running between one and two completion crews for the remainder of the year. Did I catch that right?

That's right. So if you just do the math, I mean, we've got kind of two dedicated fleets to us, but if you do the math with the number of wells we're going to turn to sales, it comes out to like 1.7 track crews is what we'll need this year. Got it. Got it. One running full-time and one, you know, with some gaps in between.

Got it. And then my follow-up, Jay, and I recognize that this is kind of a maybe simplistic way to start this, but, you know, I recognize you guys look at a lot more data and have a lot more considerations than somebody sitting in my chair does. But in my chair, you know, I look at the – the futures curve here. And we don't get above, we don't get two bucks until July. And so for my seat, it looks to me like the right number of completion crews to be running right now for at least the next several months is zero. And, you know, I recognize that's not a realistic case, but can you bridge the pieces to, you know, kind of bridge the view for, you know, it looks like the right number is zero, but why the right number for you guys is is 1.7 or 1 to 2 for the next several months?

Well, I think that's a really good question. Number one, I think if you look at how proactive we've been, typically on a conference call like this, you're going to release a FRAC crew. We've already done that. Second of all, maybe you have contracted to have that FRAC crew and you have to use them. We don't have any contracts. It's a will by will. Now, I think the other thing, just as far as cost, I mean, usually in a conference call like this, you're going to release two rigs, and it takes two or three, four months to release those rigs. And we were proactive back in December to give notice. And as Dan has said, we'll have both of those released by the beginning of March is our goal. So then, you know, Roland was asked a question about the price of natural gas to stay with an operating cash flow, which is kind of your question. I think what we tell you is that that is our goal. It's to tell you that we don't plan on spending as much money on acreage procurement as we have in the past. It tells you that probably half of our acreage that we own right now is Western Hainesville. The other half is a core. And it tells you that we're not inventory starved. So we don't have to do deals in the market whether gas prices are high or low in order to buy inventory. So then you come and you look at the cost, and we look at deflation. I mean, Dan goes over some of the cost savings that we've had from the frack company so far, and some of the cost savings we've had in drilling and completing the wells. I think all we can do is tell you that we've looked at those numbers. We've looked at hedging. You know, we've hedged about 28% of our production in 24 to 355 swaps. I think that we need to be in the 50% range. Now, you know, when will we get there? I don't know. But I think you and the market need to know that it is a corporate goal that we have. And the reason that we use kind of batting down the hatch as a theme is because if we need to delay some practice, we see that in the next month or so, then I think we can do that. If we need to lay down another rig, we'll have the optionality to do that. So again, I think your goal is, you know, how are you going to protect this thing? And that's one reason I always say, if you look at the major shareholder who owns 65% of this, if anybody's trying to protect it, the Jones family is, and they're well involved with what we do. And then I think you have to look at any minimum volume commitments or farm transportation agreements that you have and say, Are we impacted by reducing the recount? And the answer is we're not. So you have to look at all those things too when you ask that question. But we're going to continue to manage this just like we've managed it for a while. We as a group, you know, we recognize pain. I mean, some groups haven't recognized it because they haven't experienced it. We do. So it's a good thing. It's an indicator. And whatever we need to do to right this ship, that's what we plan on doing. So that's a great question.

Thank you for that elaboration. That was helpful, Jeb.

Yes, sir.

Thank you. One moment for our next question.

And our next question comes from the line of Fernando Zavala from Pickering Energy Partners. Your question, please.

Hey, guys. Good morning. Kind of going back to your comments around evaluating dropping another rig, where would that rig come from? Would it come from the western Hainesville or the core Hainesville?

If we dropped another rig, it would be in the core. It would not be the western Hainesville.

Okay. Got it. And then can you talk a little bit about the – this is my follow-up – the trajectory of production in 2024? You know, it seems like the implied 2024 guidance is in line with first quarter, so just a little bit more color there.

Yeah, if you think about the timeframe related to dropping a rig and starting to show up in terms of impacting production, Dan mentioned we were dropping the first of those two rigs here this weekend and the second rig within the next within the next two to three weeks i think he he said and so when you just like when you add a rig when you drop a rig there's plus or minus a six or seven month lag between the timing of of changing your activity level and having it flow through to production so that's why the the first half of the year production should remain relatively flat and you start to see a little bit of a decline in the third quarter and a little bit larger decline in the fourth quarter as you start to feel the full brunt of running five rigs.

Okay, that's helpful. Thank you. Thank you. One moment for our next question. And our next question. comes from the line of Jacob Roberts from TPH and Company. Your question, please.

Morning.

Morning. Morning. Morning.

I think previously you've had some commentary about joint commitments and HPP provisions on the Western Hainesville. Can you speak to the impact of running those two rigs for 2024 and any needed extensions or perhaps capture provisions to be needed in 2025 plus?

No, we feel like that, you know, that not running the three rigs like we originally anticipated this year, that that's not going to put us that far behind, and we won't really have to alter, you know, our future plans, you know, by taking this, you know, a little bit slower approach in 24. You know, but over a longer period of time, you know, we have a lot of acres to, the term acreage that, you know, has to be, we have to drill to hold, so. But given the actions we're taking this year, we're not really changing, you know, having to know that we have to extend leases, et cetera. We still can keep all these kind of on track.

You know, in fact, I think the slowdown is a positive in that in the Western Hainesville, as Dan said earlier, most of the wells we'll be drilling now will be two wells per pad. We have been drilling one well per pad. I think it lets our land group now get ahead a little bit for 25 and 26 because we have added a lot of acreage within a small window. I think it lets us position our wells better in 24 and 25 to de-risk a lot greater swath of acreage with fewer wells. So it really has been, the slowdown has served our land group a well. And as Roland said, and Dan will tell you, it has not impacted really the drilling. They think we'll add another rig in 25, like we were going to do in 24. But, you know, the results will speak for themselves. And so far, the results have been really good. They've been stellar for the acreage that we have and the area that we de-risk. which is probably from the hill to our northern well, probably 20, three or four miles. We've said that publicly. We've got a lot of acreage we de-risked there. So it looks good, and I think this environment is favorable for us to slow that down.

Thank you for that. My second question is around the leasing program that seems to have bled over from 23 to 2024 and is pretty heavily focused in the first quarter of the year. Can you just provide any detail on what caused some of those conversations to fall into this year? Has the process become more competitive? And maybe if you can, a sense of the scale of the remaining transactions in the pipeline. Thank you.

The process definitely has not become more competitive with the weak gas price environment, you know, and We're leasing from lots of different parties. There's lots of reasons why you don't actually close something you're working on. I don't think there's any significant trend there. We are rounding up where we've captured a lot of the acreage in the areas that we think are the most prospective for the play. That's really driving the program forward. More than anything else, it's just we're finishing up.

Great. Appreciate the time.

Well, you know, Luke stated that we average about $550 an acre, and in fact, at $1.61 gas, which is where we are right now, which I don't think I've read that we hadn't been this low since spring of 2016, so eight years, I can promise you there's no competition out there at $1.61 at all.

Thank you one moment for our next question. And our next question comes to the line of Bertrand Daum from Truist. Your question, please.

Hey, good morning, guys. Morning. Morning.

This one might be a little bit weird, and I'm not saying it's necessary, but if it did become necessary, is there any ability to negotiate with Quantum on the minimum volumes? It seems like you guys have a mutual interest, and even when they revert to 30%, there's probably a an interest in properly managing the asset instead of just kind of hitting a number that was inked at a different gas price. But it was purely out of curiosity.

Well, that level is set so much – far, far lower than our forecast and even our production level now. It's just not even a question to give any thoughts to.

Sounds good. Very succinct. Another one, just to keep them a little bit weird, was there any consideration instead of technically suspending the dividend, instead going to a kind of variable dividend? I just don't know if management has a view on whether or not that has a place or no place, or maybe it just doesn't mesh with the corporate view.

No, we didn't consider that.

Sounds good. I appreciate the answers. Thanks.

Great questions.

Thank you. One moment for our next question.

And our next question comes from the line of Phillips Johnson from Capital One Securities. Your question, please.

Hey, guys. Thanks. My first question is on your three and a half times max leverage ratio covenant. At current strip prices, our model shows that you might be close to reaching that later this year. Would you also see that as a possible risk? And if so, How easy would it be to get a waiver from the banks?

We don't see that. So we don't think that we come that close to that, Phillip. So I think we just continue to monitor our spending level and not use much more of the credit facility.

OK, sounds good. And just to make sure our models are calibrated, as we think about the FIBRID program, what would you expect in that well count to look like for the year in terms of both wells drilled and wells turned to sales?

Rod's got that number.

That's in the press release too. Yeah, it's in the press release. You can read it there, yeah. I guess 40.

Oh, I don't have that email. Hang on. Give me two seconds.

As it says in the press release, we plan to drill 46 gross, and that's about 36 net wells, and turn to sales 44 gross, 38 net.

Okay. Sorry about that. I completely missed that. Thank you.

Thank you. One moment for our next question.

And our next question comes from the line of Leo Marinari from Roth. Your question, please.

I just wanted to quickly follow up on some of the prepared, you know, answers here that you guys had given here. You know, Ron, you talked about production, you know, kind of flattish in the first half of the year, a little bit of a third quarter decline, and then more of a fourth quarter, you know, decline. And of course, I'm sure it's, you know, pretty obvious to you folks that that's a bit inverse to what the futures curve is suggesting, where clearly prices are expected to be lower early in 24 and then higher as you get towards those winter months in 24. So you certainly expressed the belief that you want to be kind of flexible and sort of do what you can to kind of maximize the cash flow. So is there some... some thought to pushing some of those turn-in lines out towards those later quarters and perhaps trying to shift the production a bit so it's a little bit lower this summer and maybe higher next winter? And is there any operational reasons maybe why you couldn't do that? Maybe some of the western Hainesville stuff has provisions or wells have to come online at a certain point in time.

But any color you have there would be great.

Well, you know, I think it's difficult to, you know, under shale, if you don't understand that, timing of shale production and the way that the wells are drilled and all that to try to be, you know, super precise and bring production on, you know, within what the futures curve says it could be now, which it could be different when you get there. I mean, it's not something, I mean, you obviously can give consideration to it and we can give consideration in the field if we have low, you know, spot prices that we, you know, not turn a well on that day, definitely. So you can manage these kind of around that, but, you know, I don't know that you can think that you can direct it, you know, a real precise level because, you know, you could, your assumptions could be wrong and too, plus it takes like, it takes a lot of resources to, you know, to, in preparation to bring these on and you don't have all those available, you know, at the, you know, you can't snap your fingers and get all the wells turned on in one day and, So it's just really balancing all that and balancing it with what you have, the facts you have at the time. Just because we present a plan and budget doesn't mean it's going to happen exactly that way. So we'll adjust as we go through the year to what's going on in the markets and what's available in the spot market or the index market, etc.,

And I'll add specifically to the Western Hainesville, our two frack crews are actually fracking wells there now in the Western Hainesville. So there's really only one other well right behind those, and we don't have anything else coming on in the Western Hainesville until the end of the year because, like I mentioned earlier, we got one rig that just started a two-well pad a couple of weeks ago. And our other rig is getting ready to move to a two-well pad. And obviously, you know, the Western Hanes will take more days to drill. So with two-well pads, you know, they'll be drilling all through the spring and summer and fall.

Got it. Okay, that's helpful color, guys. And I know you can't snap your fingers like you said, Roland, but it sounds like maybe there is. some flexibility to kind of, you know, manage this, you know, a little bit on y'all's end, and I'm sure you're going to be watching it very closely as the year progresses here. Okay, maybe just a follow-up on the Western Haynesville. You obviously had your reserve report out. Can you give any color around, like, what some of these Western Haynesville wells were getting booked at, maybe, like, in terms of, you know, reserves per thousand feet or however you guys want to present it here?

Yeah, and generally, you know, we don't have a lot of bookings because we're We're not trying to get beyond a direct offset as far as booking anything in the western Hainesville. It's still early, and we only had the seven producing wells in total in the play. So there's a limited number of locations in the reserve report, but I would say overall the average kind of reserve bookings are in that 3.5 BCF per 1,000 feet of completed laterals. Only really one well has a pretty significant track record of performance, which is the first one, the Circle M. And, you know, it was upwardly revised, you know, with this. It's kind of outperformed that. The rest of the wells, you know, don't have near the number of months after production. So kind of left them, you know, where they are. But, you know, the reserves are trending nicely in the play for the first wells that we've drilled.

Okay, that's great, Collin, and certainly appreciate that. And just lastly for me here, just obviously I don't think gas has turned out like anyone expected, you know, in 2024 here. It sounds like the plan is to really not kind of add debt from what I'm hearing, you know, from you here, Roland, and I guess just to the extent that, you know, for whatever reason, let's say next winter's warm and it's kind of a weaker start, you know, to the year. Hopefully that's not the case, but, you know, if that is, I mean... you know, are you still in a position where you don't want to add debt or do you have to have maybe a little bit more activity next year because of holding some of the Western Haynesville and were there any consideration of maybe putting in some, I'll call it near-term funding to kind of get you over the gap here until markets improve, you know, later in 25 and 26?

I think we position ourselves right now so that the things that we've done allow us to protect our balance sheet. I mean, if you just segregated and you look at the Western Hainesville, like Dan said, these wells will be slower to reach production. So even though we didn't add a third rig, I mean, as Raul mentioned, we're not going to have any issues with our midstream quantities. So I don't see an issue there. And then I think as far as any obligations we have to drill the complete wells, we don't have any obligations there. And we, as we said, we were very, very proactive even in December, much less January, February, to cut some costs uh so i think we're just monitored like that there's if we need to lay down another rig if we need to defer completions all of those things uh those are those are all in the hopper that we'll look at to do so uh even in in a in a in a very tough market i think we've got a lot of uh switches to pull uh to protect where we are and the bottom line is we're just so rich in inventory that we just have to protect what we already own, period. We don't have to breach the Tenth Commandment and covet everybody else's inventory. We just have to continue to perform on the Western Angle. Like Roland said, I mean, the EURs look solid. Dan said the costs are coming down. It's still early innings. But we've captured a lot of acreage, and we'll just see what the storybook tells us in the future.

Okay.

Appreciate the caller. Yes, sir. Thank you. One moment for our next question. And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Your question, please.

Hey, good morning. I love Noel. I just wanted to touch again on the Western Hainesville. I just wondered, can you talk a little bit about what kind of science you're doing on the latest Western Hainesville wells? Sort of like what are you most interested in learning about next as far as just your drilling practices, for instance?

Well, I mean, so we've, you know, I think we've stated before, you know, probably the biggest – difference between the Western Hainesville and our core is the temperature, you know, in the depth. I mean, obviously, they're a little bit deeper. If you just look at the TVDs of the wells, and, of course, with that comes temperature. And we've just really done a really good job at managing the temperature. And when I say that, manage it, getting our, you know, bottom hole assemblies to perform and stay on bottom longer. Faster ROPs, less trips in and out of the hole to get the lateral drill. So we've made a lot of gains there. And then just up top, you've got obviously a longer vertical section to drill. We've made some modifications to our casing design. We've seen our penetration rates pick up up top also. So you just kind of got to attack everything. And we don't have all of those things. you know, just totally, you know, kind of maxed out like we do in the core. I mean, in the core, we just kind of make some tweaks a little bit here and there, and you pick up a day or two. But, you know, we're picking up bigger chunks down here in the western Hainesville, just figuring this thing out.

And are you at a point where productivity of the rock is pretty much not a surprise anymore, or are you still learning things there?

I'd say the rocks turned out, I mean, we knew, everybody knows that the gas is there. There were two old wells drilled back in like 2010 and 2011 that we got data on. They had all kinds of problems, had the very inferior completions put on them. But, you know, still with that, you know, they still made a decent amount of gas. So we knew the gas was there. You know, it's really a matter of economics. And the wells... They do treat at higher pressures when they frack, but they also frack very consistently. The pressures don't just go up and down and go all over the place. That would obviously make it a lot more difficult. So they frack very consistently, which makes it easier to frack them at the high pressures. So we've had pretty good costs there. Not cost fluctuation, I mean consistent on the cost also on the completion side. We also have, a few years ago, we started drilling out these long laterals with snubbing units using a stick pipe. You can basically handle higher pressured wells with that than with coil tubing. And so we've had great success in that regard also that's helped us out with these wells. So really, I mean, the completion side, everything's just clicking along really good. We'll get some cost savings from our vendor there. And then really on the drilling side, it's just the gains we're seeing, just basically shaving days off these wells.

Great. Thanks a lot.

Yes, sir.

Good question.

Thank you. One moment for our next question.

And our next question comes from the line of Paul Diamond from Citi. Your question, please.

Thank you. Good morning. Thanks for taking the call. Just a quick, I want to touch base on some of the DNC costs in slide 15. Just wanted to get an idea of your guys' view on how much of that shipped in, shipped out and drilling is deflationary or how much should we think about that as sticky and kind of inverse for completions? How much should we expect that to be sticky going forward?

I think, so going forward this year, I think we're still, obviously with the activity, we're going to still see the deflation occurring i mean we still are seeing maybe another 10 percent cost into this uh you know this year versus the last year uh save more on the you know the completion side is a little bit more predictable uh i would say i just need to get you know it's just going to basically be lower prices from everybody the drilling side because the western hainesville is going to be a big component of our program this year you know it's also going to be on the drilling side just uh

increased performance less days to td you know for for the uh cost savings along with just the you know vendor pricing coming down understood and just kind of circle back on that towards the western haynesville the as far as like drilling days and this operational improvements are we towards you guys view are we towards the end of those or that improvement trend or is this kind of just the beginning

Oh, no. Well, we've made some pretty good improvements, but we've still got a lot of them in the pipeline coming. I mean, we're in the middle of some of those right now, and we definitely see a lot more days getting cut off these wells from even where we're at today. So, I mean, as far as trying to say in the middle, I'd say maybe that's probably maybe somewhere in there in the middle. I mean, we've probably shaved off 20 days off these things since the first couple of wells we drilled, and we still see You know, that kind of potential going forward.

Got it. So another potential 20 days decline in the drilling time.

Yes, sir.

Good.

Thanks for your time.

Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to Jay Ellis and Freddie for the remarks.

First of all, I'd like to thank all of you for your questions. They make us better managers. Hopefully, we have shown you that we've started, and I think we've been very proactive to batten down the hatch to protect our balance sheet. You know, we were very proactive on our operations arena to release the frack crew and the two rigs. You know, the underlying denominator of everything is stellar drilling performance and stellar inventory in our core area, and that area we operate in. And you look at the Western Angel, I mean, almost half our footprint corporately is in the Western Angel. Those wells look very promising. So, again, we know that it's a stressful time, but we do want to assure you that we're going to continue to manage this company with a steady hand, and we want to wish you all a happy Valentine's Day. So thank you for your time.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.