Thank you for standing by and welcome to the Comstock Resources Fourth Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen-only mode. After this speaker's presentation, there will be a question-and-answer session. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Jay Allison, Chairman and CEO. Please go ahead, sir.

All right, Jonathan. I love that broadcasting voice; it kind of starts the day off right. 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 $2 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 frac crew. Number two, several months ago, we gave notice to release two rigs and they will both finish their work by the end of this month. Number three, we suspended our quarterly dividend until natural gas prices improve. 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 mid-stream joint venture last year that allows us to build out the Western Haynesville midstream assets to be funded by the midstream partnership and not burden our operating cash flow at Comstock. Number six, we've positioned Comstock to have very few rigs needed to hold all of our corporate acres, including the 250,000 plus net acres in the Western Haynesville. Number seven, we're bullish on the long term outlook for natural gas and are growing our resource base in close proximity to the Gulf Coast market. Number eight, lastly, our Western Haynesville 'box of chocolate' on its Valentine's Day allows us to materially 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 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 US 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 continued 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 and 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 14 or 13.3 net successful operated Haynesville and Bossier shale 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 wells to sales 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 proved reserves adds. We are continuing to make progress in our Western Haynesville exploratory play. We added 23,000 net acres to our extensive Western Haynesville 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 Neyland well was completed in the Haynesville 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% from 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. On slide five, 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 were 41% lower than our sales in 2022 due to the lower gas prices we realized. Our EBITDAX 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. On 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 $0.14 higher than the average Henry Hub spot price in the quarter of $2.74. Our realized gas price during the fourth quarter averaged $2.48, reflecting a $0.40 differential to the settlement price, and a $0.32 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 the 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 Haynesville to buy and resell third-party gas. We generated about $4.4 million of profits in the fourth quarter, and that improved 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 $0.01 lower than the third quarter rate at $0.23. Our production ad valorem taxes increased $0.03 from the third-quarter level, and G&A came in at $0.02 per Mcfe, which was $0.03 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 eight, 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 Haynesville and Bossier shale drilling program. Spending on other development activity including installing production tubing, offset frac protection, and other workovers totaled $54 million. In 2023, we drilled 67 wells or 55.5 wells net to our interest and turned 74 or 55.7 net operated wells to sales. These wells had an overall average initial production 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 the 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 Tcfe-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 proved reserves that we had at the end of the year, we have another half a Tcfe of approved undeveloped reserves that aren't included as they are not expected to be drilled within the five-year 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 slide 10, we've used 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 would have had an additional 2 Tcfe of 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 $3.50 NYMEX gas price, which in our view aligns 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 an overall financial liquidity of just over $1 billion. I'll now turn it over to Dan to discuss our operations in more detail.

Okay. Thank you, Roland. Over on slide 12, this shows where our current drilling inventory stands at the end of the year into the fourth quarter. Our inventory is split between our Haynesville 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 feet and 8,500 feet. We have our long laterals between 8,500 feet and 10,000 feet. And then our extra-long laterals extend 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 Haynesville 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 operated 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 and drilled based on the wells that we've turned to sales. During the fourth quarter, we turned 17 wells to sales with an average length of 11,870 feet and this is thanks to the continued success of our long lateral drilling program. The individual lengths range 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 sales on our new Western Haynesville acreage. To date, in 2024, we have turned one well to sales in the Western Haynesville and we do expect a total of four wells to be turned to sales by the end of the first quarter. In 2023, we turned a total of 74 wells to sales 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 to sales and tested 22 new wells since the time of our last call. The individual initial production 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 15,243 feet. The Hamilton Verhalen B number 2 well located in East Texas, which had a 9 million a day initial production rate, suffered 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 Haynesville at the end of 2023, we recently placed our eighth well online. The Neyland number 1 was drilled in the Haynesville and to date, it's currently producing 31 million cubic feet a day. This well is still in the process of being tested and cleaned 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 Haynesville acreage and we are currently planning to keep two rigs running in the Western Haynesville for the remainder of the year. On slide 15, this summarizes our drilling and completion costs through the fourth quarter for our benchmark 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 lateral wells. In the fourth quarter, our drilling and completion cost averaged $1,482 a foot on the 13 benchmark long lateral 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 costs in the third quarter were 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 was primarily attributable to some slightly higher plug drill-out costs 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 by the 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 Jay.

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 Haynesville play and continuing to add to our extensive acreage position in this exciting play. At the end of 2023, our Western Haynesville acreage position totaled over 250,000 net acres. Following the creation of our midstream joint venture late last year, the capital costs associated with the build-out of the midstream assets in Western Haynesville will be funded by the midstream partnership and will not be a burden on our operating cash flow. We believe that we are building a great asset in Western Haynesville 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 are 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 Haynesville footprint, bringing our total operated rig count to five rigs, of which two are drilling in the Western Haynesville. 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 $1 billion at the end of the fourth quarter. I'll now have Ron provide some specific guidance for the rest of the year.

Thanks, Jay. On slide 17, we provide the updated financial guidance for the first quarter of this year and the full year. First quarter D&C CapEx guidance is $225 million to $275 million, and the full year D&C CapEx guidance is $750 million 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 million to $40 million on lease acquisitions in the first quarter and $40 million to $50 million over the course of the year. Capital expenditures related to Pinnacle Gas Services will be funded by our midstream partner and are expected to total $30 million to $40 million in the first quarter and $125 million to $150 million for the full year. For both the first quarter and the full year, our lease operating expenses are expected to be in a range of $0.24 to $0.28 per Mcfe. Gathering and transportation costs 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. The depletion and depreciation rate is expected to average $1.30 to $1.40 per Mcf this year. In the first quarter, our cash general and administrative expenses are expected to total $7 million to $9 million, and $30 million to $34 million for the full year. In addition, we'll have non-cash G&A in the first quarter of $2.7 million to $3 million and $10 million to $12 million for the full year. With the increase in SOFR rates in our current debt levels, cash interest expense is now expected to total $43 million to $47 million in the first quarter and $195 million to $205 million for the year, while non-cash interest will remain at approximately $2 million per quarter. Effective tax rates 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. Our first question for today comes from the line of Derrick Whitfield from Stifel Financial. Your question, please.

Good morning, all, and thanks for your time.

Yes, sir.

Let me first commend you on a strong year-end and 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?

Yes, Derrick, gas prices are constantly changing, and about two or three weeks ago, they were likely at a point where things were balanced. It's going to be quite volatile. We will keep an eye on our service costs, which are slightly decreasing due to some deflationary trends. Another strategy we might consider is reducing the number of rigs, as that significantly lowers capital expenditures and positively impacts our net operating cash flow. We'll continue to track our activities throughout the year and look for ways to streamline operations to maximize the dollars we have available.

Terrific. And as my follow-up, I wanted to shift over to the Western Haynesville, 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 breakevens to improve over time, and if you're expecting a meaningful difference in the breakevens between the Haynesville and Bossier intervals?

So, Derrick, this is Dan. I’d say we’re definitely making progress and improving our Western Haynesville wells at a faster rate. We are currently drilling our first two-well pad, and the second rig will move to its first two-well pad next, which will enhance our efficiency. We’ve made some advancements in drilling that are still helping to reduce our drill times, and we believe there’s still room to improve our speed. We are noticing an increase in our Western Haynesville wells and costs are decreasing in the core area, although the impact on efficiencies is probably not as significant since we’ve been operating there for a long time and have streamlined processes. However, with two frac crews from the same vendor, we are seeing some savings and solid performance. We’ve also brought in three new build rigs that should contribute to better overall performance. We are witnessing cost savings with rising activity levels, likely around a 10% decrease this year compared to the start of last year. During tougher times, companies become more efficient and costs drop, though it would be ideal to see higher prices to counteract some challenges. That summarizes our current position.

Very helpful. Thanks for your time.

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

Good morning, Jay, to you and your whole team there at 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 prepared 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 correct. If you calculate the numbers, we have two dedicated fleets, but based on the number of wells we plan to bring online, we will need approximately 1.7 frac crews this year.

Got it. And then

One running full-time and one with some gaps in between.

Got it. For my follow-up, Jay, I understand this might be a simplistic way to approach the situation, but I know your team analyzes much more data and factors than I do. From my perspective, looking at the futures curve, it seems we won't reach two dollars until July. Therefore, I believe the appropriate number of completion crews to operate over the next few months should be zero. While I acknowledge that may not be practical, could you explain why you see the right number being 1.7 or between one and two for the upcoming 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 well above well. 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, Roland was asked a question about the price of natural gas to stay within 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 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 in Western Haynesville; the other half is 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 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. We've hedged about 28% of our production in '24 at a $3.55 swap. I think that we need to be in the 50% range now. 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 we use kind of bats down the hedge as a theme is because if we need to delay some fracs, we see that in the next month or so, then I think we can do that. If we needed to lay down another rig, we'll have the optionality to do that. So again, I think your goal is, 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 rig count? 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, 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 ride this ship, that's what we plan on doing. So, that's a great question.

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

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 Haynesville or the core Haynesville?

If we dropped another rig, it would be in the core; it would not be the Western Haynesville.

Could you provide an update on the production outlook for 2024? It appears that the guidance for 2024 aligns with what we saw in the first quarter, so I would appreciate some additional insights on that.

If you consider the timeframe for removing a rig and the effect on production, Dan mentioned that we are taking down the first of two rigs this weekend, with the second rig to follow in two to three weeks. Similar to adding a rig, removing one results in a lag of six to seven months before noticeable changes in production occur. Therefore, in the first half of the year, production should remain fairly stable, but we expect a slight decline in the third quarter and a more significant drop in the fourth quarter as we fully experience the impact of operating 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&Co. Your question, please.

Good morning.

Good morning.

Good morning.

Good morning.

I think previously you've had some commentary about joint commitments and HPP provisions on the Western Haynesville; can you speak to the impact of running those two rigs for 2024 and any needed extensions or perhaps catch-up provisions to be needed in 2025 plus?

We believe that not operating the three rigs as initially planned this year won't significantly set us back, and we won't need to adjust our future plans by adopting a slower approach in 2024. Over the long term, we have a substantial amount of acreage that we must drill to maintain our leases. However, given the steps we are taking this year, we can keep everything on track without needing to make major changes, such as extending leases.

I believe the slowdown in the Western Haynesville is actually beneficial. As Dan mentioned earlier, we will now drill two wells per pad instead of one. This allows our land team to get ahead for 2025 and 2026, especially since we've added a significant amount of acreage in a short time. It enables us to position our wells more strategically in 2024 and 2025, thereby reducing risk across a broader area with fewer wells. This slowdown has positively impacted our land group. As Roland stated, and Dan will confirm, we have not seen any negative effects on drilling. I expect we will add another rig in 2025, just as we planned for 2024, and the outcomes will demonstrate our success. So far, our results have been impressive, especially for the acreage we hold. The area we've de-risked stretches roughly 23 to 24 miles, from the hill to our northern well, and we have effectively de-risked a lot of acreage there, which looks promising. I believe this environment is advantageous for deliberately slowing our pace.

Thanks for that. My second question is around the leasing program that seems to have bled over from '23 into 2024, and it's 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 has not become more competitive due to the weak gas price environment. However, we are leasing from various parties. There are many reasons why a deal you're working on might not close, so I don't see any significant trend there. We are actively consolidating acreage in the areas we believe are most promising for the play, which is really driving our program, and we are in the final stages of that effort.

Great. Appreciate the time.

We've 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 it, we haven'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 from the line of Bertrand Donnes from Truist. Your question, please.

Hey, good morning, guys.

Good morning.

Good morning.

Good 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 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 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. And then, just to ask something a bit unconventional, was there any consideration to move from technically suspending the dividend to possibly adopting a variable dividend instead? I'm curious if management has an opinion on whether this could be beneficial or if it doesn't align with the corporate vision.

No, we didn't consider that.

Sounds good. I appreciate the answers. Thanks.

Thank you. One moment for our next question. And our next question comes from the line of Phillips Johnston from Capital One Securities. Your question, please.

Hey, everyone. Thank you. My first question is regarding your maximum leverage ratio covenant of 3.5 times. Based on current strip prices, our analysis indicates that you may be approaching that limit later this year. Do you consider this a potential risk, and if so, how difficult would it be to obtain a waiver from the banks?

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

Okay. Sounds good. And just to make sure our models are calibrated. As we think about the five rig program, what would you expect the net well count to look like for the year in terms of both wells drilled and wells turned to sales?

Ron’s got that number.

Yes, it's in the press release as well. Please refer to it there. I don't have that email with me. Just give me a moment. As mentioned in the press release, we plan to drill 46 gross wells, which amounts to about 36 net wells, and we aim to turn 44 gross wells to sales, equating to 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 Mariani from ROTH. Your question, please.

I just wanted to quickly follow-up on some of the prepared answers here that you guys had given here. Ron, you talked about prediction, 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 decline, and of course, I'm sure it's 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 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 Haynesville stuff has provisions or wells have to come online at a certain point in time, but any color you have there would be great.

I think it's challenging to understand shale production without grasping the timing of how wells are drilled and brought online in relation to the futures market, which may differ by the time we get there. While we can definitely consider factors such as low spot prices when deciding whether to turn on a well, it's unlikely that we can manage production with extreme precision because our assumptions might not hold true. Additionally, significant resources are required to prepare for production, and we can't simply turn on all wells at once. It's a matter of balancing these factors with the available resources and the fracking capacity we have at that moment. Just because we have a plan and budget doesn't mean everything will unfold exactly as anticipated. We will make adjustments throughout the year based on market conditions and what is accessible in the spot or index markets.

I’ll add that in the Western Haynesville, our two frac crews are currently fracking wells. There is only one other well lined up behind those, and we don’t expect any additional wells to come online in the Western Haynesville until the end of the year. As I mentioned earlier, we have one rig that just started working on a two well pad a couple of weeks ago, and the other rig is preparing to move to a separate two well pad. Drilling in the Western Haynesville will require more time, so with the two well pads, work will continue throughout the spring, 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 manage this a little bit on your 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 in terms of reserves per thousand feet or however you guys want to present it here.

We currently have limited bookings because we are focusing on direct offsets rather than making any additional bookings in the Western Haynesville. It's still early in the process, and we've only drilled seven producing wells in the area. As a result, the reserve report shows a limited number of locations. On average, reserve bookings are about 3.5 BCF per thousand feet of completed lateral. Only the Circle M well has a noteworthy performance history, having exceeded expectations. The other wells haven't been in production long enough to draw significant conclusions, but overall, the reserves are showing positive trends for the initial wells we have drilled.

Thank you for the insights. I appreciate it. Lastly, I wanted to discuss the situation with gas in 2024, which has not gone as anticipated. From what I understand, it seems the strategy is to avoid adding debt. In the event next winter is warmer than expected and we start the year on a weaker note, would you still prefer not to increase debt, or might you have to ramp up some operations next year due to the Western Haynesville? Have you considered any short-term funding solutions to help bridge the gap until the market improves in 2025 and 2026?

I believe we have positioned ourselves in a way that allows us to safeguard our balance sheet. If you specifically look at the Western Haynesville, as Dan mentioned, these wells will take longer to reach production. Even though we haven't added a third rig, as Ronald pointed out, we will not encounter any issues with our midstream operations. Therefore, I don’t foresee any problems there. Regarding our drilling commitments, we are not obligated to complete any additional wells, and as we mentioned previously, we were proactive in cutting costs in December and even more so in January and February. We are continuously evaluating our options, and if necessary, we can lay down another rig or defer completions. These are all strategies we can implement, and even in a challenging market, we have multiple options to protect our position. Ultimately, we have a substantial inventory to safeguard, and there’s no need for us to seek out others' resources. We simply need to maintain our performance in the Western Haynesville. As Roland stated, the EURs appear strong, and Dan noted that costs are decreasing. While it is still early in our operations, we have secured a significant amount of acreage, and we will see how things unfold in the future.

Okay. Appreciate the color.

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.

Hello, Noel.

I just wanted to touch again on the Western Haynesville. I was wondering, can you talk a little bit about what kind of science you're doing on the latest Western Haynesville Wells sort of like, what are you most interested in learning about next, as far as just your drilling practices for instance?

We have mentioned previously that the main difference between the Western Haynesville and our core area lies in the temperature and depth. The wells are somewhat deeper, which affects the temperature. We have done an excellent job managing that aspect, particularly by optimizing our bottom hole assemblies to perform better, allowing them to stay on the bottom longer, increase penetration rates, and reduce the number of trips in and out of the hole for lateral drilling. We have achieved significant improvements in these areas. Additionally, there is a longer vertical section to drill, and we have made adjustments to our casing design, resulting in better penetration rates at the top as well. Our approach involves addressing all elements since we have not fully maximized these factors in the Western Haynesville as we have in our core area. In the core, we can typically make minor adjustments to gain a day or two of efficiency, but we are realizing larger improvements in the Western Haynesville with these changes.

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 would say the rock formations have proven reliable. It's well known that gas is present. There were two older wells drilled in 2010 and 2011 that had many issues and poor completions, but they still produced a reasonable amount of gas, confirming our knowledge of the gas presence. The key factor here is economics. The wells are treated at higher pressures during fracking, and they maintain consistent pressure levels, making the process easier compared to fluctuating pressures. We've also experienced stable costs in both fracking and completion. A few years ago, we began utilizing long laterals with snubbing units and stick pipe, which allows for better handling of high-pressure wells than coiled tubing. This approach has led to excellent results. Overall, everything on the completion side is progressing well, and we anticipate cost savings from our vendors. On the drilling side, we are notably reducing the time required to complete these wells, achieving significant improvements.

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. I appreciate you taking the call. I just want to briefly discuss some of the drilling and completion costs mentioned in slide 15. I'm curious about your perspective on how much of the decrease in drilling costs is due to deflation, and how much we should consider as being more stable, particularly in relation to completions. How sticky should we expect these costs to be moving forward?

I believe that this year, we will continue to observe deflation in our activities. We're anticipating an additional cost reduction of around 10% compared to last year. On the completion side, I think it's becoming more predictable. We'll mainly see lower prices across the board. Regarding drilling, since the Western Haynesville will significantly contribute to our program this year, we expect improved performance, with shorter time to reach total depth, which will help reduce costs, alongside decreasing vendor pricing.

Understood. Regarding the Western Haynesville, are we nearing the end of the improvement trend in drilling days and operational efficiencies, or is this just the beginning?

No, well, we've made some pretty good improvements, but we 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. As far as trying to say in the middle, I'd say maybe that's probably 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 that kind of potential going forward.

Got it. So another potential 20 days decline in 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 Allison for any further remarks.

First of all, I'd like to thank all of you for your questions. They make us better managers. Hopefully, we had shown you that we've started, and I think we've been very proactive to batten down the hatch to protect our balance sheet. We were very proactive on our operations arena to release the frac crew and two rigs. The underlying denominator of everything is stellar drilling performance and stellar inventory in our core area and in the area we operate. And you look at the Western Haynesville, I mean, almost half our footprint corporately is in the Western Haynesville. 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.