Good day, and thank you for standing by. Welcome to the Comstock Resources second quarter 2021 earnings conference call. At this time, all participants are in a listen only mode. After the speakers presentation, there will be a question and answer session. To as ask a question during the session, you will need to press star one on you telephone. Please be advised that today's conference is being recorded. If you need a further assistance, please press zero. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead. Thank you for the introduction. I know that we're reporting on the second quarter 2021 today. I know that. We're super excited about what we see for the second half of this year. We advertised that we were front-end loading our CapEx in 2021 to the first half of the year, which we did. Now we see, and actually have it today, a corporate record high natural gas production at Comstock that we are selling at high natural gas prices. The world of natural gas looks really solid, with natural gas trading at $4 range plus this morning, as I looked on the ticker. Especially Haynesville dry natural gas that is a primary feedstock gas for LNG exports to Asia and Europe, as well as to Mexico. Global demand for natural gas is very strong for industrial power generation, as well as electrical demand for cooling and heating, while supply is low to moderate, in part due to the disciplined use of capital expenditure dollars across the entire oil and gas sector, as you are all aware of in this earnings season. Our corporate strength lies in our best-in-class low-cost structure, which creates our high margins, as well as the 1,900+ net drilling locations within our 323,000 net acre Haynesville/ Bossier footprint, which we operate 91% of. One of the major tasks in 2021 was to reduce our cost of capital, which we took mighty steps forward with our 5.875% senior notes being issued in the second quarter 2021. We do feel the wind in our sails as we look at the third and fourth quarter of 2021 and 2022, and want to recommit to you our goal of reducing our leverage ratio to less than two times at the end of 2022 or before if possible. With the refinancing in place, we reduced our interest cost for Mcfe by 25% this quarter to $0.36, and are committed to continue working to reduce that number by year-end 2021, if possible. The denominator of Comstock is our consistent drilling results quarter, after quarter, after quarter in the Tier 1 Haynesville/Bossier region, which speaks volumes about all of our departments, especially our operations department, and through our quality Haynesville/Bossier rock, and we have decades of that quality rock left to drill. I know that that denominator is why Jerry Jones and his family invested $1.1 billion in Comstock since August of 2018, and we believe that is why you, the bondholders, banks, and equity owners back Comstock. Proven rock quality, proven results over many, many years. Now I'll start the formal second quarter 2021 results. Welcome to the Comstock Resources second quarter 2021 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 result presentations. There you'll find a presentation entitled "Second Quarter 2021 Results." I'm Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. If you go to slide two, please refer to slide two in our presentation. Note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If we'll go over to the second quarter 2021 highlights. If we cover the highlights of the second quarter on slide three. In the second quarter, we reported adjusted net income of $55 million, or $0.22 per diluted share. Production for the quarter averaged approximately 1.4 Bcfe a day and was 98% natural gas. Our average daily production for the quarter was 8% higher than the first quarter of 2021 and 6% higher than the second quarter of 2020. Revenues, including realized hedging losses, were $325 million, 40% higher than the second quarter of 2020. Adjusted EBITDAX of $251 million was 55% higher than the second quarter of 2020. Operating cash flow for the quarter was $196 million, or $0.71 per diluted share. For the quarter, we generated $20 million of free cash flow as our preferred dividends, increasing our year-to-year free cash flow to $53 million. That's a good start toward reaching our annual free cash flow generation goal of over $200 million. With the stronger commodity prices we're seeing in the second half of the year, we now expect free cash flow to come in well above that goal of $200 million. Lastly, we completed the task of refinancing all of our higher coupon senior notes in the second quarter, which substantially reduced our cost of capital going forward. If you turn over to slide four, we recap the refinancing transaction which closed on June 28th. We issued $965 million of new 5.875% senior notes, which are due in 2030. The proceeds from the offering were used to redeem the remainder of our 9.75% bonds. The refinancing transaction reduced our reported annual interest expense by $33 million. We will save $28 million in annual cash interest payments. Combined with the March refinancing that we did, our annual interest payments were reduced by $48 million. The lower cash interest expense will also drive significant improvements in our cash interest cost per Mcfe produced, as I mentioned earlier. On a pro forma basis, assuming the refinancing was completed at the beginning of the quarter, our second quarter interest cost for Mcfe would've been $0.36 per Mcfe as compared to our $0.48 rate in the first quarter. In addition to lowering our cost of capital, we also improved our weighted average maturity of our senior notes to 7.6 years, up from 6.3 years. I'll now turn over to Roland to review the financial results for the quarter in more detail. Roland? All right. Thanks, Jay. On slide five, we summarize our reported financial results for this recently completed second quarter. We had a solid quarter, and it was driven by that 6% production increase in combination with stronger oil and gas prices than we had last year. Our total production for the second quarter totaled 124 Bcf of natural gas and 362,000 bbl of oil. Like Jay said, this is 6% higher than we had in the second quarter of 2020, and it's an 8% increase over where we were in the first quarter of this year. Our oil and gas sales as a result, including the realized losses from our hedging program, increased by 40% to $325 million. Oil prices averaged $55.82 /bbl, and our gas price averaged $2.46/ Mcfe, both of those numbers including the impact of our hedges. Natural gas prices were 31% better than we realized last year in the same second quarter of last year. Remember that the NYMEX contract for the quarter only averaged $2.83. I know the recent run-up in gas prices is you'll really see those numbers starting in July forward. Looking at the cost side, our production costs were up about 6%, kind of matching the increase in production. Our G&A was down 5%, and our non-cash depreciation, depletion, and amortization was up 18% in the quarter. Our adjusted EBITDAX came in at $251 million. It's 55% higher than the second quarter of last year. Operating cash flow was $196 million, 67% higher than the second quarter of 2020. We did report a net loss of $184 million in the second quarter or $0.80 per share. That was all due to a very large mark-to-market loss on our hedge contracts of $205 million and a $114 million charge related to the early retirement of the senior notes from our June 28th refinancing transaction. Adjusted net income, excluding that mark-to-market unrealized hedging loss and the loss on early retirement of debt and certain other unusual items, was a profit of $55 million or $0.22 per fully diluted share. On slide six, we summarize the financial results for the first half of this year. For the first six months of the year, production totaled 241.5 Bcfe. That includes 688,000 bbl of oil. That's about 1% lower than our production for the first half of 2020. Our oil and gas sales, including any realized hedging losses, were $657 million, which is 30% higher than the first half of 2020. Oil prices for the first half of this year have averaged $52.06/bbl. That's 22% higher than last year. Our realized gas prices averaged $2.62/ Mcf. Both of those numbers, including the impact of our hedging, that's up 34% over last year. For the first half of this year, we've reported adjusted EBITDAX of $513 million, 41% higher than the same period last year. Operating cash flow is $403 million, 47% higher than last year. Overall, for this period, we reported a loss of $322.5 million or $1.39 per share. Again, this was due to the charges for the early extinguishment of debt related to both the March and June refinancings and that mark-to-market unrealized loss on our hedge position. Excluding those items, our adjusted net income would be $118 million profit or $0.46 per diluted share. Slide seven, we recap our hedging program. During the second quarter, we had 68% of our gas volumes hedged. That reduced our realized gas price to that $2.46/ Mcfe from the actual $2.59 / Mcfe we realized from selling our gas production. We also had about 38% of our oil volumes hedged, which decreased our realized oil price to $55.82 / bbl versus the $61.25 we actually realized. Overall, our hedging program resulted in realized losses of $18.8 million in the quarter. For the remainder of this year, we have natural gas hedges covering 976 million cf/d, which is around 70% of our expected production in the second half of this year. 59% of those hedges are fixed price swaps, but 41% are collars, which give us exposure to the higher prices we're now seeing. For 2022 or next year, we have about 40%-45% of our expected production hedged. Almost half of those, or 49%, are in the form of collars, which give us substantial exposure to the higher prices that we're now seeing for next year. On slide eight, we summarize the shut-in activity during the second quarter. Yeah, we had a good quarter on this front. We had only 52 million a day shut in during the second quarter, which is 3.8% of our production. That came down substantially from the 6.4% we had shut in in the first quarter. There really were no significant disruptions due to storms or other matters in the quarter. The shut-ins that we had were very routine and related primarily to production we shut in to conduct offset frac activity. On slide nine, we detail our operating cost for Mcfe. We had a good quarter there. Our operating cost for Mcfe averaged $0.54 in the second quarter. That was $0.01 lower than the first quarter rate. Gathering costs were $0.25, taxes $0.08, and the other lifting costs in the field were $0.21. Very comparable to the first quarter rates. Slide 10, corporate overhead for Mcfe. That again came in at $0.05 in the second quarter. It's one of the lowest in the industry. Again, very consistent to what we expected and what we've had in the past. We do expect cash G&A to remain in this $0.05-$0.07 range going forward. Slide 11, that's the depreciation, depletion, amortization per Mcfe produced. That came in at $0.96 in the second quarter. It was $0.01 higher than the $0.95 rate we had in the first quarter of this year. Slide 12. It's a picture of our balance sheet at the end of the second quarter, and it reflects our June 28th refinancing transaction, which closed right at the end of the quarter. We ended the quarter with $475 million drawn on our revolving credit facility, which is a $1.4 billion borrowing base. We expect to continue to reduce that as we generate free cash flow the rest of the year. Free cash flow is being really designated to continue to reduce our debt. We now have, in total, about $2.459 billion of senior notes outstanding. They're comprised of $244 million of the 7.5% senior notes, which are due in 2025. We assumed as part of the Covey Park acquisition, $1.25 billion of new 6.75% senior notes due in 2029 that we issued in March, the new $965 million of new 5.875% senior notes due in 2030 that were issued right at the end of the second quarter. We currently plan to retire the 2025 7.5% bonds, probably sometime early next year, targeting the free cash flow that's generated and using that as a permanent debt reduction move by the company. On slide 12, you can see our new revised maturity schedule. You can see now that our weighted average maturity of our senior notes is now 7.6 years after the recent refinancing, right at the end of the second quarter. We're in great shape on the maturity schedule, and as Jay pointed out, have substantially improved our cost of capital and generated substantial annual interest savings on what otherwise would be dollars that would have to go for fixed charges on our debt service. We did end the quarter with about $20 million in cash on the balance sheet. Our current liquidity is at $945 million. Slide 13, we recap the second quarter capital expenditures. In the second quarter, we spent $165 million on our development activities, and $154 million of that relates to our operated Haynesville Shale properties. We drilled 21 or 15.7 net operated horizontal Haynesville wells, and then we turned 16 or 14.2 net operated Haynesville wells to sales in this recently completed second quarter. We also spent about $10.9 million on non-operated activity and other development activity. In addition to funding our development program, we've also invested $7.6 million on leasing new exploratory acreage. Given the tremendous success of that leasing program, we have decided to increase our budget up to a maximum of $20 million to spend on putting new leases in to support our Haynesville Shale drilling program in the future, as we're seeing very good opportunities to do that at attractive terms. Right now, as Dan will go over in a minute, we're currently operating five operated drilling rigs for our 2021 program, and we see kind of maintaining those five as we look ahead into 2022. We're at a very good, consistent level we think which is right for the company. Based on this current operating plan, we expect to spend about $525 million-$560 million on this year's drilling plan, which will drill 55 net wells and turn to sales about 48 net wells. This is a small increase from what we expected at the beginning of the year. Most of that is really due to changes in the timing of when completions happen, and then also, higher than expected non-operated activity. We definitely are, again, very focused on generating significant free cash flow, and with the current gas prices, we now anticipate significantly exceeding our original target of $200 million of free cash flow for this year. We'll use that incremental free cash flow to accelerate the de-levering of our balance sheet. Now I'll turn it back over to Dan to report on operations. Okay. Thank you, Roland. Flip over on slide 14. You'll see the map outline and the summary of our new well completions. Since the last call, we've turned 21 new additional wells to sales. The 21 wells were tested at rates ranging from 15 million cf/d up to 32 million cf/d, with a 22 million cf/d average IP rate. The wells have lateral lengths ranging from 4,580 ft all the way up to 11,388 ft. We had an average for the quarter for this list of 8,251 ft. In addition to the wells we have listed here, we currently have 13 additional wells that we have in various stages of completion. Regarding the activity levels, this past May, we did drop down from six to five rigs. That's where we are today, and we intend to hold our activity flat at this level for the remainder of the year and into next year. Our fiscal DUC count currently stands at 23 wells, and we're actively running three frac crews. Over on slide 15 is an updated D&C cost trend for our benchmark long lateral wells. These are our laterals greater than 8,000 ft in length. Through the end of the second quarter, 73% of all the wells turned to sales this year have been long lateral wells. During the second quarter, our total D&C cost averaged $1,051 a foot. This represents a 3% increase compared to the first quarter, and is 2% higher than the full year 2020 total D&C cost. Our drilling cost in the second quarter increased by 7% compared to the first quarter. This is primarily attributable to a lower average lateral length versus the first quarter, but still 15% less than our drilling cost in 2020. Our completion costs remained relatively flat, with only a 2% increase from the first quarter, but we're still running 16% higher than 2020. This is due to the large number of the smaller fracs that were pumped in 2020, which led to the lower cost last year, lower completion cost. For the remainder of the year, we expect our completion costs will remain relatively flat, and we do not foresee any material increase in cost. By building on our basin leading drilling performance and keeping our current completion cost in check, we expect to maintain our total D&C cost for our benchmark long lateral wells in this 1,025-1,050 ft range. Also, I want to add that we're currently drilling two 15,000-ft laterals that we spud in June. This is a first for the company. We expect to complete these wells during the fourth quarter. We also have two additional 15,000-ft wells that we will spud later this month that will be completed in the first quarter of next year. These longer laterals are going to help bolster our efforts to further increase our lateral lengths and to drive down the footage cost further than where we've been. That summarizes the operations. I'm going to turn it back over to Jay to summarize our 2021 outlook. Okay, Dan. That's good. That's short and sweet. It's usually about 10 pages, and we've condensed it. That's a good report. Roland, same here. We'll conclude before we open it up for questions. If you look at the 2021 outlook, I'd like to direct you to slide 16, where we summarize our outlook for the remainder of this year. Our operating plan for this year is expected to provide for around 8%-10% production growth, most importantly, generate in excess, as Roland said, $200 million of free cash flow and maybe a lot more than that. Our primary focus this year is to improve our balance sheet, reduce our leverage, and lower our cost of capital, which we've made great strides on that. Our June refinancing transaction was another significant step to reducing our cost of capital with the $28 million annual savings in interest payments. Now we will primarily focus on absolute debt reduction, and we'll seek to retire, as Roland said, our 2025 bonds with free cash flow that we generate the rest of this year. If natural gas prices stay at current levels, we would expect our leverage ratio to improve to less than a 2.5 x at the end of 2021, down from that 3.8x at the end of 2020. Based on our current plans and the price outlook, we'd anticipate our leverage ratio further improving to less than 2 x at the end of 2022. We remain focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns. With our industry-leading low-cost structure, our Haynesville drilling program generates some of the highest drilling returns in all of North America. Our large inventory of Haynesville/Bossier drilling locations provide us with decades of drilling inventory. We're also focused on lowering our greenhouse gas emissions and are currently evaluating participating in one of the programs to certify our gas as responsibly sourced. We have very strong liquidity, as Roland mentioned, at the $945 million. Ron, I'll now turn it over to you to give any specific guidance for the rest of the year. Ron? Thanks, Jay. On the guidance page, we just update the guidance for the remainder of this year. Production guidance remains at the 1.33-1.425 Bcfe /d number that we had previously provided. As mentioned on the call, our development CapEx guidance is $525 million-$560 million, we anticipate on remaining at the five rigs that we're currently running over the remainder of the year. At the same time, as mentioned earlier, the leasing capital has increased to $15 million-$20 million, as we continue to add acreage. On the cost side, LOE, GTC, really all the cost items remain unchanged from the prior quarter. We continue to hit all of our targets on the cost side. With that, I'll turn the call back over to the operator to answer questions from our analysts. Thank you. As a reminder, to ask a question, you will need to press star one on your telephone. With you have your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from Derrick Whitfield with Stifel. Your line is open. Thanks, good morning, all. Good morning. With my first question, I wanted to focus on your revised 2021 capital budget. With the understanding that nearly 40% of the revision was focused on leasing, which is arguably the most accretive dollar you could spend, could you help frame the remaining components of the increase on the development side? Sure, Derrick. That's a good question. It's a modest increase despite overall. What we are seeing is, given the higher prices in the Haynesville, obviously seeing more non-operated opportunities. We've set a very high bar and said only the ones that have very high returns are we participating in, and ones that have a lower return, we actually have been able to sell down to other investors. Unfortunately, a lot of them have a very high return, so it's hard to not participate in those. We don't really control that level of activity and don't get great notice on it. Given the difference between this year and last year, you can understand why that's happening. On the operated side, where we do control that, we have a lot of the actual dollars really depend on when you complete the wells. We have a consistent drilling operation now, and that's stayed relatively the same, and we've actually probably achieved a little bit quicker drilling times. It's really the timing. That changes all the time. It's just really when do the completion dollars fall? Do they actually hit this year? Do they go into next year? It can actually be the difference between $10 million or $20 million very easily in our budget, and we're constantly looking at that. I think, to Ron's credit, we've also probably, in the past, looked at our projects and put them into three buckets. The 5,000-ft laterals, the 7,500-ft laterals, the 10,000-ft laterals, and budget it that way. I think we've developed now a very exact formula now that takes the exact footage and comes up with really a better estimate, and especially when wells fall in between those different numbers. We do see that working really well now. Since it's telling us the numbers that he's giving you guidance on, we want to be transparent and communicate that. Yeah, my only comment, these efficiencies, we've managed them, but they've moved dollars forward. They probably move them forward quicker than we want, so we try to manage that by being very selective on non-op opportunities and then just managing. 96% of what we own is HBP. We manage this drilling program. We've kept the rig count flat. I think Dan's done a really good job historically on the completion side. You can see that's pretty predictable now. Then the drilling side, we've got a lot quicker. You move a bunch of these wells forward. That's why we have more DUCs today than we normally have. We did increase the budget a little bit, and some of that is just adding acreage, which we think will be accretive to Comstock in the future. Great. Makes complete sense to me. Really as my follow-up, I wanted to build on Roland's comments and focus really on the trajectory of your D&C cost per lateral foot. Referencing slide 15, it makes sense to me that D&C costs are higher per lateral foot when you're drilling shorter laterals. As you look out into the second half of 2021 and further out into 2022, when laterals will approach 10,000 ft, how should we think about the trajectory of your D&C cost, assuming a flat price/activity environment? Well, if you look at the 10,000- 15,000 ft, remember we've got two 15,000 footers. We think that, again, it's a little early to predict it, but we think those costs, really, complete will be below $1,000 a foot. Yeah. A great example is looking at the first quarter and second quarter, where the first quarter happened to be dominated by wells that averaged over 11,000 ft. You can see the impact on the significant savings there from the longer lateral. As we continue to get more long laterals into the mix, we can go back to averaging closer to where the first quarter was, if we could have that type of lateral in excess of 10,000- ft lateral average length in the wells being completed. Yeah. Dan, why don't you make a comment? Yeah. To the comment about the longer laterals, we got a lot more longer laterals in the pipeline, especially over on the Texas side where you're not confined by one, two, or three sections, one of those three buckets. Obviously, that's our goal is to get longer. We already have several wells coming in at below $1,000 a foot, and if we can get that average upper, I mean, we're going to get that number ever lower. As far as performance, I think we'll still see some slight improvement there. I think we're ahead of the pack in the Haynesville on drilling times. Starting probably in the end of 2020 through today, we've shaved off an average of 10 days off our drill times from, say, the 2018, 2019, early 2020 average. That's already given us the numbers that we got here. Then you've just got the cost increases from the market. I mean, service cost, what are those going to do? We think between now and the end of the year, I think those will be relatively modest. Next year, at the higher prices, we know there's going to be upward pressure on prices. It's just going to be how much. Well, we'll see some inflation on steel and cement and those products. We've worked in the numbers a little bit of some inflation for service costs, not picked on the drilling side, but maybe the completion side. It's very helpful. Thanks for your time, guys. Thank you. Our next question comes from Kashy Harrison with Piper Sandler. Your line is open. Good morning. Thank you for taking my questions. Good morning. Good morning. My first question is on gas differentials. In Q2, you returned to your historical differential range of the mid-20s. I was wondering if you could talk about your expectations into Q3 and Q4, and also into 2022. If I could recall correctly, you had some gas being redirected toward the Gulf Coast and away from Perryville, and I'd like to get a better understanding of the impact to the model from these new arrangements. Yeah. It's a good question. Obviously, we had the benefit of the premium winter storm prices in the first quarter that gave us a much attractive differential in the first quarter. Back to normal as we thought we would be for this quarter. Third quarter, we expect to be very similar. Fourth quarter is when, what you alluded to, is the hopefully improved marketing opportunities with the Acadian extension coming into service. It's still planned to come in service in October. We hope to be able to move additional gas away from the Perryville hub, which that's where you get this $0.25, $0.24 differential into a market that's probably potentially $0.05 better. We'll only be moving some percentage of our gas that way. We've expected, like right now, 60% of our gas is really tied to that Perryville hub, so it's the major index price you look at when you're looking at us. That number actually drops down to 40%, hopefully in the fourth quarter and definitely to next year. That has the potential to start shaving the differential down. Those are all moving markets, so we don't want to just give you an exact number because we can't, because all those markets could move different directions. We do know if today, you're going to pick up anywhere from $0.05-$0.10 on that gas, we're able to move away from Perryville down to selling it at a Gulf Coast hub, including Gillis, which will be the new hub that's available to us, and that market's just now starting to trade, and we'll get more clarity on where that hub's going to trade at. That's great. Thank you for the color. Then my next question relates to cost inflation. You had just shared some detail on some of the pressures that you're seeing today. As you think about 2022, do you have a rough guesstimate of how we should be thinking about cost inflation in aggregate? A large premium player had thrown out 10%. I'd like to get a sense of how you guys are thinking about it. Yeah. Just to start off with what we've seen today, we have seen a few really small ones, and they've been really small, like 5% and less. For this year, that's why I say I think we're pretty good. Next year, based on where we think the markets are going, I think next year will probably, on average, be a little higher, and I think 5%-10% probably is a pretty good number. We haven't got any indicators from any of our providers that anything really major is coming. I think just at the macro level, just the higher activity, you just have to know that it's there, but I certainly don't see anything over 10%. Again, we see capital discipline. We don't see a whole lot of rigs out there, particularly on the natural gas side. There's 103 rigs, I think, drilling for natural gas in the United States. We don't see that increase. If it was in the frothy days before COVID, you might expect a lot of new rigs and stuff. I think right now, with this capital discipline, we're just not going to see runaway inflation on our side. Now, cost of our commodity has gone up. If commodity prices hadn't gone up, we probably wouldn't have as many rigs being utilized today, both on the oil side and the gas side. I think it's going to be moderate, it'll be controlled, and it'll probably be in that 5%-8% range. That's our number. That includes, again, steel, includes cement, it includes tubulars, some inflation on those costs. Thank you for that. That's great. Then a final one from me, if I may. Just wanted to ask about consolidation. Just wanted to hear your latest thoughts on consolidation within the Haynesville/Bossier area. Where your appetite currently is. Just any thoughts would be appreciated. Thank you. Ron. Well, I think a lot of the consolidation, I think size is important, but I also think your high margins and your low cost are probably more important. Everybody is seeking that the denominator is locations. Some of these companies, you have to consolidate because you're running out of locations. I think the beauty of Comstock is, two years ago, when we bought Covey Park for that $2.2 billion, and they were larger than we were, we added those locations with our locations, with the locations that we've been adding with this leasing program to have that 1,900- 2,000 locations. Like Ron and Roland and Dan said, we departmentalize in those to 5,000-ft laterals, 7,500 ft, 10,000 ft. If you're looking at Comstock needing to do some type of M&A for locations, you can X that box because we don't need to. If you're looking for Comstock to up their management, particularly from the drilling side and completion side, we drilled and completed more of these wells than anybody, so you probably don't need to. I think the only reason that we would do any M&A transaction is that the acreage is equally as valuable, and our cost structure materially improves. Quite frankly, the Jones family owns 60%-68% of the company. It would have to be blessed by them, because I think what they've invested in right now is delivering great returns, period. Size is important, the footprint that we have near the Gulf Coast with the demand for LNG to Asia and Europe, and with the lack of firm transportation commitments that we have and the high margins, we're not seeking to do something just to get bigger, period. We're way beyond that. We're in great shape. Our maturity schedule, we were fighting that for a while. The expensive bonds, we were fighting that for a while. The Series A preferred, we were fighting that for a while. The 30 million shares or so that was issued to private equity was kind of out there as an overhang. We've cured that. We've consolidated the personnel. We're not looking to do that again. We got through the COVID year with lower prices. We had fetched our RBL with the Covey transaction. Now we have $945 million. We're sitting in a sweet spot with solid production upside, solid EBITDA growth, and stronger than expected realized pricing. Our hedging into 2022, you can not like it, but I think proper management with the balance sheet we have, half of our hedges in 2022 are swaps. Half of them are collars. Some of those collars go to $6. We've averaged like $350, $60, whatever. I think it's a safe program in 2022. No, we're not aggressively fishing or looking for anybody. Now, are we opportunistic? Sure we are. I think it needs to be colored in that light. Thank you. Our next question is from Charles Meade with Johnson Rice. Your line is open. Good morning, Jay, and Roland, and the rest of the team there. Hi, Charles. Jay, I wanted to pick up a little bit on the theme you were just touching on with locations and ask you about the Bossier. I think back, it was years ago, you guys drilled some of the first really good Bossier wells that really opened a lot of people's eyes. Since then, my impression is that you guys are really just focused on the Haynesville zone. In the last couple of quarters, there have been a few capital markets transactions with other companies who have half of their remaining locations or more than half of their remaining locations in the Bossier. Can you give, in as much detail as you'd like, a view of how you see the Bossier versus the Haynesville, both for the industry as a whole in this footprint of Northwest Louisiana, East Texas, and for Comstock specifically? Yeah. Charles, I don't know how many times we've met with you face-to-face and how many companies you cover, but behind closed doors, I think your nickname is Einstein. To ask that type of question is pretty incredible because we hadn't brought it up. We didn't ask anybody to bring it up. We didn't ask you to bring it up, okay. The whole audience needs to know that. I'm going to turn this over to Dan because he's supposed to be the calm one. I want him to tell you about the two Bossier wells that we just hit. The second-best wells we drilled in the quarter. Nobody brought that up. I think you sniffed that out. Then probably half of our locations are Bossier. If you ask other outside consulting groups, they really love the Bossier. If you look at a Vine IPO, half of their upside was Bossier. If you look at Indigo, it was Bossier. We don't really talk about Bossier. That is a great question. I won't color view with my crayon. I'll give it to Dan. Dan, and you can go to slide whatever, Dan, and go with it. Charles, thank you. Please not your crayon, Jay. Anything but the crayon. It's a blue one. It's a cowboy blue. Yeah. Charles, which I did mention it earlier, but on slide 14 on the list of the wells, those two best IPs we had at the bottom there on our Arrington wells, which you can see on the map, they're further down south there in Sabine Parish. Those are in fact two Bossier completions. They're the only two Bossier completions on that list. We do like the Bossier. Obviously, it's the southern half of the play is where the Bossier exists. The two, I think this was in the last quarter, the two longest laterals we have drilled to date are a 12,500 ft and a 13,000 ft. That 12,500-ft test, which was a Jordan well, that was a Bossier, right there on the acreage on the DeSoto, Sabine Parish border. Also these next two 15,000-ft laterals we're getting ready to drill later this month are going to be Bossiers. We do like the Bossier. The Bossier is good. Charles, remember, you go back, we kicked off the Bossier in 2015 when we announced to the world we're just going to drill Haynesville/Bossier wells. We drilled nine Haynesville wells in 2015, and in December of 2015, as you well know, we drilled the first Bossier well, which is a Jordan well, and it sparked all the interest. As a public company, we have to report it in detail. It did spark the interest and it rebirth the Bossier play. Yeah. We're really excited about these 15,000-ft laterals. They are new. They will be challenging. I think we've got a great drilling recipe. Of course, the 15,000-ft laterals, we'll have to get back up the learning curve a little bit. They're not routine by any means, like we're drilling the other wells. That's our plan. As we get these 15,000-ft laterals down, we plan to develop much of our Bossier with those long laterals. Yeah. Just to add one more comment on that, Charles, that's one of the things we've been thinking about the Bossier too, as we want to migrate to the 15,000-ft laterals. The Bossier is relatively undeveloped in our acreage, there's a lot more room to do longer laterals. We can convert a much higher percentage of our Bossier inventory into the 15,000-ft laterals than we probably can realistically on the Haynesville acreage. That also enhances return. We've been thinking about that more long term because we just have so many wells to drill and such a large inventory. It's been hard to go to all the different plays yet. It's a great part of the inventory, I think the market's starting to realize that. Some of the best wells into play that are coming out of the Haynesville operators are Bossier wells now, not just all Haynesville. Well, some of the non-op opportunities have been Bossier. Yes, it's surfacing. Well, look, that's a lot of great color, guys. I appreciate that. A blind squirrel finds an acorn every now and then. Let me ask another more, maybe probably less interesting question. I look at the strip, and we've still got this $0.65 drop between March and April, and it's been there for a long time. Frankly, if you'd asked me a couple of weeks ago or a couple of months ago, I would've said, "Well, look, that spread's going to have to tighten. That calendar spread's going to have to tighten as you get closer." It hasn't. I'm curious, does that shape of the curve and that steep drop we see in the fourth month or in April of 2022, does that affect any of your planning or any of your decisions, either near term or longer term? Well, that's a good question. I think the nature of that is really just the speculation in the gas market and probably the tightness of the market and the fear that gas could be really short in those winter months there. The longer you go out on the gas curve, the less speculation's out there. A lot of it's going to be out there until winter really shows itself. It's kind of hard to plan around that. You could've looked at that last year and made the same comments, that the first quarter of 2021 was going to be where you really want to try to get your gas online in January through March. It turned out not to be a great strategy because those are going to be some of the lowest priced months of this year, of 2021. It's really hard to look at the curve and drill toward it. We do see that overall, though, over the last month, you've really seen the 2022 futures prices improve greatly, where they had been stuck at a level that was below 2021 for a long time. A lot of it's just the market trying to figure out what's the supply-demand going to look like later this year, and they're still feeling it out. We feel great about the gas market, and producer discipline has been a big component. Well, Charles, as you looked at the next seven months, we're looking on the strip right now. Gas is $4.18 all the way to $4.04, seven, eight months out. Then it dropped to that $3.37. If you'd told me three months ago I'd have $3.37 natural gas in the Haynesville, I'd be pretty happy. I like $4 better, it looks pretty good. We did front-end load 2022, if you look at the hedges, to make sure we have really good quarter in the first quarter of 2022, same thing in 2023. I think the other thing we did, because of our balance sheet, I do think we properly risk-adjusted our hedges. In hindsight, I wish we didn't have any hedges, that's not how businesses are run. I think in a moment, you have to pull whatever the hedge is, which is a swap or collar. I think we made a good business decision. That is to have half of 2022 in a swap, which is solid, in case something did go south. Also have the collar that if gas hits $4, $5, $6, we get a little bite at that. I think our budget is good. We've asked that question about our models. When we said that we have 5,000 ft, 7,500 ft, 10,000-ft laterals, we have that in both the Haynesville and the Bossier. When we start kicking off these long laterals in the Bossier, we also have those modeled out, too. We can toggle this back. If we need to accelerate a little bit and convert some of the DUCs into PDP, I think we're going to be able to do that. I think we're going to be able to pay off the Covey bond. If we can do that, then our interest cost for Mcfe continues to drop. Wasn't that many quarters ago, we were $0.52 for Mcfe, and now we're $0.36. We need to get a two on that, not a three. We're going to, like when we opened, this third and fourth quarter, they look really, really good. I know we're talking about the second quarter, but this second half of the year, it looks like we should really capitalize on all-time high corporate production here, natural gas production, with a really, really favorable natural gas price. Yeah, we see the same thing, Jay. All that insight is helpful. I appreciate it. Yep. Thank you. Our next question comes from Umang Choudhary with Goldman Sachs. Your line is open. Hi, good morning, and thank you for taking my questions. Yes, sir. My first question is on your plans on absolute debt reduction. As you mentioned, gas futures are very favorable. If it holds, you can potentially generate free cash flow of well over $200 million. You have $475 million outstanding on a credit facility. Can you talk to your plans to address the remaining maturities once you pay down your borrowings from the credit facility? Also, if you can talk to your thoughts around cash return to shareholders, and the right absolute debt level at which you plan to deploy cash back to shareholders. Yeah, those are great questions. Now that we've got the cost of the long-term debt down and got the maturities in a great spot, it's really focused on the debt reduction. We do have a significant amount of debt that we can retire, the bank facility debt, obviously. Then we purposely did not refinance the remaining bonds outstanding, because we thought that was also a good target for debt reduction. Our plans are sometime probably next year to redeem the remaining 7.5% bonds. We obviously want to create the free cash flow, and we're paying the bank facility first, and then retire those bonds next. That, over the next couple of years, gives us a lot of pre-payable debt that can help us achieve our overall debt reduction goals. If you looked at the windshield, our goal in 2014, we gave a dividend. We're not nearly there in giving a dividend, but I think you have to look through the windshield and say where you're going. With these higher prices, I think we can get this leverage down. We get the leverage down, it's got a one handle on it, one, six, seven, eight, just take a number. We're properly hedged, then I think it'd be nice to have a board meeting and say, "Hey, you know what. These are real Benjamin dollars that were going to go back to the stakeholders." They're going to be not only a dividend, but you can do what the Pioneer had start doing in a variable. I think that is absolutely a possibility within the Comstock structure because of where we're located. Again, the demand for our gas, our feed gas, to Europe and to Asia, and the demand growth as far as these export facilities are being built, and the fact that we haven't encumbered our gas with some kind of strange firm transportation commitments that are below market or minimum volume commitments that are on us. We are absolutely looking at the long ball in the next 18-24 months. At the same time, on our leasing program, every year we drill 50, 60 wells. We try to replenish that with 50, 60 more locations. That is the goal. Now, I don't want to spook the bondholders, the equity owners, anybody. We're never going to be financially reckless, period. You can forget that. We are going to be financially aggressive. Once we get this debt paid down and we've got these maturities long, it'll help the bondholders, help the equity owners, and help the analysts and help us. We're all in the same barrel together. That's our goal. That's helpful. I guess my next question was around hedging. Can you remind us the minimum percentage of production you need to hedge for your covenant? Also, I wanted to get your thoughts around future hedging. Sure. Yeah. We're currently required to hedge 50% of our proved developed producing reserves at each borrowing base redetermination. That's twice a year. Whatever the next 12 months, usually, if you look at our production outlook, 100% doesn't come from proved developed producing reserves at that time. In the 40% of our expected production to no more than 45%, we do need to hedge, in some form. It could be in the form of a collar, in order to satisfy the credit facility as the covenant currently stands. We're at those levels already for 2022 if we choose not to put any more hedges in at all. Obviously, been a huge run-up in prices, and we think we're adequately hedged for next year, and so I can't tell you if we're going to add any more or not, but I don't think we'll be hedging at a real high percentage level of 2022 right now based on how we see the outlook. Great. Thank you so much. Thanks for your question. Our next question is from Bertrand Donnes with Truist Bank. Your line is open. Morning, guys. I was wondering, in the prepared remarks, you said you were going to hold production flat, and I just wasn't sure exactly with the lower spend in the back half, whether that might kind of drift down in 4Q and 1Q 2022, and then maybe back up in 2Q or if maybe it will truly be a flattish profile? I don't think that we talked about holding production flat. We actually talked about that basically this year is kind of a we're seeing about 8%-10% growth in production. We have not really set the goals for 2022 yet. In fact, that's what we said on the final slide. You'll see it's an 8%-10% production growth, that's what our operating plan calls for. Sorry. I just meant in the back half. I thought I heard you guys say that maybe toward the end. Either way, is the lower activity, though, if there's some sort of quarterly cadence, or you don't want to get ahead of yourself and talk about that yet? I think, obviously, you're going to see the third quarter. The second half of the year is the higher production levels. We'll see higher production levels than the second quarter level coming up in the next two quarters. That is a good question. We're not going to try to peak production and drop it off. We're going to try to level it out in our model in 2022. We have management discussions on that, too. I think what we said today is that we actually front-end loaded that CapEx. We know we have that, but we've got a lot of DUCs that we can complete. We can shift some CapEx dollars around to complete those DUCs. Today, with $4, $4, $10, $20 gas, we actually are at a corporate high of a record high natural gas production at Comstock, and we're selling at a high natural gas price. We're going to monitor that in 2022. We don't expect to have a big peak and then a drop-off. That's not our goal either. That's perfect. Really just my only follow-up. With the higher gas strip, I know you guys maybe have talked about cash taxes before being pretty far out there, but just wondering if you guys could read us about. I think we still have a lot of good tax attributes which we are able to use. We don't really see cash taxes being something to really put on the radar screen for the next several years. Our goal really is that we try to maximize our taxable income to use up carry-forwards that we have, that we want to be able to use before they expire. We have a little bit of, just due to structure, have a little bit of state cash taxes. That's all we see right now. That's a fairly modest amount compared to the income we have. That's perfect. Thanks, guys. Thank you. Our next question comes from Noel Parks with Tuohy Brothers. Your line is open. Hey, good morning. Morning. Just had a few things. With the success you've had on the leasing side, I was just curious, were those leases that you had had your eye on for a long time? Were they something that expired and came available? Just that at this stage in the play's development, it's a pleasant surprise to hear that you still can put together significant additional leasing. Yeah. This is a result of the combination of Covey and Comstock, and you put the land groups together, and then you see what's floating out there that would be accretive to us in the future. We didn't go forward on those programs at all for a while, until we had the consolidated management team together. We said, "Okay, here are what we call low-hanging fruit, in our opinion." We go out, and we spent quite a few dollars on it. It's very favorable terms on the leases. Great. Thanks. I was also just thinking about the comments you were just making. As far as overall efficiency and the cost environment, where do you stand as far as the contracts on your frac spread? Do you have a horizon past which you have to negotiate on rates, or is there sort of a built-in renewal available to you at what you're paying now? Well, of course, part of it, just to preface that, remember, we do have one new three-year contract we've locked in the pricing on, the new TITAN fleet. That's next year. That probably goes into service in January. That has been fixed for three years. Dan, you can talk about, we probably need, in addition to that, we'll need one to two more frac crews. Yeah. That's right. We got BJ's providing the all-TITAN natural gas fleet. That will start. It's anticipated the crew will show up and start working about January 1, and it is fixed for three years, which we think, in the current outlook, that's going to be a great deal for us. The other, the conventional fleets, they typically, we have cost, they're contracts, and they do run through the end of this year, but they have language in there where they can make price adjustments depending on what the market's doing. In that sense, they're not locked down solid like our natural gas fleet will be. Gotcha. Thanks. The $32 million a day IP that you had in the quarter, I was wondering, is that a record for the company? I was also just curious kind of where you stand on choke management these days. No, that's not a record for the company. I think our record for the company is up in the mid, I think, about 36 million or 37 million a day is the highest IP we've ever shown. Obviously, we have wells capable of doing more. I think that's the highest we've ever reported. Choke management, basically we, even more so in a higher price environment, we basically hold the rates flat at a high rate until they get down close to line pressure, and then basically, they'll start declining off from there. That front-end loads our production and gets us a better return versus letting the well decline off from month one. Great. That's all I had. So we do- Oh, sorry. Yeah. Go ahead. Yeah, we do tailor the choke management around the well's pressure performance, each well tells us what it can do. There also could be other restraints, such as how much production can you flow off a pad. Not every well can always flow optimally just because you may have only so much transportation or you have facilities, you don't want to overwhelm them. We have to manage all those factors in deciding the flow rates. Right. Okay, thanks. That's all for me. Perfect. Thank you. Our next question comes from Leo Mariani with KeyBanc. Your line is open. Yeah. Hey, guys. I was hoping you'd help out a little bit with your CapEx spend here. You certainly talked about it being more weighted in the first half of the year. Can you help us with the next couple quarters? Should third quarter be a fair bit less than second quarter? I noticed you had kind of looks like, just based on the plan for the year, not very many completions in the fourth quarter. Is fourth quarter CapEx going to be down a lot? Can you just help us with the trajectory on the spend? Sure. You can look at just the kind of one level is look at the drilling, and we were running more rigs through May. So there's more drilling activity in the first, really January through May is six rigs, then down to five rigs for the rest of the year there. There's also maybe a couple of months where we'd actually be running four rigs because we've probably going to loan out a rig a little bit. Again, just because the drilling times have been quicker and trying to manage overall how many DUCs you build up. The drilling activity is definitely weighted to the first half. The completion activity is weighted more through the first three quarters. You might talk about how many frac crews we're running in the different quarters. We are currently running three frac crews, and right now at the end of the year, we got dropping down to one to two frac crews in Q4. That's basically what's the front-end load for the production profile this year. We obviously are looking at the current prices that we're at, and we do have discussions about do we want to try to pull some more of that forward potentially sometimes. Right now, we're dropping frac crews towards the end of the year. We're at three. We should be at one in December. Yeah. Purposely, when we set the budget. One, when you are fracking, you have more shut in, too. It's kind of just to optimize production in what's usually the better months. We kind of designed the program that way. I think we still are right now kind of sticking with that, so. Okay. That's helpful. I would imagine certainly the CapEx is going to follow all of that activity as you've described here. Right. Yeah. I guess maybe just a follow-up. I think on the previous earnings call on first quarter, you guys had talked about 3%-4% production growth in 2022. Obviously, since then, we've seen gas prices move up materially. You're clearly growing a lot faster than 3%-4% here in 2021. Do you have any just early thoughts about how you would approach, say, a $3.50 gas price environment in 2022? Is that the type of environment where you guys would like to maybe lean in a little bit more with a little bit more growth, just because the returns are so good on the drilling, or how do you think about that? We plan on keeping the same rig count, and we'll see what the efficiencies do on the drilling and completion. Right. Yeah. I think, we obviously set a goal for free cash flow. Again, it's early for us to lock into the 2021 program yet. Right now, we're assuming we're going to have these five rigs running and can achieve that type of production growth you talked about with that program. Yeah. We'll continue to look at that. A lot will depend on where we are. As we get the leverage down, we'll open up opportunities to have other decisions here. We see the leverage coming down fast and next year, really being under 2 x. It's been our goal for several years, and we definitely want to achieve that before we start spending it in advance. All right. Really just the budget will be designed upon maximizing a lot of that free cash flow and hitting the leverage targets. Production is just an output sort of. Right. The production will be a factor, but it won't be the absolute. The absolute driver will be what maximizes getting to the leverage profile we want to get. We think we have all the tools to get there next year. They're right here. We want to check that box, just like we wanted to get rid of those expensive coupon bonds. That was a goal. They're gone now. Now we're going to focus on overall debt levels and leverage and obviously, balance the EBITDAX growth with debt reduction is the balancing act on leverage. Well, we saved a lot of money in 2022 on interest expense per Mcfe. I think we get more efficient in 2022 with long laterals. Prices look solid. Again, it's the same rig count. It's just efficiencies. Those efficiencies, along with the higher price, of course, it corrects our balance sheet. It pays down our debt, fortifies our RBL, and we have really good growth because we have Tier 1 area. It's a simple story. All right, great. Thank you. You bet. Thank you. Appreciate you. Thank you. This concludes the question and answer session. I would now like to turn the call back over to Jay Allison for any closing remarks. All right. Again, some of you that joined the middle of the call, again, we're excited about the quarter, but we're more excited about the remaining six months of this year. We did front-end load our CapEx. We advertised that. We do have right now, as we speak today, corporate record high natural gas production at Comstock. It's a good time to have that because we're selling at high natural gas prices. I want you to know that we've recommitted to clean up this balance sheet. We've got good models that are strong, a good operations department, and we're thankful that we have all of you as backers. Thank you. This concludes today's conference call. Thank you for participating. You may now disconnect.