Earnings Call: Q2 2021

Aug 4, 2021

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 Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead. Again, thank you for the introduction. I know that we're reporting on the Q2 2021 today. I know that. But we're super excited about what we see for the second half of this year. We advertise that we were front end loading our CapEx in 2021 to the first half of the year, which we did. And now we see and actually have it today, corporate record high natural gas production in 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 feed stock 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 anti oil and gas sector as you are all aware of in this earnings season. Our corporate strength lies in our best of class, low cost structure, which creates our high margins as well as the 1900 plus net drilling locations within our 323,000 netacre HaynesvilleBossier footprint, which we operate 91% of. One of the major tests in 2021 was reduce our cost of capital, which we took mighty steps forward with our 5.875 percent senior notes being issued in the Q2 2021. We do feel the wind in our sales as we look at the 3rd Q4 of 2021 2022 and want to recommit to you our goal of reducing our leverage ratio to less 2 times at the end of 2022 or before if possible. With the refinancing in place, we reduced our interest cost per 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 HaynesvilleBossier region, which speaks volumes about all of our departments, especially our operations department and through our quality Haynesville Boger rock that we have decades of that quality rock left to drill. I know that that denominator is why Jerry Jones and his family invested $1,100,000,000 in Comstock since August 2018 and we believe that is why you, the bondholders, banks and equity owners, buy Comstock. Proven rock quality, proven results over many, many years. Now I'll start the formal Q2 2021 results. Welcome to the Comstock Resources' 2nd 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 2nd 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 2, please refer to slide 2 in our presentation and note that our discussions today will include forward looking statements within the meaning 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. Now if we'll go over to the Q2 2021 highlights, we cover the highlights of the Q2 on Slide 3. In the Q2, we reported adjusted net income of $55,000,000 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 Q1 of 2021 and 6% higher than the second quarter of 2020. Revenues including realized hedging losses were $325,000,000 40% higher than the Q2 of 2020. Adjusted EBITDAX of $251,000,000 was 55% higher than the Q2 of 2020. Operating cash flow for the quarter was $196,000,000 or $0.71 per diluted share. For the quarter, we generated $20,000,000 of free cash flow as a preferred dividends, increasing our year to year free cash flow to $53,000,000 That's a good start toward reaching our annual free cash flow generation goal of over 200,000,000 dollars 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 200,000,000 dollars And lastly, we completed the task of refinancing all of our higher coupon senior notes in the 2nd quarter, which substantially reduced our cost of capital going forward. If you turn over to Slide 4, we recap the refinancing transaction, which closed on June 28. We issued $965,000,000 of new 5.875 percent senior notes, which are due in 2,030. 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 $33,000,000 and we will save $28,000,000 in annual cash interest payments. Combined with the March refinancing that we did, our annual interest payments were reduced by $48,000,000 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 form a basis, assuming the refinancing was completed at the beginning of the quarter, our 2nd quarter interest cost per Mcfe would have been $0.36 per Mcfe as compared to our $0.48 rate in the Q1. In addition to lowering our cost 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 it over to Roland to review the financial results for the quarter in more detail. Roland? All right. Thanks, Jay. On Slide 5, 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 production for the 2nd quarter totaled 100 and our total production for the 2nd quarter totaled 124 Bcf of natural gas and 362,000 barrels of oil. Like Jay said, this is 6% higher than we had in the Q2 of 2020 and it's an 8% increase over where we were in the Q1 of this year. Our oil and gas sales as a result, including realized losses from our hedging program increased by 40% to $325,000,000 Oil prices averaged $55.82 per barrel and our gas price averaged 2.4 $6 per Mcfe, both those numbers including the impact of our hedges. Natural gas prices were 31% better than we realized last year in the same Q2 of last year. Remember that NYMEX contract for the quarter only averaged $2.83 So I know the recent run up in gas prices is really 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 and A was down 5% and our non cash depreciation, depletion and amortization was up 18% in the quarter. Our adjusted EBITDAX came in at $251,000,000 it's 55% higher than the Q2 of last year. Operating cash flow was $196,000,000 67 percent higher than the Q2 of 2020. We did report a net loss of $184,000,000 in the Q2 or $0.80 per share, but that was all due to a very large mark to market loss on our hedge contracts of $205,000,000 and a $114,000,000 charge related to the early retirement of the senior notes from our June 28 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 $55,000,000 or $0.22 per fully diluted share. On Slide 6, we summarize the financial results for the first half of this year. For the 1st 6 months of the year, production totaled 241.5 Bcfe. That includes 688,000 barrels of oil and that's about 1% lower than our production for the first half of twenty twenty. But our oil and gas sales, including any realized hedging losses, were $657,000,000 which is 30% higher than the first half of twenty twenty. Oil prices for the first half of this year have averaged $52.06 per barrel. That's 22% higher than last year and our realized gas prices averaged $2.62 per Mcf. Both of those numbers including the impact of our hedging and that's up 34% over last year. For the first half of this year, we've reported adjusted EBITDAX of $513,000,000 41% higher than the same period last year. Operating cash flow is $403,000,000 47 percent higher than last year. And then overall for this period, we reported a loss of $322,500,000 or $1.39 per share. Again, this was due to the charges for the early extinguishment of debt related to both the March June refinancings and that mark to market unrealized loss on our hedge position. Excluding those items, our adjusted net income would be $118,000,000 profit or $0.46 per diluted share. Slide 7, we recap our hedging program. During the Q2, we had 68% of our gas volumes hedged. That reduced our realized gas price to $2.46 per Mcfe from the actual $2.59 per McnV 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 per barrel versus the $61.25 we actually realized. Overall, our hedging program resulted in realized losses of $18,800,000 in the quarter. For the remainder of this year, we have natural gas hedges covering 976,000,000 cubic feet per day, 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% to 45% of our expected production hedged And almost half of those or 49% are in the form of collars, which give us substantial exposure to the higher prices that we're kind of now seeing for next year. On Slide 8, we summarize the shut in activity during the Q2. And we had a good quarter on this front. We had only 52,000,000 a day shut in during the 2nd quarter, which is 3.8% of our production. And that came down substantially from the 6.4% we had shut in in the 1st quarter. There really were no significant disruptions due to storms or other matters in the quarter and the shut ins that we had were very routine and related primarily to production we shut in to conduct offset frac activity. On Slide 9, we detail our operating cost per Mcfe. We had a good quarter there. Our operating costs for Mcfe averaged $0.54 in the 2nd quarter. Yes, that was $0.01 lower than the 1st 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 Q1 rates. Slide 10, corporate overhead per Mcfe. That again came in at $0.05 in the 2nd quarter. It's one of the lowest in the industry. And again, very consistent to what we expected and what we've had in the past. We do expect cash G and A to remain in this $0.05 to $0.07 range kind of going forward. Slide 11, that's the depreciation, depletion, amortization per Mcfe produced. That came in at $0.96 in the 2nd quarter. It was $0.01 higher than the $0.95 rate we had in the Q1 of this year. Slide 12, it's a picture of our balance sheet at the end of the second quarter and it $475,000,000 drawn on our revolving credit facility, which is a $1,400,000,000 borrowing base. And we expect to continue to reduce that as we generate free cash flow the rest of the year. That's really free cash flow is being really designated to continue to reduce our debt. We now have in total about 2 point $459,000,000,000 of senior notes outstanding. They're comprised of $244,000,000 of the 7.5 percent senior notes, which are due in 2025. We assumed as part of the Covey Park acquisition, dollars 1,250,000,000 of new 6.75% senior notes due in 2029 that we issued in March and then the new $965,000,000 of new 5.875 senior notes due in 2,030 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, just using targeting the free cash flow that's generated and using that as a permanent debt reduction move by the company. We do on Slide 12, you can see our new revised maturity schedule. And so 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 Q2. So 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. So we did end the quarter with about $20,000,000 in cash on the balance sheet. So our current liquidity is at $945,000,000 Slide 13, we recap the Q2 capital expenditures. So in the Q2, we spent $165,000,000 on our development activities and 150 $4,000,000 of that relates to our operated Haynesville shale properties. So we drilled 21 or 15.7 net operated horizontal Haynesville wells and then we returned 16 or 14.2 net operated Haynesville wells to sales in this recently completed second quarter. We also spent about 10,900,000 activity and other development activity. In addition to funding our development program, we've also invested $7,600,000 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 $20,000,000 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. So right now, as Dan will go over in a minute, we're currently operating 5 operated drilling rigs for our 2021 program and we see kind of maintaining those 5 as we look ahead into 2022. So we're at a very good consistent level, we think, which is right for the company. So based on this current operating plan, we expect to spend about $525,000,000 to $560,000,000 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 in 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 very focused on generating significant free cash flow and with the current gas prices, we now anticipate significantly exceeding our original target of $200,000,000 of free cash flow for this year. We'll use that incremental free cash flow to accelerate the delevering of our balance sheet. So I'll turn it back over to Dan to kind of 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 15,000,000 cubic feet a day up to 32,000,000 cubic feet a day with a 22,000,000 cubic feet per day average IP rate. The wells at lateral lengths ranging from 4,580 feet all the way up to 11,388 feet. And we had an average for the quarter of for this list of 8,251 feet. So 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 6 to 5 rigs. That's where we are today. 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 currently actively running 3 frac crews. Overall, slide 15 is an updated D and C cost trend for our benchmark long lateral wells. These are our laterals greater than 8,000 feet in length. Through the end of the second quarter, 73% of all the wells turned to sales this year been long lateral wells. During the Q2, our total D and C cost averaged $10.51 a foot. This represents a 3% increase compared to the Q1 and is 2% higher than the full year 2020 total D and C cost. Our drilling costs in the 2nd quarter increased by 7% compared to the 1st 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 Q1, but we're still running 16% higher than 2020. And 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 cost will remain relatively flat and we do not foresee any material increase in cost. So by building on our basin leading drilling performance and keeping our current completion cost in check, we expect to maintain our total D and C cost for our benchmark long lateral wells in this 10 25 foot to 10 50 foot range. Also I want to add that we're currently drilling 2 15,000 foot laterals that we spud in June. This is a first for the company. We expect to complete these wells during the Q4. We also have 2 additional 15,000 foot wells that we will spud later this month that will be completed in the Q1 of next year. These longer laterals are going to help bolster our efforts to further increase our lateral lengths and to drive down our footage cost further than where we've been. So that summarizes the operations. I'm going to turn it back over to Jay to summarize our 2021 outlook. Okay, Dan. That's short and sweet. It's usually about 10 pages and we've condensed it. That's good report and rolling the 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 percent to maybe 10% production growth and most importantly generate in excess as Roland said $200,000,000 of free cash flow and maybe a lot more than that. And 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 $28,000,000 annual savings and 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 at 2.5 times at the end of 2021, down from that 3.8 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 times 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 HaynesvilleBossier 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. And we have very strong liquidity, as Roland mentioned, at the $945,000,000 So 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 point 3 3 Bcfe to 1.425 Bcfe per day number that we had previously provided. As mentioned on the call, our development CapEx guidance is $525,000,000 to $560,000,000 and we anticipate on remaining at the 5 rigs we're currently running over the remainder of the year. And at the same time, as mentioned earlier, the leasing capital has increased to $15,000,000 to $20,000,000 as we continue to add acreage. On the cost side, LOE, GTC, really all the cost items remain unchanged from the prior quarter. And so there's 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. Our first question comes from Derrick Whitfield with Stifel. Your line is open. Thanks and 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 can spend. Could you help frame the remaining components of the increase on the development side? Sure, Derek. That's a good question. It's a modest increase despite overall, but it's really what we are seeing is given the higher prices in the Haynesville, obviously seeing more non operated opportunities. We've set a very hot 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. So we don't really control that level of activity and don't get great notice on it. But 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. So it's really the time and that changes all the time. So it's just really when did the completion dollars fall? Do they actually hit this year? Do they go into next year? It can actually be the difference between $10,000,000 or $20,000,000 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 kind of looked at our projects and put them into 3 buckets, the 5,000 foot laterals, the 7,500 foot laterals, the 10,000 foot laterals and budgeted that way. And I think we've kind of developed now a very, very, 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. So we do see that working really well now. And since we it's telling us kind of the numbers that he's giving you guidance on, we want to be transparent and communicate that. Yes, 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've tried to manage that by being very selective on non op opportunities and then just managing 96% of what we own is HBP. So we manage this drilling program. We've kept the rig count flat. I think Dan has done a really good job. Historically, on the completion side, you can see that's pretty predictable now and in the drilling side, we've got a lot quicker. So you move a bunch of these wells forward. That's why we have more DUCs today than we normally have. But we did increase that 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. And really as my follow-up, I wanted to build on Roland's comments and focus really on the trajectory of your D and C cost per lateral foot. Referencing Slide 15, it makes sense to me that D and 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 feet, how should we think about the trajectory of your D and C cost assuming a flat priceactivity environment? Well, if you look at the 10000 to 15000 foot, remember we've got 215,000 footers. We think that again, it's a little early to predict it, but we think those costs are really going to be below $1,000 a foot. Yes. A great example is looking at the Q1 and Q2 where the Q1 happened to be dominated by wells that averaged over 11,000 feet and you saw that you can see the impact on the significant savings there from the longer laterals. So as we continue to get more long laterals into the mix, we can kind of go back to averaging closer to where the Q1 was, if we can have that type of lateral in excess of 10,000 foot lateral average linked in the wells being completed. Yes. So Dan, why don't you make a comment? Yes. So we got to the comment about the longer laterals. So we got a lot more longer laterals in the pipeline, especially over on the Texas side where you're not confined by 1, 2, 3 sections one of those 3 buckets. And 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 up or 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 mean, I think we're ahead of the back in the Haynesville on drilling times. We've 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. So that's already given us the numbers that we got here. And then you 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. So but next year at the higher prices, I mean, we know there will be 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 kind of those products. I mean, we'll see we've kind of 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 and thank you for taking my questions. Good morning. So my first question is on gas differentials. So 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 towards 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. Yes. It's a good question. And obviously, we had the benefit of the premium winter storm prices in the Q1 that gave us a much attractive differential in the Q1 back to normal as we thought we would be for this quarter. Q3, we expect to be very similar. Q4 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 And we hope to be able to move additional gas away from the Perryville hub, which is kind of that's kind of where you get this kind of $0.25 $0.24 kind of differential into a market that's probably potentially $0.05 better. Now we already have gas. So we'll only be moving some percentage of our gas that way and we kind of 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%, kind of hopefully in the Q4 and definitely to next year. So that has the potential to start shaving the differential down. And so we don't really 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. But we do know if today you're going to pick up anywhere from $0.05 to $0.10 on that gas we're able to move away from Perryville down to selling it at a Gulf Coast hub, including Gilles, which will be the new hub that's available to us. And that market is just now starting to trade and we'll get more clarity on where that hub is going to trade at. That's great. Thank you for the color. And then my next question relates to cost inflation. You had already 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? Permian player had thrown out 10% and I'd like to get a sense of how you guys are thinking about it. Yes. I think so just to start off with what we've seen today, we really have we've seen we have seen a few really small ones and they've been really small like 5% and less. So 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 we'll probably on average be a little higher. And I think 5% to 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 we just you just have to know that it's there. But I certainly don't see anything over 10%. No. And again, we see capital discipline. We don't see a whole lot of rigs either particularly on the natural gas side. I mean, there's 103 rigs, I think, drilling for natural gas in the United States. So we don't see that increase. I mean, so if it was in the frothy days before COVID, you might expect a lot of new rigs. 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 price hadn't gone up, I mean, we probably wouldn't have as many rigs being utilized today, both on the oil side and the gas side. So I think it's going to be moderate, it will be controlled and it will probably be in that 5% to 8% range. That's our number. And that includes, again, steel, includes cement, it includes tubulars, some inflation on those costs. Thank you for that. That's great. And then the final one for me, if I may. Just wanted to ask about consolidation. Just wanted to hear your latest thoughts on consolidation within the HaynesvilleBossier area, where your appetite currently is? Just any thoughts would be appreciated. Thank you. Right. Well, I think a lot of the consolidation, I think size is important. But I also think I think your high margins and your low cost are probably more important. And everybody is seeking that kind of the denominator is locations. I mean some of these companies that you have to consolidate because you're running out of locations. I think the beauty of Comstock is 2 years ago when we bought Covey Park for that $2,200,000,000 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 1900 to 2000 locations. And like Ron and Roland and Dan said, we departmentalize and those to 5,000 foot laterals, 7,500, 10,000 foot. So if you're looking at Comstock needing to do some type of M and A for locations, you can exit that box because we don't need to. If you're looking for a comp stock to up their management for particularly from the drilling side and completion side, I mean, 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 and A transaction is that the acreage is equally as valuable and our cost structure materially improves. And quite frankly, the Jones family owns 60% to 68% of the company. We 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, but the footprint that we have near the Gulf Coast with the demand for LNG to Asia and Europe and with the lack of farm transportation commitments that we have and the high margins, I mean, 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 30,000,000 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 spiced our RBL with the Covey transaction. Now we have $945,000,000 I mean, we're sitting in a sweet spot with solid production upside, solid EBITDA growth and stronger than expected realized pricing. And our hedging into 2022, you can not like it, But I think proper management with the balance sheet we have, I mean, half of our hedges in 2022 are swaps, half of them are collars. Some of those collars go to $6 I mean, we've averaged like $3.50, dollars 60 whatever, but I think it's a safe program in 2022. So, no, we're not aggressively fishing or looking for anybody. Now, are we opportunistic? Sure, we are. Sure, we are. But 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. But since then, my impression is that you guys are really, really just focused on the Haynesville zone. And in the last couple of quarters, there have been a few capital markets transactions with other companies who have half of the remaining locations or more than half of the remaining locations in the Bossier. And so 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 kind of in this footprint of Northwest Louisiana, East Texas and for Comstock specifically? Yes. 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 name is nickname is Einstein. So to ask that type of question, it's pretty incredible because we hadn't brought it up. We didn't ask anybody to it up. We didn't ask you to bring it up, okay? The whole audience needs to know that. But if I'm going to turn this over to Dan because he's supposed to be the calm one. But I want him to tell you about the 2 Bossier wells that we just hit, the single best wells we drilled in the quarter, nobody brought that up. I think you sniffed that out. And then probably half of our locations are Bossier. And if you ask other outside consulting groups, they really love the Bossier. If you look at Avon IPO, half their upside is Bossier. If you look at Indigo, it's Bossier. We don't really talk about Bossier. That is a great trade question. I won't color you with my crayon. I'll give it to Dan. So Dan, and you go to slide whatever Dan and go over that. Charles? Please not your crayon, Jay. Anything but the crayon. It's a blue one. Cowboy blue. Yes. So Charles, if which I did mention it earlier, but on slide 14 on the list of the wells, those 2 best IP the IPs we had at the bottom there on our Errington wells which are you can see on the map they're further down south there in Sabine Parish. Those are in fact 2 Bossier completions. They're the only 2 Bossier completions on that list. We do like the Bossier. Obviously, it's the southern half of the play is where the Bossier exists. And the 2 I think this was in the last quarter. The 2 longest laterals we have drilled to date are 12,500 and 13,000. So that 12,500 foot test, which was a Jordan well, that was a Bossier right there on the acreage on the Desoto Sabine Parish border. And also these next 215,000 foot laterals we're getting ready to drill later this month are going to be Bossier's. So we do like the Bossier. The Bossier is good. And Charles, remember, you go back, we kicked off the Bossier in 2015 when we announced to the world we're just going to drill HaynesvilleBossier wells. We drilled 9 Haynesville wells in 2015. And in December of 2015, as you well know, we drilled the 1st Bossier well, which is a Jordan well and it kind of it sparked all the interest as a public company. We have to report it in detail. It did spark the interest in a rebirth of Bossier play. Yes. So we're really excited about these 15,000 foot laterals. They are new. They will be challenging. I think we've got a great drilling recipe. Of course, the 15,000 foot laterals will have to get back up the learning curve a little bit. I mean, they're not routine by any means like we drill on the other wells. But that's kind of our plan. As we get these 15,000 foot laterals down, we plan to develop much of our Bossier with those long laterals. Yes. And that's just to add one more comment on that, Charles, is that that's one of the things we've been thinking about the Bossier too as we want to migrate to the 15,000 foot laterals. The Bossier is relatively undeveloped in our acreage and there's a lot more room to do longer laterals or we can convert a much higher percentage of our Bossier inventory into the 15,000 foot laterals that we probably can realistically on the Haynesville acreage. So that's and that also enhances returns. So 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. But it's a great part of the inventory. And I think the market is starting to realize that. And some of the best wells in the play that are coming out of the Haynesville operators are Bossier wells now. Well, some of the non op opportunities have been Bossier. So yes, it's surfacing. Well, look, that's a lot of great color, guys. I appreciate that. Blind squirrel finds an acorn every now and then. But let me ask another kind of more maybe probably less interesting question. I look at the strip and we've still got this $0.65 drop between March April and it's been there for a long time. I frankly if you'd asked me a couple of weeks ago or a couple of months ago, I would have said, well, look, that's going to those are that spread is going to have to tighten, that calendar spread is going to have to tighten as you get closer, but it hasn't. And so I'm curious, does that shape of the curve and that steep drop we see in the 4th month of 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. And I think that's that the nature of that is really just the speculation in the gas market and the 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 speculations out there. So a lot of it's going to be out there until winter really kind of shows itself. So it's kind of hard to plan around that. I mean, you could have said, you could have looked at that last year and made the same comments that the Q1 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 that's those are going to be some of the lowest price months of this year of 2021. So 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 21 for a long time. So 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 filling that out. So we feel great about the gas market and producer discipline has been a big component. Well, Charles, as you looked at, I mean, the next 7 months we're looking on the strip right now. I mean, gas is 4.18 all the way to 4.04, 7, 8 months out. And then it dropped to that 3.37. I mean, if you told me 3 months ago, I'd have 337 natural gas in the Haynesville, I mean, I'd be pretty happy. I like 4 better, but it looks pretty good. So 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. And I think the other thing we did because of our balance sheet, I mean, I do think we properly risk adjusted our hedges. In hindsight, I wish we didn't have any hedges, but that's not how businesses are run. I think in a moment, you have to pull whatever the hedge is, which is swap or collar. And I think we've made a good business decision. And that is to have half of 'twenty two minuteus swap, which is solid in case something did go south. But then also have the caller that if gas hits $4, $5, $6 we get a little bite at that. And I think our budget is good. We've asked that question about our models. When we said that we have 5,000 foot, 7,500 foot, 10,000 foot laterals, we have that in both the Haynesville and the Bossier. So when we start kicking off these long laterals in the Bossier, we also have those models out too. And 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 NCFE continues to drop. It wasn't that many quarters ago, we were $0.52 for NCFE and now we're $0.36 We need to get a 2 on that, not a 3. So we're going to like when we opened, this 3rd Q4, I mean, 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. Yes. We see the same thing, Jay. That all that insight is helpful. I appreciate it. Yes. Thank you. Our next question comes from Hume Gowrie 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 reduction. As you mentioned, cash futures are very favorable. And if it holds, you can potentially generate free cash flow of well over $200,000,000 You have $475,000,000 outstanding on a credit facility. Can you talk to your plans to address the remaining maturities? And once you pay down your borrowings on the credit facility? And 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? Yes, those are great questions. And we are now that we've kind of 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 and then we kind of we purposely did not refinance the remaining bonds outstanding because we thought that was also a good target for debt reduction. So 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'll put in the bank facility first and then retire those bonds next. And so that's a that over the next couple of years gives us a lot of prepayable debt debt that can help us achieve our overall debt reduction goals. Yes. If you looked at the windshield, our goal in 20 14, we gave a dividend. We're not nearly there in giving a dividend, but I think you have to look to the windshield and say where you're going. And 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, 1, 6, 7, 8, just take a number and we're properly hedged, then I think it should be nice to have a Board meeting and say, hey, you know what, these are real Benjamin dollars that we're going to go back to the stakeholders are going to be not only a dividend, but you can do what the pioneers of the world is 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 fee gas to Europe and 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 farm transportation commitments that are below market or minimum volume commitments that are onerous. So we are absolutely looking at the long balls in the next 18 months to 24 months. And at the same time on our leasing program, every year we drill fifty-sixty wells. We try to replenish that with fifty-sixty more locations. So that is the goal. I don't want to spook the bondholders, equity owners, anybody. I mean, we're never going to be financially reckless, period. You can forget that. We are going to be financially aggressive. And that once we get this debt paid down and we've got these maturities loan, it will help the bondholders, help the equity owners and help the analysts and help us. So we're all in the end kind of in the same barrel together. That's our goal. That's helpful. And I guess my next question was around hedging. Can you remind us the minimum percentage of production you need to hedge for your covenant? And also I wanted to get your thoughts around future hedging? Sure. Yes. We're currently required to hedge 50% of our proved developed producing reserves at each borrowing base redetermination. So that's twice a year. So whatever the next 12 months of now usually if you look at our production outlook, 100% doesn't come from proved developed producing reserves at that time. So 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. So we're at those levels for the next for already for 2022, if we choose not to put any more hedges in at all. So obviously been a huge run up in prices. And I think 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 22 right now based on how we see the outlook. Great. Thank you so much. Thanks for your question. Our next question is from Bertrand Donis with Truist Bank. Your line is open. Good morning, guys. I was wondering in the prepared remarks, you said you're 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 maybe it will truly be kind of 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 we're seeing about 8% to 10% growth in production and we have not really set the goals for 2022 yet And so we're Yes, in fact, that's what we said on the final slide. I mean, you'll see it's an 8% to 10% production growth and that's what our operating plan calls for. So I just meant the back half. I thought I heard you guys say that maybe towards the end. But either way, is the lower activity though, if there's some sort of quarterly cadence or you just you don't want to get ahead of yourself and talk about that yet? Well, I think obviously you're going to see the Q3, I mean that's kind of the second half of the year is the higher production levels. So we will see higher production levels in the 2nd quarter level coming up in the next two quarters. But that is a good question. We're not going to try to peak production to drop it off. We're going to try to level it out in our model in 2022. I think we have management discussions on that too. I think what we said today is that we actually we 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. But today with $4 $4 $10 $20 gas, I mean, we actually are at a corporate high or record high natural gas production at Comstock and we're selling at a high natural gas price. But 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. And then 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 wonder if you guys could revisit that? Yes. I think we still have a lot of good tax attributes, which we are able to use. And so we don't really see cash taxes being something to really put on the radar screen for the next several years. And our goal really is to 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 do the structure, have a little bit of state cash taxes. That's all we kind of see right now. But 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. Good 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 your eye on for a long time, were they something that expired and came available? Just at this stage in the place development, it's a pleasant surprise to hear that you still can put together significant additional leasing. Yes. This is a result of the combination of Covey and Comstock. When you put the land groups together and then you see what's kind of floating out there, they would be accretive to us in the future. So that's and then we didn't go forward on those programs at all for a while until we had the consolidated management team together. And then we said, okay, here what we call low hanging fruit in our opinion. So we go out and when we spent quite a few dollars on it, but we it's very favorable terms on the leases. Great. Thanks. And 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 path 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 3 year contract we've locked in the pricing on the new Titan fleet, that's next year, that probably goes into service in January. So that has been fixed for 3 years. And then Dan, you can kind of talk about the we probably need in addition to that, we'll need 1 to 2 more frac crews. Yes. So that's right. So we got the BJ's providing the kind of the all turbine 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 3 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 run through the end of this year, but they do have language in there where they can make price adjustments depending on what the market is doing. So in that sense, they're not locked down solid like this like our natural gas fleet will be. Got you. Thanks. And the 32,000,000 a day IP that you well, you had in the quarter, I was wondering is that a record for the company? And I was also just curious kind of where you stand on choke management these days? So no, that's not a record for the company. But I think our record for the company is up in the mid I think about $36,000,000 or $37,000,000 today is the highest IP we've ever showed. I mean, obviously, we have wells capable of doing more. I think that's the highest we've ever reported. Token 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 we will start declining off from there. And that kind of front end loads our production and gets us some better return versus let the well decline off from month 1. Great. So we do. Sorry. Go ahead. Yes. We do tailor the choke management around the wells pressure performance and each well tells us what it can do. And there also could be other restraints such as how much production can you flow off a pad. So there's not every well can always flow optimally just because you may have only so much transportation or your facilities, you don't want to overwhelm them. So we have to manage all those factors and 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. Hey, guys. I was hoping you could help out a little bit with kind of your CapEx spend here. You certainly talked about it being more weighted in the first half of the year. Can you kind of help us with the next couple of quarters? Should Q3 be a fair bit less than Q2? And I noticed you had kind of looks like just based on the plan for the year kind of not very many completions in the Q4. So is Q4 CapEx going to be down a lot? Can you just kind of help us with the trajectory on the spend? Sure. And you can look at this kind of one level is looking 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 6 rigs then down to 5 rigs for the rest of the year there. There's also maybe a couple of months where we'd be actually be running 4 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. So the drilling activity is definitely weighted to the first half. The completion activity is weighted more through the 1st 3 quarters. Dan, so you might talk about how many frac crews we're running in the different quarters? So we are currently running 3 frac crews. And right now at the end of the year we got dropping down to 1 to 2 frac crews in Q4. And that's basically what's the front end for the production profile this year. And that will be 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. But right now we're dropping frac crews towards the end of the year. We're at 3. We should be at 1 in December. Yes. Purposely, one, when we set the budget to say, hey, we want to one, when you are fracking, you have more shut in too. So it's kind of just to optimize production in what's usually the better months, we kind of design the program that way. And I think we still right now kind of sticking with that. Okay. That's helpful. And I would imagine sort of the CapEx is going to follow all of that activity as you've described here. Right. Yes. I guess maybe just a follow-up. I think on the previous earnings call on Q1, you guys had talked about kind of 3% to 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% to 4% here in 2021. Do you have any just kind of 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. Yes. I think we well, obviously, we set a goal for free cash flow. And again, it's kind of early for us to lock in to the 2021 program yet. But right now, we're kind of assuming we're going to have these 5 rigs running and can achieve kind of that type of production growth you talked about with that program. So yes, we'll continue to look at that. But a lot will depend on where we are. As we get the leverage down, we'll open up opportunities to have other decisions here. But yes, we see the leverage coming down fast and next year really being under 2 times been our goal for several years. And we definitely want to achieve that before we start spending it in advance. All right. So really just the budget will be designed upon kind of maximizing a lot of that free cash flow and hand in leverage targets then production is just kind of an output sort of Right. The production will be a factor, but it won't be the like 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. And so they're right here. So 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. So 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'll save a lot of money in 2022 on interest expense per Mcfe. I think we'll get more efficient in 2022 with loan laterals. Prices look solid. So again, it's the same rig count. It's just efficiencies. And those efficiencies along with a higher price, of course, it corrects our balance sheet. It phased in 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. And 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 kind of the middle of the call. And again, we're excited about the quarter, but we're more excited about the remaining 6 months of this year. We did front end load our CapEx. We advertise that. We do have right now as we speak today corporate record high natural gas production at Comstock. And it's a good time to have that because we're selling at high natural gas prices. So I want you to know that we 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 packers. So thank you. This concludes today's conference call. Thank you for participating. You may now disconnect.