Good day, and thank you for joining us. Welcome to the Q3 2021 Comstock Resources, Inc. Earnings Conference Call. Currently, all participants are in listen-only mode. After the speakers finish their presentations, we will have a question-and-answer session. I would now like to turn the call over to Mr. Jay Allison, Chairman and CEO. The floor is yours.

Thank you. Thank you, everyone. It's a little rainy outside in Frisco, Texas. I guess winter is coming our way. What a great time to be in the natural gas business, especially in the Haynesville. I want to have a couple of clarifying statements before we start the actual third quarter 2021 results. With our Bakken properties under contract for that $154 million, which most of you're aware of, and closing expected in the coming weeks. We did pre-announced that we would accelerate completion activity on the 9.4 net Haynesville wells this year, to bring those volumes forward into our current strong market for natural gas. The increased production from those wells really will appear in the first quarter of 2022. Now, I thought it would be a good time to talk about the direction of the company. The direction of Comstock is to continue to focus on capital efficiency in the Haynesville and generation of free cash flow. Specifically, over the next several quarters, we plan to use that free cash flow to pay off our credit facility, and to retire the 7.5% bonds in May of 2022. Then, with our debt reduction goals met, we want to establish a shareholder dividend. So, with that opening statement, I now want to go back, I want to welcome everybody to Comstock Resources third 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 results presentations. There, you'll find a presentation entitled Third Quarter 2021 Results. I am 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. Now if you'll flip over, please refer to Slide 2 in our presentations and note that our specialists today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Now highlights, this is Slide 3, the third quarter 2021 highlights. We cover the highlights of the third quarter on Slide 3. In the third quarter, we generated $84 million of free cash flow after paying preferred dividends increasing our year-to-date free cash flow generation to $137 million. Given the strong outlook for natural gas prices, we now expect to significantly exceed our original annual free cash flow generation goal of over $200 million. For the quarter, we reported adjusted net income of $91 million or $0.34 per diluted share. Our production increased 25% in the quarter to 1.424 MMcfe per day, and was 98% natural gas. Revenues including realized hedging losses increased 86% to $394 million. Our adjusted EBITDAX in the third quarter grew by 109% to $309 million. Operating cash flow for the quarter was $255 million, or $0.92 cents per diluted share. And again, we announced the sale of our Bakken properties for $154 million. We expect to close the divestiture in the next several weeks. We are using a portion of the proceeds from that sale to accelerate completion of these 9.4 net drilled uncompleted wells to benefit from the stronger winter pricing. We've now started completion operations of those wells, which Dan will go over within a minute, which have been completed by year-end with production in January of next year. And we recently engaged with MiQ to initiate the independent certification of our natural gas production under the MiQ methane standard. Dan will also cover that in his formal presentation. If you flip to Slide 4, we cover our announcement to sell the Bakken assets, on Slide 4. We recently announced that we're selling our non-operated Bakken shale properties to Northern oil and gas for $154 million. The assets sold include interest in 442 or 68.3 net well bores. As of June 30, the proved reserves associated with the properties totaled 10.8 million barrels of oil and 44.2 billion cubic feet of natural gas. We expect to close the transaction in the next several weeks. I'll now turn it over to Roland Burns, our CFO to cover the third quarter 2021 financial results. Roland?

Thanks, Jay. On Slide 5, we summarize our financial results for the third quarter of 2021. We had a very strong quarter, driven by that 25% production increase combined with substantially improved oil and gas prices. Our production in the third quarter totaled 129 Bcf of natural gas and 346,000 barrels of oil. That was 25% higher than the third quarter of 2020, and it's 4% higher than what we were producing in the second quarter of this year. Our oil and gas sales, including the losses realized from our hedges increased by 86% to $394 million in the third quarter. Our oil prices in the quarter averaged $58.58, and our gas price averaged $2.90 per Mcfe, that's after the impact of our hedges. Our realized hedged natural gas price in the quarter was 49% higher than the third quarter last year. Our production costs were up 36% in the quarter, reflecting the higher production level, combined also with higher production taxes resulting from the stronger prices that we realized. Our G&A, though, was down 10%. And our depreciation, depletion, and amortization was up 30% in the quarter. Adjusted EBITDAX came in at $309 million. That's 109% higher than the third quarter of 2020. And our operating cash flow for the quarter was $255 million, 174% higher than the third quarter of last year. We did report a net loss of $293 million in the quarter or $1.26 per share. But that was all due to the very large mark to market loss on our hedge contracts of $393 million, that resulted from the surge in oil and gas futures prices since the end of the second quarter. Adjusted net income excluding the unrealized hedging losses and certain other unusual items was actually a profit of $90.6 million, or $0.34 per diluted share. On Slide 6, we summarize the results for the first nine months of this year. Production for the first nine months averaged 372.5 Bcfe, which is 7% higher than the same period in 2020. Oil and gas sales including realized hedging losses were $1.1 billion, 47% higher than the same period last year. Oil prices were 36% higher at $54.24 per barrel, and our realized natural gas price averaged $2.72 per MCF, both of those including the effect of our hedges, and that was 39% stronger than 2020. Adjusted EBITDAX for this period has increased 61% to $823 million. Operating cash flow at $658 million has increased 80% from 2020. For the first nine months of this year, we did report a $615 million loss, or $2.66 per share. Again, this was due to two items: the large mark to market loss on hedged contracts, and a charge for early retirement of debt related to our March and June refinancing transactions. Adjusted net income excluding the unrealized hedging losses and the charge for early debt retirement and other unusual items was a profit of $209 million or $0.80 per diluted share. On Slide 7, we cover our hedging program. During the third quarter, we did have 70% of our gas volumes hedged, which did reduce our realized gas price to $2.90 per MCF from the $3.79 per MCF that we realized from selling our production. We also had 40% of our oil volumes hedged, which reduced our oil price to that $58.58 per barrel, versus the $66.11 that we received. Our realized hedging losses in the quarter were $117 million. For the remainder of the year, we have natural gas hedges covering 967 million cubic feet a day, which is about 70% of our expected production in the fourth quarter. Fifty-eight percent of those hedges are price swaps, and then 42% are collars, which also gives us exposure to the higher prices. For next year, we have approximately 50% of our expected production hedged. But 46% of those 22 hedges are swaps, and 54% are collars, which give us exposure to the higher prices that we're seeing for next year. I also want to point out that since the second quarter report, we've only added new hedge contracts covering 75 million a day of our gas production. And those were in the form of wide collars. They had a $3 floor and a weighted average ceiling of $5.58. So these positions are not out of the money as some of the comments that you might have seen this morning or saying, but they do help us achieve the 50% requirement that we have to hedge our production under our bank credit facility. Now that requirement is going to melt away as our leverage falls below two. So, as we achieve our leverage goals next year, we no longer be required to hedge our volumes. Slide 8, we summarize the shut-in activity during the third quarter. We had about 81 million a day or 5.8% of our natural gas production shut-in during the third quarter, as compared to 3.8% in the second quarter. The shut-ins this quarter were mainly due to the really high level of completion activity that we had, both for our own activity and offset operators. And that's necessary in order to protect the older wells when we track a new well nearby. On Slide 9, we detail our operating costs for Mcfe. Our operating cost averaged $0.60 in the third quarter, $0.06 higher than the second quarter rate. This increase was mostly due to higher production taxes coming from the higher oil and gas sales we had for the quarter. Our gathering costs were $0.27 to production and other taxes averaged $0.13, and the field-level operating cost averaged $0.20, both together in operating costs were fairly comparable to our second quarter rates. Slide 10, we detail our corporate overhead costs for Mcfe. And our cash G&A cost per Mcfe remained at a steady $0.05 per Mcfe in the third quarter. Slide 11 shows the DD&A per Mcfe produced, that averaged $0.98 in the quarter, about $0.02 higher than the $0.96 rate we had in the second quarter. Proceeding to Slide 12, we recap our balance sheet at the end of the third quarter. We had $525 million drawn on our revolving credit facility at the end of the quarter. And we expect to use our free cash flow and proceeds from the Bakken sale to further pay down that balance during the rest of the year. On October 22, our bank group reaffirmed our $1.4 billion borrowing base, and right now we have just under $2.5 billion of senior notes outstanding comprised of the $244 million of 7.5% senior notes due in 2025, $1.25 billion of the 6.75% senior notes due in 2029, and $965 million of our new 5% and 7% senior notes due in 2030. We currently plan, as Jay mentioned, to retire the 7.5% bonds next May with the free cash flow that we're generating. The reduction in our debt and the growth in our EBITDAX so far is driving a substantial improvement to our leverage ratio, which has now fallen to 2.3 times if you'd look at the third quarter on a standalone basis. We see this improving further over the next two quarters and we expect this to get below 1.5 times in 2022. At the end of the quarter, our financial liquidity has grown to over $1 billion. On Slide 13, we give a recap of the third quarter capital expenditures. In the third quarter, we spent $162 million on our development activities, and $143 million of that was on our Haynesville operated shale properties. We drilled 13 or 11.7 net new operated Haynesville wells, and then we turned 27 or 22.4 net wells to sales in the third quarter. We also spent about $90 million on non-operated activity and other development activity. In addition to funding our development program, we also spent $5 million on leasing up new exploratory acreage. We're currently running five operated rigs for our 2021 drilling program. And we plan to remain at that level for the rest of this year. Based on our current operating plan for this year, we expect to spend between $590 million to $630 million, which would include drilling 52.5 net operated Haynesville wells, and then turning 54.4 net operated wells to sales. The increased spending from our earlier budget is related to the acceleration of the completion activity on an additional 9.4 net drilled but uncompleted wells. Accelerating this activity allows us to bring these wells on several months early versus our prior schedule, where completion activity was not going to begin on any of these wells until January 2022. So, this has been funded with part of the proceeds from our $154 million divestiture of the Bakken properties. We are going to remain very focused on generating significant free cash flow for this year and as we look into 2022. And with the current gas prices, we anticipate significantly exceeding our original target of $200 million of free cash flow generation for this year. That incremental free cash flow and proceeds from the Bakken sale will be used to also accelerate our delevering plans. And now we're excited to be able to on the verge of accomplishing those, getting our debt down to a level that we think is the right level for the company, and having a leverage ratio that's also at that right level. I'll now turn it over to Dan, to kind of report on operations in the quarter.

Thank you, Roland. Over on Slide 14, this is a map outlining the area of our most recent well activity. We have completed 15 new wells since the time of our last call. These wells were drilled with lateral lengths that range from 4,578 feet up to a high of 10,530 feet, the average lateral length being 7,925 feet. The wells tested at IP rates that range from 11 million a day up to 30 million a day with a 22 million a day average IP rate. We currently have 13 additional wells that have been drilled that are waiting on completion. On our activity levels, we're currently running five rigs and three frac crews. Our activity will remain steady at these levels through the end of the year, while we expect the number of our DUCs to further decrease by year-end. Over on Slide 15, is the updated D&C cost trend for our benchmark long lateral wells. These include all our laterals that were drilled with greater than 8,000 foot lateral lengths. For the third quarter, our total D&C remained flat at $1,051 a foot as compared to the second quarter and 2% higher than our full year 2020 D&C cost. Our drilling costs in the third quarter increased by 5% to $410 a foot compared to the second quarter, but 10% below our drilling costs in 2020. The quarter-to-quarter drilling cost increase was mainly attributable to rising pipe prices and a slightly lower drilling efficiency we had due to lower average lateral lengths drilled in the third quarter. Conversely, we experienced the slight quarter-to-quarter decrease of 3% in our completion costs. The decrease resulted from a higher completion efficiency that we were able to achieve during the third quarter. As a result of the rapid increase in commodity prices during the third quarter, we have already experienced some increase in service cost. Looking ahead to the fourth quarter and early next year, we anticipate a 10% average increase in service cost as the demand increases. We plan to partially offset these higher service costs with an increase in efficiencies by drilling longer laterals. In September, we successfully drilled, cased, and cemented two 15,000 foot laterals on the same pad, which we believe is the first in the basin. Those laterals were drilled to the Haynesville formation and both these wells are currently being completed. We expect to have these wells turn to sales by mid-December. We're also in the process of drilling two additional 15,000 foot laterals in the Bossier formation. We expect to finish drilling these wells before year-end and the wells will be completed during the first quarter of next year. On Slide 16, we will cover our recent agreement with MiQ to initiate the certification of our natural gas production in North Louisiana and East Texas under the MiQ methane standard. MiQ will oversee an independent third-party audited assessment of methane emissions from our company-wide gas production, which is primarily made up of our Haynesville and Bossier shale gas production. Responsible energy solutions will serve as the third-party auditor for the certification process. The certification will cover 2 BCF a day of natural gas production that we produce for ourselves and our partners. This initiative demonstrates our commitment to produce our natural gas under strict environmental standards. It will also allow us to deliver differentiated responsibly sourced natural gas to our customers. This process is expected to commence by the end of this year and we anticipate that we will achieve certification during the first half of 2022. I will now turn it back over to Jay, to summarize our outlook for the remainder of the year.

All right, Dan, and thank you. Again, to kind of reiterate what Dan said, this certification, we hope to cover all the gas we produce and then our partners, that's a 2 BCF by the middle of next year. So I think that's a big step for us. We're cautious before we hired MiQ. We think they will do a great job at a reasonable cost. So if you look at 2021, this is on Page 17, kind of the outlook. And I can tell you, we're just really excited about the quarter about what the fourth quarter looks like, and particularly what 2022 would look like. 2018, '19 were consolidation years, 2020 was a COVID year, and '21 and '22, those are the delevering years. Just to focus on free cash flow as Roland said, focus on creating a strong balance sheet, being thankful we have this extensive inventory of drilling where 93% to 94% of this acreage is held by production. I think Dan and his group have done a really, really good job. We continue to be a low-cost operator. But I'd like to direct you to Slide 17, we summarize our outlook for the remainder of the year. Our original operating plan, which is what we told you, for this year, expected to provide production growth close to 10%. And most importantly, generate an excess of $200 million in free cash flow well. We're currently on track to significantly exceed the targeted $200 million in free cash flow as probably anticipated. The primary focus this year is to improve our balance sheet, reduce our leverage, and lower our cost of capital. Our March and June refinancing transactions have reduced our cost of capital with the $48 million annual savings in interest payments, and the free cash flow is being used to reduce our debt. Our leverage ratio has already improved to 2.3 times in the quarter, down from 3.8 times at the end of 2020. And then based upon our current plan and the price outlook, we anticipate our leverage ratio further improving to less than 1.5 times in 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 in the Haynesville/Bossier drilling locations provide us with decades of drilling inventory. We'll also focus on lowering our greenhouse gas emissions and have demonstrated our environmental stewardship with our recent partnership with MiQ to certify our gas as responsibly sourced. We have very strong liquidity right now with over a billion dollars of liquidity. So with that, I'll turn it over to Ron, to give you some guidance for the remaining three months.

Thanks, Jay. On Slide 18, we provide our guidance for the fourth quarter, which is just the last three months. For the production side, we expect production to average between 1.42 and 1.45 Bcfe per day, that'll be plus or minus 99% gas and that incorporates the sale of the Bakken that is anticipated to close sometime around mid-November. Development capital, as mentioned, is $115 million to $135 million, including the impact of the spending related to the acceleration of the 13 or 9.4 net DUC completions in order to benefit from the stronger winter pricing. We're using a portion of the Bakken sales proceeds to fund that acceleration and those DUCs are now expected to all be online sometime in late December to the end of January, versus the original budget in the February, March timeframe. That budget anticipates remaining at five rigs at our current five rigs over the remainder of this year. We also anticipate spending another $1 million to $2 million on the leasing activities. LOE costs on a unit basis in the fourth quarter are expected to average $0.19 to $0.23, which is down from our prior annual guidance of $0.21 to $0.25. Gathering and transportation costs are expected to remain in the $0.23 to $0.27 range. The production and ad valorem taxes are expected to average $0.12 to $0.14, which is up from the prior guidance of $0.08 to $0.10, and that is all related to the impact of higher oil and gas prices. The DD&A rate of $0.90 to $1.00 is unchanged as is our cash G&A guidance of $0.05 to $0.07. I'll now turn the call back over to the operator, and we'll take questions from analysts who cover the company.

Your first question comes from the line of Derrick Whitfield from Stifel. Your line is now open.

Thanks, and good morning, all. With my first question, I wanted to focus on your revised 2021 capital plan and early outlook for 2022. Following the Bakken divestiture and DUC announcement, I think there was some investor concern that Comstock would maintain a higher activity trajectory, headed into 2022 based on the additional CapEx added to the 2021 plan. With the understanding that you're not formally got into 2022 at this time, how should we directionally think about activity as we approach 2022?

I think, we haven't given guidance for 2022. But net, net, net, we're probably going to have a 4% to 6% year-over-year growth. That's kind of our goal. We haven't back into what the budget would look like. I mean, we got to see where natural gas prices are. I think, we're not overly hedged, so we're in good shape there. And again, our direction of the company, what we're going to do, we're going to use that free cash flow to pay down 7.5% bonds, pay off our bank facility, and then try to establish a shareholder dividend. We're not going to try to wreck the party. We're going to have a 4% to 6% growth. This is our goal right now. But we have not put out any guidance.

Thanks, Jay. And for my follow-up, I'll actually focus on the bigger picture item that you just closed with there. As we model your free cash flow profile at strip, we project you'll achieve your targeted 1.5 net debt to EBITDA leverage next year, and with free cash flow yields on our models in the 30% range for '22 and '23, we see really material potential for return of capital. And while you noted dividend in your prepared remarks, would it be safe to assume return of capital would take the form of a modest fixed dividend plus variable dividend or share buyback? Any color you could offer on preference between return of capital options would be greatly appreciated?

Well, I think again, we used to have a dividend. Let's say, we would reinstate our dividend. It's been so long, we had a dividend in 2014. We believed back then, that if you had the location, you had the balance sheet, and you had the low cost and you had the geographic region, that you could forecast the next two or three, four years of pretty consistent growth even with variable commodity prices, that you shouldn't be a dividend yielding company. So again, we don't want to get ahead of ourselves, we want to make sure that we do get these leverage ratios. And I think we're going to be what the process really is and what the budget that we have with the cost we have. We do think there's going to be some inflation. I think that 1.5 leverage ratio, we're kind of like we said, $200 million in free cash flow in 2021. And we're going to we think materially beat that. I think that we're going to beat that 1.5 leverage ratio, which means to your point, we're going to have quite a bit of just cash. It's going to be cash on the balance sheet, because we'll have paid down our RBL, we will have it hopefully $1.4 billion completely undrawn. And all the debt that will be due to be in 2029, and 2030. And again, that's why I go back and say, when were the consolidation years for us? They were line years, they were 2018, 2019. And now what we've got to do is, we've got to cultivate what we bought in those two years, and you get rid of the COVID year. So again, I think our key to you is that it's just production growth, because you do need a little bit of growth. And that includes bringing the DUCs forward from the latter part of '21 over to the production of 2022. So you'll see a little bit higher production there. I'm not going to beat around the bush there, since we didn't give any guidance. Does that give you a feel and a confidence about what we're doing or do I need to elaborate more?

Jay, I think that's suffice. I think there's a tremendous amount of free cash flow yield above and beyond what would be required to pay off the debt. And I think the markets would certainly look for clarity over time with how that would take form. And clearly, we have some time left to chip away at the debt. But certainly, you guys are in a great position. So that's very helpful. And thanks for your time.

Your next question comes from the line of Austin Aucoin from Johnson Rice. Please go ahead.

Good morning to all. Now you're up to 50% hedged on your forecast in 2022 volumes, and we expect leverage ratios to get below 2 times. Are you all satisfied with the current hedged book? Or is there anything that will lead to more hedging for 2022 volumes?

Yeah, we're really satisfied with - I mean, we've accomplished our goals for '22. We're not very hedged in '23. But for the next - our typical just to kind of get out there, 12 to 18 months hedge. So yeah, and we finished up that, like I pointed out with very wide collars, because we do believe gas prices are going to be strong next year. And so, we like that structure. But as we accomplish our leverage goals, I mean, the need for hedging at high percentages, really, it goes away. And, we expect to be a lot lighter in the percentage that we hedge going forward.

With a process that we've now seen for years, you wish we didn't have that much hedge. But we're probably not overly hedged based upon the peers. But as Roland said, it's not our plan to put in any more hedges, period. We think we didn't accomplish our goal. With that amount of hedge, I think the banks are comfortable with it. Everybody's comfortable with it. So we're going to keep it status quo right now.

Thank you for that color. And my follow-up is, you all said you expect to see about 10% service costs inflation. I just wondered is that mainly in labor, or is that in steel or due to the bottleneck?

Yeah, I think there's an article about the haves and have-nots that came out today. And I do believe this is going to be correct. I think that if you're a small operator out there, you're going to have a hard time getting pipe, you're going to have a hard time getting rigs that are not exorbitant price. And I think that if you're like a Comstock or larger producer, and you keep three, four or five rigs busy at a time, I think our cost will still go up maybe that 10% is our number overall and our drilling cost is going to go up a little bit. We think pipe costs are going to go up a little bit. They've been so low for so long. But we've worked that inflation number into our 2022 budget internally. So the numbers that we kind of allude to in 2022, we've got a 10% inflation factor in those numbers. And that's a pretty big inflation number to look at what kind of CapEx numbers we might run. So, Dan, do you want to comment more on that?

Yeah, I think you hit the nail on the head. I think, for some of the really smaller operators out there, that don't have big programs, I think they are going to be challenged in securing pipe, securing rigs, and securing frac crews, primarily, those three things. We're in pretty good shape on our pipe, being secured out through the second quarter of next year. We have seen, I'd say overall percentage increases, that's probably the largest increase we've seen to date has been on steel or pipe prices. We're up 15%, 17% right now versus first of the year. We think that'll ease up some more in the next year. We know the rig rates are going to be increasing going into next year. But I think when you average all of the services that make up the daily spread rates, when we're drilling and completing these wells, we still feel right now that 10% across the board increase is a pretty good number. And, we'll see where we're at by say middle of next year.

We're pretty good barometer too, because we use a couple of different drilling companies. We use three different fracking companies. So we're not just connected to one company. It can be good or bad. But we do have a kind of a smorgasbord of companies that have helped us year after year after year achieve our consistent low drilling and completion costs. I think they're going to be team members in the future same way that midstream. We've got several midstream partners that are looking at us as a pure play Haynesville producer with proximity close to LNG takeaway facilities that would like to do some more business with us. And we're eager to do business with them. So we can lock up takeaway capacity to the Gulf.

I appreciate the color. That's all for me.

The next question is from Bertrand Donnes from Truist. Your line is now open.

Good morning, guys. With the announcement of you accelerating some of those turning lines into the end of the year. Is that something that maybe we should think about could be a reoccurring thing for the company? Some of the Northeast guys have done this, where each year they kind of load up their turning line schedule right before the winter. Or maybe if there's just room for you to do it with choke management?

I think, what we want to do going forward, especially given the service companies being busier is that we keep a consistent level of activity that matches our - so as the frac services to match our drilling activity. This year we didn't have that type of plan. We kind of got caught up. But I think going forward, it's going to be much more - we have to control the cost of our services if we can have a consistent level of activity versus trying to ramp up or not. So Dan, you might add to that.

Yeah, I'd say really, kind of get to the heart of your question. I kind of see this really as a one-time event. We got caught up under DUCs. We've been carrying some DUCs really throughout the year. This acceleration of these 13 gets us caught up under just a normal cadence. And when your frac crews are coming in behind, we're always going to have between five and 10 DUCs, just the way that they're the definition of a DUC. But we think going into next year, we'll just kind of maintain that high single-digit level. Normal cadence frac crews come in behind the rigs and don't really see building any DUC higher than that going forward.

And then, I think if you look at the big footprint we have on our acreage, there could be some takeaway issues in the Haynesville. People don't have a bigger footprint. So we spread our production out. We've got a front run that takeaway. I think that's another plus that we have. And remember the reason we have the DUCs in 2020, we went for probably two and a half months without fracking a well and we had four rigs drilling wells. So, you get kind of compounds over to what we look like at the end of 2020 going into 2021, we had the five rigs in 2021, so we just never got caught up on the DUCs.

That's good, guys. And then really just the follow-up, I know you guys are trying to target longer laterals. Can you maybe just talk about your willingness to? Is that part of the leasing budget that you want to core up your acreage maybe do swaps? Or is that incremental saving, not necessarily worth it, and you're just going to target the longer lateral locations that you already have, when you can?

So this is Dan. It'll certainly affect maybe some of our trades, but really the driver is just better efficiencies. When you drill a long way from 5 Ks to 10 Ks, the returns are so much better. Your efficiencies are better. Your cost per foot comes down. And so really, this is just a natural extension to go from 10 to 15. Now, that's in Louisiana, you kind of got the three buckets on the Louisiana side. You got one section or section and a half or three sections. But in Texas, it's a little more random. I mean, we'll have some of the 13 and 14,000 footers. So it's just kind of a - it's a little more just random lengths between 10 and 15. Like I said, we've drilled and cased these first two. They went really well. We're drilling the next two now and kind of pending the results of these, which we feel pretty good about. We're going to have several more that we're going to drill next year, and probably even more in '23. So that's going to help combat this kind of our service cost environment by getting our costs down and getting more efficient.

And any other comments Dan on some of the inbound calls have been and what do you think about the 10,000, 15,000 foot laterals, your ability to drill them and complete them. Any other comments that you want to make to the public?

So I mean, we feel great about drilling the 15,000 foot laterals and really completing them. The one thing that's different about a 15k, it has a little bit of a different risk profile. I mean, if you run into some issues, it could cost you a little more time and money to remedy those issues when you're that far out in a lateral. So, we have to take those things into consideration. But, we're on the learning curve for the 15k. I mean, we just right out of the chute, I think we did a great job on those first two. And, it's only going to get better. I think we rely on obviously, the tools from our vendors to improve. And I just think that we'll get better from here. So I don't think there's any doubt that the 15,000 foot laterals are going to become a mainstay. We're here to stay.

We usually have dialed in our all the operations superintendent, so they'll tell you, we set most of the records in Haynesville. I think that's right, Dan?

Correct. A lot of the records.

You said a lot of records. So again, I don't think anybody's drilled or completed more of these wells than we have, at least somebody has taken that tag. So again, we don't read the book to figure it out how to do it. We write most of it. And then that part that we don't know, we read it intensely.

Well, that sounds good. That's all for me, guys.

Thank you.

Next is Leo Mariani from KeyBanc. You may ask your question.

Hey, guys. I just want to ask about activity. If I sort of saw this correctly, it looks like fourth quarter activity out in the field is roughly the same as it was in third quarter. I guess you guys are expecting CapEx to go down quite a bit in 4Q. I was just looking for some color behind that.

I think the activity is a lot less. We do say we're running five rigs, but two of those are really working with properties would have an interest in, working for the Jones partnership. So the drilling activity actually in the fourth quarter is a lot less given the number of rigs running for our own account. And completion activity -

And then, Leo, on completions, we brought on our turn to sales during the third quarter about 22 net wells, and that's going to be closer to 10 in the fourth quarter.

Okay, that's helpful. And then just I wanted to touch base on taxes here a little bit. So it looks like we started to maybe see some cash taxes kind of creep into the numbers here in 2021. I understand you might have had some one-time payments in the third quarter. But can you speak to what your overall expectations are in this kind of current commodity price environment for cash tax as we get into next year?

Yeah, there were no payments, cash payments of taxes that went out at all. But we do - if we put, we've had an increase to the current tax provision. And that's all state taxes, not federal. And so, I think the taxes were highly influenced this quarter by the very large mark to market losses, which creates some unusual items. You're not able to kind of forecast the same utilization of the NOLs and stuff when you have cumulative losses, just under the accounting rules. But those don't match reality. Reality is we forecast very big profits and we'll be able to utilize the NOLs, even though we can't show that under our accounting rules. But overall, I mean yeah, there is with the high profit levels, we'll have some level of state taxes. We still have probably several years out before we start forecasting federal cash taxes.

Okay. Thanks, guys.

Your next question comes from the line of Noel Parks from Tuohy Brothers. Your line is now open.

Hi, good morning. Just a couple of things, I want to run by you. Apologies if you may have touched on this earlier. But since we've had these other fairly large Haynesville transactions over the course of the year, I just was curious as far as acreage trading, trying to clean up leases, have some of those assets changing hands been helpful or a hindrance as far as just dealing with other operators?

Hey, this is Dan. We got several of those working right now. And I would definitely say that it's going to be a big help. Some of these deals were not closed, and really taken effect yet. But, for instance, we have one in particular, we're already talking with the new operator. So I think that's going to definitely be a big benefit more than hindrance anyway, going forward.

The race that it's a win-win for both sides. We have a bank group that extends their laterals, and they have acreage, they can extend ours. So it's definitely a two-lane road. So I think everybody wins on that.

Great. And on the ESG front, I was interested in your choice of MiQ standard. I just wonder if you could talk a little bit about why you chose that particular one. I recall you saying that there have been other vendors that have been participating in the base that have some back and forth, as far as who was being used?

Yeah, I'd say, there's not a lot of potential people that we could use. But we just - I mean, we went with MiQ, because we like the transparency. And, just looking ahead down the road, we feel like we're going to be in really good shape partnering with them. They got a really strong standard. And, of course, they really pretty much are all about emissions. And we have really - our mission intensity right now, our methane intensity right now is really, really well. I mean, we can score really well with that as it is now. So we just need to focus on some of the other things with them. And we think, they're going to help us achieve that.

Great, thanks. Just one thing kind of related and this one is maybe for Roland. I was curious, I know it's very early to be thinking about this. But do you have any sense of what the accounting might look like for gas deemed RSG? In terms of if it commands a premium, is that just part of or do you anticipate that's just part of realized price? Or is that some sort of other category of revenue? Just wondering if that had come up yet?

I would assume that the accounting will be just shown in higher price realizations. And that's really as you enter into a contract with the purchaser, you agree on standards, and then you'll have a process like an audit, like we'll have here to certify those standards to the purchaser, and then they'll be willing to - and then under that contract, if you achieve those standards, they'll pay you that premium to what otherwise they might be buying the gas for. That's the theory. And I think as we are able to directly connect, especially with LNG purchasers that kind of want to overall achieve - to ensure that the product they are buying has been responsibly sourced, and that they can take credit for that, and achieving their environmental goals. I mean, we're there to help that process and allow them to show that the gas from producers like us, in a large dry gas basin with high volume wells, new equipment, that we don't have high methane leakage that they criticize the overall natural gas industry for. So, I think that's why we think this is really important for us and the other dry gas producers, that we can differentiate our product, because we think - and not be tagged with other people where they are achieving these standards. So, I think, even if we don't get a premium price, it's very, very important for us achieving our own environmental goals.

Yeah, I think if you look at the scoreboard, like Dan said, I mean, we have such low ESG intensity, and we put that in the press release. I mean, even though, I think as 5.1, we lowered it by 38% since 2018 to this 3.12. We're very good for the environment. But I think to improve your scoreboard, whatever we need to do to demonstrate that we're committed to the highest environmental standards, we're going to do that. We don't flare gas, much of those things that are issues we don't have to start with. Now, we just have to make sure that we drill, complete and we produce these wells, we don't have any leakage. I mean, again, we're so fortunate to be a pure play really Haynesville player, particularly after the base of the Bakken. So we welcome these challenges. I think we will become a better company for the challenges.

Great. Thanks a lot.

Your last question is from Kashy Harrison from Piper Sandler. You may ask her question.

Good morning, everyone. And thank you for taking my question.

Yes, yes. You're the last one. Let's save the best for last.

You talked a little bit earlier about takeaway response to another question. And I wondered if you could just maybe dig into that a little bit. How much takeaway do you think is in the Haynesville to get from that general area down to the Gulf Coast? And I'm trying to think through what the ceiling on Haynesville production might be over the longer period of time?

Roland?

We hate to really get into that kind of overall, but because we know our situation really well and probably don't want to be real specific on the whole basin. But, we're situated really well. And, our goal is not only to have a takeaway, which we have a substantial takeaway, but have that connected more to the Gulf. And we will be, as we go into this fourth quarter, and especially December, we will be less than 25% of our gas tied to the Perryville hub, which has a little bit wider differential than our Gulf Coast indexes. So, our goal is to get that number to zero and that we have a lot of initiatives working on that. So we're more focused on direct access to the Gulf to get premium prices. And as a backstop, we can sell the gas at the regional hubs.

And you know, what that comes from? It comes from planning. We're asked all the time, when can you drill certain wells, and we said, well, we go out into 2021, 2022. And we figured out that we have ample takeaway at ample units at agreeable prices to keep that low cost category. So, as far as the Haynesville I mean, we're always right. Maybe there's a bigger day of availability, we don't really know. You never know till you test the market.

That is helpful, both on the company level and the macro level. Thank you.

I think the good thing about the Haynesville, though, is as the years progress, you do have people putting steel in the ground. So if there is going to be demand, and I think maybe selling the takeaway may expand another 2 BCF in the next 18-months to two years, we'll go from 10.5 to 12.5 to call it 14-days plus the export to Mexico. I think the midterm is going to provide the positive we need, period. I think they're going to partner with Comstock to get the gas to the Gulf. Are we good?

Yes. That ends our question-and-answer session. I'll turn the call back over to you for the closing remarks.

Okay. Again, I want to thank everybody for the most valuable thing you have time. So you spent about an hour of that with us. We're by far the single largest pure play in the Haynesville, and I think we're very fortunate to be there. It was through planning with the Jones family, et cetera, that we were able to get there. And then now all of a sudden, you can see the demand for the gas in U.S. and on other worldwide. This global demand for gas needs that they needed in Europe, they needed it in Asia, they need it here. I think LNG, I think those FIDs are looking positive to add some more export facilities within the next several years. So I think, again, the key we sorted out an hour ago the direction of the company, what do we want to do. We want to have capital efficiency. I think Dan hit on that. We don't stay in the Haynesville, we've always said that. We want to generate significant free cash flow, I think it's a lot of you had asked, the model shows that that will happen. And then specifically, what do we want to do? I mean, we want in the next several quarters, we do want to pay off our RBL. We want to use that free cash flow to do that. And then we want to retire this 7.5% bond by May of 2022. And then as a lot of you alluded what are you going to do with the rest of the cash for well. With all those goals met the debt reduction goals, we're going to look at establishing a shareholder dividend, and then growth in 2022. Again, it's at 4% to 6% is what we would think. And we've not given out any guidance. Thanks. It looks really good in the world of natural gas, and Haynesville and particularly at Comstock. So thank you for your time.

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