Good day. Thank you for standing by, and welcome to the Q3 2021 Comstock Resources, Inc. earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during that session, you will need to press star one on your telephone keypad. If you require any further assistance, please press star zero. Thank you. I would now like to hand the conference over to your speaker today, Mr. Jay Allison, Chairman and CEO. The floor is yours.
Thank you, everyone. It's a little rainy outside in Frisco, Texas. I guess winter is in the air. It's coming our way. You know, what a great time to be in the natural gas business, especially in the Haynesville. I wanna have a couple of clarifying statements before we start the actual third quarter of 2021 results. With our Bakken properties and the contract for that $154 million, which most of you are aware of, and closing expected in the coming weeks, we did pre-announce that we would accelerate completion activity on the 9.4 net Haynesville wells this year to bring those volumes forward into a current strong pricing environment for natural gas. The increased production from those wells really will appear in the first quarter of 2022.
Now, I thought it'd be a good time to talk about the direction of the company. You know, 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 2022. With our debt reduction goals met, we want to establish a shareholder dividend. With that opening statement, I wanna go back on 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. 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'll flip over, please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now, the highlights. This is slide three, the third quarter 2021 highlights. We cover the highlights of the third quarter on slide three. 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 Bcf a 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 $225 million or $0.92 per diluted share. 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 the completion of this 9.4 net drilled uncompleted wells to benefit from the stronger winter pricing. You know, we've now started completion operations of those wells, which Dan will go over with in a minute, that'll be completed by year-end with production January of next year. We recently engaged MiQ to initiate the independent certification of our natural gas production under the MiQ Methane Standard. Dan will also cover that in his part of the presentation. If you flip to slide four, we cover our announcement to sell the Bakken assets on slide four. 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 wellbores. By June 30, the proved reserves associated with the properties totaled 10.8 MMbbl and 44.2 Bcf 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 of 2021's financial results. Roland?
Thanks, Jay. On slide five, we summarize our financial results for the third quarter of 2021. We had a very strong quarter, which was driven by that 25% production increase combined with substantial improved oil and gas prices. Our production in the third quarter totaled 129 Bcf of natural gas, 346,000 bbl .
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 that we 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 also 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 that we generated 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 six, 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. This was due to two items, the large mark-to-market loss on the hedge 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 $209 million profit or $0.80 per diluted share. On slide seven, 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.
58% of those hedges are price swaps, and then 42% are collars, which also give 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% or more than half 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 they had a weighted average ceiling of $5.58.
You know, these positions are not out of the money as some of the comments that you might have seen this morning are saying. 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. As we achieve our leverage goals next year, we'll no longer be required to hedge our volumes. Slide eight, 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. You know, that's necessary in order to protect the older wells when we frack a new well nearby. On slide nine, 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 is 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. The production and ad valorem taxes averaged $0.13, and the field level operating cost averaged $0.20. Both the gathering and field level 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 for Mcfe remained at a steady $0.05 for Mcfe in the third quarter. Slide 11 shows the DD&A for 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 kind of 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.
Right now, we have just under $2.5 billion of senior notes outstanding, comprised of the $244 million of the 7.5% senior notes due in 2025, $1.25 billion of the 6.75% senior notes due in 2029, and $965 million of the, of our new five and, you know, 5.875% 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 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 of 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-$630 million, which will 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 gonna begin on any of these wells until January 2022. This is being funded with part of the proceeds from our $154 million divestiture of the Bakken properties. We are gonna remain very focused on generating significant free cash flow for this year and as we look into 2022. 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 the proceeds from the Bakken sale will be used to also accelerate our delivering plans.
Now we're excited to be able to be 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 the 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 outline we're showing 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 activities 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 benchmarked long lateral wells. These include all our laterals that were drilled with at 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 cost in 2020.
The quarter-over-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 a slight quarter-over-quarter decrease of 3% in our completion cost. 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've 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 through 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 be finished drilling these wells before year-end, and the wells will be completed during the first quarter of next year. On slide 16, we'll 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 we'll 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 that we produce and then our partners, that's at 2 Bcf by the middle of next year. I think that's a big step for us. We were cautious before we hired MiQ. We think they'll do a great job at a reasonable cost. If you look at 2021, this is on page 17, kind of the outlook. 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. You know, 2018, 2019 were consolidation years.
2020 was a COVID year. 2021 and 2022, you know, that's the deleveraging years. It's a focus on free cash flow, as Roland has said, focus on creating a strong balance sheet. You know, being thankful we have this extensive inventory of drilling. 93.4% of this acreage is held by production. I think Dan and his group have done a really good job. We continue to be, you know, a low-cost operator. I'd like to direct you to slide 17, where we summarize our outlook for the remainder of the year. You know, 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 in excess of $200 million of free cash flow.
Well, you know, we're currently on track to significantly exceed the target $200 million in free cash flow, as Roland had stated. Now, 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 a $48 million annual savings in interest payments. The free cash flow is being used to reduce our debt. Our leverage ratio has already improved to 2.3 x in the quarter, down from 3.8 x at the end of 2020. Based upon our current plan and the price outlook, you know, we anticipate our leverage ratio further improving to less than 1.5 x 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. You know, 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 responsible source. We have very strong liquidity right now, over $1 billion of liquidity. With that, I'll turn it over to Ron to give you some guidance for the remaining three months. Ron?
Thanks, Jay. On slide 18, we provide our guidance for the fourth quarter, which is just the last three months. On the production side, we expect production to average between 1.42 Bcfe and 1.45 Bcfe per day. That'll be ±99% gas. That incorporates the sale of the Bakken, which is anticipated to close sometime in around mid-November. Development capital, as mentioned, is $115 million-$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, and 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-$2 million on the leasing activities. LOE costs on a unit basis in the fourth quarter are expected to average $0.19-$0.23, which is down from our prior annual guidance of $0.21-$0.25. Gathering transportation costs are expected to remain in the $0.23-$0.27 range.
The production and ad valorem taxes are expected to average $0.12-$0.14, which is up from the prior guidance of $0.08-$0.10, and that is all related to the impact of higher oil and gas prices. DD&A rate of $0.90-$1.00 is unchanged, as is our cash G&A guidance of $0.05-$0.07. I'll now turn the call back over to the operator, and we'll take questions from analysts who cover the company.
As a reminder, to ask a question, you will need to press star one on your telephone keypad. Again, that is star one on your telephone keypad. Your first question comes from the line of Derrick Whitfield from Stifel. Your line is now open.
Thanks and good morning, all.
Morning.
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 add up to the 2021 plan. With the understanding that you're not formally guiding to 2022 at this time, how should we directionally think about activity as we approach 2022?
I think you know we haven't given guidance for 2022, but net you know we're probably gonna have a 4%-6% year-over-year growth. That's kind of our goal. We haven't backed into what the budget would look like. I mean we've got to see where natural gas prices are. I think you know we're not overly hedged, so we're in good shape there. Again this you know our direction of the company you know what we're gonna do we're gonna use that free cash flow to pay down the $7.5 million bonds, pay off our bank facility, and then try to establish a shareholder dividend. We're not gonna try to wreck the party.
You know, we're gonna have a 4%-6% growth is our goal right now, but we have not put out any guidance.
Thanks, Jay. 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. With free cash flow yields on our models in the 30% range for 2022 and 2023, we see really material potential for return of capital. 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, you know, we used to have a dividend. You know, I'd say we would reinstate our dividend. It's been so long. We had our dividend in 2014. We believed back then that if you had the locations, you had the balance sheet, and you had the low cost, and you had the, you know, the geographic region that you could forecast the next two, three, four years of pretty consistent growth, even with variable commodity prices, that, you know, you should be a dividend-yielding company. So, you know, again, we don't want to get, you know, the cart before the horse. We want to make sure that we do get these leverage ratios.
I think we're gonna be, you know, with the prices where they are and with the budget that we have, with the cost we have, and we do think there's gonna be some inflation. I think that 1.5 leverage ratio, we're gonna. We're kinda like we said, $200 million in free cash flow in 2021, and we're gonna, we think, materially beat that. I think that we're gonna beat that 1.5 leverage ratio, which means, to your point, we're gonna have quite a bit of just cash. It's gonna be cash on the balance sheet because we'll have paid down our RBL. We'll have it to hopefully $1.4 billion completely undrawn. Our only debt that'll be due will be in 2029 and 2030.
Again, that's why I go back and say, well, you know, when were the consolidation years for us? They were the lean years. They were 2018, 2019. 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. 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 2021 over to the production of 2022. You'll see a little bit higher production there. So does that.
I know I've got to beat around the bush there since we didn't give any guidance, but does that give you a feel and a confidence about what we're doing, or do I need to talk some more?
Yeah, I think that's sufficient. I think there's a tremendous amount of free cash flow yield above and beyond what would be required to pay off the debt. I think the markets would certainly look for clarity over time with how that would take form. Clearly, we have some time left to chip away at the debt, but certainly you guys are in a great position. That's very helpful, and thanks for your time.
Yeah. Again, I know what you're leaning into, and we're leaning into the same thing. I mean, the day that we can have a board meeting and we have hundreds of millions of free cash flow and just cash there, we've solved all of our liquidity, etc., listen, we're gonna be good stewards of that money 'cause it's your money and our shareholders' money, okay?
Thanks, Jay.
Your next question comes from the line of Austin Aucoin from Johnson Rice. Please go ahead.
Hi, Good morning to all.
Morning.
Let's see. Now y'all are up to 50% hedged on y'all's forecasted 2022 volumes, and that, we expect y'all's leverage ratio to get below 2x. Are y'all satisfied with the current hedge book, or is there anything that would lead to more hedging for 2022 volumes?
Yeah, we're real satisfied with that. I mean, we've accomplished our goals for 2022. We're not very hedged in 2023. But for the next, our typical just to kinda get out there 12-18 months hedge. Yeah, we finished up that, you know, like I pointed out, with very wide collars, 'cause we do believe gas prices are gonna be strong next year. We like that structure. But as we accomplish our leverage goals, I mean, the need for hedging, you know, at high percentages, really it goes away. We expect to be a lot lighter in the percentage that we hedge going forward.
You know, with the prices that we've not seen for years, you wish we didn't have that much hedge. You know, we're probably not overly hedged based upon the peers. As Roland said, you know, it's not our plan to put in any more hedges, period. We think we've accomplished our goal with that amount of hedge. I think the banks are comfortable with it. Everybody's comfortable with it. We're gonna keep it status quo right now.
Thank you for that color. My follow-up is, y'all said y'all expect to see about 10% service cost inflation. I just wonder, is that mainly in labor, or is that in steel or due to the bottleneck?
Yeah, I think there's an article about the have and have-nots that came out today, and I do believe that's gonna be correct. I think that if you're a smaller producer out there, you're gonna have a hard time getting pipe. You're gonna have a hard time getting rigs that are not exorbitant in price. I think that if you're like a Comstock or a larger producer, and you keep three, four, five rigs busy at a time, I think our costs will still go up maybe that 10% is our number overall. I know drilling costs are gonna go up a little bit. We think frac costs are gonna go up a little bit. They've been so low for so long.
You know, we've worked that inflation number in our 2022 budget internally. The numbers that we kind of allude to in 2022, we've got a 10% inflation factor in those numbers. That's a pretty big inflation number if you look at what kind of CapEx number we might run. Dan, you wanna comment more on that?
Yeah, I think you hit the nail on the head. I think, you know, for some of the really smaller operators out there that don't have big programs, you know, I think they are gonna be challenged on, you know, securing pipe, securing rigs, and securing frac crews, primarily those three things. You know, we're in pretty good shape on our pipe, being secure out through, you know, the second quarter of next year. We have seen, I'd say overall on percentage increases, that's probably the largest increase we've seen to date, has been on steel or pipe prices. We're up, you know, 15%-17% right now versus first of the year. We think that'll ease up some more into next year. We know the rig rates are gonna be increasing going into next year.
I think when you average in all of the services that make up the daily spread rates, you know, when we're drilling and completing these wells, you know, we still feel right now that 10% across the board increase is a pretty good number. You know, we'll see where we're at, you know, by, say, middle of next year.
You know, we're a pretty good barometer too because we use, you know, a couple of different drilling companies, we use three different fracking companies, so we're not just connected to one company.
Yeah, it can be good or bad, but we do have a kind of a smorgasbord of companies that have helped us year after year achieve you know our consistent low drilling and completion costs. I think they're gonna be team members in the future, same way as a midstream. You know, we've got several midstream partners that are looking at us as a pure play Haynesville producer with the you know proximity close to LNG takeaway facilities that you know 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 from me.
Thank you.
Next question is from Bertrand Donnes from Truist. Your line is now open.
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 recurring thing for the company? You know, some of the Northeast guys have done this, where each year they kinda 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 you know what we wanna do going forward, especially given the service companies you know being busier, is to keep a consistent level of activity that matches you know our drilling activity. Have the frack services to match our drilling activity. This year you know we didn't have that type of plan. We kinda get it caught up. I think going forward, it's gonna be much more, we have to control the cost of our services if we can have consistent level of activity versus trying to create DUCs or not. Dan, you might add to that.
Yeah. I'd say really kinda get to the heart of your question. This is I kinda see this really as a one-time event. We got caught up on our DUCs. We've been carrying, you know, some DUCs really throughout the year. This acceleration of these 13 gets us caught up, you know, under just a normal cadence. When the frac crews are coming in behind a rig, we're always gonna have between five and 10 DUCs just the way that they're, you know, the definition of a DUC. We think going into next year, you know, we'll just kinda maintain that high single digit level. Normal cadence, frac crews coming behind the rigs and don't really see, you know, building any DUCs higher than that going forward. Roland made a good point.
You know, when times get busy like this, it's really important to schedule.
Is that incremental saving not necessarily worth it and you're just gonna target the longer lateral locations that you already have, when you can?
Well, this is Dan. It'll certainly affect, you know, maybe some of our trades, but really the driver is just, you know, better efficiencies. When we went from 5 Ks to 10 Ks, you know, 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, you know, to go from 10 to 15s. Now, that's in Louisiana. You know, you kind of got the three buckets in on the Louisiana side. You know, you got 1 section or a section and a half or three sections. In Texas, it's a little more random. I mean, you know, we'll have some will be 13s, some 14,000-footers. It's just kind of a. It's a little more just random lengths between 10 and 15.
We, you know, like I said, we've drilled and cased these first two. They went really well. We're drilling the next two now. You know, kinda pending the results of these, which we feel pretty good about, we're gonna have several more, you know, that we're gonna drill next year and probably even more in 2023. That's gonna help combat, you know, this kinda higher service cost environment by getting our costs down and just getting more efficient.
Dan, any other comments? I know some of the inbound calls have been, you know, what do you think about the 10,000-15,000 foot laterals, you know, your ability to drill them and complete them. Any other comments that you wanna make to the public?
I mean, we feel great about drilling the 15,000-foot laterals and really completing them. You know, the one thing that's different.
Hey, guys. Just wanna ask about activity. If I sort of saw this correctly, looks like fourth quarter activity out in the field is roughly the same as it was in the third quarter. I guess you guys are expecting CapEx to go down, you know, quite a bit in 4Q. I was just looking for some color behind that?
I think the activity is a lot less. Yeah, we do say we're running five rigs, but two of those, you know, are really working, you know, with properties we'd have an interest in, working for the Jones Partnership. The drilling activity actually in the fourth quarter is a lot less, well, you know, given the number of rigs running for our own account. In completion activity,
Yeah, Leo, on completions, you know, we've brought on or returned to sales during the third quarter of about 22 net wells, and that's gonna be closer to 10 in the fourth quarter.
It's a lot lower activity quarter.
Okay. Yeah, I guess I thought you guys were running the same five rigs and three crews each quarter, but it sounds like maybe there, you know, some working interest differences there as well and perhaps some timing on the payments.
Yeah, even I think the crews that we'll average, I mean, for one on our account, again, you know, are significantly less than three for the quarter.
Closer to two and a half crews.
Okay. That's helpful. Just, I wanted to touch base on taxes here a little bit. It certainly looks like we started to maybe see some cash taxes kind of creep in to the numbers here in 2021. I understand there might have been some one-time payments in the third quarter, but could you just speak to what your overall expectations are in this kind of current commodity price environment for cash taxes as we get into next year?
Yeah. There were no payments, cash payments of taxes that went out at all. You know, we do, you know, we had an increase to the current tax provision, and that's all state, you know, state taxes, not federal. I think the taxes were highly influenced this quarter by the very large, you know, mark-to-market losses, which create 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. Those aren't, those don't match reality. Reality is we forecast very big, you know, profits, and we'll be able to utilize the NOLs even though we can't show that, you know, for, on a, you know, under accounting rules.
Overall, I mean, yeah, there is, with the high profit levels, we'll have some level of state taxes. We still have, you know, we probably are several years out before we start forecasting, you know, federal, you know, cash taxes.
Okay. Thanks, guys.
You know, in probably six or seven, eight years, I haven't heard the issue of taxes, so that's a pretty good. I'm glad we're in that era. It's a good thing. I hope we have more of those questions in 2022.
Your next question comes from the line of Noel Parks from Tuohy Brothers. Your line is now open.
Hi. Good morning.
Morning.
A couple things I wanted to run by you. Apologize if you might 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. You know, we got several of those working right now, and I would definitely say that it's gonna be a big help. You know, some of these deals are not closed and really taken effect yet. You know, for instance, we have, you know, one in particular where we're already, you know, talking with the, you know, the new operator. I think that's gonna definitely be a big benefit, more than a hindrance anyway going forward.
The reason it's a win-win for both sides, we have acreage that can extend their laterals, and they have acreage that can extend ours. It's definitely a two-lane road. I think everybody wins on that.
Great. On the ESG front, I was interested in your choice of the MiQ standard. I just wondered if you could talk a little bit about why you chose that particular one. I recall you saying that there had been other vendors that had been participating in the base set and some back and forth as far as, you know, who was being used.
Yeah, I'd say, you know, there's not a lot of potential people that we could use, but I mean, we went with MiQ because we like the transparency. You know, just looking ahead down the road, we feel like, you know, we're gonna be in really good shape partnering with them. They got a really strong standard, and, you know, of course, they really pretty much are all about emissions. You know, we have really our emission 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.
We just need to focus on some of the other things with them, and we think, you know, we think they're gonna help us, you know, achieve that.
Great. Thanks. Just one thing kind of related, and this one's maybe for Roland. I was curious. I know it's very early to be thinking about this. Do you have any sense of what the accounting might look like for a gas deemed RSG in terms of if it commands a premium? You know, is that just part of or do you anticipate that's just part of realized price, or is that some sort of other, you know, other category of revenue? Just wondering if that had come up yet.
Well, I would assume that the accounting will be just, you know, shown in higher price realizations. That's really the, you know, as you enter into a contract with a purchaser, you know, you'll agree on standards, and then you'll have an audit like we'll have here to certify those standards to the purchaser, and then they'll be willing to, you know. Under that contract, you know, that, if you achieve those standards, you know, they'll pay you that premium to what otherwise they might be buying the gas for.
That's the theory, you know, and I think as we are able to directly connect, especially with LNG purchasers that kind of want to, you know, overall achieve a to ensure that the product they're buying has been responsibly sourced and that they can take credit for that, you know, in 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, you know, in a large dry gas basin with high volume wells, new equipment, that we don't have, you know, high methane leakage that they criticize, you know, the overall natural gas industry for.
I think that's why we think this is really important for us and the other dry gas producers, you know, and that we can differentiate our product because we think, you know, and not be tagged with other people's, you know, where they aren't achieving these standards. I think even if we don't get a premium price, it's very, very important, you know, for us achieving our own environmental goals.
Yeah, I think, you know, if you look at the scoreboard, like Dan said, I mean, we have such low GHG intensity, and we put that in the press release. I mean, even though I think it was 5.1, you know, we lowered it by 38% since 2018 to this 3.12. We're very good, you know, for the environment. I think that approach for scoreboards, you know, you whatever we need to do to demonstrate that we're committed to the highest environmental standards, we're gonna do that. We, you know, we don't flare gas. Most 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 produce these wells. We don't have any leakage. I mean, we're so fortunate to be a pure play, really Haynesville player, particularly after the divestiture of the Bakken. So, you know, we welcome these challenges. I think we've become a better company for the challenges.
Great. Thanks a lot.
Your last question is from Kashy Harrison from Piper Sandler. You may ask your question.
Good morning, everyone, and thank you for taking my question.
Yes, yes. You're the last one. They saved the best for last.
You know it. You know, you had talked a little bit earlier about takeaway, you know, in 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, you know, to get, you know, from that general area, you know, down to the Gulf Coast? I'm trying to think through, you know, what the ceiling on Haynesville production might be, over a longer period of time.
Ron, you go.
We hate to really get into that comment overall, but 'cause we, you know, we know our situation really well and don't probably don't wanna be real specific on the whole basin. We're situated really well. Our goal is not only to have the takeaway, which we, you know, we have a lot, you know, substantial takeaway, but have that connected more to the Gulf. We will be as we go into this fourth quarter and especially December, you know, we'll be less than you know, 25% of our gas tied to the Perryville hub, you know, which has a little bit wider differential, you know, than our Gulf Coast indexes. Our goal is to get that number to zero.
It might take a long, you know, and we have a lot of initiatives working on that. We're more focused on direct access to the Gulf to get premium prices. And as a backstop, you know, we can sell the gas at the regional hubs, but.
You know what that comes from? It comes from planning. You know, we're asked all the time, you know, when can you drill certain wells? We said, well, we go out into 2021, 2022, and we figure out that we have ample takeaway at ample, you know, at agreeable prices to keep that low cost category. You know, as far as the Haynesville, I mean, we always read 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.
You know, I think the good thing about the Haynesville, though, you know, 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 this LNG takeaway may expand another, you know, 2 Bcf in the next 18 months to two years. We'll go from 10.5 Bcf-12.5 Bcf or 12 Bcf-14 Bcf plus the export to Mexico. I think the midstream's gonna provide the pipelines that we need, period. I think they're gonna partner with, you know, with the Gulf Coast 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 wanna thank everybody for, you know, the most valuable thing you have, your time. You spent about an hour of that with us. You know, we're by far the single largest pure play in the Haynesville. 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. Now all of a sudden, you can see the demand for the gas in U.S. and on other, you know, others worldwide, this global demand for gas, you know, needs it. They need it in Europe, they need 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.
I think again, the key when we started out an hour ago, the direction of the company, what do we wanna do? You know, we wanna to have capital efficiency. I think Dan hit on that. We'll stay in the Haynesville. We've always said that. We wanna generate significant free cash flow. I think as a lot of you had asked, the model shows that that'll happen. Specifically what do we wanna do? I mean, we want in the next several quarters, we do wanna pay, we wanna pay off our RBL, and we wanna use that free cash flow to do that. Again, we want to retire the 7.5 bond by May of 2022.
As a lot of you alluded, what are you gonna do the rest of the cash for? Well, with all those goals met, the debt reduction goals, you know, we're gonna look at maybe to establish a shareholder dividend. Growth in 2022, again, it's at 4%-6%, is what we would think, and we've not given out any guidance. Things look really good in the world of natural gas and Haynesville and particularly at Comstock. Thank you for your hour.
That concludes today's conference call. Thank you all for participating. You may now disconnect.