Comstock Resources, inc (CRK) Q3 2021 Earnings Call Transcript

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Comstock Resources, inc (CRK 2.21%)
Q3 2021 Earnings Call
Nov 3, 2021, 11:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Today's conference is scheduled to begin shortly. Please continue to standby. Thank you for your patience. Good day. Thank you for standing by, and welcome to the Q3 2021 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions]

I would now like to hand the conference over to your speaker today, Mr. Jay Allison, Chairman and Chief Executive Officer. The floor is yours.

M. Jay Allison -- Chairman and Chief Executive Officer

Thank you, everyone. It's a little rainy outside of Frisco, Texas, guest winters in the airs 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 clarified statements before we start the actual third quarter of 2021 results. With our Bakken properties of a contract for that $154 million, which most of you are aware of, and closing expected in the coming weeks, we did preannounce that we would accelerate completion activity on the $9.4 net Haynesville wells this year to bring those volumes forward into our 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 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 a bit we want to establish a shareholder dividend. So with that opening statement, I don't want to 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 Vice President 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 in such statements to be reasonable, there could 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 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. 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 this 9.4 net drilled uncompleted wells to benefit from the stronger winter pricing. We've now started completion operations on those wells, which Dan will go over within a minute, have been completed by year-end with production January of next year. And 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 well bores. 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 next several weeks.

I'll now turn it over to Roland Burns, our Chief Financial Officer, to cover the third quarter 2021's financial results. Roland?

Roland O. Burns -- President and Chief Financial Officer

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 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 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 hedge natural gas price in the quarter was 49% higher than the third quarter last year.

Our production costs were also -- 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 and A, though, was down 10%, and our depreciation and 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 a 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 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% are 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. So these positions are not out of the money as some of the comments that you might have seen this morning and are saying, they do help us achieve the 50% requirement that we have to hedge our production under our bike 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, will no longer be required to hedge our volumes. Slide eight, we summarized 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 to order to protect the older wells when we frac a new well nearby. On Slide nine, we detail our operating cost 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. The production at Avalor taxes averaged $0.13 and the field level operating cost averaged $0.20. Both together and fill over costs were fairly comparable to our second quarter rates. Slide 10, we detail our corporate overhead cost for Mcfe, and our cash G and A cost per Mcfe remained at a steady $0.05 per Mcfe in the third quarter. Slide 11 shows the DD and 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 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 million borrowing base. And 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 our new 5% and 7%, 8% 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 stand-alone 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 shelf 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 to $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 going to begin on any of these wells until January, 2022. So this is being 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 the proceeds from the Bakken sale will be used to also accelerate our delevering plans. And 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 offset the right level.

I'll now turn it over to Dan to kind of report on operations in the quarter.

Daniel S. Harrison -- Chief Operating Officer

Thank you, Roland. Over on Slide 14. This is a map outlined. We show in 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 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 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 and C cost trend for our benchmarked long lateral wells. These included all our laterals that were drilled with greater than 8,000 foot lateral lengths.

For the third quarter, our total D and C remained flat at $1,051 a foot. As compared to the second quarter and 2% higher than our full year 2020 D and 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-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 a slight quarter-to-quarter decrease of 3% in our completion costs the decrease resulted from a higher completion efficiency that was 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 through an increase in efficiencies by drilling longer laterals. In September, we successfully drilled, cased and cemented 215,000 foot laterals on the same pad, which we believe is the first in the basin. Both 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 are 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 companywide 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 two Bcf a day of natural gas production that we produce for our sales 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.

M. Jay Allison -- Chairman and Chief Executive Officer

All right, Dan, thank you. Again, to kind of reiterate what Dan said, this certification we hope to cover all the guests that we produce and then our partners, that's a two Bcf by the middle of next year. So I think that's a big step for us. We are cautious before we hired MiQ. We think they'll 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, that's the delevering years. It's a focus on free cash flow. As Ronald has said, focused on creating a strong balance sheet, being thankful we have this extensive inventory of drilling 93%, 94% of this acreage is held by production. And 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, where 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 in excess of $200 million of free cash flow. Well, we're currently on track to significantly exceed the target $200 million in free cash flow, as Roland has stated. 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 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. And 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 responsible sourced. We have very strong liquidity right now, over $1 billion of liquidity.

So with that, I'll turn it over to Ron to give you some guidance for the remaining three months. Ron?

Ronald E. Mills -- Vice President of Finance and Investor Relations

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 and 1.45 Bcfe per day. That incorporate, that will be plus or minus 99% gas and that incorporates the sale of the Bakken, which is anticipated to close sometime in 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 time frame. 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 cost 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, 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. DD and A rate of $0.90 to $1 is unchanged as is our cash G and 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.

Questions and Answers:

Operator

[Operator Instructions] Our first question comes from the line of Derrick Whitfield from Stifel. Your line is now open.

Derrick Whitfield -- Stifel -- Analyst

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 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?

M. Jay Allison -- Chairman and Chief Executive Officer

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 have a back in to what the budget would look like. I mean, we've got to see where natural gas prices are. I think we're not overly hedged. So we're in good shape there. And again, this -- our direction of the company, what we're going to do, we're going to use that free cash load to what -- to pay down the 7.5% bonds to pay down or pay off our bank facility and then try to establish a shareholder dividend. We're not going to try to direct the party we're going to have a 4% to 6% growth is our goal right now, but we have not put out any guidance.

Derrick Whitfield -- Stifel -- Analyst

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.

M. Jay Allison -- Chairman and Chief Executive Officer

Well, I think, again, we used to have a dividend. I'd say we would reinstate our dividend. It's been so long. We had a dividend in 2014. We believe back then that if you have the locations, you have the balance sheet and you had the low-cost and you had the geographic region that you could forecast the next two, three, four years of pretty consistent growth, even with variable commodity prices, that you should be a dividend yielding company. So again, we would -- we don't want to get the carrot for the horse. We want to make sure that we do hit these leverage ratios. And I think we're going to be -- what the prices where they are and where the budget that we have, with the cost we have, and we do think there's going to be some inflation I think that 1.5 leverage ratio, we're going to -- we're kind of like we said $200 million of 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 will have it, hopefully, $1.4 billion completely undrawn and our only debt that will be due will be in 2029, 2030 and again, that's why I go back and say, when were the consolidation years for us were the lane years, they were the 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 of our production there. So does that -- I'm not going to beat around the bush there since we didn't give any guidance because that gives you a feel and a confidence about what we're doing? Or do I need to talk some more.

Derrick Whitfield -- Stifel -- Analyst

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.

M. Jay Allison -- Chairman and Chief Executive Officer

Yes. And again, I know what you're leaning into, and we're leaning into the same thing. I mean, the day that we could have a board meeting, and we have hundreds and hundreds and hundreds of millions of free cash flow and just cash there. We've sold all of our liquidity, etc. Listen, we're going to be good stewards of that money because it's your money and/or make shareholders money, OK?

Derrick Whitfield -- Stifel -- Analyst

Thank you.

Operator

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

Austin Aucoin -- Johnson Rice -- Analyst

Hi, good morning to all. Now you are up to 50% hedged on your forecasted 2022 volumes, and that we expect leverage ratio to get below 2 times. Are you all satisfied with the current hedge book? Or is there anything that will lead to more hedging for 2022 volumes?

Roland O. Burns -- President and Chief Financial Officer

We're real satisfied with that. We've accomplished our goals for '22. We're not very -- we have very hedged in '23. But for the next -- our typical is to kind of get out there, 12 to 18 months hedge. So yes, we -- 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 -- and we like that structure. But as we accomplish our leverage goals, I mean, the need for hedging at high percentages really goes away, and we expect to be a lot lighter in the percentage that we hedge going forward.

M. Jay Allison -- Chairman and Chief Executive Officer

With the prices that we've not 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've accomplished our goal. With that amount of hedge, I think the banks are comfortable with it. Everybody is comfortable with it. So we'll keep it status quo right now.

Austin Aucoin -- Johnson Rice -- Analyst

And my follow-up is said, you'll expect to see about 10% service cost inflation. I was just wondering, is that mainly in labor? Or is that in steel are due to the bottleneck?

M. Jay Allison -- Chairman and Chief Executive Officer

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

Daniel S. Harrison -- Chief Operating Officer

Yes. I think you get 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 on 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 in 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 will ease up some more into next year. We know the rig rates are going to be increasing going into next year. But I think when you average in all of the services that make up the daily spread rates when we're drilling 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.

M. Jay Allison -- Chairman and Chief Executive Officer

We're a pretty good barometer too because we use a couple of different drilling companies. We use three different fracking companies. So we're not disconnected to one company, it could be good or bad. But we do have kind of a smorgasbord of companies that have helped us year achieve our consistent low drilling and completion costs. And I think they're going to be team members. In the future, same way as the 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 capacity to the Gulf.

Austin Aucoin -- Johnson Rice -- Analyst

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

M. Jay Allison -- Chairman and Chief Executive Officer

Thank you.

Operator

Next question is from Bertrand Donnes from Truist. Your line is now open.

Bertrand Donnes -- Truist -- Analyst

Good morning guys. With the announcement of you accelerating some of those turner 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 schedule right before the winter? Or maybe if there's just room for you to do it with choke management?

Roland O. Burns -- President and Chief Financial Officer

I think that what we want to do going forward, especially given the service -- the service companies being busier is to keep a consistent level of activity that matches our -- so have the frac services to match our drilling activity. This year, we didn't have that type of plan. We kind of get it 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 consistent level of activity versus trying to create DUCs or not. So Dan, you might add to that?

Daniel S. Harrison -- Chief Operating Officer

Yes. I'd say, really kind of get to the heart of your question, this is -- I kind of see this really as a onetime event. We got caught up on our DUCs. We've been carrying 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 -- the frac crews are coming in behind a rich, we're always going to have between five and 10 DUCs, just the way that they're -- the definition of a duck. But we think going into next year, we'll just kind of maintain that high single-digit level. Normal cadence for crews coming behind the rigs and don't really see building any ducts higher than that going forward. And Roland made a good point. When times get busy like this, it's really important to schedule your crews to have minimal gaps that you don't have to drop crews or add crews because that can be really challenging when things get to be in high demand.

M. Jay Allison -- Chairman and Chief Executive Officer

Well, 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 kind of 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 2.5 months without fracking a well, and we had four rigs drilling wells. So you had kind of compounds over what we look like at the end of 2020 going into 2021 we have the five rigs in 2021. So we just never got caught up on the DUCs.

Bertrand Donnes -- Truist -- Analyst

That's good, guys. And then really, just a 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 gain?

Daniel S. Harrison -- Chief Operating Officer

Well, so this is Dan. It will certainly affect maybe some of our trades, but really, the driver is just better efficiencies when you drill when we went from 5Ks to 10Ks, 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 1.5 or three sections. But in Texas, it's a little more random. I mean, we'll have some of 13,000, some 14,000 footers. So it's just kind of a -- it's a little more just random lengths between 10 and 15. We -- 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 so that's going to help combat this kind of higher service cost environment by getting our costs down and just getting more efficient.

Bertrand Donnes -- Truist -- Analyst

Bertrand Donnes And any other comments, John, I know some of the inbound calls have been 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?

Daniel S. Harrison -- Chief Operating Officer

So -- yes, I mean, we feel great about drilling the 15,000 foot laterals and really complete 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 can 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 a learning curve for the 15Ks. I mean we just right out of the shoot. 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 -- we're here to stay.

M. Jay Allison -- Chairman and Chief Executive Officer

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

Daniel S. Harrison -- Chief Operating Officer

Correct. A lot of the records.

M. Jay Allison -- Chairman and Chief Executive Officer

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

Bertrand Donnes -- Truist -- Analyst

Well, sounds good. That's. Thank you. Again, want to ask a question.

M. Jay Allison -- Chairman and Chief Executive Officer

Thank you.

Operator

[Operator Instructions] Next is from Leo Mariani from KeyBanc. You may ask your question.

Leo Mariani -- KeyBanc -- Analyst

Hey guys. I just wanted to ask a little bit 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 the third quarter. But I guess you guys are expecting capex to go down quite a bit in 4Q. I was just looking for some color behind that.

Ronald E. Mills -- Vice President of Finance and Investor Relations

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.

Roland O. Burns -- President and Chief Financial Officer

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

Ronald E. Mills -- Vice President of Finance and Investor Relations

So it's a lot lower activity quarter.

Leo Mariani -- KeyBanc -- Analyst

Okay. I guess I thought you guys were running the same five and three crews each quarter, but it sounds like maybe there some working interest differences there as well and perhaps some timing on the payments.

Ronald E. Mills -- Vice President of Finance and Investor Relations

Even I think the crews that will average, I mean, for on our account, again, significantly less than three for the quarter.

Daniel S. Harrison -- Chief Operating Officer

Closer to two, 2.5 crews.

Leo Mariani -- KeyBanc -- Analyst

Okay. That's helpful. And then 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 onetime payments in the third quarter. But can you just speak to what your overall expectations are in this kind of current commodity price environment for cash tax as we get into next year?

Daniel S. Harrison -- Chief Operating Officer

Yes, there were no payments, cash payments of taxes that went out at all. But we do -- we made -- we put -- we 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 are -- 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 for -- under accounting rules. So -- but overall, I mean, yes, 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.

M. Jay Allison -- Chairman and Chief Executive Officer

Okay. Probably six or seven, eight years, I haven't heard the issue of taxes. So that's a pretty good -- bad word of that error. It's a good thing. I hope we have more of those questions in 2022.

Operator

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

Noel Parks -- Tuohy Brothers -- Analyst

Hi, good morning. Just a couple of things. I wanted to run by you. And apologies if you might have touched on this earlier, but since we've had these other fairly large Haynesville transaction 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?

Daniel S. Harrison -- Chief Operating Officer

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 are not closed hadn't really taken effect yet. But for instance, we have one in particular, where we're already talking with the new operator. So I think that's going to definitely be a big benefit, more than 100 anyway going forward.

M. Jay Allison -- Chairman and Chief Executive Officer

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

Noel Parks -- Tuohy Brothers -- Analyst

Great. And 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 have been other vendors that have been participating in the base that have some back and forth as far as who is being used?

M. Jay Allison -- Chairman and Chief Executive Officer

Yes. I'd say, there wasn't really a lot of -- 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.

Noel Parks -- Tuohy Brothers -- Analyst

Great. And 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 wondered if that had come up, yes.

Roland O. Burns -- President and Chief Financial Officer

I would assume the accounting will be just shown in higher price realizations, and that's really the -- as you enter into a contract with the purchaser, you'll agree on standards, and then you'll have a process like our 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, that 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 a -- to ensure that the product they're 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 products because we think and not be tagged with other peoples 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.

M. Jay Allison -- Chairman and Chief Executive Officer

Yes. I think 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. And even though I think it's 5.1, we lowered it by 38% since 2018 to this 3.12. It's -- we're very good for the environment. But I think that in terms of scoreboards, you -- 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 hand player, particularly at the divestiture of the Bakken. So we welcome these challenges. I think we've become a better company for the challenges.

Noel Parks -- Tuohy Brothers -- Analyst

Great, that's all.

Operator

Your last question is from Kasope Harrison from Piper Sandler. You may ask your question.

Kasope Harrison -- Piper Sandler -- Analyst

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

M. Jay Allison -- Chairman and Chief Executive Officer

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

Kasope Harrison -- Piper Sandler -- Analyst

You know it. You had talked a little bit earlier about takeaway 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 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 a longer period of time?

M. Jay Allison -- Chairman and Chief Executive Officer

Ron, you go with that.

Ronald E. Mills -- Vice President of Finance and Investor Relations

We hate to really get into that comment overall, because we know our situation really well. I don't -- 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 the takeaway, which we have 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'll be less than 25% of our gas tied to the Perryville hub, which has a little bit wider differential than our Gulf Coast index is. So our goal is to get that number to zero. It might take a -- and 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, but...

M. Jay Allison -- Chairman and Chief Executive Officer

And you know what that comes from, it comes from planning. We're asking 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 at agreeable prices to keep that low-cost category. So as far as the Haynesville, I mean, we always read, maybe there's a big day of availability. We don't really know. You never know to you test the market.

Kasope Harrison -- Piper Sandler -- Analyst

So that is helpful, both on the company level and the macro level.

M. Jay Allison -- Chairman and Chief Executive Officer

I think the good thing about the Ansell, though, as the years progress, you do have people putting skill in the ground. So if there is going to be demand, and I think maybe this LNG takeaway may expand another two Bcf in the next 18 months, two years. We'll go from 10.5% to 12.5% quarter to 14 Bcf, plus the export to Mexico. I think the midstream is going to provide the topline that we need period. I think they're going to partner with the Comstock to get the gas to the Gulf. Are we good?

Operator

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

M. Jay Allison -- Chairman and Chief Executive Officer

Okay. Again, I want to thank everybody for, again, the most favorable thing you have your time. So you spend 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, etc., that we were able to get there. And then now all of a sudden, you can see the demand for the gas in the U.S. and on others worldwide. This global demand for gas needs that they need it in Europe. They needed in Asia, they needed 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, and we started 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're going to stay in the Haynesville. We've always said that. We want to generate significant free cash flow. I think as 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, we want to pay off our RBL. We want to use that free cash flow to do that. Again, we want to retire the 7.5% bond by May of 2022. And then as a lot of you alluded, what you're going to do the rest of the cash for -- well, with all those goals met, the debt reduction goals, we're going to look at maybe to establish 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. Things look really good in the world of natural gas in Haynesville and have particularly at Comstock. So thank you for your hour.

Operator

[Operator Closing Remarks]

Duration: 59 minutes

Call participants:

M. Jay Allison -- Chairman and Chief Executive Officer

Roland O. Burns -- President and Chief Financial Officer

Daniel S. Harrison -- Chief Operating Officer

Ronald E. Mills -- Vice President of Finance and Investor Relations

Derrick Whitfield -- Stifel -- Analyst

Austin Aucoin -- Johnson Rice -- Analyst

Bertrand Donnes -- Truist -- Analyst

Leo Mariani -- KeyBanc -- Analyst

Noel Parks -- Tuohy Brothers -- Analyst

Kasope Harrison -- Piper Sandler -- Analyst

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