Comstock Resources, Inc. (CRK) Q4 2021 Earnings Report, Transcript and Summary

Thank you for standing by and welcome to Comstock Resources Fourth Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today's conference may be recorded. [Operator Instructions]. I would now like to hand the conference over to your host, Chairman and CEO, Jay Allison. Please go ahead.

Thanks for that introduction. On behalf of the 204/5 Comstock employees and the Board of Directors, I'll make a few opening comments, and then we'll go to the results. First, Comstock shift as Ron Mills has talked about the analysts. Comstock shift to longer laterals. The 10,500 foot laterals in 2022 versus the 8800 foot laterals in 2021. You should all know that it's expected to great value on a per well basis going forward. We have better cost efficiencies, we should have a lower decline curve, thus an increase in well performance. We will review that on this call later on. The higher capital efficiencies associated with the longer laterals did allow us to more than offset the impact of higher service cost in the fourth quarter of 2021, you can see that in the numbers, and we have seen higher service cost. We will use commitment from the board and from management. We will use the free cash flow to pay off the revolver and redeem the remaining $244 million of the 2025 bonds; that's our goal. We do have a target, continue to have this leverage ratio with 1.5 or less. We think we can get there in the second half of 2022, and that does open discussions up on returning capital to shareholders. I know we might have that question. Our drilling inventory, which is the holy grail of E&P companies, I think that's why you have a lot of M&As in the last year or two years. But our drilling inventory has never been more valuable or stronger because in 2021 we made great strides in extending our lateral length per location by 25% from by average lateral length at the end of 2020. It was 6,840 feet, and today it's about 8,520 feet. If you look at that 25 year’s worth of drilling inventory, based upon our 2022 activity, we've got 1,633 net locations. 53% of those were Haynesville, and 47% were [Indiscernible]. And just think. I mean, 902 net locations with lateral lengths. [Indiscernible]. On the operational front, which is I think that's the nucleus of this company. On that front, we increased our drilling footage per day by 25%. We went from 800 fee to 1,001 feet per day, and that's how you make money. Our average lateral length at the wells from the fourth quarter, 11,443 feet in the region as we drilled 415,000 per lateral wells, two Haynesville two Bossier, two Haynesville wells through Ford on. And we just -- as of this morning, we put two 215,000-foot version wells sales. Again in spot of higher service costs we were able to lower our drilling and completion cost due to improved operational performance and improved capital efficiencies associated with the longer laterals drilled into fourth quarter 2021, which that will be carried over into 2022. We have a few slides to take you back to 2018 and be accountable for our performance, so it's kind of a turnaround year. That's the year that Jerry Jones and his family invested in Comstock, and since that time, Comstock has surfaced as the only pure-play Haynesville producer. So welcome to the Comstock Resources Fourth 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 presentation, there you'll find a presentation entitled the fourth quarter 2021 results. I'm Jay Allison, Chief Executive Officer Comstock. With me is Roland Burns, our President and Chief Financial Officer, Daniel Harrison, our Chief Operating Officer, and Ron Mills, our VP Finance, Investor Relations, to [Indiscernible] to Slide 2. Going forward to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities falls. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Our fourth quarter 2021 highlights Slide 3. We cover the highlights on the fourth quarter on Slide 3. In the fourth quarter, we generated a $105 million of free cash flow from operating activities, increasing our total free cash flow generation, for 2021 to $262 million. Including the impact of our acquisition and divestiture activity, our total free cash flow for the year was $343 million. For the quarter, we reported adjusted net income of $99 million or $0.37 per diluted share. Our operating cash flow for the quarter was $250 million or $0.90 per diluted share. Our revenues, including our realized hedging losses, increased 37% to $380 million. Our adjusted EBITDAX for the fourth quarter was $297 million, 41% higher than the fourth quarter of last year. Our production increased 12% in the quarter to 1.348 bcf a day. In the fourth-quarter, we completed 215,000 foot Haynesville wells, which had IP rates of 48 and 41 million cubic feet equivalent per day, both of which are new corporate records to Daniel Harrison review in a moment. During the quarter, we also closed on the sale of our Bakken properties and closed a bolt-on acquisition for $35 million. If you'll flip over to Slide 4, we will go over some of the major accomplishments in 2021. We significantly reduced our cost of capital by refinancing $2 billion of our senior notes in March and June, which saved us $48 million in cash and interest expense and extended our average maturity from 4.7 years to 7.1 years. We also reduced the amount outstanding under our bank credit facility by $265 million with our free cash flow and ask and sale proceeds and approved our leverage ratio to 2.2 times as compared to 3.8 times in 2020. With another successful year at our Haynesville shale drilling program, we drilled 64 gross or 51.9 net wells, including four 15,000 foot laterals. The wells, we put to sales at an average IP rates are 23 million cubic feet equivalent per day. We grew our SEC pool reserves by 9% to 6.1 TCFB was a PV10 value of $6.8 billion. We replaced a 199% of our production at a low all-in fond and goals at $0.60 for MCFE. Highlighting our attractive cost structure, we achieved a 78% EBITDAX margin, one of the highest in the industry. In addition, we achieved a 12% return on average capital employed, and a 27% return on average equity. In 2021, we added 49,000 net acres to our acreage position perspective for the Haynesville and Bossier, through a leasing program and acquisitions totaling, $57.7 million or $1178 per acre. We took several big steps in 2021 on the environmental front. Early in 2021, we partnered with BJ Energy Solutions to deploy it's next-generation natural gas power TITAN Frac Fleet, which is expected to be put in service in April. The most significant step we took was to partner with MiQ to certify our natural gas production under the MiQ methane standard. Flip over to Slide 5 and we recap the bolt-on acquisition in a section that we did close late December for purchase process, $35 million. The acquisition included 18.1 net producing wells, and 17,331 net acres, in Harrison, Leon, Panola, Rogerson and Russ counties. With the acquisition, we added 57.9 net drilling locations, which represents approximately one year's worth of our drilling inventory. The acreage is 94% held by production. The acquisition also added the lateral lengths on 44 of our existing drilling locations to be increased. I'll now turn the call over to Roland to discuss financial results, Roland.

Yes. Thanks, Jay. On Slide 6 in the presentation, we compare some of our fourth-quarter financial measures to the fourth quarter of 2020. Our production increased 12% to 1.35 BCF a day. Adjusted EBITDAX grew 41% to $297 million. We generated $250 million of discretionary cash flow during the quarter, 62% higher than 2020's fourth quarter, and adjusted net income totaled $99 million during the quarter, 186% increase from the fourth quarter of 2020. We generated $105 made of free cash flow from operations in the quarter, or $204 million if you include the impact of the acquisition and divestiture activity, which most of that occurred in the fourth quarter. This free cash flow contributed to an improvement in our leverage ratio, which improved to 2.2 times, down from 3.2 times at the end of 2020. Our cash flow per share during the quarter was $0.90 per share, up from $0.56 in the fourth quarter of 2020. And adjusted earnings per share was $0.37 per share as compared to $0.14 in the fourth quarter of 2020. On Slide 7, we show how much Comstock has changed since 2018 when Jerry Jones and his family invested in the company. Production growth has averaged 117% over the last three years. EBITDAX has gone from $287 million to $1.1 billion at a compounded annual growth rate of 97%. Cash flow has grown from $206 million back in 2018 to $908 million this year in 2021, averaging a 114% over the last 3 years. Adjusted net income has grown from $29 million to $303 million at a compounded annual growth rate of 319%. And free cash flow from operations has grown to $262 million, and our leverage ratio has improved from 4.5 times to 2.4 times. On a per-share basis, cash flow has gone from a $1.96 to $3.29, and earnings has gone from $0.27 to a $1.16. On Slide 8, we provide a breakdown of our natural gas price realizations. And this is an important slide to understand the quarterly results as -- and we've had a very volatile NYMEX contract here during the fourth quarter, which has continued into the first quarter of this year. On this slide, we show how the NYMEX contract settlement price -- and we show the average NYMEX stock price for each quarter. So during the fourth quarter, there was a very significant difference between the quarter's NYMEX settlement price of $5.83 and the average Henry Hub spot price of $4.74. So during the quarter, we nominated 67% of our gas to be sold at index prices, which are more tied to the contract settlement price, or the final price that the contract comes off the market at. And then, we also sold 33% of our gas in the daily spot market. So if you use those percentages, the approximate 9X reference price for looking at our activity in the fourth quarter would have been $5.47, not $5.83 So I realized pricing from the fourth quarter averaged $5.22, which reflects a $0.25 differential from that reference price, which is fairly in line with our historical results. In the fourth quarter, were also 72% hedged. So that reduced our final realized gas price to $3 per MCF. On Slide 9, we detailed our operating costs for Mcfe and the EBITDAX margin. Operating cost per Mcfe averaged $0.67 in the fourth quarter. That was $0.02 higher than the third quarter rate. Our lifting cost and gathering cost were both up by $0.01, but production taxes were down by $0.03. Higher G&A cost of $0.08 was also higher in the quarter, and that's primarily related to year-end adjustments for bonuses. We do expect our G&A to go back to average somewhere between $0.06 to $0.07 per Mcfe in 2022. Our EBITDAX margin, including hedging, came in at 78% in the fourth quarter, unchanged from our third quarter margin. On Slide 10, we recap our fourth-quarter and full-year 2021 drilling and completion costs. In the fourth quarter, we spent a $140 million on development activities, $114 million of that related to our operated Haynesville and Bossier shale properties. We also spent $8 million on non-operated wells, and we had $15 million that we spent on other development activity in the Haynesville -- in our Haynesville operations. We spent an additional $3 million for our properties outside of the Haynesville. For the full-year, we spend $628 million on development activities, $554 million was related to our operated Haynesville and Bossier Shale properties. We also spent $74 million on non-operated activity and for other development activity outside of just drilling and completion. We drilled 51.9 net operated Haynesville horizontal wells and we turned 54.2 net wells to sales in 2021. We also had additional 2.2 net wells from our non-operated activity. In addition to funding our development program, we also spent $58 million on acquisitions. Most of those acquisitions related by an undrilled Haynesville Shale acreage. Slide 11 covers our proved reserves at the end of 2021. We grew our SEC proved reserves from 5.6 Tcfe to 6.1 Tcfe in 2021, and we replaced 199% of our production. Our 2021 drilling activity added 797 BCFE to prove reserves, and we had about 89 BCFE of positive price-related revisions. We also added 203 BCFE of proved reserves through our acquisition activity. The reserve additions were offset by divestiture of a 100 BCFE, which is primarily our Bakken Shale properties. Our all-in finding costs for 2021 came in at a very attractive $0.60 per MCFE. Our [Indiscernible] finding costs for '21 came in at $0.71 per MCFE. Our reserves are almost a 100% natural gas. Following the sale of our Bakken properties. The PV ten value of our proved reserves at SEC pricing was $6.8 billion at the end of last year. In addition to the 6.1 Tcfe of SEC approved reserves, we have an additional 2.4 Tcfe approved by developed reserves, which are not included in that number, as they're not expected to be drilled within the 5-year window required by the SEC rules. We also have another 4.4 Tcfe of 2P or probable reserves, and we have 7.2 Tcfe of 3P or possible reserves for a total overall reserve base of 20.1 Tcfe on a P3 basis. Slide 12 shows our balance sheet at the end of 2021. We had $235 million drawn on our revolving credit facility at the end of the year after repaying $265 million during 2021. The reduction in our debt and the growth of our EBITDAX drove a substantial improvement to our leverage ratio, which was down to 2.2 times in the fourth quarter on a standalone basis as compared to 3.8 times in 2020. We plan on retiring $479 million of debt in 2022. That would include redeeming our 2025 senior notes. We are targeting to be below 1.5 times levered in 2022, and we ended 2021 with financial liquidity of almost $1.2 billion. I'll now turn it over to Daniel to discuss our operations.

Okay. Thanks, Roland. I'll flip over on Slide 13. This is where we show our average lateral length. We drilled by year going back to 2017, along with our estimated average lateral link for this year, and also our record longest lateral that we've completed to-date. In 2017, our average lateral length was 6,233 feet, as we were drilling primarily a mix of 4,500 foot and 7,500 foot laterals. We had just adjust started drilling our first 10,000 foot laterals. In subsequent years through 2020, we slowly increased the number of 10,000 foot laterals that we were drilling, which allowed us to gradually increase the average lateral length. In late 2020, we successfully drilled and completed our first laterals exceeding 12,500 feet, and our average lateral length in 2020 had increase to 8,751 feet. Now, through the end of 2021, we have successfully drilled and completed four 15,000 foot laterals with two drilled to the Haynesville and two drilled into the Bossier. In 2021, our average lateral length increased to 8,800 feet. Our record longest laterals today these 15,155 feet and was drilled and completed in the Haynesville in late 2021. Building on the success of our 15,000 foot laterals, we now anticipate our average lateral length to increase by 19% in 2022, up to 10,484 feet. In 2022, we anticipate drilling approximately 21 wells with laterals longer than 11,000 feet, and nine of these being 15,000 foot laterals. By continuing to execute our long lateral strategy, we'll be better able to maintain our low cost structure into the higher-price environment. On Slide 14, we highlight the improvement in our drilling performance, which is based on the total footage drills abide by the number of days from spud to TD. Our drilling performance was relatively stable from 2017 through 2019 in the 700 foot per day range. In 2020, our drilling performance improved 15% to 800 feet a day, and in 2021, our drilling performance improved an additional 25% to just over 1,000 feet per day. While our record fastest well to date was drilled last year at an average rate of 1,461 feet a day. The performance improvements have been achieved via drilling the longer laterals, combined. Well, sounds rolling practices improved to over liability and execution at the field level. With our goal of drilling longer laterals in future years, we expect to maintain our drilling performance at a very high level. On Slide 15, is our updated D&C cost trend for our benchmark long lateral wells. These are wells with an average lateral length greater than, with the lateral greater than 8,000 feet. Our D&C cost averaged the $1027 a foot in the Fourth Quarter, which is a 2% decrease compared to the third quarter, and flat compared to our full year 2020 D&C cost. Breaking this down, our drilling costs remained essentially unchanged for the quarter $413 a foot, while our completion costs were down 4% quarter-over-quarter to $615 a foot. In spite of the higher service costs we began to experience during the last quarter, we were still able to achieve the slightly lower DNC cost due to improved operational performance, and improved capital efficiency associated with the longer average lateral length that we drilled during the quarter. Our average lateral length for the quarter was 11,443 feet. This is the longest quarterly average lateral length we've achieved to-date and was accomplished primarily due to the completion of our first 215,000 foot laterals that were turned to sales during the fourth quarter. Our capital efficiencies associated with the longer lateral was allowed us to offset the impact of the higher service costs during the quarter. While we do continue to see service costs further increase into this year, our ability to execute on the longer laterals with the more robust economics will help cushion and partially offset the negative effects of the higher service costs. On Slide 16 is a map outlining our fourth-quarter well activity. Since the last call, we have completed and turned 16 new wells to sales. The wells were drilled with lateral lengths ranging from 8,504 feet to 15,155 feet with an average lateral of 10,508 feet. The wells were tested at the IP rates that ranged from $12 million up to $48 million a day with a 23 million cubic feet per day average IP. The results this quarter include our first two plans, 15, 000 foot Haynesville laterals, the tally 32, 29, 20, HCI Number 1 and Number 2 wells. These wells were completed for laterals of 14,685 feet and 15,155 feet, and tested at rates of 41 million and 48 million cubic feet a day. The seven wells with the lower IP rates are in Panola County in the liquids-rich area of the Haynesville. The high BTU gas in this area will generate a yield at 25 to 40 barrels plant products, which will enhance the economics from a dry gas well with similar production by 20% to 30%. Also, during the quarter, we successfully drilled two additional 15,000 foot laterals into the Bossier. As mentioned earlier, these two wells were turned to sales late last night, and we will be reporting on those on the next call. Regarding activity levels, we did finish out 2021 running five rigs and three frac crews. We're in the process now of adding two rigs, increasing our rig count to seven and will remain at the seven rig count throughout the remainder of this year. We plan to continue running three full-time frac crews throughout the rest of the year. On Slide 17, this is a detail of the 2021 drilling inventory. The drilling inventory is split between the Haynesville and Bossier locations, and it's divided into four categories. We got our short laterals up to 5,000 feet; medium laterals at 5,000 to 8,000 feet; our long laterals at 8,000 to 11,000 feet. We got a new extra strong category now for the wells beyond 11,000 feet. Our total operated inventory currently stands at 1,984 gross locations. Ones is also 1,420 net locations, which represents a 72% average working interest across the operated inventory. Based on the -- our non-operated inventory currently stands at 1,425 gross locations in 213 net locations, and this represents a 15% average working interest, but across the non-operated inventory. Based on the recent success of our new extra-long lateral wells, we've modified the drilling inventory to take advantage of our acreage position, and where possible, we have extended our future laterals out further to the 10,000 feet to 15,000 feet range. In our new extra-long lateral bucket, we capture all our wells that now extend beyond 11,000 feet long, and in this bucket, we currently have 397 gross operated locations and 287 net operated locations. These are split 50/50 between the Haynesville and the Bossier. So to recap our total gross inventory, would have 436 short laterals, 392 medium laterals, 759 long laterals, and now 397 extra-long laterals. The total gross operated inventory is split at 53% in the Haynesville and 47% in the Bossier. Also by extending our laterals, we had increased the average lateral length in the inventory from 6,840 feet, now up to 8,520 feet, which is a 25% increase. And in addition to the uplift in our economics, the longer laterals will help to release our surface footprint on future activity and also further reduce our greenhouse gas and methane intensity levels. In summary, our current inventory provides us with over 25 years of future drilling locations based on our planned 2022 activity levels. With our ability to execute on the new ultra-long laterals are drilling economics are more robust, and it enhances the value of our acreage position. I will turn it now back over to Jay to summarize the outlook for 2022.

Well, like we said earlier, our drilling inventory, which Daniel just said, while it is a holy grail of the big companies just never been more valuable and stronger than it is today. If you go to Slide 18, I direct you to the summary for our outlook for 2022. We expect our 2022 drilling program to generate 4% to 5% production growth year-over-year. And we would expect to generate an excess of $500 million of free cash flow at current commodity process. And 2022, the lateral length of the wells in this year's program is expected to be 19% longer than the 2021 wells. The additional investment we're making this year and our drilling program will pay off in the future years, as the lateral length per well will have a lower decline rate than the shorter laterals. In 2022, our operating plan is focused on repaying $479 million of debt, including redeeming our 2025 senior notes. We continue to have an industry-leading low cost structure, which gives us best-in-class drilling returns. We are working on the certification of our natural gas production as responsibly sourced gas under the MiQ standard. At the end of 2021, we had financial liquidity of almost $1.2 billion, which is expected to increase further in 2022 as we repay the remaining borrowings outstanding on our bank facility. So Ron, I'll turn it over to you to give some guidance for the rest of the year.

Thanks, Jay. On Slide 19, we provide the financial guidance. As shown on the slide, first quarter production guidance of 1.24 to 1.29 BCF E a day and the full-year guidance is 1.39 to 1.45 BCF a day. During the first quarter, we only plan to turn to sales about 15% of the planned wells to be turned to sales for the year. And those wells have a little bit lower working interest than the wells later in the year. As a result, the majority of our wells turned to sales and production growth are expected to occur during the second and third quarters of this year. And development Capex guidance is $750 million to $800 million, which is based on a similar number of turn to sales wells as last year and incorporates an expected 10% increase in service cost and the impact of our average lateral links being 19% longer this year. As a result, if you factor in the 10% inflation and the 19% longer laterals, the midpoint of our guidance would actually represent about 3% to 5% of an improvement in inefficiencies mostly related to the longer laterals. We've also budgeted for $8 million to $12 million of additional leasing cost. Our LOE expected to average $0.20 to $0.25 in the first quarter and $0.18 to $0.22 for the full year, while our gathering and transportation cost expected to average $0.23 to $0.27 in the first quarter and $0.24 to $0.28 for the year. Production and ad valorem taxes expected to average $0.10 to $0.14 a year based on current price outlook. Our DD&A rate is expected to average $0.90 to $0.96 per Mcfe. Cash G&A is expected to total $7 million to $8 million in the first quarter and $29 million to $32 million in 2022, with non-cash G&A expected to average almost $2 million a quarter. Cash interest is expected to come in around $38 million to $45 million in the first quarter and $152 million to $162 million, $160 in 2022, and that incorporates the planned redemption of our 2025 notes later this year. From a tax standpoint, the effective tax rate of guidance of 22% to 27% is in line with what we've been reporting. And going forward, we expect to defer 90% to 95% of the taxes with the cash taxes being related to state taxes. I will now turn the call back over to the operator for the Q&A session.

[Operator Instructions] Please, stand by while we compile the Q&A roster. Our first question comes from the line of Derrick Whitfield of Stifel. Your line is open.

Thanks and good morning, all.

Morning.

With my first question, I wanted to focus on the outputs of your 2022 plan and your confidence in executing against it. When we analyze the balance of the year for Comstock the set up certainly seems positive to us based on potential positive production revisions in the institution on a return of capital program, and specifically on production. Your 2022 production plan on average appears to be outpacing consensus estimates by about 2% for the balance of the year after adjusting for Q1 guidance. With that said and with your activity being more steady-state relative to past year's, could you speak to your confidence in executing against this in light of the tighter labor in service price environment?

This is Daniel. So we -- we're fairly confident we can execute, the way that we've got it planned. We factor our scheduling based on the most recent cadence that we've been at, and we've had a little bit of that already built into the numbers at the end of last year. And so we foresee that to be at the same pace going into this year. So I'd say yeah, we feel pretty strongly we can execute the way that we've got laid out this year.

Great. And then, for my follow up.

Hold up, hold up.

We did have a few hiccups during the weather a week or so ago with hauling sand and some driver issues. I mean, we have seen that, but I don't think it has impacted. Daniel.

It hadn't impacted the overall schedule. We did start seeing a little bit of it in the fourth quarter. It was spotty, and we've finally got that built into our scheduling and our dates. Basically, just based on that latest level of cadence there, I mean, that's kind of what we see for the rest of this year. I mean, obviously, if something changes, we'll have to go back and revisit our scheduling and dates a little bit.

I think the key is we do have our drilling contractors lined up, and we do have our frac service companies lined up.

It's addressed as best you guys can at this point it seems. And then for my follow-up, I wanted to focus on return of capital. After achieving your targeted 1.5 times net debt to EBITDA leverage ratio later this year. Could you speak to your near-term and longer-term views on return of capital, and how the near-term could take form later this year?

Sure Derrick, that's a good question. And obviously, we're -- front and center is to first achieve our debt reduction goal, which is -- we have a $479 million is a pre -payable debt and we think that will be achieved first and then after that, we do see additional free cash flow that the company will be generating later in the year. And we're still evolving in our return on capital theory. And we obviously have a majority stockholder to consult with. But I think our first goal will be to establish a sustainable dividend. Yeah, let -- we had one in 2014, so we're excited to put that back in place. And so as this year progresses and we see where gas prices land, very volatile first quarter so far with gas prices. We'll know the right time to put that dividend in, but the debt reduction target happens first in achieving leverage ratio happens first, but then after establishing a base dividend, I think -- again, I think we could change our mind, but I think we'd like to have a share repurchase authorization in place. Add that as another supplement to the return of capital.

I think the [Indiscernible] is, we've had a dividend before. So it's not something new. And when we had to remove it, we did remove it. So to tell you that we should have more discussions, because our leverage ratio would allow us to open those discussions up, to talk about that, I mean, that's a beautiful thing to talk about, and I think we will be there more sooner than later. And remember, the Jones own 60% to 65% of the company, so they're very interested in having this talk perform properly. So we -- I think when we weigh a dividend, is that what the market is looking for so that they guaranteed yield. So we'll assess all of that, and we'll make a good decision.

And we've laid the groundwork in our big bond refinancings we did. We've laid the groundwork for the strategy as we go forward.

Yeah.

So I think it's all in place. In place in our debt instruments and our commitments to the rating agencies, commitments to the bondholders, I think we have a very balanced approach, but we've laid the groundwork for a return of capital program, hopefully that we get to initiate this year.

That's great, very helpful. Thanks for your time.

Thank you. Our next question comes from Charles Meade of Johnson Rice. Your line is open.

Good morning, Jay, to you and your whole team there.

Good morning. Always good to hear from you.

Oh, you're kind. Jay, I think we got some of the detail from Daniel on when you're going to add the rigs. I think what I heard is that you are in the process of adding two rigs right now, and I'm curious about how or what the implications are for how your production is going to progress over the year? I think Ron mentioned that that 2Q and 3Q are going to be the big growth quarters. But can you tell us how should we think about how you're bringing those rigs on, when they're going to be contributing to production, and what the shape of the year looks like?

We have returned to the first quarter production plan, and it's fairly -- it's just lower completions -- number completions. And Ron had talked about that, and you had mentioned that it's really before growing our production in the second quarter and third quarter of 2022. Now, I think from there on out, we have some pretty predictable growth. We're [Indiscernible] -- we're in a transition from the shorter laterals to the longer laterals. And that's all we're in. We're in like the six-month transition. And it takes a while. Like we said in the fourth quarter, our average lateral length was over 11,000 foot, and that's because we drilled those four 15,000 feet lateral wells, and I know when Daniel scripted, he didn't know they were turned to sales the two Bossier wells. So he changed the script, but we did turn off sales, by less not early this morning but it takes a little longer, but it's certainly more efficient on the dollars spent, and I think as you see, in the quarters to come, if we can abate this decline curve from 40 +% to the thirties, that's going to help -- that's going to help with our RBL. That's going to help with our model, and it's going to lower our costs. So we will have -- the sixth rig is here, we'll have a seventh rig, and we've got a drilling schedule that will --actually I think that we complete two extra wells this year versus where we were in 2021. But it's just a pure transition to a more cost efficient way that I've we take go generate more free cash flow. And again, I think if you go to that, just look at the basin we're in, and you look at the footprint we're in, we're not condensed in a small area. We can spread out into Texas and Louisiana with this drilling program. And that's why I think you're going to see us while we've added all these laterals, even in the diversified property that we bought, if you look at where our existing footprint was, we extended laterals on some existing locations, 44 of those were extended with diversified acreage that we added.

Yeah.

I think you're going to see some more of that.

I got a couple of comments [Indiscernible]. Specifically, I think we do have the 7 rigs operating right now. But one thing we'd normally -- when you think about rigs, we do -- at least half of one of those rigs will be used for our contract drilling services, which really don't -- doesn't affects our budget. So I would say we're really have 6-and-a-half rigs to deliver on our budget. The other half will be due in work. That's not in our budget. And -- so I think that's how I view it. But I think the production is more weighted to the second half of the year. There is this kind of 6-month transition period. I think when you go longer term, I think that the longer laterals we do see probably right now if we keep at the same activity level, having -- in '23 having a higher production growth than the rate we're on now, that's going to be the benefit of going to these longer laterals and the timeframe. The other thing that's extending the production timeframe on these wells is the practice of completing more than two wells at a time, and typically, we always want to complete at least two wells, but there are a lot of projects where in order to minimize shut-in activity that you have to have for that we're grouping multiple pads, and that also does create delays in production coming on. And I think that's also incorporated. There's more of that in this year's planned and in the previous years where we may have five wells, seven wells, multiple -- multiples, more than 2 coming online at the same time as we do multiple pads together to minimize shut-in time.

And Charles, I think if you look at our growth chart, you'll see second, third quarter, fourth quarter volume of production grows pretty substantially. And if you look at the 2022 program, we have 13 wells that have laterals greater than 11,000 feet and half of those are 15,000 foot laterals. So we have put those in too. We've floated those in. But I think you're going to see first quarter. It will be lower, but then second, third, fourth quarter, we'll continue to grow. And then, you'll see that, as Roland mentioned, into 2023, we'll have [Indiscernible] as the normal drilling longer lateral wells and completing them.

Got it. That's helpful detail, particularly about the contract drilling piece and. Jay, I want to go back to -- you mentioned those two 15,000 foot of Bossier wells, and I recognize that we're just not only in the early days, in the early hours here, on how those wells are performing. But I wonder if you can just share anything more about what the drilling and completion went like for those. And particularly, I'm curious, do you have any sense of whether you're actually really able to effectively stimulate all the way out to the toe or are you reaching some kind of technical limit there?

Yeah let me -- I want to comment, I'll turn it over to Daniel, but if you remember, we've got 53% of our locations were Haynesville and then the rest are Bossier. And what we chose to do, Charles, we chose to say instead of drilling 4, 15 thousand foot Haynesville, let's do 2 Haynesville, 2 [Indiscernible]. So we did the 2 Haynesville, and as you know, what's it, $80 -- $89 million a day for both of them. I think is 48 and 41. So we've got 2 great wells there. Now I think on the Bossier, remember we didn't go back into probably December 2015. We were one of the first companies to drill a Bossier that made really successful and started this Bossier drilling. You can ask the Indigo's of the world, etc. When they were here, I mean, they looked at that well. We have drilled a bunch of Bossiers before. So Daniel was confident that we should drill these two Bossier wells. So, Daniel, you want to comment on those? And I did turn to sales and we expect them to be really good wells, but they did turn to sales by [Indiscernible] this morning. Daniel.

I'll just add that we did the four 15K laterals that we drilled. On average, the Bossier drilled a little bit faster than we did drill. The fastest to those four wells was one of these Bossier wells. We drilled it to TD in 29.5 days, so that's a pretty, pretty strong performance there. As far as fracking them out to TD, saying there's a 10K, we didn't have any issues on these two Bossier wells, drilling, all deploys, got all the way out to the end of the laterals with no issues. So that's -- and some -- when you start out with the first few wells, you always have a few hiccups, then you get a little better from there, and we certainly expect that to happen on our future 15,000 foot laterals. We'll get a little bit faster and a little more efficient.

Thank you for the call.

Thank you.

Thank you. Our next question comes from Neal Dingmann of Truist Securities, your line is open.

Good morning, guys. I just follow on what you were saying just on the Bossier 16 outlines. All your Bossier opportunities, I'm just wondering how you all think maybe in broad terms or average terms? How you think about the overall economics on some of the -- just say your core Bossier area versus Haynesville?

So the economics of the Bossier wells, they -- you're going to get a little bit because they're more like the East Texas wells. We get a little bit lower RFPs on the Bossier’s with a little bit flatter decline rates. The economics of the Haynesville’s basically where we drill in the -- are always going to be better than the Bossier just across the inventory. But going to the 15K's, the economics, you're looking at -- if you just kind of look at a set gas price. Say, we ran these back before at the lower gas process, but an average 7,500-foot lateral versus a 15 K, which is kind of how we look the wells that we're drilling. Either drill one or the other. You're looking at a 100% rate of return on a 15-day well. and you're looking at something that's closer down to 60% or 70% return on 7,500 feet lateral. And this -- we expect to get better with these 15Ks. We saw what happened with the 10Ks and so we've already outlined several things where we know we can make some improvements on the 15Ks.

[Indiscernible] I was just going to ask that for my follow-up, you guys certainly are getting some better returns just on overall, not just as you said Bossier and Haynesville longer laterals, I'm just wondering, could you talk about the improvements we'll continue to see. Is it just purely the longer laterals or there's some improvements on even completions that are part of this upside and it runs down a good job of showing us that per foot upside that you're seeing, and I'm just wondering is just purely because longer laterals or what else is driving that?

Well, the drilling -- the drilling performance is basically across all the laterals. That's just the better drilling practices. Some of that is the better tool reliability from our vendors. But that's on all the laterals regardless of link. But it becomes more profound when you start drilling the longer laterals. You get a bigger bang for the buck from those things. So what -- I can't remember what's your second part of your question was.

No, that was it. I just didn't know besides longer laterals if there's things incomplete -- on the completion side that you're doing that -- considering your returns and returns on per foot are improving, I didn't know if there are other things completion-speaking that's driving these returns as well.

The completion side is just an efficiency gain from getting longer; that's a little bit more just the ratio. I think on the drilling side; we're probably seeing a little bit better gains. You know what the fracs is? It's just basically the performance of our frac crews. We certainly expect to get enough layup when we go to our natural gas fleet in April. We expect to see a little bit better performance there, and --

Our stages and clusters have been pretty consistent.

We've been pretty much at about the same performance level on the frac side, stages per day like Jay mentioned. We've definitely seen probably a bigger pickup on the drilling side just to recap -- recorrect that answer.

Got it. Thank you, guys. Great details.

Thank you. Our next question comes from Leo Mariani of KeyBanc Capital Markets Inc. Please go ahead.

Hey, guys., just wanted to get a sense of what your appetite is these days on the M&A side. Obviously, you've done some deals for of the last several years to really increase the size of the company, the inventory. What do you think the outlook is? These days, are there other Haynesville properties out there you think might be a good fit for Comstock?

You know we are -- we're always asked if we're looking outside the basin, and the answer's no. So get rid of about 90% of the whole world there. And I think that within the basin, Leo, as you know, most of the Haynesville producers have been consolidated. I mean, you've got -- I think you've got two out there that are still kind of lingering, and we understand one of them may be for sale right now. But I think we do shop all the time. I think you've got to shop in order to not be a compulsive buyer. We do shop. We look, but as of right now, I think our 2022, 2023 plan is continuing to add incremental valuable acreage around our existing footprint that will enhance our laterals. So we don't really see a lot of activity on the M&A front at all.

Okay. That's helpful. There's certainly been a fair bit of discussion on this topic. But if I just take a high level look at some of the changes in the '22 program versus '21. It looks like the number of wells are turning to sales, is roughly the same. But you are getting 19% more lateral feet this year. So certainly a pretty big step-up in feet completed here. But when we just overall look at the production growth, call it 4% to 5% this year, it's a little bit lower than it was last year. When you guys look at that, do you really think this is mostly just a timing issue? And really the benefit here is '23. I know we talked about this a little bit, just wanted to kind of clarify that.

That's a great question, and I do think it's a timing issue because I do think that we -- once you get to 23, you see a similar growth rate of 21. But I think it's the big transition to the longer laterals, and it's a timeframe also not running consistent number of rigs during -- and not I running as many rigs in the fourth quarter. Obviously, I think that a lot of that's all timing. I think this year, with a more consistent program, that's starting here towards the end of the first quarter. In maintaining that through '23, you will see more consistent growth and doing a lot longer laterals. We'll see -- we'll reap the benefits from these larger laterals in the -- specially in the second half of this year, and then all of next year. In [Indiscernible] with a -- hopefully a little bit lower decline profile from the longer laterals which they provide. You don't have to invest as much. So you create that capital efficiencies, but it takes a while to show up in the numbers.

[Indiscernible] I think again; you look at the inventory. We've got really impeccable inventory. You look at our margins, have been really high. You look at the operations group, year after year after year after year, they've delivered stellar performance. You do more from 5,000 foot laterals to 7,500 foot to 10,000 foot to 15,000 foot, as Daniel has said, and I think our efficiency, which is our operational efficiency, has been very predictable. I did think there's some pain for six months in transitioning to these longer laterals, but it will certainly be worth it.

Yeah, no, that's helpful. And maybe just lastly, if you guys could talk a little about the outlook that you expect for Haynesville price differentials here. Obviously, there was a little bit of noise there in the fourth quarter with bid-week versus spot, but maybe just going forward here in '22, just give us a sense for what type of differential you will see for Comstock and any basin dynamics you want to discuss?

Yeah, we -- yeah, we've seen real stability in our differentials because we've taken a lot of steps to protect that, including locking that in with longer-term sales contracts, and even putting in a basis hedge there. So really, that wasn't the noise at all. That's why we tried to show. The real noise was midweek versus the spot price, which was -- we haven't experienced that. I don't think in a long time, in the overall gas market. And it was very, very, very volatile in the fourth quarter, and the difference between those was so dramatic, that it creates a large differential. It's easy to model those separately, and I think are generally, if you assume 70% of our gas is going to be tied to that contract price and 30% is tied to the spot price, both prices are available. You don't need to assume it's a 100% either way, because it can't be, it's impossible to go 100% in the index market that -- you have to deliver that gas. So I think that is -- you just haven't seen that as being important to separate in the past because there hasn't been a very big difference between those two numbers. January, look at the first quarter January. You didn't see a big difference between those two numbers. But February, a dramatic difference. You had the contract close at a 626. a very high number, immediately, spot market was lower than that. So we don't know how that progresses this year, but obviously going to be some of that in the first quarter to keep an eye on and see what happens to March but also see if February, the spot market can catch up to that contract price would be nice. Got a little way to go to do it.

Okay. Thank you, guys.

Thank you, Leo.

Thank you. Our next question comes from Fernando Zavala of Pickering Energy Partners. Your line is open.

Good morning, and thanks for the time. I was wondering if you could give some numbers around base decline trends into year-end '22 and beyond? And maybe relative to 2020 and 2021 with obviously the tailwinds as longer laterals hitting into year-end '22 and beyond?

What would -- you could add a little bit. What was the very beginning part of the question that you're asking?

Sorry. Yeah, if you could give some numbers around base decline trends into year-end '22 and 2023?

In terms of base decline, I mean, we're currently kind of -- I think Jay referenced right around 40%, 40 +%. Over time, as we transition to those longer laterals, that should have a positive effect on that decline rate. With the shorter lateral wells, when you think about bringing them on and the way you -- the managed pressure flow back, you take into account maybe a flattish decline for five or six months. On the longer laterals, you expect that to be nine to ten months, and depending on either in the longer lateral -- longest laterals, it could be up to 12 months. So over time, as you get more of those wells in your production base, that corporate decline rate should start moving down. I don't know if it -- if 2022 has that much of an impact, it should start to show up in '23 and even to probably a greater extent in '24. But the benefit of that is if you can go from call it 40% to the mid-30s, that has a dramatic impact on maintenance capital requirements going forward and it just really makes your whole program a lot more efficient.

Yes, and if you step back, if we were predominantly 5,000 foot laterals, we would have to be talking about an excess of 50% base decline rate, and I think you saw the -- you see some of the few other operators in the Haynesville have that but it's -- the lateral length is the major difference between what we even have and now and versus higher decline rates. It's all of the lateral link is the major difference in that.

And then, I think if you, again, drill these long laterals for well, as Ron said, you don't have to spend as much capital to grow your production 4% to 5% because you don't have a steeper decline. That's the goal.

I mean, yeah, that's helpful. Thank you. And I guess that goes to my follow-up question, about how you -- how are you all thinking about activity and spending balances in '23. It's like you said. The benefits of the longer laterals start showing up in 2023. So -- like how you -- you have options to scale back activity and stay within that 4% to 5% growth, just how you all are thinking about that.

Right. It's early for us to think about it, but I think if we don't pull back, that we will have -- the numbers would tell you that we should have higher growth rate in '23 if we'd stay at a constant level. We'll target free cash flow. How do we maximize free cash flow generation, how do we maximize overall results, what is the base and takeaway? What's the pressure on the gas market? There's a lot of factors. We're in a more unique basin than maybe Appalachia, so a lot of that we really have to get closer in to see how this year progresses.

Together, 2023 too. I mean, kind of your point. We don't have this $479 million a shorter-term debt that we can play off so, that free cash flow number, we're going to have a lot of quote, excess free cash flow over and above whatever our Capex budget would be. So 2023 will be a huge turning point for the company, but I think it it starts in 2022.

Got it. Thanks, guys.

Thank you. Our next question comes from Raymond Deacon of Petro Lotus. Go ahead.

Good morning, Jay, and Roland, and Daniel, Ron.

Hi, Raymond.

I had a quick question for Daniel, which is, do you -- if I were to look at the inventory number now and assume that -- is the right assumption that most of those wells will be drilled 20% longer versus what you have shown there, and would that reduce the amount of inventory in terms of number of wells by 20%?

I think we've actually -- the new inventory chart we provide here and this is rolling, actually reflects a lot of remapping, but, there will be a constant interest in remapping both through acreage trades, we've got -- I think the other major -- yeah, everybody likes the longer laterals in the basin. So as -- now some of this consolidation has occurred, there's a refocus now in engaging with adjacent operators on acreage trades, so we hope you continue to do those. Yes, there will be more remapping to come, but what we're presenting now is the result of remapping a lot, and changing the lateral length. It's changed by 25%, it's a very dramatic difference from the inventory you saw before.

I was thinking -- I was looking back at the numbers. If you look at we have 1633 net locations and those that are greater than 8000 foot laterals, it's 902 of them. And if you start at the end of last year's that was 745, and today it's 902 to [Indiscernible] point that said remapping and maybe the diversified that we bought, etc and swapping acreage with some continuous offset operators. But that's the remap in the last year and we plan on trying to do more that because it's a win-win for both companies.

Got it. Got it. And have you decided already where the two incremental rigs will go at the end of this quarter?

Yeah, Raymond, this is Daniel. The first our 6 rig basically [Indiscernible] yesterday and will be the 7th rig [Indiscernible] probably late next week. And we got both of those rigs are going to work in our Logansport area.

Okay. Got it. And just one last question on realizations. If you were to -- I know Aethon has the sales process on that's been a significant addition to the rig count in the Haynesville. Do you think that differentials probably would've narrowed a bit if you hadn't had this big recent increase in activity; is that fair?

I think you're talking about maybe Perryville, Carthage differentials? I mean --

Yes, right.

Differentials -- they were -- they didn't widen in the fourth quarter. Again, we just -- we only had like, 10% of our sales subject to it. Because we kind of plan for that, we've moved a lot of gas away from Perryville, it's no longer our dominant index. So yes, I think if you're an operator that's a 100% tied to that. You should probably plan on higher differentials, but we're going to be, so we're not going to be that tied to that in 2022, when we -- when the [Indiscernible] went into operation in December, it was a big shift and majority of our gas has felt at the Gulf Coast indexes, which they don't -- they tend to stay tighter to Henry Hub. And then the gas that we can actually put into the Gulf Coast indexes, we've really taken a lot of protective measures to try to lock in that differential, close to that $0.25 number and not have too much gas exposed to a wider differential in those markets.

To add to Roland's --

Got it.

--point [Indiscernible] Acadian deal with the enterprise, that was negotiated 2018, early 19 ' and it came on to December '21. So,

So that -- that's going to help mitigate the -- and you didn't see it much in '21 because it was only one month. But it definitely helped -- probably helped us in the fourth quarter a little bit with December, and you're going to see it help keep that differential from having to slide now in '22. So that's totally a different factor. Looking at the index price versus the spot price, that's totally unrelated to that. That's just the [Indiscernible] --

Right. One step back to your question, we -- when we plan to drill these wells, I mean, we look at the marketing side to make sure we don't have any takeaway issues because in that place you do have a takeaway issue. We haven't seen that when we plan these wells. '20, '22, '23, we looked in advance on that. Right. And Jay, does the MiQ realization help you at all in those -- in terms of realizations are lower gathering fees. Do you get access to different markets, or?

Well, you hope to in the future. I think that's the -- as we're able to find purchasers that want to give us credit for that, I would say we don't have that now in maybe in our region right now, they're most in price, but as we are with the direct access to [Indiscernible] Hub and being able to sell directly to LNG, to the extent they have customers that want to lock in to responsibly source gas. We have that mechanism -- we will have that mechanism in place hopefully mid year in '22. So we're ready to do that, but that could be the case, but we'll see but --

I think that flexibility, Raymond, will be valuable.

Yeah.

Got it, yes. That's great. And just -- I guess, one -- last one, I'm asking too many questions. But the breakdown of Bossier versus Haynesville in 2022 is there -- is there much of a change versus '21?

So the write-down in 2022 is going to be pretty similar to what we had in 2021.

Got it.

But just a handful --

Thank you so much.

Just a handful [Indiscernible]

Yeah. Okay. Got it.

Thank you. At this time, I'd like to turn the call back over to Jay Allison for closing remarks. Sir?

Again, I want to thank everybody for staying on from the beginning to the end of the conference call and I guess I would close. You [Indiscernible] the fundamentals of the dry natural gas market, we don't think that there have been stronger, particularly in the footprint that we're at, and the reason we say that is this demand now is on a global basis due to the LNG export facilities that are near our Haynesville, Bossier base on our footprint. So we're pure play. We plan on slaying that and trying to reduce our calls to extend our laterals and deliver the results. '22 should be a watershed year, '23 should be incredible. Our inventory is strong, so again, we thank you for your support.

And this concludes today's conference call. Thank you for participating. You may now disconnect.