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Comstock Resources, Inc.(NYSE: CRK)
Q4 2021 Earnings Call
Feb 16, 2022, 11:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Thank you for standing by, and welcome to Comstock Resources fourth quarter earnings conference call. [Operator instructions] I would now like to hand the conference over to your host, Chairman and CEO Jay Allison. Please go ahead.
Jay Allison -- Chairman and Chief Executive Officer
Thanks for that introduction. On behalf of the, say, 204 or 205 Comstock employees and the board of directors, I'll make a few opening comments, and then we'll go to the results. First, Comstock's shift, I think as Ron Mills has talked about to the analysts, I think Comstock's shift to longer laterals, the 10,500-foot laterals in 2022 versus the 8,800-foot laterals in 2021, you should all know that it's expected to create a 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 costs in the fourth quarter of 2021. You can see that in the numbers.
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And we have seen higher service costs. We will use commitment from the board and from management. We'll 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 at 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 may 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 our 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 years' worth of drilling inventory based upon our 2022 activity, we've got 1,633 net locations.
53% of those were Haynesville, 47% were Bossier. And just think, I mean 902 net locations with lateral lengths 8,000 feet or longer. 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 feet to 1,001 feet per day, and that's how you make money.
Our average lateral length at the wells in the fourth quarter, 11,443 feet. And the reason is we drilled four 15,000-foot lateral wells, two Haynesville, two Bossier. The two Haynesville wells we report on and we just, as of this morning, we put the two 15,000-foot Bossier wells to sales. Again, in spite of higher service costs, we're able to lower our drilling and completion costs due to improved operational performance and improved capital efficiencies associated with the longer laterals drilled in the fourth quarter of 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. That was 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.
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 result presentation. There, you'll find a presentation entitled fourth quarter 2021 results. I'm Jay Allison, chief executive officer of Comstock.
With me is Roland Burns, our president and chief financial officer; Dan Harrison, our chief operating officer; and Ron Mills, our VP of finance and investor relations. If you flip to Slide 2, refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements will be reasonable, there could 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 $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 in 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 two 15,000-foot Haynesville wells, which had IP rates of 48 million and 41 million cubic feet equivalent per day, both of which are new corporate records that Dan Harrison will 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'll 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 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 asset sale proceeds and improved our leverage ratio to 2.2 times as compared to 3.8 times in 2020. With another successful year in our Haynesville Shale drilling program, we drilled 64 gross or 51.9 net wells, including four 15,000-foot laterals. On the wells we put to sales at an average IP rate of 23 million cubic feet equivalent per day, we grew our SEC proved reserves by 9% to 6.1 Tcfe with a PV-10 value of $6.8 billion. We replaced 199% of our production at a low all-in finding cost of $0.60 per 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 prospective for the Haynesville and Bossier through a leasing program and acquisitions totaling $57.7 million or $1,178 per acre. We took several big steps in 2021 on the environmental front.
Early in 2021, we partnered with BJ Energy Solutions to deploy its next-generation natural gas-powered 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 East Texas that we did close late December for a purchase price of $35 million. The acquisition included 18.1 net producing wells and 17,331 net acres in Harrison Leon, Panola, Robertson and Rust 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, but 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?
Roland Burns -- President and Chief Financial Officer
Yeah, 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 Bcfe 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 our adjusted net income totaled $99 million during the quarter, a 186% increase from the fourth quarter of 2020. We generated $105 million 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 114% over the last three 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 four and a half times to 2.4 times. On a per share basis, cash flow has gone from $1.96 to $3.29 and earnings has gone from $0.27 to $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 we've had a very volatile NYMEX contract 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 spot price for each quarter. 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. 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. If you use those percentages, the approximate NYMEX reference price for looking at our activity in the fourth quarter would have been $5.47, not $5.83. Our 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 we were also 72% hedged, so that reduced our final realized gas price to $3 per Mcf.
On Slide 9, we detailed our operating cost per Mcfe and the EBITDAX margin. Operating costs per Mcfe averaged $0.67 in the fourth quarter. That was $0.02 higher than the third quarter rate. Our lifting cost and gathering costs were both up by $0.01, but production taxes were down by $0.03.
Higher G&A costs 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 $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 spent $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 an 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 proved 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 a divestiture of 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 drill pit finding costs for '21 came in at $0.71 per Mcfe. Our reserves are almost 100% natural gas following the sale of our Bakken properties. The PV 10 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 proved reserves, we have an additional 2.4 Tcfe of proved undeveloped reserves which are not included in that number as they are not expected to be drilled within the five-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 stand-alone 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 Dan to discuss our operations.
Dan Harrison -- Chief Operating Officer
OK. Thanks, Roland. 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 length 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, and we had just 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 lateral exceeding 12,500 feet, and our average lateral length in 2020 had increased 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 lateral to date is 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 drilled divided 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 with sound drilling practices, improved tool reliability 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 Bismarck long lateral wells.
These are wells with an average lateral length greater than -- with a lateral greater than 8,000 feet. Our D&C cost averaged $1,027 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 costs. Breaking this down, our drilling costs remained essentially unchanged for the quarter at $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 D&C 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 two 15,000-foot laterals that were turned to sales during the fourth quarter. The higher capital efficiencies associated with the longer laterals 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 IP rates that range 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 planned 15,000-foot Haynesville laterals, the Talley 32-29-20 HC number one and number two wells. These wells were completed with 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 of 25 to 40 barrels of 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'll 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 the detail of the 2021 drilling inventory. The drilling inventory is split between the Haynesville and Bossier locations. It is divided into four categories.
We've got our short laterals up to 5,000 feet, median laterals at 5,000 to 8,000 feet, our long laterals at 8,000 to 11,000 feet, and we've got a new extra-long category now for the wells beyond 11,000 feet. Our total operated inventory currently stands at 1,984 gross locations, 1,420 net locations, which represents a 72% average working interest across the operated inventory. Based on -- our non-operated inventory currently stands at 1,425 gross locations and 213 net locations and this represents a 15% average working interest 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 to 15,000-foot 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. To recap our total gross inventory, we have 436 short laterals, 392 medium laterals, 759 long laterals, and now 397 extra-long laterals. The total gross operated inventory is split 53% in the Haynesville and 47% in the Bossier.
Also, by extending our laterals, we have 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 reduce 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, our drilling economics are more robust and it enhances the value of our acreage position.
I'm going to turn it now back over to Jay to summarize the outlook for 2022.
Jay Allison -- Chairman and Chief Executive Officer
Well, like we said earlier, our drilling inventory, which Dan just said, it is the holy grail of E&P companies. It's never been more valuable or stronger than it is today. If you go to Slide 18, I'd direct you to kind of the summary of 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 in excess of $500 million of free cash flow at current commodity prices.
In 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 are making this year in our drilling program will pay off in the future years as our 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. Ron, I'll turn it over to you to give some guidance for the rest of the year.
Ron Mills -- Vice President of Finance and Investor Relations
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 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. Development capex guidance is $750 million to $800 million, which is based on a similar number of turned to sales wells as last year, and incorporates an expected 10% increase in service costs and the impact of our average lateral lengths 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 efficiencies, mostly related to the longer laterals.
We've also budgeted for $8 million to $12 million of additional leasing costs. 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 costs are 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 noncash 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 million 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'll now turn the call back over to the operator for the Q&A session.
Questions & Answers:
Operator
[Operator instructions] Our first question comes from the line of Derrick Whitfield of Stifel. Your line is open.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Thanks and good morning, all.
Jay Allison -- Chairman and Chief Executive Officer
Morning.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
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 setup certainly seems positive to us based on potential positive production revisions in the institution and 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 years, could you speak to your confidence in executing against this in light of the tighter labor and service price environment?
Dan Harrison -- Chief Operating Officer
Yeah. This is Dan. So we -- we're fairly confident we can execute the way that we've got it planned. We kind of factor our scheduling based on the most recent cadence that we've been at.
And we've had a little bit of that kind of already built into the numbers at the end of last year. We foresee that to be kind of at the same pace going into this year. I'd say, yes, we feel pretty strongly we can execute the way that we've got it laid out this year.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Great. And then, for my follow up.
Jay Allison -- Chairman and Chief Executive Officer
We did have a few hiccups during the weather a week or so ago with the hauling sand and some driver issues. I mean we have seen that, but I don't think it's impacted, Dan.
Dan Harrison -- Chief Operating Officer
It hasn't impacted the overall kind of schedule. We did start seeing a little bit of it in the fourth quarter, it was kind of spotty. And we've kind of got that built into our scheduling and our dates. So 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.
Jay Allison -- Chairman and Chief Executive Officer
I think the key is, we do have our drilling contractors lined up, and we do have our frac service companies lined up.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
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 one and a half 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?
Roland Burns -- President and Chief Financial Officer
Sure. Derrick, that's a good question. And obviously, front and center is to first achieve our debt reduction goal, which is we have the $479 million of 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.
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 would be to establish a sustainable dividend. We had one in 2014, so we're excited to put that back in place. As this year progresses and we see where gas prices land, a very volatile first quarter so far with gas prices, but we'll know the right time to put that dividend in. But the debt reduction target happens first and achieving the leverage ratio happens first.
And 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 and have that as another supplement to the return of capital.
Jay Allison -- Chairman and Chief Executive Officer
I think the beauty is we've had a dividend before, so it's not something new. And when we had to remove it, we did remove it. 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'll be there more sooner than later.
And remember, the Jones' own 60% to 65% of the company, so they're very interested in having the stock perform properly. I think when we weigh a dividend, is that what the market is looking for, that guaranteed yield? We'll assess all of that, and we'll make a good decision.
Roland Burns -- President and Chief Financial Officer
And we've laid the groundwork with our big bond refinancings we did. We've laid the groundwork for the strategy as we go forward.
Jay Allison -- Chairman and Chief Executive Officer
Yeah.
Roland Burns -- President and Chief Financial Officer
So I think it's all in place and placed in our debt instruments and our commitments to the rating agencies, commitments to the bondholders. I mean, I think we want to 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.
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
That's great, very helpful. Thanks for your time.
Operator
Thank you. Our next question comes from Charles Meade of Johnson Rice. Your line is open.
Charles Meade -- Johnson Rice -- Analyst
Good morning, Jay, to you and your whole team there.
Jay Allison -- Chairman and Chief Executive Officer
Good morning. Always good to hear from you.
Charles Meade -- Johnson Rice -- Analyst
You're kind. Jay, I think we got some of the detail from Dan on this on when you're going to add the rigs. I think what I heard is that you're in the process of adding two rigs right now. And I'm curious about how -- what the implications are for how your production is going to progress over the year.
I think Ron mentioned that 2Q and 3Q are going to be the big growth quarters. But can you tell us how should we think about how both you're bringing those rigs on, when they're going to be contributing production, and what the shape of the year looks like?
Jay Allison -- Chairman and Chief Executive Officer
We advertised a first quarter production decline, and it is really just lower well completions, number of completions. And Ron had talked about that, and as you had mentioned, it's really before growing our production in the second quarter and third quarter 2022. And I think from there on out, we have some pretty predictable growth. We are, Charles, we're in a transition from the shorter laterals to the longer laterals, and that's all we're in.
We're in like a 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-foot lateral wells. And I know in Dan's script, he didn't know we had turned to sales the two Bossier wells, so he changed the script, but we did turn those to sales late last night, 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-plus percent to the 30s, that's going to help with our RBL, it's going to help with our model, and it's going to lower our costs. 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 -- 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 we think will generate more free cash flow. And again, I think if you go to that, you have to look at the basin we're in, you have to 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. And I think you're going to see some more of that.
Roland Burns -- President and Chief Financial Officer
I had a couple of comments too that specifically, I think we do have the seven rigs operating right now. But one thing, 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 didn't affect our budget. I would say we're really a 6.5 rig to deliver on our budget. The other half will be doing work.
That's not in our budget. 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 a six-month transition period.
I think when you go longer term, I think the longer laterals, we do see probably right now, if we keep at the same activity level, having -- and '23 having higher production growth than kind of the rate we're on now, that's going to be the benefit of going to these longer laterals in the timeframe. The other thing that's kind of extending the production timeframe on these wells is the practice of completing more than two wells at a time. And we typically 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 kind of incorporated. There's more of that in this year's plan than in the previous years where we may have five wells, seven wells, multiples more than two coming online at the same time as we do multiple pads together to minimize shut-in time.
Jay Allison -- Chairman and Chief Executive Officer
And Charles, I think if you look at our growth chart, you'll see second, third quarter, fourth quarter, I mean, 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. We have put those in too, we floated those in. But I think you're going to see first quarter it will be lower, but then second, third, fourth quarter will continue to grow.
And you'll see that, as Roland mentioned, into 2023. We'll have forked in to as the normal drilling longer lateral wells and completing them.
Charles Meade -- Johnson Rice -- Analyst
Got it. That's helpful detail, particularly about the contract drilling piece. Jay, I want to go back to -- you mentioned those two 15,000-foot Bossier wells. And I recognize that we're just not only in the early days and the early hours here on how those wells are performing, but I wondered if you could 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?
Jay Allison -- Chairman and Chief Executive Officer
Yes. Let me -- I want to comment and then I'll turn it over to Dan. But if you remember, we've got 53% of our locations for Haynesville and then the rest are Bossier. And what we chose to do, Charles, we chose to say instead of drilling four 15,000-foot Haynesville, let's do two Haynesville, two Bossier.
We did the two Haynesville, and as you know, I mean, what's it 89 million a day for both of them? I think it's 48 and 41, so we've got two great wells there. And then I think on the Bossier, remember, we -- go back into probably December 2015, we were one of the first companies to drill at Bossier that was really successful and kind of started this Bossier drilling. You can ask the Indigos of the world, etc., when they were here, I mean, they looked at that well. We have drilled a bunch of Bossier before, so Dan was confident that we should drill these two Bossier wells.
Dan, do you want to comment on those? And they did turn to sales and we expect them to be really good wells, but they did turn to sales late last night, this morning. Dan?
Dan Harrison -- Chief Operating Officer
I'll just add that we did -- the four 15,000 laterals that we drilled, on average the Bossiers drilled a little bit faster. We did drill, the fastest of those four wells, was one of these Bossier wells, we drilled it to TD in 29.5 days. So that's pretty strong performance there. As far as fracking them out to TD, same as 10,000, we didn't have any issues on these two Bossier wells.
Drilling out all the plugs, got all the way out to the end of the laterals with no issues. So that's -- when you start out the first few wells, you always have a few hiccups and 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.
Charles Meade -- Johnson Rice -- Analyst
Thank you for the call.
Jay Allison -- Chairman and Chief Executive Officer
Thank you.
Operator
Thank you. Our next question comes from Neal Dingmann of Truist Securities. Your line is open.
Neal Dingmann -- Truist Securities -- Analyst
Good morning, guys. Can 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?
Dan Harrison -- Chief Operating Officer
So the economics of the Bossier wells, they -- you're going to get a little bit -- they're more like the East Texas wells, we get a little bit lower IPs on the Bossiers with a little bit flatter decline rates. The economics of the Haynesville is basically where we drill and are always going to be better than the Bossiers just across the inventory. But going to the 15,000s, the economics, you're looking at, if you just kind of look at a set gas price of say -- we ran these back before at the lower gas prices, but an average 7,500-foot lateral versus a 15,000, which is kind of how we look at the wells that we're drilling, you either drill one or the other, you're looking at 100% rate of return on a 15,000 well and you're looking at something that's closer to down to 60% to 70% return on a 7,500-foot lateral. And this -- we expect to get better with these 15,000s.
We saw it happen with the 10,000s, and so we've already outlined several things where we know we can make some improvements on the 15,000 case.
Neal Dingmann -- Truist Securities -- Analyst
It's funny you said that. 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, but on Haynesville, longer laterals. I'm just wondering, could you talk about the improvements you're continuing to see? Is it just purely the longer laterals, or are there some improvements on even completions that are part of this upside? I know Ron's done a good job of sort of showing us the per foot upside that you're seeing, and I'm just wondering, is this purely because of longer laterals or what else is driving that?
Dan Harrison -- Chief Operating Officer
Well, 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 length.
But it becomes more profound when you start drilling the longer laterals, you get a bigger bang for the buck from those things. I can't remember what your second part of your question was.
Neal Dingmann -- Truist Securities -- Analyst
No, that was it. I just didn't know besides longer laterals if there's things come on the completion side that you're doing to -- certainly returns and returns on per foot are improving. I didn't know if there's other things completion speaking that's driving these returns as well.
Dan Harrison -- Chief Operating Officer
The completion side is just an efficiency gain from getting longer. That's a little bit more kind of just a ratio. I think on the drilling side, we're probably seeing a little bit better gains. With the fracs, it's just basically the performance of our frac crews.
We certainly expect to get an uplift when we go to our natural gas fleet in April, we expect to see a little bit better performance there.
Jay Allison -- Chairman and Chief Executive Officer
Our stages and clusters have been pretty consistent.
Dan Harrison -- Chief Operating Officer
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 kind of recap that answer.
Neal Dingmann -- Truist Securities -- Analyst
Got it. Thank you, guys. Great details.
Operator
Thank you. Our next question comes from Leo Mariani of KeyBanc Capital Markets Inc. Please go ahead.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
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 over the last several years to really kind of increase the size of the company, the inventory. What do you think kind of the outlook is these days? Are there other Haynesville properties out there you think might be a good fit for Comstock?
Jay Allison -- Chairman and Chief Executive Officer
You know we are -- we're always asked, are we looking outside the basin? And the answer is no. I get rid of about 90% of the whole world there. 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.
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 continue to add incremental valuable acreage around our existing footprint that will enhance our laterals. We don't really see a lot of activity on the M&A front at all.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
OK. That's helpful. And there's certainly been a fair bit of discussion on this topic, but if I just kind of take a high-level look at some of the changes in the '22 program versus '21, it looks like the number of wells you're turning to sales is roughly the same, but you are getting kind of 19% more lateral feet this year. So certainly, a pretty big step up in feet completed here.
But when we just kind of 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. I just wanted to kind of clarify that.
Dan Harrison -- Chief Operating Officer
Yes, that's a great question. I do think it's a timing issue because I do think that we -- when you get to '23, you kind of 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 kind of not running consistent number of rigs during -- not running as many rigs in the fourth quarter. Obviously, I think that a lot of that is all timing.
I think this year, with a more consistent program that's starting here toward the end of the first quarter and maintaining that through '23, you'll see more consistent growth and doing a lot more long laterals. We'll reap the benefits from these longer laterals in especially in the second half of this year and then all of next year. And then with 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 efficiency, but it takes a while to show up in the numbers.
Jay Allison -- Chairman and Chief Executive Officer
Leo, I think again, you look at the inventory, I mean, we've got really impactful inventory. You look at our margins, they've been really high. You look at the operations group, I mean 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 Dan has said, and I think our efficiency, which is our operational efficiency, has been very predictable.
I do think there is some pain for six months in transitioning to these longer laterals, but it will certainly be worth it.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Yeah. No, that's helpful. And maybe just lastly for you guys, can you talk a little bit about kind of 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 kind of going forward here in '22, just give us a sense for what type of differential you'll see for Comstock and any basin dynamics you want to discuss?
Roland Burns -- President and Chief Financial Officer
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 what we tried to show. The real noise was bid week 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 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 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 100% either way because it can't be -- it's impossible to go 100% in the index market.
You have to deliver that gas. 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 626, a very high number. Immediately, spot market was lower than that. We don't know how that progresses this year, but obviously there's 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 spot market can catch up to that contract price would be nice.
We've got a little ways to go to do it.
Leo Mariani -- KeyBanc Capital Markets -- Analyst
OK. Thank you, guys.
Jay Allison -- Chairman and Chief Executive Officer
Thank you, Leo.
Operator
Thank you. Our next question comes from Fernando Zavala of Pickering Energy Partners. Your line is open.
Fernando Zavala -- Pickering Energy Partners -- Analyst
Hey, all. Good morning, 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 of longer laterals hitting into year-end '22 and beyond.
Ron Mills -- Vice President of Finance and Investor Relations
You cut out a little bit. What was the very beginning part of the question that you're asking?
Fernando Zavala -- Pickering Energy Partners -- Analyst
Sorry. Yes, if you could give some numbers around base decline trends into year-end '22 and 2023.
Ron Mills -- Vice President of Finance and Investor Relations
In terms of base decline, I mean currently kind of I think Jay referenced kind of right around 40%, 40 plus percent. 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 we think about bringing them on and the way you manage pressure flow back, you kind of take into account maybe a flattish decline for five or six months. On the longer laterals, you expect that to be nine to 10 months.
And depending on -- in the 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 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.
Roland Burns -- President and Chief Financial Officer
Yeah. 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, you maybe see some of a few other operators in the Haynesville have that, but the lateral length is the major difference between what we even have now and versus higher decline rates. It's all the lateral length is the major difference in that.
Jay Allison -- Chairman and Chief Executive Officer
Yeah. And then I think if you again drill these long laterals for a while, as Ron said, you don't have to spend as much capital to grow your production 4% or 5% because you don't have as steep a decline. That's the goal.
Fernando Zavala -- Pickering Energy Partners -- Analyst
Yeah, that's helpful. Thank you. And I guess that goes to my follow-up question about how you all are thinking about activity and spending balances in '23 as like you said, the benefits of the longer laterals start showing up in 2023. Are you -- you have options, right, to scale back activity and stay within that 4% to 5% growth? Just how you all are thinking about that?
Roland Burns -- President and Chief Financial Officer
It's kind of early for us to think about it. But I mean, I think, yes, 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 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 basin 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.
A lot of that, we really have to get closer in to see how this year progresses.
Jay Allison -- Chairman and Chief Executive Officer
If you go to 2023 too, I mean kind of to your point, we don't have this $479 million of shorter-term debt that we can pay off. That free cash flow number, we're going to have a lot of excess free cash flow over and above whatever our capex budget would be. 2023 will be a huge turning point for the company, but I think it starts in 2022.
Fernando Zavala -- Pickering Energy Partners -- Analyst
Got it. Thanks, guys.
Operator
Thank you. Our next question comes from Ray Deacon of Petro Lotus. Go ahead.
Ray Deacon -- Petro Lotus Analytics -- Analyst
Hey. Good morning, Jay, and Roland, and Daniel, Ron.
Jay Allison -- Chairman and Chief Executive Officer
Hi, Ray.
Ray Deacon -- Petro Lotus Analytics -- Analyst
I had a quick question for Dan, 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%?
Roland Burns -- President and Chief Financial Officer
I think we've actually -- the new inventory chart we provide here, and this is Roland, actually reflects a lot of remapping. But I mean there will be a constant interest in remapping both through acreage trades. We've got -- I think the other major -- everybody likes the longer laterals in the basin, so as now some of this consolidation has occurred, there's a refocus now engaging with adjacent operators on acreage trades, so we hope to continue to do those. Yes, there will be more remapping to come, but what we're presenting now is kind of the result of remapping a lot and changing the lateral.
It's changed by 25%. It's a very dramatic difference from the inventory you saw before.
Jay Allison -- Chairman and Chief Executive Officer
Well, I think, and I was looking back at the numbers, if you looked at we have 1,633 net locations and those that are greater than 8,000-foot laterals, it's 902 of them. And if you start at the end of last year, that number was 745. And today, it's 902. To Roland's point, that's that remapping and the diversified that we bought, etc., etc., and swapping acreage with some continuous contiguous to offset operators, but that's the remapping of the last year.
And we plan on trying to do more of that because it's a win-win for both companies.
Ray Deacon -- Petro Lotus Analytics -- Analyst
Got it. Got it. And have you decided already where the two incremental rigs will go at the end of the or this quarter?
Dan Harrison -- Chief Operating Officer
Yes. Right, this is Dan. The first, our sixth rig basically spud its first well yesterday, and we'll be -- the seventh rig will be spudding its first well probably late next week. We've got both of those rigs are going to work in our Logansport area.
Ray Deacon -- Petro Lotus Analytics -- Analyst
OK. Got it. Got it. And just one last question on realizations.
If you were to -- I know Aton 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 have narrowed a bit if you hadn't had this big recent increase in activity? Is that fair?
Roland Burns -- President and Chief Financial Officer
I think you're talking about maybe Perryville Carthage differentials? Those differentials, I mean they did 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 100% tied to that, you should probably plan on higher differentials. But we're going to be -- we're not going to be that tied to that in 2022. When the Acadian went into operation in December, it was a big shift and the majority of our gas is sold at the Gulf Coast indexes, which they don't -- they tend to stay tighter to Henry Hub. And then the gas that we can't actually put into the Gulf Coast indexes, we really take 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.
Jay Allison -- Chairman and Chief Executive Officer
And to Roland's point, remember, the Acadian deal with Enterprise, that was negotiated 2018, early '19, and it came on in December of '21. So.
Roland Burns -- President and Chief Financial Officer
Yeah, so 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 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 widen out in '22. But that's a totally different factor looking at the index price versus the spot price, that's totally unrelated to that. That's just the --
Jay Allison -- Chairman and Chief Executive Officer
Kind of one step out from your question, 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 Appalachia, you do have a takeaway issue. We haven't seen that. When we planned these wells, '22, '23, we looked in advance on that.
Ray Deacon -- Petro Lotus Analytics -- Analyst
Right. And Jay, does the MiQ realization help you at all in those in terms of realizations or lower gathering fees? Do you get access to different markets or?
Roland Burns -- President and Chief Financial Officer
Well, you hope to in the future. I mean, I think that's the -- I think that's -- as we're able to find purchasers that want to give us credit for that, I would say we don't have that now. And maybe in our region right now, they're more interested in price. But as we're -- with the direct access to Gillis Hub and being able to sell directly to LNG, to the extent they have customers that want to lock in to possibly source gas, we have that mechanism.
We'll have that mechanism in place hopefully midyear in '22. We're ready to that. But that could be the case, but we'll see.
Jay Allison -- Chairman and Chief Executive Officer
I think that flexibility, Ray, will be valuable.
Ray Deacon -- Petro Lotus Analytics -- Analyst
Yeah. Got it. 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 much of a change versus '21?
Jay Allison -- Chairman and Chief Executive Officer
The breakdown in 2022 is going to be pretty similar to what we had in 2021.
Ray Deacon -- Petro Lotus Analytics -- Analyst
Got it.
Roland Burns -- President and Chief Financial Officer
But just a handful.
Jay Allison -- Chairman and Chief Executive Officer
Just a handful of deliverables.
Ray Deacon -- Petro Lotus Analytics -- Analyst
OK, got it.
Operator
Thank you. At this time, I'd like to turn the call back over to Jay Allison for closing remarks. Sir?
Jay Allison -- Chairman and Chief Executive Officer
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, if you look at the fundamentals of the dry natural gas market, we don't think they have ever been stronger, particularly in the footprint that we're in. 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 basin, our footprint. We're a pure play.
We plan on staying that and trying to reduce our costs, 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.
Operator
[Operator signoff]
Duration: 71 minutes
Call participants:
Jay Allison -- Chairman and Chief Executive Officer
Roland Burns -- President and Chief Financial Officer
Dan Harrison -- Chief Operating Officer
Ron Mills -- Vice President of Finance and Investor Relations
Derrick Whitfield -- Stifel Financial Corp. -- Analyst
Charles Meade -- Johnson Rice -- Analyst
Neal Dingmann -- Truist Securities -- Analyst
Leo Mariani -- KeyBanc Capital Markets -- Analyst
Fernando Zavala -- Pickering Energy Partners -- Analyst
Ray Deacon -- Petro Lotus Analytics -- Analyst
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