Comstock Resources, Inc.

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 speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference may be recorded. Should you require any further assistance, please press star zero. I would now like to hand the conference over Over to your host, Chairman and CEO, Jay Allison. Please go ahead.

Thank you for that introduction. You know, on behalf of the 200 and say four or five Comstock employees and the Board of Directors, I'd like a few opening comments and then we'll go to the results. First, you know, Comstock shift, I think as Ron Mills has talked about the analyst, I mean, Comstock shift to longer laterals, you know, the 10,500 foot laterals in 2022 versus the 800 foot laterals in 2021. You know, you should all know that it's expected to create a great value on a per well basis going forward. You know, we have better cost efficiencies. We should have a lower decline curve, thus an increase in well performance. You 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. So you can see that in the numbers. And we have seen higher service costs. You know, 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 the salvage 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. You know, our drilling inventory, which is the holy grail of V&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 than 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 are Hainesville. 47% are 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 Sainsville, two Bossier. Two Sainsville wells we report on, and we just, as of this morning, we put the two 15,000 foot Bossier wells to sales. You know, 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 into fourth quarter 2021, which that will be carried over into 2022. You know, 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 Hainesville 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 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 Barnes, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Best Relations. If you slip to slide two, refer to slide two 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 should be reasonable, There can be no assurance that such expectations will prove to be correct. Our fourth quarter 2021 highlights, slide three. We cover the highlights on the fourth quarter on slide three. 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 Hainesville wells, which had IP rates of 48 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 blocking properties and closed a bolt-on acquisition for $35 million. If you'll flip over to slide four, we'll go over some of the major accomplishments in 2021. You know, 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 Hainesville Shell drilling program, We drilled 64 gross or 51.9 net wells, including four 15,000-foot laterals. The wells we put to sales had an average IP rate of 23 million cubic feet equivalent per day. We grew our SEC-approved reserves by 9% to 6.1 TCFE with a PV10 value of $6.8 billion. We replaced 199% of our production at a low all-in finding cost of $0.60 per MCFA. 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 Hainesville 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 five, 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 Russ counties. Over 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 length on 44 of our existing drilling locations to be increased. I'll now turn the call over to Roland to discuss financial results. Roland?

Yeah, thanks, Jay. On slide six in the presentation, we compare some of our fourth quarter financial measures to the fourth quarter of 2020. Our production increased 12 percent to 1.35 BCFE a day. Adjusted EBITDA grew 41 percent 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, 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 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 90 cents per share, up from 56 cents in the fourth quarter of 2020. and adjusted earnings per share was 37 cents per share as compared to 14 cents in the fourth quarter of 2020. On slide seven, 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 4.5 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. And we've had a very volatile NYMEX contract, you know, 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. 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 NYMEX reference price for looking at our activity in the fourth quarter would have been $5.47, not $5.83. So I realize pricing from the fourth quarter averaged $5.22 per which reflects a 25-cent differential from that reference price, which is fairly in line with our historical results. In the fourth quarter, we were also 72 percent hedged, so that reduced our final realized gas price to $3 for MCF. On slide nine, we detailed our operating costs for MCFE and the EVA-DAX margin. Operating costs for MCFE averaged 67 cents in the fourth quarter. That was two cents higher than the third quarter rate. Our lifting costs and gathering costs were both up by one cent, but production taxes were down by three cents. Higher G&A costs of eight cents 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 six to seven cents for MCFE in 2022. Our EBITDAX margin, including hedging, came in at 78 percent 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 cost. In the fourth quarter, we spent $140 million on development activities $114 million of that related to our operated Hainesville 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 our Hainesville operations. We spent an additional $3 million for our properties outside of the Hainesville. For the full year, we spent $628 million on development activities, $554 million was related to our operated Hainesville and Bossier Shell 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 Hainesville 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 Hainesville Shell acreage. Slot 11 covers our approved reserves at the end of 2021. We grew our SEC-approved 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-approved reserves, and we had about 89 BCFE of positive price-related revisions. We also added 203 BCFE of approved reserves through our acquisition activity. The reserve additions were offset by a divestiture of 100 BCFE, which is primarily our Balkan shale properties. Our all-in finding cost for 2021 came in at a very attractive 60 cents per MCFE. Our drill pit finding cost for 21 came in at 71 cents per MCFE. Our reserves are almost 100% natural gas, following the sale of our Balkan properties. The PV10 value of our approved 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 of approved undeveloped reserves, which are not included in that number as they're 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 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're 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.

Okay. 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 laterals 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 Hainesville 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 DMC cost trend for our benchmark long lateral wells. These are our wells with an average lateral length greater than 8,000 feet. Our DMC 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 DMC cost. 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 costs 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 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 planned 15,000 foot Hainesville 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 Pamola County in the liquids-rich area of the Hainesville 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 frack crews. We're in the process now of adding two rigs, increasing our rig count to seven, and we'll remain at the seven rig count throughout the remainder of this year. We plan to continue running three full-time frack 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 Hainesville and Bossier locations, and it's divided into four categories. We've 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, 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. 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 Hainesville and the Bossier. So 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 Hainesville 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. 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.

Well, like we said earlier, our drilling inventory, which Stan just said, I mean, it is a holy grail of B&P companies. It's never been more valuable and stronger than it is today. If you go to slide 18, I direct you to kind of 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 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 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 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 to $800 million, which is is based on a similar number of turn-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 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 to $12 million of additional leasing costs. Our LOE expected to average 20 to 25 cents in the first quarter and 18 to 22 cents for the full year, while our Gathering and transportation costs 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 D&A rate is expected to average $0.90 to $0.96 per MCFE. Cash D&A is expected to total $7 to $8 million in the first quarter and $29 to $32 million in the 2022, with non-cash E&A expected to average almost $2 million a quarter. Cash interest is expected to come in around $38 to $45 million in the first quarter and $152 to $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.

As a reminder, to ask a question, you will need to press star 1 on your telephone. Again, that's star 1 on your touchtone telephone to ask a question. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from the line of Derek Whitfield of Stiefel. Your line is open.

Thanks, and good morning, all. Morning. Good 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 setup certainly seems positive to us based on potential positive production revisions in the institution at 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?

Yeah, this is Dan. So we, you know, we're fairly confident we can execute the way that we've got it planned. We, you know, 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. And so we, you know, we foresee that to be kind of at the same pace going into this year. So I'd say, yeah, you know, we feel pretty strongly we can execute the way that we've got it laid out this year.

Great.

And for my follow-up. We did have a few hiccups, you know, during the weather a week or so ago. you know, with hauling sand and some driver issues. I mean, we've seen that, but I don't think it's impacted, Dan.

It hasn't impacted, you know, the overall kind of schedule. We did start seeing a little bit of it in the fourth quarter. It was kind of spotty. And, you know, we've kind of got that built into our scheduling and our dates. So, you know, basically just based on that latest update, level of uh you know cadence there i mean that's kind of what we see for the rest of this year i mean obviously you know if something changes you know we'll have to go back and revisit you know our our uh scheduling and dates a little bit i think the key is we do have our drilling contractors lined up we do have our frac service companies lined up so it is de-rest 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 long-term views on return of capital and how the near-term could take form later this year?

Sure. Derek, that's a good question. And obviously, you know, front and center is to first achieve our debt reduction goal, which is, you know, we have, you know, the $479 million of prepayable 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. You know, we're still evolving in our return of capital theory, and we obviously have a majority, you know, stockholder to consult with. But, you know, I think our first goal would be to establish a sustainable portfolio dividend. 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, and achieving that leverage ratio happens first. But And then after establishing a base dividend, I think, you know, again, I think we could change our mind, but, you know, I think we'd like to have a share repurchase authorization in place and have that as another supplement to the return of capital.

You know, I think the beauty is we've had a dividend before, so it's not something new. And, you know, when we had to remove it, we did remove it. So, you know, to 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 is on 60 to 65% of the company. So they're very interested in having the stock perform properly. So I think when we weigh a dividend, You know, is that what the market is looking for, that guaranteed yield? So we'll assess all of that, and we'll make a good decision.

And we've laid the groundwork, you know, in our big bond refinancings we did. We've laid the groundwork for this strategy as we go forward. 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 all... You know, we want to have a very balanced approach, but we've laid the groundwork for a return to capital program, you know, 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 Mead 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.

Well, you're kind. Jay, I think we got some of the detail from Dan 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 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 – are going to be the big growth quarters. But can you tell us how should we think about, you know, how you're bringing those rigs on, when they're going to be contributing production, and what the shape of the year looks like?

You know, we advertise a first quarter production decline, and it's really just lower well completions, number of completions. And Ron had talked about that, and you had mentioned it's really before growing and our production in the second quarter and third quarter of 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. 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 is 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 would turn to sales at 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 dollar spent. And I think as you see, you know, in the quarters to come, if we can abate this decline curve from 40 plus percent at 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 cost. 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, 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, you know, 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. Forty-four of those were extended with diversified acreage that we added. And I think you're going to see some more of that.

I had a couple of comments, too, specifically. I think we do have the seven rigs operating right now. But one thing, we normally, you know, when you're thinking about rigs, you know, we do – At least half of one of those rigs will be used for our contract drilling services, which really doesn't affect our budget. So I would say we're really a six-and-a-half rig to deliver on our budget. The other half will be doing work that's not in our budget. And so I think that's how I'd view it. But I think the production is more weighted to the second half of the year. There is this kind of 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 it the same activity level and 23 having a 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 time frame. The other thing that's kind of extending the production time frame 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 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, you know, 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, I mean, production grows pretty substantially. And if you look at the 2022 program, I mean, we have 13 wells that 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'll be lower, but then second, third, fourth quarter will continue to grow. And you'll see that, as I mentioned, in 2023, we'll have forked in to the norm of drilling longer lateral wells and completing them.

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?

Yeah, let me. I want to comment, and I'll turn it over to Dan. But if you remember, we've got, you know, 53% of our locations were Hainesville, and then the rest were Bossier. And what we chose to do, Charles, we chose to say instead of drilling four 15,000-foot Hainesville, let's do two Hainesville, two Bossier. So 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. Then I think on the Bossier, remember, we go back into probably December 2015. We're one of the first companies to drill a Bossier that was, I mean, really successful and kind of started this Bossier drilling it. You can ask the indigos, the world, et cetera, when they were here. I mean, they looked at that well. So we have drilled a bunch of boziers before. So Dan was confident that we should drill these two bozier wells. So, Dan, you want to comment on those? And they did turn to cells, and we expect them to be really good wells, but they did turn to cells like last night, this morning.

Yeah, I'll just add that we did, you know, the four 15K laterals that we drilled. On average, the boziers drill a little bit faster than we did drill. You know, the fastest of those four wells was – one of these Bossier wells, we drilled it to TD in 29.5 days. So that's, you know, that's pretty strong performance there. As far as fracking them out to TD, you know, same as a 10K, 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, you know, that's, you know, when you start out the first few wells, always have a few hiccups and you get a little better from there. We certainly expect that to happen on our future 15,000-foot ladders will get a little bit faster and a little more efficient.

Thank you for the color.

Thank you. Thank you. Our next question comes from Neil Dingman of Truist Securities. Your line is open.

Morning, guys. Can 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, you know, just say your core Bossier area versus Hainesville?

So the economics of the Bossier wells, you know, 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. You know, the economics of the Hainesville, you know, basically where we drill in the, are always going to be better than the Bossiers, just the across the inventory. But, you know, going to the 15Ks, you know, 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 15K, 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 you know, 100% rate of return on a 15K well, and you're looking at something that's closer down to 60 to 70% return on a 7,500-foot lateral. And this, you know, we expect to get better with these 15Ks. We saw it happen with the 10Ks, and so we've already outlined several things where we, you know, where we know we can make some improvements on the 15Ks.

Is it 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, Bojabon, 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 longer laterals, or what else is driving that?

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

No, that was it. I just didn't know besides longer ladders if there's things on the completion side that you're doing to get certain 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.

So 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. You know, with the fracks, it's just basically the performance of our frack crews. We certainly expect to get an uplift when we go to our natural gas fleet, you know, in April. We expect to see a little bit better performance there. You know, our stages and clusters have been pretty consistent. We've been pretty much at about the same performance level on the frack side stages per day, like Jay mentioned. We've definitely seen probably a bigger pickup on the drawing side, just to kind of recap that answer.

Got it. Thank you, guys. Great details.

Thank you. Our next question comes from Leo Mariani of KeyBank. 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 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?

You know, we're always asked, are we looking outside the basin? And the answer is no. So I 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. We understand one of them may be for sale right now. But I think, you know, 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. So we don't really see a lot of activity on the M&A front at all.

Okay, 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 returning to sales is roughly the same, but you are getting you know, kind of 19%, you know, more lateral feet this year. So certainly pretty big step up in feet, you know, completed here. But when we just kind of overall look at the production growth, you know, 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.

Yeah, 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, you know, the big transition to the longer laterals, and it's a timeframe also kind of, you know, not running consistent number of rigs, you know, during, you know, and not 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, you know, here, you know, toward the end of the first quarter, In maintaining that through 23, you'll see more consistent growth and, you know, doing, you know, a lot more long laterals. We'll reap the benefits from these longer laterals, you know, especially in the second half of this year and then all of next year. And then, you know, with hopefully a little bit lower decline profile from the longer laterals, which they provide, you know, 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.

Leo, I think, again, you look at the inventory. I mean, we've got really impeccable inventory. You look at our margins, they've been really high. You look at the operations group. I mean, year after year after year after year, they've delivered stellar performance. You do more from 5,000-foot laterals to 70, 500-foot to 10,000-foot to 15,000-foot, as Dan has said. And I think our efficiency, which is our operation efficiency, has been very predictable. I do think there is some pain for six months in transitioning to these longer laterals, but it would certainly be worth it.

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, you know, 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.

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, you know, we haven't experienced that, you know, I don't think in a long time, you know, in the overall gas market. And it was very, very, you know, very volatile in the fourth quarter, and the difference between those was so dramatic that it, you know, it creates a large differential. It's easy to model those separately, you know, and I think generally, you know, 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, you know, it's impossible to go 100% in the index market. You have to deliver that gas. So I think that is, you know, 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, you know, look at the first quarter, January, you didn't see a big difference between those two numbers. But February, dramatic difference. You had the contract close at a, you know, 626, a very high number. Immediately, spot market was lower than that. So, you know, we don't know how that progresses this year, but, you know, obviously there's going to be some of that in the first quarter to keep an eye on and see what happens to March, you know. But, Also see if February, you know, if the spot market can catch up to that contract price would be nice. Got a little ways 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.

Hey, all. Good morning. Thanks for the time. I was wondering if you could give some numbers around base decline trends into year N22 and beyond, maybe relative to 2020 and 2021, with obviously the tailwinds of longer laterals hitting into year N22 and beyond.

You cut out a little bit. What was the very beginning part of the question that you're asking?

Oh, sorry. Yeah, if you could give some numbers around base decline trends into year N22 and 2023 and

In terms of base decline, I mean, we're 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. You know, with the shorter lateral wells, you know, when you think about bringing them on and the way the managed pressure flow back, you know, 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 even the longest laterals 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, you know, 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.

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

Yeah, and I think if you, again, grow 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.

Yeah, that's helpful. Thank you. And I guess that goes to my follow-up question about how y'all are thinking about activity and spending balances in 23 as, you know, like you said, the benefits of the longer lateral start showing up in 2023. So, like, are you – you have options, right, to scale back activity and stay within that 4% to 5% growth, just how y'all are thinking about that?

Well, it's kind of early for us to think about it, but, I mean – I think, yeah, I think if we don't pull back, that we will have – the numbers would tell us we should have higher growth rate in 23, you know, if we stay at a constant level. But, you know, we'll target, you know, free cash flow. How do we maximize free cash flow generation? How do we maximize overall results? What does the basin take away? What's the pressure on the gas market? There's a lot of factors. You know, 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.

If you go to 2023, too, I mean, kind of your point, we don't have this $479 million of shorter-term debt that we can pay 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 starts in 2022. Got it.

Thanks, guys.

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

Hey, good morning, Jay and Roland and Dan, Ron. 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%?

I think we've actually, you know, the new inventory chart we provide here And this is Roland. Actually, it reflects a lot of remapping, but, I mean, there will be a constant, you know, interest in remapping, you know, both through acreage trades. We've got, you know, 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 to continue to do those. So, yeah, 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 length. It's changed by 25%. It's a very dramatic difference from the inventory you saw before.

Well, I think, and I was looking back at the numbers, if you look, 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. Today it's 902 to Roland's point. That's that remapping and, you know, the diversify that we bought, et cetera, et cetera, and swapping acreage with some continuous offset operators. But that's the remapping in the last year. And we plan on trying to do more of 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, Ray, this is Dan. The first, our sixth rig basically spud its first well yesterday, and the seventh rig will be spudding its first well probably late next week. And we've got both of those rigs are going to work in our Logan's Port area. Okay. Got it. Got it.

And just one last question on that. realizations. If you were to, I know Athon has a sales process on that's been a significant addition to the rig count in the Hainesville. 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?

I think you're talking about the maybe Perryville, Carthage differentials. I mean, that's the, you know, differentials. I mean, they did widen in the fourth quarter. Again, we only had like 10% of our sales subject to it because we kind of planned for that. We've moved a lot of gas away from Perryville. It's no longer our dominant index. So, yeah, I think if you're an operator that's 100% tied to that, you know, you should probably plan on higher differentials. But, you know, we're not going to be that tied to that and In 2022, you know, when the Acadian went into operation in December, you know, it was a big shift, and the majority of our gas is sold at the Gulf Coast indexes, which, you know, they tend to stay tighter to Henry Hub. And then the gas that we can't 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 25-cent number, you know, and not have too much gas exposed to, you know, a wider differential, you know, in those markets.

Going to Rob's point, remember the Acadian deal with Enterprise, that was negotiated in 2018, early 19, and it came on in December of 21.

Yeah, so that's going to help mitigate, you know, 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, you know, keep that differential from, you know, having to widen out, you know, in 22. But, you know, that's a totally different factor looking at the index price versus the spot price. That's totally, you know, unrelated to that.

That's just the... You know, Rick, kind of one step out for 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 plan these wells, you know, 22, 23. We looked in advance on that.

Right. And, Jay, does the MIQ realization help you at all in terms of realizations or lower gathering fees? Do you get access to different markets?

Well, you hope to in the future. I mean, I think that's the – I think that's, you know, as we're able to – you know, find purchasers that want to give us credit for that. I would say we don't have that now. And maybe in our region, you know, right now they're more interested in price. But, you know, as we're, you know, with the direct access to Gillis Hub, you know, and being able to sell directly to LNG, you know, to the extent they have customers that want to lock in to responsibly source gas, you know, we have that mechanism. We'll have that mechanism in place, hopefully mid-year, you know, in 2022. So we're ready to that. But that could be the case, but we'll see.

I think that flexibility, Ray, will be valuable. Yeah.

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

So the breakdown of 2022 is going to be pretty similar. to what we had in 2021. Got it. Just a handful of those. 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. If you still get the fundamentals of the dry natural gas market, we don't think they've ever been stronger, particularly in the footprint they were 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 Hainesville-Bossier Basin, our footprint. So we're pure play. We plan on slaying 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.

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