Comstock Resources, Inc.

Ladies and gentlemen, thank you for standing by, and welcome to the fourth quarter 2020 Comstock Resources, Inc. earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star 1 on your telephone. As a reminder, today's program is being recorded. I would now like to introduce your host for today's program, Jay Allison, Chairman and Chief Executive Officer. Please go ahead.

Jonathan, thanks for giving us that warm welcome. As most of you know, our home office is in Frisco, Texas, which is just north of Dallas. And today, if you looked at our windows, you would think that we're in snowy Alaska or reporting from the ski slopes in Colorado. In fact, Alaska is probably warmer than the recent sub-zero temperatures that we've seen here with the wind chill factors. Our offices have been closed for three days now, and only probably four of us are here today reporting from the office. You know, this Arctic freeze in Texas and the mid-continent creates challenging days in the world of natural gas. We've experienced idle frack fleets, idle drilling rigs due to the freeze-offs, as well as record demand just to keep the power on in our homes. In fact, millions are still without power as we speak. With 99% of our reserves being natural gas, which is the cleanest fossil fuel, and our world-class Hainesville-Boger gas fields being located in close proximity to the Gulf Coast LNG market and near major petrochemical plants and close to the industrial demand corridors, I can tell you that Comstock is well-positioned to help meet the existing and future needs for predictable and reliable energy in America. With 2020 being such a whipsaw year, I'm pleased that all 204 employees of Comstock who work for you have delivered solid results for the year and expect 2021 to be outstanding. Thank you for trusting us as we continue to seek to close out every day as a stronger company. With that, I'll start the welcoming part. Welcome to the Comstock Resources fourth quarter 2020 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation titled Fourth Quarter 2020 Results. I am Jay Allison, as Jonathan said earlier, 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, is joining us on the phone. Please refer to slide two in our presentation. Note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you'll turn over to slide three, we will recap some, not nearly all, but some of our 2020 accomplishments. The most significant accomplishment is our successful navigation of one of the most difficult years for our industry ever. Despite realizing $1.80 for our gas and $32.36 for our oil, we still were able to turn in profitable financial results, excluding unrealized hedging losses. You know, we completed an accretive $207 million equity offering in May, which is the first natural gas common equity offering since 2016. The offering allowed us to redeem our Series A preferred stock and save $21 million per year from the elimination of dividend payments. The 41.3 million shares we issued in the offering eliminated the need to deliver 52.5 million shares in the future for the conversion of the preferred. We also completed two successful senior notes offerings totaling $800 million to repay bank debt. This increased financial liquidity from $166 million to $930 million. We also reduced our usage of our bank credit facility from 88% to 36%. We had another year of strong results from our 2020 Hainesville Bossier Shell Drilling Program We drilled 55 or 46.1 net successful wells that we operate. We've turned 54 or 40.9 net operated wells to sales with an average IP rate of 25 million cubic feet per day. In 2020, we were able to lower our well cost by 16%. Our two-mile laterals, which Dan will talk about in a minute, averaged $1,026 for completed lateral footed 2020 versus 2020. 1,215 in the prior year. This allowed us to grow our approved reserve base by 3% at a low-end finding cost of 66 cents per MCFE. Despite having to use very low prices to determine our SEC approved reserves, they grew by 3% to 5.6 TCFE. Our reserve additions replaced 159% of our 2020 production. If you'll go over to slide four, we cover some of the highlights of the fourth quarter on slide four. We resumed completion activities in the third quarter and our natural gas production increased by 6% from the low third quarter level. The production in the quarter was still impacted by a high shut-in level of 6.6%. Now, this is mainly due to actions we took in October to shut in $300 million a day of our operated production in response to very low natural gas spot prices. We turned 22 or 16.4 net Hanesville wells to cells with an average lateral length of 8,899 feet the fourth quarter. We're well positioned for continued production growth in the first quarter of 2021 and throughout the remainder of the year of 2021. Our conservative operating plan in 2021 is focused on reducing our leverage ratio by both growing EBITDAX and reducing debt. We're targeting to generate over $200 million in free cash flow in 2021, The higher production and improvement to oil and gas prices allowed us to return to profitability in the fourth quarter. We reported oil and gas sales of $277 million. Our EBITDA came in at $211 million, and we generated $155 million, or 56 cents per share, in operating cash flow. Our adjusted net income for the quarter was $35 million, or 14 cents per share. Lastly, we ended the year with very strong financial liquidity of $930 million. So now I'll turn it over to Roland to cover our financial results in more detail. Roland?

All right. Thanks, Jay. On slide five, we summarize our reported financial results for the fourth quarter of 2020. Our production for the fourth quarter totaled 109 BCF of natural gas and 340,000 barrels of oil. This is 11% lower than production from the fourth quarter 2020. of 2019. Our oil and gas sales, including realized hedging gains, were $277 million, about 10% lower than 2019 due to the lower production level. Oil prices in the period averaged $44.47 per barrel, and our realized gas price averaged $2.40 per MCF, including hedging gains. So overall, our natural gas prices were up 4%, in the quarter, and our oil prices were down a little bit. Looking at the cost side, our lifting costs were down 11% in the quarter, and our depreciation, depletion, amortization, and G&A were both down 7% in the quarter. Our adjusted EBITDAX came in at $211 million, or 10% lower than 2019's fourth quarter. Our operating cash flow was $155 million, which was 18% lower than 2019. And we reported a net profit of $77.5 million for the fourth quarter, or 30 cents per share. The net income for the quarter did include an $80.2 million unrealized gain from the mark-to-market of our hedge positions, which was mainly driven by the change in natural gas prices since September 30th. Adjusted net income, excluding the unrealized hedging gain and certain other unusual items, was a profit of $34.6 million, or 14 cents per diluted share for the quarter. On slide six, we summarized the financial results for all of 2020. Our production for 2020 totaled 460 BCFE, which that includes 1.5 million barrels of oil. That's 49% higher than 2019's production. The increase mainly reflects the acquisition of Covey Park that we closed in July of 2019. Pro forma for the Covey Park acquisition, our production increased 2% year over year. Our oil and gas sales, including realized hedging gains, were $993 million, which was 21% higher than 2019. Oil prices, including hedging, averaged $40.88 in 2020, and our realized gas price, including hedging, averaged $2.07 per MCF, which was 12% lower than 2019. Adjusted EBITDAX for the year was $722 million, an 18% increase over 2019. Operating cash flow was $521 million, which was 11% higher than 2019. Overall, we did report a net loss of $83 million for the year or $0.39 per share, but that loss was entirely due to the mark-to-market unrealized loss on our hedge positions. Excluding unrealized hedging losses and other unusual items, we had a net profit of $49.6 million or $0.23 per diluted share for 2020. Despite a year of very low oil and gas prices, we were able to have a profitable year and we did not have any impairments or other write-downs of our assets, which is, I think, an unusual, you know, compared to many other companies in our industry. That says a lot about the quality of our assets and our low-cost structure. On slide seven, we cover our hedging program. And during 2020, we had 51% of our gas volumes hedged, which increased our realized gas price to the $2.07 for MCF I mentioned, as compared to the $1.80 that we actually received from selling our production. We also had 84% of our oil volumes hedged. That increased our realized oil price to the $40.88 per barrel versus the $32.30 per barrel we actually received. Overall, our realized hedging gains totaled $134.5 million in 2020. With the continued strength in natural gas prices, we've continued to add to our hedge book. Since we last reported earnings, we've hedged another 90 million cubic feet of our production for the second half of 2021 and another $100 million per day for the first half of 2022. For 2021, we have natural gas hedges covering almost $900 million a day of our gas production, which is around 65% of our expected 2021 production. The weighted average floor price of our 2021 gas hedge is $2.51. Going forward, we're primarily focused on adding to our 2022 hedge position. We continue to target having 55 to 70 percent of our production hedged for the upcoming 12 to 18-month period. Slide eight, we recap how much of our production was shut in during the last quarter of the fourth quarter. So, we had 6.6 percent of our natural gas production shut in in the fourth quarter. compared to the 7.2% we had in the third quarter. As we had talked about at our third quarter call, in early October, we voluntarily shut in 300 million a day of our production, really during the first two weeks of October, due to the very low spot market gas prices. The remaining of the shut-in in the fourth quarter is really due to offset frack activity. We also had 2% of our oil production curtailed or shut in in the quarter, That's a big decrease from how much was shut in earlier in the year. On slide nine, we detail our operating costs per MCFE produced. Our operating costs per MCFE averaged 56 cents in the fourth quarter as compared to the third quarter of 55 cents. Gathering costs were 26 cents, our taxes averaged 9 cents, and our field level cost averaged 21 cents. The fluctuation between our lifting costs and gathering costs is related to where the new wells were completed during the quarter, but we continue to expect those costs to remain within the guidance ranges that we have been providing. On slide 10, we detail our corporate overhead for MCFE. Our cash G&A costs in the quarter were $0.04 per MCFE, which is down from the third quarter, primarily due to year-end accrual adjustments. We do expect our cash G&A costs to return to a more normalized level of five to six cents going forward. On slide 11, we detailed the depreciation, depletion, and amortization per MCFE produced. Our DD&A averaged 94 cents in the fourth quarter, about one cent lower than the 95-cent rate we had in the third quarters. Slide 12 shows the balance sheet at the end of 2020. We currently have $500 million drawn on our $1.4 billion revolving credit facility, and we do expect to use our free cash flow that we are targeting to generate in 2021 to continue to pay that down. We have just over $2.25 billion of senior notes outstanding, comprised of $619 million of our 7.5% senior notes due in 2025. and $1.65 billion of our nine and three quarters senior notes due in 2026. With a quarter end cash position of $30 million, our current financial liquidity stands at $930 million. On slide 13, we summarize our fourth quarter and full year 2020 capital expenditures. We spent $169 million on development activities in the fourth quarter, of which 151 was spent on the operated Hainesville Shell properties. We also spent $6.5 million to lease new Hainesville acreage in the quarter. For the full year, we spent $484 million on all development activities, including $410 million, which was spent on our operated Hainesville Shell properties. We drilled 46.1 net operated horizontal Hainesville wells, and we turned 40.9 net operated horizontal Hainesville wells to sales in 2020. We also spent another $82 million in 2020 on non-operated wells and other development activity. And we spent a total of $7.9 million in 2020 on leasing new Hainesville acreage. So right now we're currently utilizing six operated rigs for our 2021 drilling program, but we do expect to drop one of our operated rigs later this year due to the faster drilling times that we're achieving as Dan's going to go over with his operating results. Based on our current operating plan for 2021, we expect to drill 51 net operated Hainesville wells and turn about 50.5 net operated wells to sales in 2021. At the end of 2021, we expect to have about 17.9 net ducts to carry into 2022. We estimate our total development capital expenditures will come in between $510 million and $550 million, and we're also budgeting to spend an additional $7 million to $10 million on the leasing program. We remain focused on generating significant free cash flow and will continue to target over $200 million of annual free cash flow generation as we plan our drilling activity. On slide 14, we summarize our oil and gas reserves at the end of 2020. We grew our approved reserves from 5.4 TCFE at the end of 2019 to 5.6 TCFE on an SEC basis at the end of 2020. Our 2020 drilling activity added 366 BCFE to our approved reserves, and we had 367 BCFE of positive performance-related provisions driven by the strong well performance of our Hainesville wells. Depositive reserve revisions more than offset negative price-related revisions, which were 86 BCFE, that related to using the low first-of-the-month 2020 average prices to determine reserves. Our all-in finding cost for 2020 came in at a very attractive 75 cents per MCFE, or 66 cents if you exclude the price-related revisions. Our reserves were 99 percent natural gas, and then 36 percent of our reserves were developed. Ninety-five percent of our approved reserves are in the Hainesville-Bossier, two percent are in the Bakken, and three percent are in other regions. The PV10 value of our approved reserves was $2 billion, using the SEC prices of $1.99 for gas and $39.57 for oil. And 67 percent of that PV 10 value is related to our developed reserves. Using a NYMEX reference price of $2.75 for gas and $50 for WTI oil, which is more reflective of our current price outlook, the PV10 value of our approved reserves increases to $4.4 billion. And the quantities of approved reserves with those prices would increase to 5.8 TCFE. using that $275 and $50 reference prices. In addition to those approved reserves, we have an additional 2.4 BCFE approved undeveloped reserves, which are not included in our approved reserves, as we're not currently expecting to drill those within the five-year window required by the SEC rules. We also have another 4.6 TCFE of 2P or probable reserves, and 6.8 TCFE of 3P or possible reserves for a total reserve base of 19.6 TCFE on a P3 basis. I'll now turn it over to Dan to cover the fourth quarter drilling results in more detail.

Okay. Thank you, Roland. If you flip over to slide 15, this is going to be an outline of our current acreage position, which has now increased in the fourth quarter to 323,000 net acres. We do control the majority of the acreage with a 91% operated position and have an average working interest in the acreage of 82%. We currently have 1,953 net future drilling locations identified on this acreage with 93% of the acreage currently held by production. Since starting our high-intensity completion program in 2015, we've now turned 272 wells to sales with an average IP rate of 24 million cubic feet a day. We're currently running a total of six operated rigs. We do plan to release one of our rigs in May of this year and continue with five rigs for the remainder of the year. We're currently running three frac crews, and we anticipate running an average of just 2.2 frac crews for the full year of 2021. We currently have 25 ducts. on our schedule, we anticipate our duck count staying in the 20 to 25 range for the remainder of the year. Over on slide 16, this is our latest Hainesville-Bossier drilling inventory as of year end 2020. Our operated inventory currently stands at 2,214 gross locations and 1,719 net locations. This represents a 78% average working interest on our operated inventory. Our non-operated inventory consists of 1,585 gross locations and 234 net locations, which represents a 15% average working interest on the non-operated inventory. On our gross operated locations, we currently have 485 short laterals, 799 medium laterals, and 930 long laterals. If you split these out, the 2,214 gross locations by zone, We have 52% of our locations in the Haynesville and 48% are in the Bossier. This inventory provides the company with over 30 years of drilling locations based on our current activity levels. On slide 17 is a map outline and summary of the 20 new wells that we've turned to sales since the last call. The new wells are mostly located on our east Texas and southwest DeSoto parish acreage, and we did have one well completed over and around Grove Acreage. The wells were tested at rates ranging from $18 million a day up to $33 million a day with a 24 million cubic feet per day average IP rate. The wells were drilled with lateral lengths ranging from 6,751 feet up to 12,716 feet, with an average lateral length of 9,288 feet. And they were all completed with 3,500 pounds per foot sand loadings on our fracks. We drilled and completed our longest lateral ever during the fourth quarter at 12,716 feet on the Jordan 1694 number one well, which is down in the Southwest DeSoto Parish acreage. We are currently completing a 13,000 plus foot lateral that will be turned to sales during the first quarter. And this will be our new record long well at that time. On slide 18 and on the next three slides are the D&C cost trends for our different lateral-linked buckets. Here on slide 18 shows the D&C cost trend for our long lateral wells, which are wells that have length greater than 8,000 feet. On our long ladder wells in the fourth quarter, we experienced a 5% increase in our total DNC costs due to a 15% increase in our completion costs. This was primarily due to the resumption of pumping our larger frac design of 3,500 pounds per foot in the fourth quarter after pumping our smaller frac design of 2,800 pounds per foot in the second and third quarters. We were able to offset a portion of our increased completion costs with lower drilling costs in the fourth quarter due to an increase in drilling efficiency. With this increase in drilling efficiency, we have reduced our drilling costs further in the first quarter, and we do expect to maintain a lower drilling cost for the remainder of the year as we drive our drilling costs down to historic lows. This will help offset the higher completion costs that we anticipate as a result of the increase in industry activity and higher associated service costs. Since 70% of the wells we drill in 2021 will be long laterals, our cost performance in this category is the major driver in the success of our drilling program. Due to the higher drilling efficiency, we're confident that we will be able to maintain our DNC costs relatively flat in this 1,000 to 1,050 foot range for our longer laterals. Ultimately, the gas price environment and market demand for services will determine where our costs settle out in this range. On slide 19 is the DNC cost for our medium lateral wells. These are wells with links between 6,000 and 8,000 feet long. On our medium lateral wells in the fourth quarter, we had a total DNC cost of $11.26 a foot. This represents a slight decrease of 3% from the previous quarter. Our completion cost also increased for our medium-linked laterals due to resuming the larger frac design in the fourth quarter. we were able to still achieve a lower DNC cost in the fourth quarter by driving our drilling costs down by 10% with our increased drilling efficiencies. Same as our long ladder wells, we have reduced our drilling costs further into the first quarter of this year and expect to maintain this lower drilling cost throughout the rest of the year. On slide 20, so this is the D&C cost trend for our short lateral wells. These are the wells that have lateral lengths less than 6,000 feet. As you see here, we've not completed any short lateral wells for the last two quarters, which is by design, since these wells do have a higher cost and inferior economics compared to the longer laterals. When we do drill our short wells, we attempt to drill them as part of multi-well pads with our longer laterals to reduce costs and enhance our returns. Same as with the longer laterals on the previous two slides, we've continued to substantially drive down our costs on our short lateral wells. Over the course of the last year, we have successfully converted many of the short lateral wells in our inventory to longer lateral wells via acreage trades with other operators and also with some small bolt-on acreage acquisitions. We continue to pursue these opportunities to this day. where there are opportunities. To reiterate on our operations, we're confident we can maintain our current low DNC cost structure by capitalizing on the drilling efficiencies we've been able to achieve to date and building on these going forward. These lower drilling costs will help to offset the higher completion costs that we anticipate for the remainder of the year as a result of increased industry activity and associated higher service costs. That summarizes things up on the operations side. I'm now going to turn it back over to Jay.

All right, Dan. Well, thank you. If you would, let's go to slide 21, where we'll summarize what we think is our outlook for really a fabulous 2021. We remain focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns. You know, our inventory, as Dan had mentioned, 1,953 Nat Haines will vote your drilling locations, provide us with decades of drilling inventory. Our operating plan for the year is expected to provide production growth and generate an excess of $200 million of free cash flow, as Roland had pointed out. In 2021, we're focused on improving our balance sheet, as we've told everybody for months and months, reducing our leverage and lowering our cost of capital. You know, with current natural gas prices, we would expect our leverage ratio to improve to around 2.5 times at the end of 2021, down from the 3.8 in 2020. With our industry-leading low-cost structure, our Hainesville drilling program generates some of the higher drilling returns in North America. You know, we have currently hedged approximately 65% of our 2021 production to protect our high drilling returns. We have very strong financial liquidity of that $930 million. So, with that, I want to turn it over to Ron. He can provide some specific guidance for the rest of the year. So, Ron.

Thanks, Jay. On slide 22, we provide financial guidance for 2021. The updated guidance from our November call reflects the impact of the timing of our drilling and completion schedule, as well as the shut-ins that were discussed earlier in the call. Looking at 2021, our development CapEx guidance is $510 to $550 million, and that budget anticipates the release of one of our operated rigs in May, as Dan mentioned. We also anticipate spending another $710 million on leasing activities. Our production guidance is 1.33 to 1.425 BCF per day. Our lease operating costs expected to average $0.21 to $0.25 per MCFE in 2021, and our gathering and transportation costs are expected to average $0.23 to $0.27 per MCFE. Production and average alarm taxes expected to remain in the $0.08 to $0.10 per MCFE range, and our DD&A rate is expected to average $0.90 to $1 per MCFE. As mentioned earlier, we believe our cap G&A rate is expected to return to the more normal 5 to 7 cents per MCFE range. We'll now turn the call back over to the operator to answer questions on the call.

Certainly. Ladies and gentlemen, if you do have a question at this time, please press star then 1 on your touchtone telephone. If your question has been answered and you'd like to remove yourself from the queue, please press the pound key. Our first question comes in the line of Derek Whitfield from Stiefel. Your question, please.

Thanks, and good morning all, and certainly congrats on a strong quarter and a positive outlook. Referencing slide eight, you guys were clearly impacted by several uncontrollable events in Q3 and Q4, and I'd imagine Q1 could similarly be impacted by the current weather. At this time, do you have a sense of weather-related outages for Q1 and more broadly beyond Q1? How would you envision that shut-in metric trending based on your 2021 outlook?

Yeah, that's a great question, Derek. And some of the shut-ins, obviously, for the fourth quarter, you know, were voluntary. You know, we didn't want to accept really low spot prices, so some of our gas that wasn't nominated that's in our swing gas, you know, we decided to shut in in the first part of October and But I think as you go into 2021, you know, we haven't had those type of issues. We've had very good, really very good spot prices so far all throughout 21. And then obviously in the last, you know, the last with all the events in Texas in the last week, you know, obviously incredible spot prices for our swing gas, our marketing department, you know, With the index prices kind of being set lower at the beginning of the month and the rising gas prices both in January and February that we've experienced, you know, we actually were a little bit less – we actually exposed ourselves more to the spot market than normal, and that's going to pay off, I think, you know, handsomely, you know, and improve price realizations in the first quarter, especially whatever gas we've been able to sell over the last – ever since last Thursday, just some phenomenal pricing opportunities, which hopefully will probably continue through the week. Now, the negative to that is, you know, is there going to be shut-in production due to the weather? And through Tuesday, we could have said no. We were at really full production all the way through Tuesday. And then starting yesterday – We started to see some issues where water haulers really can't come and service the wells because of the road conditions in north Louisiana. So, you know, we see some shut-ins now that are, you know, close to 20% of our normal production levels. We think that's only going to be in place for, you know, for a few days. It really depends on, you know, when – road activity can resume. And then once road activity resumes, we can hopefully get back to normal production activities.

Derek, one of the good things, and Dan and Patrick and really the people in the field have done a really great job. Some of the wells that we had shut in because we were fracking some wells since the frack crews were frozen out everywhere. We were able to bring that shut-in production online. So Dan Harrison may want to comment on that. And, again, it's our field people that did such a phenomenal job on that. And as Roland mentioned, the marketing people, Alex, Whitney, et cetera, the whole group, I think they've really delivered great results. Dan, any comments?

Yeah, I'll just basically add to what you said, Jay. Our people here in the office and the field have done a fantastic job. Our frack crews have been down since roughly probably Saturday morning. And we did have a substantial amount of gas that we put back on production when the frack crews, you know, was shut in for offset frack protection. And we did get that production back on from Saturday through Tuesday. So we actually had a lot higher, we had a lot more gas production, you know, from Saturday through Tuesday when the prices spiked. We're kind of starting to see the effect of that really just starting yesterday. like roland mentioned you know we just can't get the water haulers to service our wells and all our tanks are filling up for the water and and uh you know a little bit of downtime with the midstream treating plants also uh not really freezing problems per se at the wells but just kind of those two things i mentioned is what's starting to get us really just starting yesterday so kind of probably through the remainder of this week till we get kind of some above freezing temperatures you know i think we'll have is where we'll see the effects

So like Roland said, I think our prices will be a little higher. I don't think we'll have a huge impact from shut-ins. I think, you know, we don't give any guidance, but if anything, it should lean towards the positive.

And keep in mind, Derek, in a normal quarter, we'll always have anywhere from 3% to 5%, you know, shut-in around our completion activity. So that's, you know, what's abnormal is when we go to 7% or 6%. We'll have to see how the first quarter ultimately shakes out. But, you know, there could be more pluses than minuses from the storm as far as overall profit to the company. We'll know more, I guess, in a week or two to really sum up the impact. But right now we think that we might overall could be a very positive impact on the first quarter.

You know, we'd like to get back to norm, but, you know, 2020, you had COVID. That wasn't norm. Then you have all the storms. That wasn't norm. You had, you know, we had this weather come in for 2021, so that's not norm. So I guess we should just start to live with that outside the norm. But these numbers in 2020, even though, again, it was like we said, it's a whipsaw year, but they were really good numbers. And 2022, starting out like this with weather issues, where we are with this demand and the performance of the field people, I think you'll be pleased with the results that hopefully we can show you.

And I think that this week highlights what's unique about Comstock. One, we're in the Gulf region, so we were really able to take advantage of some of these really super premium prices. And two, we don't have huge midstream commitments, and we have a lot of flexibility in our marketing. And so we were able to move gas to some really great premium opportunities. And, you know, I think our marketing group is working overtime, you know, during this, you know, spotting these opportunities. It's really started showing up last Thursday, you know, and it'll probably continue through this week. But that's the unique thing about Comstock is the flexibility we have in marketing, the strength, I think. And then we have the strength, like we showed in October – you know, to pull that gas off the market and not have to sell it at a very low price. So I think that's a strength in both sides.

Well, and again, we've mentioned earlier this LNG. I mean, LNG pulled back from 11.2 Bs to about 6 or 7 Bs because, you know, the governor, the Texas governor called Freeport and Corpus Christi and said, we need that gas to keep these homes warm. So even with LNG pulling back, export to Mexico pulling back, you know, two or three Bs, I mean, you still see where, you know, where the challenge is of this meeting this demand. So we're in the right area. We're a couple hundred miles from this corridor where you need to be. That's where these transportation costs are a lot cheaper than if you're in Appalachia. They're probably $1, $1.50 cheaper in certain areas. And we have pipelines available that if you do need more gas, you know, we can really supply it if we really do need it in the long run, period.

Well, guys, thanks for the very comprehensive response to that question. It's my follow-up, perhaps for Jay, in light of the more constructive gas backdrop that we're seeing and your success in adding acreage during the quarter. Could you comment on the current state of the AMD market?

Yeah, you know, we think in We still think you're going to have consolidation. I think that, you know, Wall Street should not allow material production growth. I mean, kind of like Devin announced today, they've got a variable dividend. They're the first company to give a variable dividend. I think all these companies, their leverage ratio needs to be down. Their bank bonds need to be down. We think that the new norm is consolidation. Of course, cleaner energy, and I think that's why Jerry Jones invested his big and plus in the Comstock, because we do have the cleanest fossil fuel. I mean, we can clean it up more, and we're going to do that. I think that bigger is better if you keep your quality and if you keep your costs down. Most of these deals, as you know, they were done with stock and at assumption of debt, except maybe the Chevron deal with EQT, and I think that was a blend of stuff. But if you're looking into Permian, I think the challenge in the Hainesville is you've got a lot of private equity-backed companies, so you don't have really a numeral denomination as far as value, and you do on publicly traded companies. So I think there'll still be a push. I think some of these companies will come a little more gassier because they probably should, and I think we're kind of in that sweet spot there that that if we came off a big $2.2 billion transaction with Covey, and it was tier one the whole way. And like Roland said, we were one of the very few companies, it's pretty thin air, we don't have any impairments. You got $1.99 gas price and you got a really low oil price, you don't have any impairments. And then we had all these adjustments for reserves for successful operations this year. If you can continue to do that, then I think you should see an active M&A market. But we expect it. We expect the Hainesville to get fewer in number as far as companies this year and in all other basins. But we try to – it's your money. It's your company. And we try to not just grow for the sake of growing. You have to grow – not to make a lateral movement, to make a forward important movement. And you have to decrease your leverage when you do it. So that's the market we're in. And that's what we see for the future. You know, we've got 18 or 19 banks that have got us. We probably have a dozen research analysts that follow us. We're thankful for that. We added more in 2020. We've been in the bond market, as Roland said, two times for this last year, 500 million in June and, uh, $300 million in August, so we've got very good allies there, and they tell us the truth on what we need to be doing or not. So I think we're going to have access to the things we need if the opportunities are there, particularly with the backing of the Jones family and smart money and a smart business with a smart product. So that's where we are. It's just a little bit of rambling, but you have to ramble in the world of the public, as you know.

Very helpful, guys. Thanks for your time.

Thanks, Eric. Thank you. Our next question comes from the line of Doug McIntosh from Johnson Rice. Your question, please.

Good morning, Jay. Morning. Maybe for Dan, but on the 21 guide, you know, you've got capex and activity down a little bit and production kind of modestly up despite, you know, call it five less turning lines. I appreciate the increased efficiency you're seeing on the drilling side, but what are some of the things that you are seeing that give you confidence in hitting that production number despite fewer turning lines? I mean, is it going to be targeting some higher return areas, or is it more driven on the shift back to higher-intensity completions? Any color there would be helpful.

Yeah, let Dan answer that, and I'll clean up if I need it. Okay, Doug?

Here you go. So we're really encouraged by what we've seen on the drilling side. You know, it's been pretty sustained. We see it getting better. Actually, going forward, we are going to try to get longer in our laterals, which are going to give us better returns. I'd say the activity, as far as where the whales are going to be, are still a pretty good spread across all of our acreage. You know, we mentioned in here we have gone back to the larger frack jobs. We did, you know, and I think it was still, you know, the right call to go and, Try the lower frack jobs. We were in a really low gas price of environment, and, you know, we got some production history on them. They didn't look terrible, but, you know, we looked like across the board. And this was really kind of the East Texas, far kind of North Caddo areas. We maybe 0.2 VCF per thousand kind of we saw, you know, short for the smaller jobs. we've never really changed our job size over in the better areas of like Grand Cane, Logan Sport, and Elm Grove. So I would say a little better performance from going back to the larger freight jobs, getting longer, and basically drilling faster, getting cheaper.

Yeah, Dan, and I think the biggest factor toward the more efficient 2021 plan from when we were when we even looked at it in the third quarter, is the drilling time. That's been the little bit of – so basically wells are coming on quicker, and so it's just a more – the capital you're spending is generating production a little bit faster because of these really good drilling times that the operations groups achieve. And you might maybe give some examples.

Well, you know, and that's one reason we try to break out. We take you along this journey with us because it's, again, your time and money. On 18, 19, and 20, we might be the only company that has gone that micro with, you know, kind of a shovel there to go into what we look like with greater than 8,000 foot lateral, shorter than 6,000 foot, and between six and eight. And what we've been able to do is Dan, you know, kind of Sunday, Monday, Tuesday, I mean, he'll snap his fingers. He said, you know, we used to drill those 4,500 foot wells pretty quick, and now we drill those 10,000 foot laterals. He'll snap his fingers pretty quick and predictable. If you look right now, we're at 12,000, 13,000 foot. And quite frankly, you know, we don't want to get people too excited. But the longer these laterals are, you know, we can get them 13,000, 14,000, 15,000 feet. These economics really, really are favorable. And we've, again, I don't think there's any company. You put everybody together, all 204 of us together. No company has drilled or completed more extended lateral hands-completed things with buzzer wells than we have. So Dan may give a little peep.

Give a few examples, Dan, of how much the drilling time has changed on the long lateral.

Well, I mean, like on average, so we, you know, a 10K lateral before, let's just say you, Spud rig release, you were at 28 to 30 days. I mean, you know, if you get those down to 22, 23 days, you apply that across five rigs across an entire year, you know, you're turning a lot more wells to sales. That's a lot more frack jobs. It's more cement jobs. It's more strings of casing that you're buying. So, you know, your budget goes up, right? I mean, with the same, you know, number of rigs, you're actually spending a lot more money. So it allows us to dial it back, drop a rig, you know, basically get the same results with less rigs.

Right. The production comes on earlier, and you use less equipment to get the same type of results. So I think that's a little bit of what you see in the outlook, you know, for 21 versus really three months ago.

Well, as you go over, we used to drill those 4,500-foot ladders. We drill 500 feet a day. If you look at the wells we drilled in the last three or four months, We've gone from anywhere from 6,000 feet a day, which is a novelty, to 2,000 or 3,000 feet a day, which is kind of the norm right now. So that is the difference. And, you know, we use a couple thousand feet a day. We're getting a little more than that on some of these, but, you know, we'll have a hiccup or two. So that is really the answer, and we're comfortable enough to start kind of advertising that on the low side. So hopefully we can meet this.

All right, great. Thank you for all that color. And then just for a quick follow-up, one of your bigger competitors recently coming out of bankruptcy in the basin. If you could just remind us kind of how much exposure you all have to them from a non-op perspective, and I'd have to imagine you've been in conversations with those guys, and how good of a field do you have for kind of what they have planned for this year and what that could mean for you all?

Yeah, they spun out the 50,000 acres to the south, and Williams owns that. And Williams is trying to do something with that as that's public as part of the bankruptcy. And then, you know, 85% of Chesapeake, their budget's in gas. Some of it's in the Marcello. Some of it's in the Ainswell. I think they're going to keep two or three rigs busy. We know them really well. We're glad that they came out as aggressive as they did, as clean as they did. getting rid of that $7 or $8 billion of debt and will make the sector look good now. But I don't think they're going to drill too many wells to upset the balance of supply. I think their board will take care of them.

No, Don, and your question was, you know, we don't have a lot of exposure to Chesapeake-operated projects, and actually they're about a rig, so they're running, you know, What they're talking to the investors about is not very different than what they were doing while they were bankrupt. So their activity level is not that materially different in the Hainesville. But we don't have a lot of exposure to their operated projects.

In fact, the last wells that we had exposure to, we bought that acreage and renegotiated the firm and drilled several wells. So it's all positive, but we don't have – Our exposure and our numbers to them is minuscule.

Okay. Thank you for that.

Thank you. Our next question comes from the line of Neil Deenman from Spiti Securities. Your question, please.

Morning. I have a question for you, Dan. I'm looking at that slide, and Derek kind of touched on this a little bit. On slide 15 just shows the massive footprint. Can you give an idea just on cadence? I know you were talking about it. I guess what I want to try to be clear, Dan, was talking about, maybe some of the larger jobs. I'm just trying to get a sense of, you know, with the five rigs running this year, maybe geographically where and kind of what size or what type of wells you're going after.

Well, I think that overall, a large percentage of wells are going to be the long laterals, probably 80% or so. 75% to 80% of our budget will be, just like it has been the last couple of years, will be for laterals over 8,000 feet. And I think the overall averages are probably going to go up because of these extra long lateral wells that we're doing, you know, 12,000, 13,000 feet. But we still plan to drill wells across our footprint and not concentrate in one part of our large footprint in the Hainesville.

And, you know, something I would add is you've got to be careful. you know, to really just focus on one area because, you know, we have to look at our midstream capacities and where we can get rid of the gas also. So sometimes you can't bring on a real high peak volume of gas in one specific area because, you know, the midstream can't handle that all at one time.

Plus we like to try to minimize that shut-in time for offset frac. So if we always drill wells at our very best area, we'd never be able to produce our best wells. And so – Part of the whole drilling plan is also looking at how do we optimize overall production from the different areas, looking at midstream, looking at shut-ins. So you try to blend all these things together to create the best program for the dollars we want to spend. And I think that's kind of what we have in store for 21.

I think that goes back to the quality inventory. You know, we tiered all tier one, two, three, four, five. I mean, it depends upon what the price is, what the midstream looks like, et cetera, et cetera, the cost, the depth. But we have, you know, the last three or four years, I mean, we drilled all parts of our inventory, and you can see what the numbers look like. It is not just leaning on tier one, tier one, tier one, tier one plus. The numbers we give you, it's a pure blend of, of our total footprint from north, south, east, west. That's very important, and our PDP component shows that.

Now, in the last several years, we've had some joint ventures where we were earning acreage based on drilling, and we also did a special kind of program with our majority stockholder. These were in Caddo Parish area, and some of that was some of our more northern acreage. At one time, it was very extensional to the play. But most of that's all been fully developed now, and so we were drilling there, you know, to finish that up. Now, we typically didn't have high working interest in those projects, but all those projects have been finished. And so I think once you look ahead, you see us more just having free reign to go anywhere in our footprint, and everything we're doing is probably a fairly high working interest. that's a little bit of a change overall from maybe if you just look at our historical deal, I think it will be positive from the standpoint of higher ownership overall in each well we drill because we've finished those joint venture opportunities.

And we'll drop our rig count like we said.

Right. And that's part of the reason why I can have a little bit lower rig count because we're not drilling low interest wells with one of those rigs like we might have been in the past to kind of finish up our our joint ventures for our partners.

You know, we think we've got a good hedge book starting for 2021. You know, that's 65%. And like Roland said, we'll be in the 55% to 70% range in hedges other than swaps or callers. And 2022 is our goal.

No, great detail, Jay and Roland. Dan, I appreciate that. One follow-up. I like how you guys are being, you know, I guess my question is, you know, with the five rigs plus, And, you know, you definitely show the great returns that you have. Jay, you were rolling maybe talk about what I appreciate is, you know, versus some folks that are trying to go out for free cash flow that just immediately try to drop all rigs and generate the near-term free cash flow, which you know they can. I think you all seem to have a much more sustainable type plan. I'm just wondering, as you mapped out the plan for this year with five rigs, could you discuss that a little bit, how you arrived at that and

You know what we did in 2020, again, it was a strange year. I mean, we came off a huge acquisition in 19. 2020 was a very disruptive year for everybody. I mean, we go two, two and a half months without a frat crew working, and, you know, we drop our rig count from seven, six, five, four. Even with that, you know, we ended up with a really good year. I think 2021 is a settling year. Some of the JVs that we had, they're gone now. The longer laterals, you know, we've become more and more and more comfortable with that. That's why we break that out on page 18, 19, 20. I think the marketing group has done a good job. So you're going to see some increased production in 21 only because it's kind of a catch-up from what we did at the latter part of 20. And then I think when you roll into 22, you know, you'll see that 3% to 5% growth. But since our costs are low, that's why we're able to have this 200-plus million of free cash flow. Like Roland said, we have more undedicated gas in Angel than any other company. We market about two Bs a day. We sell, you know, 1.2, 1.3, plus 1.4 on our own. So I think all of those things combined, all those things combined give us this 2021, I mean, really good solid fuel where you see a lot of these companies, they've If you keep your budget flat, usually your production goes down. If you increase it a little bit, your production may stay flat. The one great thing we have, we can keep this, you know, $510 million plus with these ducks that we have kind of rolling over. We can have really good production growth in 21. We'll have great free cash flow in 21, and we'll carry over that in 2022, and it's it just, you can see it works, but it's an anomaly in the whole world of energy.

Yeah, I think like Jay said that, you know, and we did, it was kind of a, we were going from a high growth company in 2019, you know, with after the Covey Park acquisition, you had the low prices of 20, you know, we reacted, pulled the rigs way back, and then searching for that level of sustainability like you asked, I think that did take us a little time to think through and and I think really adapt to the new drilling times. And so I think we looked ahead, looking ahead, we, we, we do kind of look at a sustainable kind of free cashflow number, which we can continue to grow on, grow from, but that five rigs kind of cemented in to kind of providing that kind of longer term growth. So we, we, we, we catch up here in the first quarter, you know, with catching up the ducks from last year and, uh, And then we decided, hey, you know, the five rigs is a sustainable program that can go into 22 and go into the future, create kind of what we're really looking for, which is we do want to focus on free cash flow and then have modest growth of production. But we wanted to do it from a position of strength, so we had to get back to our full strength after, you know, really playing defense in 20. So I think that we're really pleased with where the outlook is now, and we certainly don't. Even with higher prices, we just look at that as an opportunity to get caught up really quick on the balance sheet. That's the major goal of the company. And we wanted to put the production level at a level that's sustainable, but also at a proper level for the leverage we have. And we've accomplished that in the first quarter, and then we can kind of sustain, and then we're really focused on free cash flow in the future. And And I think we have all the tools to do it.

You know, one thing that's different in 2021, I would say that we've kind of digested Covey in 2020, even with COVID. So I think our model is a lot better. You know, I think David Terry has done a really good job working with Ron, working with Dan and Patrick Magoo and others to get our model. You know, what does our model look like? What are the drilling costs? Where are all the sticks? You know, where's our almost 2,000 sticks on the map? Which ones will we drill? You give them the marketing group and say, you know, can we sell our product there? Our model is so much better now than it was even in third quarter. That's why we're so positive in our tone, in our numbers, about how far we've taken this company in a short time. But the model is so important. And again, I'll really give Ron the credit on that because he's accountable for really the model and the numbers to the analyst.

Very good. Great details. Thank you all. Thank you. Our next question comes from the line of Leo Mariani from KeyBank. Your question, please.

Just one quick question for me, and perhaps this is, you know, for Ron potentially, just a question on the guidance. What can you tell us about kind of the cadence for CapEx in production, just thinking on kind of a quarterly basis here in 21.

Ron, you got a shout out.

Yeah. Leo, we only really provide the annual guidance for just the typical guidance. I would tell you that with the carryover for some of those ducks that were mentioned earlier in the call. The first quarter is going to be the highest spending level. The fourth quarter is going to be the lowest, and then the second and third quarters will be somewhat in between. And then, you know, in terms of the cadence on the production side, we'll see if you know, pretty steady growth over the first three quarters, and then that flattening out a little bit in the fourth quarter, given the current status or schedule of completion cadence in the fourth quarter.

Okay, that's great color. Very helpful. It's all for me. Thanks.

Thanks, my guys. Thank you. Our next question comes from the line of Uman Chaudhry from Goldman Sachs. Your question, please.

Hi, good morning, and thank you for squeezing me in. I have a quick question. Gas futures have improved. Wanted to get your thoughts on what you're seeing from non-operated partners with respect to activity levels. And also, I guess I wonder what price point would you actually consider adding activity say if the gas prices keep improving here?

Yeah, good question. We're probably not a good one to ask about non-operative partners because that's just such a small part of the company. We just don't have a lot of exposure. We have a little bit to some of the private companies in the Haynesville, a little bit to Chesapeake, but we see their activity level being fairly similar to where they've been. As far as, you know, we really aren't looking to use the extra revenues that probably come in for these improved prices because we like the growth profile we have in place now. And so we would just use that to accelerate our delevering because that's our major goal.

Again, 91% of what we have we operate. If we don't operate any of the Balkan, that would be the biggest part if we don't operate.

Right. We don't operate. And DeBaca has become a very small part of the company. It's, you know, 2% of the company. So it's not that significant to us. But overall, yeah, we will use the, you know, hopefully the higher prices, you know, to just achieve our goal of getting under two times leverage faster because that's really the major goal the company has. Everything else is how do you get there. And we think that we've got the right production profile that fits the company well. And so now it's really like, you know, The leverage is not where we want it to be. In the next two years, our goal is to really come back and be able to tell you at the end of two years that we have the balance sheet that we want and the cost of capital now reflects that and we'll consider that a big success.

Well, like the analysts say, we're a low-cost producer, high margins. We've got impeccable inventory. The weakness that we have is our cost of capital, so we We did incur a debt, although we added equity and delevered with a copy. We added expensive bonds. That's mainly the high-cost capital. So we've got to deal with that in the future. But I think we can do that internally the next year or so.

That makes sense. Thank you so much for the follow-up. Thank you. Good questions.

Thank you. Our next question comes from the line of Noel Parks for Brothers. Your question, please. Hey, good morning.

Hey, though. Morning.

Sorry if you touched on this already, but the amount you spent for new acreage leasing in fourth quarter, I think it was about $6.5 million. Was that just bolt-on acreage you had your eye on for a while?

Yeah, you know, we're opportunistic all the time. If we can add a handful of acres that we think will either lengthen our laterals or give us good drilling performance, locations in the future. I mean, we're always optimistic on that. We always have been.

Yeah, we've given that, and we think there's not a lot of competition for that type, and so we've really been working that hard and have a lot of looking across the whole landscape of the prospective Hainesville and trying to find any kind of open leases and go after them. So that's something we've allocated some dollars to do in 21 also.

Great. And you talked a good bit about the gas environment and already have an eye to hedging in 2022. And as I've just looked at the futures curve, I'm just wondering, do you think 2022 is still relatively low considering the demand profile? I'm kind of wondering if we – We have another leg up, you think, in the trade. We think we have a bunch of things up.

Yeah, we think definitely. And we think that 22 – I mean, and it's not a – it's a problem that we've had for a long time. The longer-term curve just reflects a lot of the illiquidity of the natural gas futures contract. And so people talk about, oh, why don't you hedge out five years? Well, they're just – you know, if you're a large producer, it's hard to do. You take a – and so that's why our 12 to 18 months kind of cycle is our hedging cycle. And we do think 22 is not priced right, in our opinion. But, you know, we're mainly going to be able to hedge, though we're pretty attractively using collars more in 22 so we can have some of the exposure to the upside that probably shows up. I mean, the gas market, in our opinion, is going to be pretty tight this summer. You know, and I think the people have been, you know, non-believers in gas and really torture gas with the warm winter, but I think they could end up with a pretty big, you know, very tight market is what everybody's telling us for this summer.

I mean, we think the 2022 has got as many legs as it should have been going upwards. I mean, we definitely think it's positive, not negative.

Great. And, you know, one thing I noticed in the reserves, I noticed you had – almost 350Bs of positives performance revision. Can you just talk about those?

Yeah, we're pretty proud of that. And I think in a year when you're using a low price, typically you're fighting that. But these wells have such a low cost structure that we didn't really suffer from having a bunch of non-economic reserves. We always lose a little bit of reserves from using a very low price in the tail. But overall, I think we've been very conservative in our reserve bookings for undeveloped wells. And I think as they're booked fairly conservatively, and then as they're drilled, we obviously have additions there at a higher number than they were booked at. Plus, we actually had overall positive revisions on our PDP and all our reserves from the performance of the wells. So I think it points to the good job operations do. But it's also, I think, that it's a testimony to, you know, we are very conservative in preparing those numbers. And so they're conservatively booked. So when they actually become real wells, they typically have a, you know, there's an upside to them once they are really drilled. And I think that goes back historically, and we haven't had negative performance revisions in a long, long time. I think that's a testimony to the quality of the properties and the conservative bookings that they were booked at.

You know what? That's a great question, too, because most people don't see that. They never ask that question. It's a great question. They have 367 BCFE of performance revisions added in a terrible year for pricing issues. So that's, again, that's a good marker that we're solid on that.

And just to give you some perspective, so sort of what vintage of bookings worthy that you're seeing the performance revision? Is it sort of stuff from, you know, four or five years ago where the tail decline isn't as steep as you thought, or is it just outperformance of more recent wells?

Well, I think it's the overall Hainesville well, and it's also the fact that it's hard to see in the numbers, but generally, you know, what's happened to our inventory is that we've turned, you know, short laterals into long laterals, and, you know, they've become more economic, and there's been a lot of remapping of the inventory, you know, and we had, I think we had just closed Covey Park, so there was a little bit of integration to kind of really get all that done, and probably didn't have that optimized at the end of 2019 in our reserves. You know, we probably had a, and I think as we were able to work through and, uh, redraw the laterals and et cetera, you know, and, and the performance of the wells overall in the, in the lower, uh, in the lower development costs that they now have compared to what we expected in 2019, a lot of positive factors kind of contributed to that, to that. But, uh, but, um, including just the actual wells, their actual performance was better than what they were in the reserve report for. So I think all those together is another good year of positive revisions, which we had last year also.

Terrific. Thanks a lot.

Thank you.

Thank you. Our next question comes from the line of Cassia Harrison from Simmons Energy. Your question, please.

Good morning, all. Thanks for taking my question. I'll keep it simple. Just one quick one for me. Can you discuss what proportion of gas in a quarter would typically be sold on bid week versus spot market? Thank you.

Yeah, good question. I mean, typically we target to have just about 75% to 80% to sell the index basis because that's kind of how our you know, the index prices match up well with our hedging program, right? The spot prices might not because of this. But we can't go to – we don't want to go to a much higher percentage because we have a lot of new wells coming on, and there's, you know, production issues can come and go, so we don't want to ever be caught having to buy gas to fill a, you know, something we can't deliver on. So that's our basic rule. Now, I think there's sometimes when we just say, you know, they just set that – I think we probably went lighter on selling in the index market for the first quarter so far. And we were more, I think we were more at, what was our exact number? Dan, do you have it there? I think we were more 35% in the spot market for right now. Yeah, 35% to 40% actually for the month of February. And that was a little bit lighter than the month of – January. So we're a little bit more in the spot market than normal. A lot of it, though, we do have a big ramp up in production going on in the first quarter. So that's part of that. You want to be conservative as you're bringing on a lot of wells because you don't have the exact timing. But I think that's paid off pretty well in both January and February because prices have been moving up and And then, obviously, this week is like hitting the jackpot. It's some of these incredible prices. I mean, frankly, we were able to get super premium prices for a material amount of production anywhere from $15 an MCF to maybe some even at $179 an MCF. So those are the spot prices that are out there.

But to answer your question, I mean, 70% to 80%, that's kind of the norm. That's the norm.

That's where we like to be, yeah.

The 40 that we might be in February is a little unusual. Yeah. All right, that's it for me. Thank you, and looking forward to seeing those realizations when you're in 51 earnings.

Yeah, we're interested to see how it all shakes out in the end, too. Good question.

Thank you. Our next question comes in the line of Phillips Johnson from Capital One. Your question, please.

Hey, guys. Thanks. Just one for me as well. It's really just a follow-up to Roland's comments on the leverage ratio target. It looks like you guys will probably hit that sub-two times target probably by mid-22 or so if the strip holds. Jay, you mentioned Devin paying variable dividends. I'm wondering if you could address the board's preferred method of returning the cash to return cash to shareholders once you sort of achieve that leverage ratio goal?

Well, you know, as you well know, I mean, at the end of probably 2014, we were a dividend issuing company. I think we issued 12.5 cents per quarter. So, we did that. And, of course, I mean, the wheels fell off the sector in the first quarter of 2015. So, Our goal, every company should have a goal of being in a position to have giving a dividend, period. I don't, you know, I don't think we have enough shares to be buying shares back. So, you know, we don't see doing that at all. We need to get more shares and float. I think we've got great inventory. We need to get the stock price performing and we need to be, you know, you asking how come the dividend is not high enough question. So that's our goal. We want to be in a position to be able to give a dividend, period.

But we'll address the leverage first because you want to have the right balance sheet.

We have to do that. Hopefully we can do that in 21 and 22.

Yeah, no, I agree 100%. Is there anything about variable dividends that you see as maybe being a drawback?

No. I think once you've got the size of a company that you need and you've got the inventory, I mean, You know, Devin just did a big acquisition, a consolidation. I mean, they've got the bulk. They've got the market cap. They've got low cost of capital. They've got inventory. I mean, you know, we don't have any, but right now, you know, we don't have any issues as far as where our acreage is located to get drilling permits, you know, that are material at all. So our acreage is well positioned in good areas. So they're not kind of politically charged issues around them. I think that's good. But, no, I think, you know, Pioneer came out with a variable concept and Devin issued one. I think that's the new business plan. I mean, you've got to – that goes back to the question of M&A. Do you need M&A? I think you do. You have to have bigger. You have to be more predictable. You can't rely upon capital from Wall Street to feed a company that's not making any money. You have to have free cash flow. I mean, all those things I believe we're going to give you and are giving you. And kind of at the end of that funnel is you need to have a company that can give a dividend. Period. That's just another sign that you're healthy.

And we'll be able to, since we're going to work on our balance sheet, like you said, for this year, next year, we'll be able to see how the variable versus fixed dividend, you know, kind of work with our other peers. And so we'll be able to kind of look to see if the market –

method they like better and and so we'll study that to make a real decision on the structure but the first the first job number one is getting the balance sheet to where everybody's very comfortable saying yeah you should be paying a dividend and so we're focused on job one absolutely we've always said that we've got to get our cost capital lower we've got to get our leverage down you know you'd love to to be in the one time i mean we're 3.8 we want to be in the two five low twos uh by the end of 21 and then lower in 22. But then I think you have to have something in your scope around the corner, and that is you want to be able to have the flexibility, you know, to have what kind of hedges we need or don't need, and the leverage needs to be down. Leverage will get you in trouble. You know, time is on your side. We've got long-term bonds. That's favorable. Our leverage is too high. Our cost of capital is too high.

Yeah. I agree with all those comments. Thanks, guys.

Thank you. Yes, sir. Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to Jay Allison for any further remarks.

All right, Jonathan. I just have one closing remark, and it's kind of a housecleaning item. We received a notice from the New York Stock Exchange this week thanking us for 25 years of listing partnership with ILMA. They attached a customized listed emblem highlighting Comstock's milestone. So, you know, it's kind of thin air to be an NYSE company for 25 years. I mean, even for some of the most recognized, largest companies in the world. But we are there. You know, if you have time to go to the Comstock website to see the emblem, please do. Or, you know, if you want to turn to page 22 in our corporate presentation day, you can see it. But, again, I want to thank you for trusting us with your time and with your money, and we want to close every day as a stronger company if we can. So great questions, great support. Stay warm, everybody.

Thank you, ladies and gentlemen, for your participation in today's conference. This does include the program. You may now disconnect. Good day.