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 one 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. Hi, 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. Today, if you looked out our windows, you would think that we were in snowy Alaska or reporting from the ski slopes in Colorado. In fact, Alaska's probably warmer than the recent subzero temperatures that we've seen here with the wind chill factor. Our offices have been closed for three days now, and only probably four of us are here today reporting from the office. This arctic freeze in Texas and the mid-continent creates challenging days in the world of natural gas. We've experienced idle frac 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 Haynesville/Bossier 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, and 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. We completed an agreed of $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 - $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 Haynesville/Bossier shale drilling program. We drilled 55 or 46.1 net successful wells that we operate. We turned 54 or 40.9 net operated wells to sales with an average IP rate of 25 million cu f t 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 foot in 2020 versus $1,215 in the prior year. This allowed us to grow our proved reserve base by 3% at a low-end finding cost of $0.66 per Mcfe. Despite having to use very low prices to determine our SEC proved 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. 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%. This is mainly due to actions we took in October to shut in 300 million a day of our operator production in response to very low natural gas spot prices. We turned 22 or 16.4 net Haynesville wells to sales with an average lateral length of 8,899 ft in 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 EBITDAX came in at $211 million, and we generated $155 million, or $0.56 per share in operating cash flow. Our adjusted net income for the quarter was $35 million, or $0.14 per share. Lastly, we ended the year with very strong financial liquidity of $930 million. 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 bbl of oil. This is 11% lower than production from the fourth quarter 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 bbl. Our realized gas price averaged $2.40 per Mcf, including hedging gains. 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. We reported a net profit of $77.5 million for the fourth quarter, or $0.30 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 $0.14 per diluted share for the quarter. On slide six, we summarize the financial results for all of 2020. Our production for 2020 totaled 460 Bcfe, which that includes 1.5 million bbl 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, unusual, 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. During 2020, we had 51% of our gas volumes hedged, which increased our realized gas price to the $2.07 per 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 bbl versus the $32.30 per bbl 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 cu f t 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%-70% of our production hedged for the upcoming 12–18-month period. Slide eight, we recap how much of our production was shut in during the last quarter, the fourth quarter. We had 6.6% of our natural gas production shut in the fourth quarter compared to the 7.2% we had in the third quarter. As we had talked about in 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 the fourth quarter is really due to offset frac activity. We also had 2% of our oil production curtailed or shut 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 cost for Mcfe averaged $0.56 in the fourth quarter as compared to the third quarter of $0.55. Gathering costs were $0.26, our taxes averaged $0.09, and our field level cost averaged $0.21. The fluctuation between our lifting cost and gathering cost 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 cost to return to a more normalized level of $0.05-$0.06 going forward. On slide 11, we detail the DD&A, the depreciation, depletion, and amortization per Mcfe produced. Our DD&A averaged $0.94 in the fourth quarter, about $0.01 lower than the $0.95 rate we had in the third quarter. 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, 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 9.75% 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 million was spent on the operated Haynesville Shale properties. We also spent $6.5 million to lease new Haynesville 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 Haynesville Shale properties. We drilled 46.1 net operated horizontal Haynesville wells, and we turned 40.9 net operated horizontal Haynesville wells to sales in 2020. We also spent another $82 million in 2020 on non-operated wells and other development activity. We spent a total of $7.9 million in 2020 on leasing new Haynesville acreage. Right now we're currently utilizing 6 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 gonna go over with his operating results. Based on our current operating plan for 2021, we expect to drill 51 net operated Haynesville 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 DUCs 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-$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 proved 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 proved reserves, and we had 367 Bcfe of positive performance-related revisions driven by the strong well performance of our Haynesville wells. The positive 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 $0.75 per Mcfe, or $0.66 if you exclude the price-related revisions. Our reserves were 99% natural gas and then 36% of our reserves were developed. 95% of our proved reserves are in the Haynesville/Bossier, 2% are in the Bakken, and 3% are in other regions. The PV-10 value of our proved reserves was $2 billion, using the SEC prices of $1.99 for gas and $39.57 for oil, and 67% 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 PV-10 value of our proved reserves increases to $4.4 billion. The quantities of proved reserves with those prices would increase to 5.8 Tcfe using that $2.75 and $50 reference prices. In addition to those proved reserves, we have an additional 2.4 Bcfe of proved undeveloped reserves, which are not included in our proved 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 2 P or probable reserves and 6.8 Tcfe of 3 P 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 gonna 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 cu f t 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 DUCs on our schedule. We anticipate our DUC count staying in the 20-25 range for the remainder of the year. Overall, slide 16, this is our latest Haynesville/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 were mostly located on our East Texas and Southwest DeSoto Parish acreage, and we did have one well completed over in our Elm Grove acreage. The wells were tested at rates ranging from 18 million a day up to 33 million a day with a 24 million cu f t per day average IP rate. The wells were drilled with lateral lengths ranging from 6,751 ft up to 12,716 ft with an average lateral length of 9,288 ft, and they were all completed with 3,500 pounds per ft sand loadings on the fracs. We drilled and completed our longest lateral ever during the fourth quarter at 12,716 ft on the Jordan 1694 number 1 well, which is down in the southwest DeSoto Parish acreage. We are currently completing a 13,000+ ft 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 length buckets. Here on slide 18 shows the D&C cost trend for our long lateral wells, which are our wells that have lengths greater than 8,000 ft. On our long lateral wells in the fourth quarter, we experienced a 5% increase in our total D&C cost due to a 15% increase in our completion cost. This was primarily due to the resumption of pumping our larger frac design of 3,500 pounds per ft in the fourth quarter after pumping our smaller frac design of 2,800 pounds per ft 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 to 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 D&C costs relatively flat in this 1,000 ft-1,050 ft 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 D&C cost for our medium lateral wells. These are wells with lengths between 6,000 and 8,000 ft long. On our medium lateral wells in the fourth quarter, we had a total D&C cost of $1,126 a ft. This represents a slight decrease of 3% from the previous quarter. While our completion cost also increased for our medium-length laterals due to resuming the larger frac design in the fourth quarter, we were able to still achieve a lower D&C cost in the fourth quarter by driving our drilling costs down by 10% with our increased drilling efficiencies. Same as our long lateral 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, this is the D&C cost trend for our short lateral wells. These are the wells that have lateral lengths less than 6,000 ft. 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 cost 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 D&C 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, Ron, 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. Our inventory, as Dan had mentioned, 1,953 net Haynesville/Bossier drilling locations provide us with decades of drilling inventory. Our operating plan for the year is expected to provide production growth and generate in 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. 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 Haynesville drilling program generates some of the higher drilling returns in North America. 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. With that, I want to turn it over to Ron. He can provide some specific guidance for the rest of the year. 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 million-$550 million. 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 Bcf-1.425 Bcf per day. Our lease operating cost is expected to average $0.21 per Mcfe -$0.25 per Mcfe in 2021. Our gathering and transportation costs are expected to average $0.23 per Mcfe-$0.27 per Mcfe. Production and severance taxes expected to remain in the $0.08 per Mcfe -$0.10 per Mcfe range. Our DD&A rate is expected to average $0.90 per Mcfe -$1.00 per Mcfe. As mentioned earlier, we believe our cash G&A rate is expected to return to the more normal $0.05 per Mcfe -$0.07 per Mcfe range. We will 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 one 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 to the line of Derrick Whitfield from Stifel. Your question please. Thanks, 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 did you envision that shut-in metric trending based on your 2021 outlook? Yeah, that's a great question, Derrick. some of the shut-ins, obviously, for the fourth quarter, were voluntary. We didn't want to accept really low spot prices. some of our gas that wasn't nominated, that's in our swing gas, we decided to shut in in the first part of October. I think as you go into 2021, we haven't had those type of issues. We've had very good spot prices so far all throughout 2021. then obviously, with all the events in Texas in the last week, obviously, incredible spot prices for our swing gas. Our marketing department, with the index prices setting lower at the beginning of the month and the rising gas prices both in January and February that we've experienced, we actually exposed ourself more to the spot market than normal, and that's going to pay off, I think, handsomely in improved price realizations in the first quarter. Especially whatever gas we've been able to sell ever since last Thursday, just some phenomenal pricing opportunities, which hopefully it will probably continue through the week. Now, the negative to that is there going to be shut-in production due to the weather? Through Tuesday, we could have said no. We were at really full production all the way through Tuesday. 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. We see some shut-ins now that are close to 20% of our normal production levels. We think that's only going to be in place for a few days. It really depends on when road activity can resume. once road activity resumes, we can hopefully get back to normal production activities. Derrick, 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. Dan Harrison may want to comment on that. Again, it's our field people that did such a phenomenal job on that. As Roland mentioned, the marketing people, Alex, Whitney, et cetera, the whole group, I think they've really delivered great results. Dan, any comment? 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. We did have a substantial amount of gas that we put back on production when the frack crews was shut in for offset frack protection, and we did get that production back on from Saturday through Tuesday. We actually had a lot more gas production from Saturday through Tuesday when the prices spiked. We're kind of starting to see the effects of that really just starting yesterday. Like Roland mentioned, we just can't get the water haulers to service our wells, and all our tanks are filling up with the water. A little bit of downtime with the midstream treating plants also. 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. Kind of probably through the remainder of this week till we get kind of some above freezing temperatures, I think we'll have is where we'll see the effects. Like Roland said, I think our prices will be a little higher. I don't think it'll have a huge impact from shut-ins. I think, we don't give any guidance, but if anything, it should lean towards the positive. Keep in mind, Derrick, in a normal quarter, we'll always have anywhere from 3% to 5% shut-in to around our completion activity. What's abnormal is when we go to 7% or 6%. we'll have to see how the first quarter ultimately shakes out. 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. right now, we think that we might overall could be a very positive impact on the first quarter. We'd like to get back to norm, but 2020, you had the COVID, that wasn't norm, then you have all the storms. That wasn't norm. We had this weather coming in for 2021, so that's not norm. I guess we should just learn to live with that outside the norm. These numbers in 2020, even though, again, like we said, it's a whipsaw year, they were really good numbers. 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. Well, I think 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. 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. I think our marketing group is working overtime during this, spotting these opportunities, which really started showing up last Thursday, and it'll probably continue through this week. That's the unique thing about Comstock is the flexibility we have in marketing, the strength, I think. We have the strength, like we showed in October, to pull that gas off the market and not have to sell it at a very low price. I think that's a strength in both sides. Well, again, we've mentioned earlier this LNG. LNG pulled back from 11.2 Bs to about six or seven Bs because the governor of Texas called Freeport and Corpus Christi and said, "We need that gas to keep these homes warm." Even with LNG pulling back, the export to Mexico pulling back two or three Bs, you still see where the challenge is of this meeting this demand. 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. We have pipelines available that if you do need more gas, 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. As 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 A&D market? Yeah. We still think you're going to have consolidation. I think that Wall Street should not allow material production growth. Kind of like Devon announced today, they've got a variable dividend, and they're the first company to give a variable dividend. I think all these companies, their leverage ratio needs to be down. Their bank borrowings need to be down. We think that the new norm is, of course, cleaner energy, and I think that's why Jerry Jones invested his billion-plus into Comstock, because we do have the cleanest fossil fuel. We can clean it up more. 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. If you're looking in the Permian, I think the challenge in the Haynesville 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. I think there'll still be a push. I think some of these companies will come a little more gas here because they probably should. I think we're kind of in that sweet spot there that we came off a big $2.2 billion transaction with Covey, and it was Tier 1 the whole way. Like Roland said, we're one of the very few companies, it's pretty thin air, where you 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. 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. We expect it. We expect the Haynesville to get fewer in number as far as companies this year, and in all other basins. 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. You have to decrease your leverage when you do it. That's the market we're in, and that's what we see for the future. We've got 18 or 19 banks that help guide 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 $300 million in August. We've got very good allies there, and they tell us the truth on what we need to be doing or not. 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. It's smart money in a smart business with a smart product. 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, Derrick. Thank you. Our next question comes from the line of Dun McIntosh from Johnson Rice. Your question please. Good morning, Jay. Morning. Maybe for Dan, but on the 2021 guide, you've got CapEx and activity down a little bit and production kind of modestly up despite, call it five less turning lines. I appreciate the increase in efficiency you're seeing on the drilling side, but what are some of the things that you all are seeing that give you confidence in hitting that production number despite fewer turning lines? I mean, is it you're 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 then I'll clean up if I need it. Okay, Dun? Here you go. We're really encouraged by what we've seen on the drilling side. 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 wells are going to be, are still a pretty good spread across all of our acreage. We mentioned in here we have gone back to the larger frac jobs. We did, and I think it was still the right call to go and try the lower frac jobs. We were in a really low gas price of environment and we got some production history on them. They didn't look terrible, but we look like across the board, and this was really kind of the East Texas, far kind of North Caddo areas. We may be 0.2 Bcf per thousand, kind of we saw short for the smaller jobs. We've never really changed our job size over in the better areas of like Grand Cane, Logansport, and Elm Grove. I would say a little better performance from going back to the larger frac 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 even looked at it in the third quarter is the drilling time. Basically, wells are coming on quicker. It's just the capital you're spending is generating production a little bit faster because of these really good drilling times that the operations group's achieving. You might maybe give some examples. 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 2018, 2019, and 2020, we might be the only company that has gone that micro with kind of a shovel nose, the shovel there, to go into what we look like with greater than 8,000 ft laterals, shorter than 6,000 ft, and between six and eight. What we've been able to do is, Dan, kind of Sunday, Monday, Tuesday, I mean, he'll snap his fingers. He said, "We used to drill those 4,500 ft wells pretty quick, and now we drill those 10,000 ft laterals," he'll snap his fingers, "pretty quick and predictable." If you look right now, we're at 12,000, 13,000 ft. Quite frankly, we don't want to get people too excited, but the longer these laterals are, we can get them 13,000, 14,000, 15,000 ft. These economics really, really are favorable. We've, again, I don't think there's any company. You put everybody together, all 200 forums together, no company has drill completed more extended lateral, has completed horizontal [measure] wells than we have. Dan may give a little peep, and- Give a few examples, Dan. You got two or three examples there. Yeah. Of how much the drilling time has changed on the long laterals? Well, I mean, like on average, so a 10K lateral before, let's just say you spud the rig release, you were at 28-30 days. I mean, if you get those down to 22-23 days, you apply that across five rigs across an entire year, you're turning a lot more wells to sales. That's a lot more frac jobs. It's more cement jobs. It's more strings of casing that you're buying. Your budget goes up, right? I mean, with the same number of rigs, you're actually spending a lot more money. It allows us to dial it back, drop a rig. 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. I think that's a little bit of what you see in the outlook for 2021 versus really three months ago. Well, as you go over, we used to drill those 4,500 ft laterals. We'd drill 500 ft a day. If you look at the wells we've drilled in the last three or four months, we've gone from anywhere from 6,000 ft a day, which is a novelty, to 2,000 ft or 3,000 ft a day, which is kind of the norm right now. That is the difference. We used a couple thousand ft a day. We'll get a little more than that on some of these, but we'll have a hiccup or two. That is really the answer, and we're comfortable enough to start kind of advertising that on the low side. We hopefully can meet this. All right. Great. Thank you for all that color. Just for a quick follow-up. One of your bigger competitors we've seen coming out of bankruptcy in the basin. Just if you could just remind us kind of how much exposure you all have to them from a non-op perspective. I'd have to imagine you've been in conversations with those guys, and how good of a feel do you have for kind of what they have planned for this year- Well, you know- What that could mean for y'all? Yeah. They spun out the 50,000 acres to the south, and Williams owns that. Williams is trying to do something with that, as that's public, as part of the bankruptcy. 85% of Chesapeake, their budget's in gas. Some of it's in the Marcellus, some of it's in the Haynesville. 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. I don't think they're going to drill too many wells to upset the balance of supply. I think their board will- No, Dan, your question was that- They'll take care of them. We don't have a lot of exposure to Chesapeake operated projects. Actually, the amount of rigs that they're running, what they're talking to the investors about is not very different than what they were doing while they were bankrupt. Their activity level is not that materially different in the Haynesville. 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 farm and drilled several wells. Yes. We operated that. It's all positive. Our exposure and our numbers to them is minuscule. Okay. Thanks for that. Thank you. Our next question comes from the line of Neal Dingmann from Truist Securities. Your question, please. Morning. Jay, my question for you or Dan, I'm looking at that slide, and Derrick kind of touched on this a little bit, on slide 15, just shows the massive footprint. Could you give an idea just on Haynes? I know you were talking about 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, with the five rigs running this year, maybe geographically, where and what size or what type of wells you're going after. Well, I think that overall, a large percent of the wells are going to be the long laterals, probably 80% or so. 75%-80% of our budget, just like it has been the last couple of years, will be for laterals over 8,000 ft. I think the overall averages are probably going to go up because of these extra-long lateral wells that we're doing, 12,000, 13,000 ft. We still plan to drill wells across our footprint and not concentrate in one part of our large footprint in the Haynesville. Yeah. Neal, something I would add is you got to be careful to really just focus on one area, because we have to look at our midstream capacities and where we can get rid of the gas also. Sometimes you can't bring on a real high peak volume of gas in one specific area because the midstream can't handle that all at one time, so. Plus, we like to try to minimize that shut-in time for offset fracs. If we always drill wells at our very best area, we'd never be able to produce our best wells. 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. You try to blend all these things together to create the best program for the dollars we want to spend. I think that's what we have in store for 2021. Yeah, I think that goes back to the quality inventory. We Tier it all, Tier 1, 2, 3, 4, 5. It just depends upon what the price is, what the midstream looks like, et cetera, the cost, the depth. We have, the last three or four years, we've drilled all parts of our inventory, and you can see what the numbers look like. It is not just leaning on Tier 1, Tier 1, Tier 1, Tier 1+. The numbers we give you, it's a pure blend of our total footprint from north, south, east, west. That's very important, and our PDP component shows that. Dan, 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, and at one time it was very extensional to the play. Most of that's all been fully developed now, and so we were drilling there to finish that up. Now we typically higher ownership overall in each well we drill because we've finished those joint venture opportunities. We'll drop our rig count, like we said. Right. 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 finish up our joint ventures for our partners. We think we've got a good hedge book starting in for 2021. That's 65%, and like Roland said, we'll be in the 55%-70% range in hedges other than swaps for collars in 2022 is our goal. No, great details, Jay and Roland, Dan, appreciate that. One follow-up. I guess my question is, with the five rigs plus, and you definitely show the great returns that you have. Could Jay, you or Roland maybe talk about what I appreciate is, 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- Sure. You know what we did in 2020, again, it was a strange year. We came off a huge acquisition in 2019. 2020 was a very disruptive year for everybody. We go two and a half months without a frac crew working, and we drop our rig count from seven, six, five, four. Even with that, 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. The longer laterals, we've become 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. You're going to see some increased production in 2021, only because it's kind of a catch-up from what we did at the latter part of 2020. I think when you roll into 2022, you'll see that 3%-5% growth. Since our costs are low, that's why we're able to have this $200+ million of free cash flow. Like Roland said, we have more undedicated gas and within any other company. We market about two Bcf a day. We sell 1.2, 1.3, +1. 4 on our own. I think all of those things combined give us this 2021, really good solid feel where you see a lot of these companies, 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 $510 million plus with these DUCs that we have rolling over. We can have really good production growth in 2021. We'll have great free cash flow in 2021, and we'll carry over that in 2022. You can see it works, but it's an anomaly in the whole world of energy. Yeah, I think like Jay said that we were going from a high growth company in 2019 after the Covey Park acquisition. You had the low prices of 2020. We reacted, pulled the rigs way back. searching for that level of sustainability like you asked, I think that did take us a little time to think through and I think really adapt to the new drilling times. I think looking ahead, we do look at a sustainable free cash flow number, which we can continue to grow from, but that five rigs kind of cemented in to providing that longer term growth. We catch up here in the first quarter with catching up the DUCs from last year, and then we decided, "Hey, this five rigs is a sustainable program that can go into 2022 and go into the future," create 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 really playing defense in 2020. I think that we're really pleased with where the outlook is now, and 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. We wanted to put the production level at a level that's sustainable, but also at a proper level for the leverage we have. We've accomplished that in the first quarter, and then we can sustain, and then we're really focused on free cash flow in the future. I think we have all the tools to do it. One thing that's different in 2021, I would say that we've kind of digested Covey in 2020, even with COVID. I think our model is a lot better. I think David Terry has done a really good job working with Ron, working with Dan and Patrick McGough and others, to get our model. What does our model look like? What are the drilling costs? Where are all the sticks? Where's our almost 2,000 sticks on the map? Which ones will we drill? You give the marketing group and say, "Can we sell our product there?" Our model is so much better now than it was even in the 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. The model is so important. Again, I 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 KeyBanc. Your question, please. Hey, just one quick question from me, and perhaps this is for Ron, potentially. Just a question on the guidance. What can you tell us about the cadence for CapEx in production? I'm just thinking on a quarterly basis here in 2021. Ron, you got a shout-out. Yeah. Leo, we only really provide the annual guidance. That's the typical guidance. I would tell you that with the carryover for some of those DUCs that were mentioned earlier in the call, the first quarter's 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. In terms of the cadence on the production side, we'll see 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. That's all for me. Thanks. Thanks, Leo. Thank you. Our next question comes from the line of Umang Choudhary 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. also, I wonder what price point would you actually consider adding activity, say, if the gas prices keep improving here? Yeah, good question. Yeah, 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. We see their activity level being fairly similar to where they've been. As far as we really aren't looking to use the extra revenues that probably come in from these improved prices because we like the growth profile we have in place now. we would just use that to accelerate our de-levering, because that's our major goal. Again, 91% of what we have, we operate. we don't operate any of the Bakken. That would be the- Right. Yeah. Biggest part that we don't operate. Right. The Bakken has become a very small part of the company. It's 2% of the company, so it's not that significant to us. Overall, yeah, we will use hopefully the higher prices, 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. now it's really like 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. We did incur a debt, although we added equity and delevered with the company. We added expensive bonds. That's mainly the high cost of capital. We've got to deal with that in the future, but I think we can do that internally in the next year or so. That makes sense. Thank you so much for the color. Thank you. Good questions. Thank you. Our next question comes from the line of Noel Parks, Tuohy Brothers. Your question, please. Hey, good morning. Hey, Noel. Morning. Sorry if you touched on this already, but the amount you spent for new acreage leasing in the fourth quarter, I think it was about 6.5 million. Was that just a bolt-on acreage you've had your eye on for a while? Yeah. We're opportunistic all the time. If we can add Haynesville acres that we think will either lengthen our laterals or give us good drilling locations in the future, I mean, we're always opportunistic on that. We always have been. Yeah. 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 Haynesville and trying to find any kind of open leases and go after them. that's something we've allocated some dollars to do in 2021 also. Great. You talked a good bit about the gas environment and already have an eye to hedging in 2022. As I 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 have another leg up, you think, in the 2022 strip here. We think we have a bunch of legs up. Yeah, we think definitely, and we think that 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. People talk about, "Oh, why don't you hedge out five years?" Well, if you're a large producer, it's hard to do. that's why our 12 -1 8 months cycle is our hedging. we do think 2022 is not priced right, in our opinion. we're mainly going to be able to hedge, though, pretty attractively using collars more in 2022. We can have some of the exposure to the upside that probably shows up. The gas market, in our opinion, is going to be pretty tight this summer. I think the people have been non-believers in gas and really tortured gas with the warm winter, but I think they could end up with a pretty big, very tight market is what everybody's telling us for this summer. I mean, we think that 2022's got as many legs as a centipede going upwards. We definitely think it's positive, not negative. Great. One thing I noticed in the reserves, I noticed you had almost 350 Bs of positive performance revisions. Can you just talk about those? Yeah, we're pretty proud of that. 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. Overall, I think we've been very conservative in our reserve bookings for undeveloped wells, and I think they're booked fairly conservatively. 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. I think it points to the good job operations too, but it's also, I think, that it's a testimony too. We're very conservative in preparing those numbers, and so they're conservatively booked. When they actually become real wells, they typically have an upside to them once they are really drilled. I think that Well- If you look back historically, and we haven't had negative performance revisions in a 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, and they never ask that question. It's a great question. To have 367 Bcfp of performance revisions added in a terrible year for pricing, that's, again, that's a good marker that we're solid on that. Yeah, just to give you some perspective, so sort of what vintage of bookings were you that you're seeing the performance revisions? Is it sort of stuff from 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 Haynesville well, and it's also the fact that it's hard to see in the numbers, but generally, what's happened to our inventory is that we've turned short laterals into long laterals and they've become more economic. There's been a lot of remapping of the inventory. 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. I think as we were able to work through and redraw the laterals and et cetera, and the performance of the wells overall, and 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. Including just the actual wells, their actual performance was better than what they were in the reserve report for. I think all those together, it's 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 Kashy 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 the spot market? Thank you. Yeah. Good question. Yeah. Typically, we target to have just about 75% - 80% sell on the index basis, because that's kind of how our. The index prices match up well with our hedging program, right? The spot prices might not because of the. We don't want to go to a much higher percentage because we have a lot of new wells coming on and production issues can come and go, so we don't want to ever be caught having to buy gas to fill something we can't deliver on. That's our basic rule. Now, I think there's some times when we just say, they just set that. I think we probably went lighter on selling into the index market for the first quarter so far, and I think we were more at What was our exact number? Dan, do you have it there? I think we were more at 35% in the spot market for- Yeah, I think that's right For right now. Yeah, 35%-40%, actually, for the month of February. Yeah. That was a little bit lighter than the month of January. 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. I think that's paid off pretty well in both January and February because prices have been moving up. Obviously, this week is like hitting the jackpot, some of these incredible prices. Frankly, we were able to sell at super premium prices for a material amount of production, anywhere from $15 an Mcf to maybe some even at $179 an Mcf. Those are the spot prices that are out there. To answer your question, 70% - 80%, that's 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 release Q1 earnings. Yeah. We're interested to see how it all shakes out in the end, too. Good question. Thank you. Our next question comes on the line of Phillips Johnston 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 2022 or so if the strip holds. Jay, you mentioned Devon paying variable dividends. I'm wondering if you could address the board's preferred method of returning cash to shareholders once you've achieved that leverage ratio goal. Well, as you well know, at the end of probably 2014, we were a dividend-issuing company. I think we issued $0.125 per quarter. We did that. Of course, the wheels fell off the sector in the first quarter of 2015. Our goal, every company should have a goal of being in a position to have giving a dividend, period. I don't think we have enough shares to be buying shares back. We don't see doing that at all. We need to get more shares in float. I think we've got great inventory. We need to get the stock price performing, and then we need to be You asking how come the dividend's not high enough question. That's our goal. We want to be in a position to be able to give a dividend, period. We'll address the leverage first because you want to have the right balance sheet before you start- We have to do that. Hopefully, we can do that in 2021 and 2022. 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, Devon just did a big acquisition, a consolidation. They've got the bulk, they've got the market cap, they've got low cost of capital, they've got inventory. Right now, we don't have any issues as far as where our acreage is located to get drilling permits that are material at all. Our acreage is well-positioned in good areas, so there are not politically charged issues around them. I think that's good. No, I think Pioneer came out with a variable concept, and Devon issued one. I think that's the new business plan. 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. All those things, I believe we're going to give you and are giving you. 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. 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 work with our other peers. We'll be able to look to see at the market which method they like better, and so we'll study that to make a real decision on the structure. Yeah. The first job, number one, is getting the balance sheet to where everybody's very comfortable saying, "Yeah, you should be paying a dividend." we're focused on job one. Absolutely. We've always said that. We've got to get our cost of capital lower. We've got to get our leverage down. You'd love to be in the one time. We're at 3.8. We want to be in the 2.5, low twos by the end of 2021, and then lower in 2022. 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, 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. 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 a kind of housecleaning item. We received a notice from the New York Stock Exchange this week thanking us for 25 years of listing partnership with them. They attached a customized listed emblem highlighting Comstock's milestone. It's kind of thin air to be an NYSE company for 25 years, even for some of the most recognized largest companies in the world. We are there. If you have time to go to the Comstock website to see the emblem, please do. If you want to turn to page 22 in our corporate presentation today, you can see it. 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. Great questions, great support. Stay warm, everybody. Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.