Ladies and gentlemen, thank you for joining us for the Quarter One 2021 Comstock Resources Earnings Conference Call. Please be aware that this call is being recorded. Currently, all participants are in a listen-only mode. Following the presentations, there will be a question-and-answer session. I will now pass the call over to Jay Allison, Chairman and Chief Executive Officer. Jay, the floor is yours.

All right, thank you. Good morning, everybody. Welcome to the Comstock Resources first quarter 2021 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation titled first quarter 2021 results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations here. I know that the four of us will be presenting today, but I always want to take the time to thank all the 205 employees within the Comstock umbrella plus all the consultants and the service companies that we deal with to create the results that we have today. So I want to thank everybody. To flip forward to page two. Please refer to slide two in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you flip over to three, what we tried to do in our first quarter financial operating results press release, we tried to outline 10 bullet points that you could look at even if you didn't read the rest of that release, and it would tell you what the quarter looked like. So this is kind of a highlight of those 10 bullet points that we sent out earlier. We cover the highlights of the first quarter on slide three. In the first quarter, we reported adjusted net income of $63 million or $0.25 per diluted share. Production for the quarter averaged 1.281 Bcfe a day and was 98% natural gas. Our average daily production in the quarter was 6% higher than the fourth quarter of 2020, but 7% lower than the first quarter of 2020. Including a realized gas loss, our first quarter average realized price was $2.88 per Mcfe, up from $2.16 per Mcfe in the first quarter of 2020. Revenues, including realized hedging losses, were $332 million, which were 22% higher than the first quarter of 2020. Adjusted EBITDAX of $262 million was 30% higher than the first quarter of 2020. Operating cash flow for the quarter was $207 million or $0.75 per diluted share. During the first quarter, our total capital spending was $169 million, including $6 million we spent on leasing activities. For the quarter, we generated $33 million of free cash flow after preferred dividends, which is a good start to reaching our annual free cash flow goal of $200 million given this quarter is modeled to be our highest CapEx quarter for the year. In March, we refinanced $1.15 billion of our higher cost senior notes with $1.25 billion of 6.75% new senior notes. The refinancing created annual cash interest savings of $19.5 million and extended our weighted average maturity of our notes to 6.7 years, up from 4.9 years. In April, our bank group reaffirmed our $1.4 billion borrowing base. Dan Harrison will review the results of our successful Haynesville shale drilling program as well as report on our results and reducing our greenhouse gas emissions later in this report. If you'll flip over to slide four, we recap the March 4th refinancing we completed. We completed two note offerings to issue a total of $1.25 billion of new 6.75% senior notes due 2029. The proceeds from our offerings were used to refinance approximately half of our higher coupon notes. Through a tender offer, we redeemed $375 million of the 7.5% notes due 2025 and $777 million of our 9.75% notes due 2026. The refinancing transaction reduced our reported annual interest expense by $44.3 million and reduced our annual cash interest payments by $19.5 million. The lower cash interest expense will also drive significant improvements in our cash interest cost per Mcfe produced as we expect interest per Mcfe to fall to under $0.40 for the fourth quarter as compared to $0.48 this quarter. In addition to lowering our cost of capital, we also increased our weighted average maturity of our senior notes to 6.7 years, up from 4.9 years. We will look to refinance more of our 9.75 senior notes after they become callable in August of this year. With that, now, I'll turn it over to Roland to review the financial results of the quarter in more detail.

All right. Thanks, Jay. On slide five, we summarize our reported financial results for the first quarter of 2021. Our production for the first quarter of 2021 totaled 113 Bcf of natural gas and 326,000 barrels of oil. This is 8% lower than the production we had in the first quarter of 2020, but 6% higher than what we're producing in the fourth quarter of last year. Our oil and gas sales, including the realized loss from our hedging, increased 22% to $332 million in the first quarter despite the lower production, due primarily to higher oil and gas prices. Oil prices in the period averaged $47.87 per barrel, and our gas price averaged $2.79 per Mcf, including hedging losses. Natural gas prices were up 37%, partly due to the higher NYMEX index prices we had in the quarter and partially due to higher spot prices we realized in February. Our production costs were also up 2% while our G&A was down 8% and our DD&A was down 1% in the quarter. Adjusted EBITDAX came in at $262.1 million, 30% higher than 2020's first quarter. Operating cash flow was $206.6 million, which was also 30% higher than the first quarter of 2020. We reported a net loss of $138.4 million in the first quarter or $0.60 per share. But that reported loss was mainly due to a $238.5 million charge related to the early retirement of the senior notes from our March 4th refinancing transaction and the unrealized loss from the mark-to-market of our hedge positions at the end of the quarter of $13.1 million. Adjusted net income, excluding the loss on early debt extinguishment and the mark-to-market hedging loss and certain other unusual items, was a profit of $63.3 million or $0.25 per diluted share. Slide six we cover our hedging program. During the first quarter we had 70% of our gas volumes hedged, which reduced our realized gas price to $2.79 per Mcf from the $2.86 per Mcf we realized from selling our production. We also had 37% of our oil volumes hedged, which decreased our realized oil price to $47.87 per barrel versus the $50.69 per barrel we received. Our realized oil and gas hedging losses in the quarter totaled $8.4 million. Since we last reported earnings, we've added another 40 million cubic feet per day of natural gas swaps for 2022 at a settlement price of $2.70 per Mcf. For 2021, we have natural gas hedges covering 936 million cubic feet per day of our 2021 production, which is about 69% of our total expected production this year. 63% of those hedges are swaps and 37% are collars, which gives us exposure to higher prices. For 2022, we have natural gas hedges covering 174 million cubic feet of our 2022 production and an additional 120 million cubic feet of swaptions that we expect to get exercised. Going forward, our primary focus is only adding to our 2022 hedge position. We continue to target to having 55% to 70% of our production hedged over the next 12 to 18 months. On slide seven, we summarize the shut-in activity during the first quarter. We had $80 million per day, or 6.4% of our natural gas production, shut-in in the first quarter, as compared to about 6.6% in the fourth quarter of last year. During the February winter storm, we shut-in as much as 500 million cubic feet of our production over the course of several days due to road closures, which limited our ability to haul produced water, downtime associated with downstream pipelines in plants, and then other freezing problems that we had in the field. Excluding the shut-in related to the storm activity, we would have had about 4% of our production shut-in due to routine offset frac activity and other workovers. We anticipate returning to a normal 4% to 5% shut-in level in the second quarter of this year. On slide eight we detail our operating costs per Mcfe. Our operating cost per Mcfe averaged $0.55 in the first quarter. It's about $0.01 lower than in the fourth quarter of last year. That was comprised of gathering costs of $0.26, production and other taxes of $0.08, and other field level operating cost of $0.21 per Mcfe. On slide nine we detail our corporate overhead costs per Mcfe and that averaged 5% in the first quarter, which is up about $0.01 from the fourth quarter of last year. We do expect our cash G&A cost to remain in this $0.05 to $0.06 range going forward. In slide 10 we detail the depreciation, depletion, and amortization per Mcfe produced that averaged $0.95 in the first quarter, $0.01 higher than the $0.94 rate in the fourth quarter. So, overall, our operating cost structure was very comparable to where we were at the fourth quarter last year. On slide 11, we show our balance sheet at the end of the first quarter. We had $550 million drawn on our revolving bank credit facility at the end of the quarter, and we expect to use our free cash flow that we're generating this year to pay down a portion of that revolver throughout 2021. We also have $2.367 billion of senior notes outstanding comprised of $244 million of our 7.5% senior notes due in 2025, $873 million of our 9.75% senior notes due in 2026, and then the $1.25 billion of the new 6.75% senior notes due in 2029. We also show our revised maturity schedule on slide 11 where you can see the $1.25 billion of our debt now has been pushed out to 2029. With a quarter-end cash position of $77 million, our current liquidity stands at $927 million. On slide 12, we recap our first quarter capital expenditures. In the first quarter, we spent $163 million on development activities of which $150.4 million was related to our operated Haynesville shale development program. We drilled 21, or 19 net to us, operated horizontal Haynesville wells, and we turned 10 of those wells to sales, or nine net to us, in the quarter. In the first quarter, we also spent $12.7 million on non-operated wells and other development activity. In addition to funding our development program, we also spent $5.8 million on leasing exploratory acreage in the quarter. We're currently running six operated rigs for our 2021 drilling program, but we expect to drop one of those operated rigs this month. And based on our current operating plan for this year, we expect to spend approximately $510 million to $550 million and drill 67 operated Haynesville wells, or 56 net wells to us, and then turn about 55, or 49 net wells, to sales. We continue to be very focused on generating significant free cash flow this year, and we continue to target generating over $200 million of free cash flow in 2021 as we plan our capital spending. I'll now turn it over to Dan to report in more detail on our operating results this quarter.

Thank you, Roland. Please turn to slide 13. You'll find a map outline and summary of the 13 new wells we've put into production since the last call. These wells are situated on our East Texas and De Soto Parish properties in Louisiana. They were tested with production rates ranging from 19 million cubic feet per day to 32 million cubic feet per day, averaging 25 million per day. The lateral lengths of these wells varied from 4,568 feet to 13,043 feet, with an average length of 8,132 feet. This includes our longest lateral completed so far, which is 13,043 feet on the Roberts TTB #2H well in Harrison County, Texas. We currently have nine more wells at different stages of completion. At this time, we are operating six rigs and three frac crews. As Roland mentioned earlier, we plan to let go of one of our drilling rigs in the next few days and will continue to operate five rigs for the rest of the year. We also expect to average 2.3 frac crews for the remainder of the year. On slide 14, you can see the updated trend for drill and completion (D&C) costs for our long lateral wells, those over 8,000 feet. In the first quarter, we made progress in reducing our total D&C costs. Our average D&C cost was $1,010 per foot in the first quarter, which is a 2% decrease from our average D&C cost in 2020. Our drilling costs dropped significantly to $365 per foot, a reduction of 15% from the previous quarter and 20% lower than our full-year 2020 average drilling cost. This reflects the improved drilling efficiencies and shorter drill times we've achieved since late last year. Our completion cost in the first quarter increased to $645 per foot, which is a 10% rise from the previous quarter and a 13% increase from our full-year 2020 completion cost. This rise is solely due to the larger fracs we began pumping late last year, which involved higher sand and water volumes. By maintaining our leading drilling performance, we can manage the increased completion costs tied to larger stimulation treatments while still keeping our overall cost structure low going forward. On slide 15, we showcase the continued improvement in our emission intensity over the last three years. In late 2020, we updated our website to include a sustainability section to highlight our ESG initiatives and provide our ESG performance metrics. As a mainly dry natural gas producer, our emission intensity ranks favorably against industry peers. Since 2018, our emission intensity has improved to 3.12 kilograms CO2 equivalent, a 38% improvement. Our sustained focus on greenhouse gas and methane emissions, along with the use of dual fuel drilling rigs, has driven this progress. We remain committed to further enhancing our ESG metrics. Recently, we signed a three-year contract with BJ Energy Solutions to deploy the second natural gas-fueled pressure pumping fleet in the Haynesville, which we will discuss further on the next slide. On slide 16, we cover our partnership with BJ to introduce the second next-generation fracturing fleet in the Haynesville, starting in early 2022. BJ's TITAN fleet operates using 100% natural gas for well completions, which is expected to further reduce our CO2 and methane emissions while also improving the economics of our wells by leveraging the efficiencies of the TITAN fleet. With the TITAN fleet, CO2 emissions are expected to decrease by 25% compared to our conventional diesel-powered equipment. Methane emissions are projected to improve by 60% compared to diesel-only powered equipment and over 95% compared to dual fuel options. The TITAN fleet requires only eight pumps compared to 18 in our traditional frac fleets, reducing our necessary pad size by more than 30% while also meeting stringent noise requirements in North America. The three-year contract secures our current load completion costs and provides opportunities for cost-saving efficiencies, all while minimizing the environmental impact of our future well completions. I will now turn it back over to Jay to summarize our outlook for the remainder of the year.

Thank you, Dan. We saw that BJ issued a press release today regarding their partnership with Comstock on a new natural gas-powered completion facility. This marks their second facility, and it's a positive announcement. If you look at slide 17, you'll see a summary of our outlook for the rest of the year. Our operational plan is set to deliver modest production growth and, crucially, generate over $200 million in free cash flow, as Roland mentioned. This year, our main objectives are to enhance our balance sheet, reduce our leverage, and lower our capital costs. Our refinancing transaction in March was a significant first step towards decreasing our capital costs, resulting in $19.5 million in annual interest savings. If natural gas prices remain stable, we anticipate our leverage ratio will improve to around 2.5 times by the end of 2021, down from approximately 3.8 times at the end of 2020. The first quarter's annualized figure is already at 2.7 times. We are committed to sustaining and enhancing our low-cost structure and our top-tier drilling returns. Our Haynesville drilling program, with its industry-leading cost efficiency, yields among the highest returns in North America. Our extensive portfolio of Haynesville/Bossier drilling sites gives us decades of inventory. As Roland mentioned, we've hedged about 69% of our 2021 production to safeguard our strong drilling returns, and we are backed by solid financial liquidity of $927 million. Now I'll hand it over to Ron for more specific guidance for the rest of the year.

Thanks, Jay. On slide 18 we show the guidance table. You'll note that it's unchanged from February when we updated the guidance. So despite the impacts of the winter storm, our production guidance still remains in the 1.33 Bcf to 1.425 Bcf a day range. Our CapEx guidance remains on the development side $510 million to $550 million which, as has been mentioned a couple times, contemplates the dropping of one of our operated rigs in the next couple of days. In addition to those development expenditures, we still expect to spend up to $10 million or so on leasing expenditures. LOE and gathering and transportation costs remain in the $0.21 to $0.25 per unit range and $0.23 to $0.27 per unit range, respectively, while production and ad valorem taxes are expected to average $0.08 to $0.10 per Mcfe. DD&A rate is still to be in the $0.90 to a $1 per Mcfe range, and our cash G&A is expected to remain in this $0.05 to $0.07 range. I'll now turn the call back over to the operator for Q&A from analysts who cover the company.

Thank you. Our first question comes from Derrick Whitfield from Stifel. Your line is open.

To start first with your operational guidance on page 12. You guys are iterating full-year production guidance despite a 1.5 net well decrease in your wells to sales. Perhaps that's simply time, but that seemingly implies improving production performance per well. If so, could you speak to some of the drivers?

You cut out a little bit, Derrick. But I think you're asking about slide 12 regarding the reduction of about 1.5 wells turned to sales compared to the February conference call. Are you looking for an explanation of why production remains stable despite this decrease?

That is correct. And sorry for the connection if there was an issue. So my thought process is perhaps that's simply timing but that would seemingly imply improving production performance per well. And if so, could you speak to those drivers?

Yeah, this is Dan. The completion schedule is the main factor at play. We had some wells that shifted to the beginning of next year instead of being completed by the end of this year. While this change affects the number of wells we are turning to sales, it doesn't impact our production, as the output from those wells will start right at the end of the year. So, production for this year remains unaffected.

Okay. And then maybe it's my follow up for Dan. I wanted to focus on the Roberts well you noted in your prepared remarks. Based on your experience to date, where do you believe the efficient frontier is for Comstock in lateral lengths and are you sensing any material degradation in frac efficiency at that length?

So I'll answer the second one first. No, we're not experiencing any degradation in frac efficiency. That I think will be longer, and we do have longer laterals planned in our schedule in the future. As far as what the sweet spot is going to be I think was your first question, it kind of remains to be seen, but we feel pretty strongly about being able to drill 15,000-foot laterals. For us, I think the risk of drilling and completing the 15,000-foot laterals, drilling them especially, is probably not real high on our list, but it's going to be just the risk of when you're completing the well, if you've got to do any kind of well intervention work-out, when you get out to laterals that long, it requires you to use a rig to do any kind of clean outs or anything versus coils. So it just kind of changes the risk profile a little bit, but we definitely think the value is there to get longer up to 15,000 foot. Definitely increased value and better returns.

Well, to Dan's point, if we can extend these wells, we've we drilled wells to 13,000-plus feet this last quarter. But if we can extend our average well to 13,000 to 15,000 feet to lateral, that's like one of the shorter laterals being drilled. So you don't have to add surface or intermediate. So you can get rid of those costs, and it's just a horizontal length that you're drilling. So the economics, the pure dollars that you're spending, makes a lot more sense to drill the lateral length and, like Dan said, so we don't see a lot of issues in the drilling of it, and we've been able to complete these pretty consistently. So we do think there's a lot of upside value that is not in any of these numbers if we can continue to extend these laterals, which was your question, I think that was really your question.

I would agree with your assessment. Thanks again for your time, guys.

Thank you. Next question comes from the line of Neal Dingmann from Truist. Your line is open.

Hey. Good morning, guys. It's actually Bertrand filling in for Neal. The first question, the drilling efficiency gains in 1Q that you saw was I think you guys were talking to faster drilling times. Was that just while you were drilling or is that in between wells? Was there was there something driving that more specifically? It just seemed like a large drop quarter-over-quarter.

So, Dan, you might give some statistics that we've been given from some of the service companies. I want to brag on you a little bit for what you've been able to do.

This reflects the performance of our drilling team. We have set several records for the footage drilled in 24 hours for both the intermediate hole and the lateral. This improvement is due to a combination of factors. We have received many inquiries about our progress. We are drilling significantly faster in the intermediate phase, having reduced the number of days required. The average time for our 10,000 lateral days to total depth was in the high 20s just a few quarters ago, and now it’s in the high teens to low 20s. This achievement is a result of everyone's efforts. We noticed signs of this improvement earlier, but until our entire fleet operates with this level of efficiency, it doesn’t reflect in our numbers. We reached this efficiency in the fourth quarter and the first quarter, which is why we are reporting the percentage decrease today.

We can drill these wells in 18 to 20 days and complete them in about 30 days. Currently, we have two wells on the pad. Regarding the frac stages, we can complete around three to five stages per day, and we have maintained a consistent pace, even as we increased our completion costs slightly. However, we have managed to reduce our drilling costs to $1,010 per foot. I expect this cost structure to continue moving forward, and we haven't encountered significant issues in drilling or completion. This indicates we're operating within the optimal areas of our footprint in Harrison, Panola, Caddo, and De Soto Parishes. Our acreage is strong, and we’re optimistic about our inventory for 2021, with some locations already planned for drilling in 2022.

And it sounds like, so you're saying it really is just the drilling speed, so it's more sustainable. It wasn't just a bunch of wells close to each other for the quarter or anything like that?

No, not at all.

That's the beauty of the footprint.

It's definitely an improvement.

That's a great question, though. Yes.

Thank you. Next question comes from the line of Kevin Cunane from Citigroup. Your line is open.

Good morning, everyone. Just sticking on the drilling efficiencies. Obviously, you just commented you're getting a bit faster. And then looking at the guidance on slide 12, you moved up total operated wells drilled by five, your DUCs expanded just on lower wells turned to sales. That's inclusive of already dropping of rigs here in May. Is there a possibility that you would be able to reduce your rig activity further and maybe bring those wells drilled back down to the original guidance, or is that kind of a bit higher on a continuity program into 2022? Just kind of get a feel of when you'd be able to kind of reap more cash flows through the better drilling efficiency that you've been experiencing.

So we have these faster drill times, basically, faster cycle times on the drilling side is kind of what's creating a little bit larger DUC list than what we would have normally had. I think as far as the number of rigs decreasing further, we don't really see that right now. We're just running the number of rigs to keep us basically in maintenance mode on production. So to keep our production growth basically in the single digits, five rigs looks to be about the right recipe for us.

Yeah. Again, we've said we're going to have modest growth. I think that's what it is. If you look in 2022, it's 3%, 4% growth, something like that. It's modest. We're going to have a lot of DUCs carried over. I think a lot of that is from efficiency. Again, we said that we're going to drop a rig this month, so I think that'll help. And then I think we've always advertised that we were going to increase the amount of sand and water. So if you look on that slide 14, that's probably a good number for the completion side, that $645 a foot. And then on the drilling side, I know Patrick McGough is listening. He's somewhere in the office listening, and he's VP of Ops. And he pushes really, really, really hard to make sure that our drilling costs are down. He's done a great job. It shows up on slide 14. I think we have the best group out there. Of course, that's our opinion, and the numbers I think show it. But if we can decrease those, we will. I think the good thing is it is very predictable. We're very consistent with these wells. 25 million a day IP rate, we're not trying to trick you with a high IP rate. We drill in all four corners of our acreage, and the 320,000-plus net acres we have and almost 2,000 locations, they're really good quality. It's decades. And all we do now just this year is gave you a preview of what 50 completed wells might look like for the year, and it's really all about the financial integrity. We need to keep hedging like Roland and Ron are doing. Gas prices look really good. I think that the whole sector is going to be disciplined. If you're a public oil company, you're going to be disciplined, and the same thing with gas. And we think Appalachian group's kind of locked in. Swing area may be the Haynesville because of where LNG is and because the pipelines are added. All we're trying to do is give you the basic rule to tell you this is a great engine and a company to invest in if you're looking for low cost, high margins, and run by Dan and Roland and Patrick, and the whole group. So it's a good story.

Great. That's it from me. Appreciate the color.

Thank you. Next question comes from the line of Steve Dechert from KeyBanc. Your line is open.

Hey, guys. Just want to see, do you guys think that the lower number of TILs that you talked about earlier and '21 can maybe push you in the lower half of your '21 CapEx guide?

I think it's a $510 million to $550 million.

No, we think the guidance that's out there is pretty good for basically the plan that we have.

You never know what tomorrow brings, but that's what we advertise today, though.

With the uptick in activity, there's always the chance that you could still see a little bit of material cost increases on the completion side. And even the rigs, the rig count's going up, so most of our rigs are on well-to-well contracts. So that's always a possibility.

Got it.

The only longer-term contract we have, and we've said this, is with BJ. All the rest of them are, like Dan said, whether it's a drilling company or a fracking company. It's really well-to-well.

Okay, makes sense. And just to follow up. So can you give some color on the production cadence here in '21 and just what you think you see as the high quarter for this year?

Steve, similar to what I mentioned in the first quarter, we expect sequential growth in the second and third quarters, followed by a leveling off in the fourth quarter based on our current completion schedule. Essentially, the growth from the first quarter will likely be distributed between the second and third quarters. In the fourth quarter, we anticipate it will stabilize or possibly decline slightly due to the timing of when wells are brought online.

Next question comes from Umang Choudhary of Goldman Sachs. Your line is open.

Great. Good morning, and thank you for taking my questions. My first question is as you look toward 2022 gas futures, the curve appears to be in sharp backwardation. Wanted to get your thoughts around the expectation for gas prices heading into next year. And then within that context, maybe if you can touch upon your plans to manage risk through your hedging program?

The question about gas prices indicates that we are seeing a positive situation developing for the summer, with gas storage levels below the five-year average and significantly lower than last year. This is primarily due to record LNG exports and exports to Mexico, which has contributed to a constructive environment, despite less than favorable weather for natural gas this year. Overall, the outlook appears optimistic, and we have noticed the natural gas futures market, particularly for 2021, reacting positively by moving closer to the $3 mark. As we look towards 2022, we are aiming to set our hedges while we have reached our targets for 2021. We have made a small start with around 20% hedging for 2022, and we remain patient. We are hopeful that gas prices will continue to strengthen beyond the current month. With our industry-leading low-cost structure and high margins—79% in the first quarter—we believe we can maintain these margins throughout the year, especially with better index prices expected from the second to the fourth quarter. We see a strong foundation for achieving our 2021 goals.

Yeah. And Umang, what we've done and you can see, the recent hedges we've added in '22 have been swaps. We continue to monitor the collar market as well as the '22 strip has moved up. We've just taken the opportunity to do some swaps, but we continue to want to have a combination of both swaps and collars in our '22 hedge book, so that we do create a base level of cash flow, but also have some upside on a significant portion of our hedges when we get to that year.

And to Ron's point, the swaps give you a little more stability because they're at $2.70. The collars give you a little more upside. So as you said, we blend those in like we did in 2021. And the future, we look at the industrial demand is growing in Mexico. I think 80% of the gas that goes to Mexico, which is about 7 Bs a day comes from the Texas area. Some of that comes from the Permian. If you look at where the LNG export facilities are, we're exporting about 11.5 Bs a day, probably 10.5 Bs of that comes from where we are, the Gulf Coast area. So we see that as a strong market. We see Asia gas is $7, gas in Europe at $8, the spreads $1 or $2, it costs a $2 to liquefy it and transport it over there, and our gas is $3. So you look at the winter they had in Europe, I think the storage is low there. You look at demand growth in Asia, it sets us up for a really good I think next 18 to 24 months really because I think the public companies particularly will be disciplined with growth in CapEx. It's associated gas. We're not fearful it is going to grow because we think these companies will be giving dividends and buying shares back, returning dollars to their stakeholders. That's exactly why our focus is to improve our balance sheet, reduce our leverage, and lower our cost of capital. So I think it's a good drum for this whole sector for 2021, '22.

Great. That's really helpful. And as my follow-up. As you improve your leverage through free cash flow generation and production growth toward your two times goal and given your favorable view of natural gas prices heading into next year, I wanted to get your initial thoughts around activity levels. Like what do you think is the most sustainable activity level which Comstock can sustain over the next few years?

I believe that the five drilling rig program is a sound model for sustainable low-production growth that the company is pursuing. If we begin to see better efficiencies, we may consider scaling back. We're also enhancing our free cash flow not only through CapEx savings but also from reduced interest expenses, which will allow us to use less of our margin to cover fixed costs. We anticipate more improvements in this area moving forward. We've completed only half of this work, and we aim to finish it in the next year to reduce our overall interest burden. We see this year as a strong opportunity to build on our foundation, but it will take about two years to bring the balance sheet to the desired level, which is leverage well below two times. We're off to a good start, but there's still a considerable amount of work ahead.

The script appears promising. Currently, it's around $2.90. Looking ahead eight or nine months, it might reach $3.12 or $3.20. It’s beginning to behave as we anticipated, just as we enter the summer months. Our aim is to lower our leverage ratio to the low-2s or high-1s. Achieving this would significantly enhance the value of the company. If Dan Harrison and his team, including Patrick, can provide longer laterals due to our expansive footprint and numerous tier one drilling locations, we can generate substantial wealth. Geographically, we are better positioned than any other company for dry gas, especially in relation to the LNG export area. This advantage will likely attract interest in our company, as it represents our own equity.

Thank you.

Thank you. There are no further questions at this time. I would like to turn the call back to Jay Allison for closing remarks.

Thank you. I want to emphasize that we operate like a family here. You hire us to manage the company, you invest in our bonds, and you believe in our equity, and we take that responsibility seriously. We've demonstrated this over the past 35 years. We are followed by about 10 analysts, and I believe today is a pivotal day. It seems everyone agrees with our vision and the positive outlook we're presenting. We boast decades of drilling locations in the Haynesville/Bossier area, which is quite rare; most companies typically have only 10 to 15 years of viable locations. Our cost structure is among the lowest in the industry, and we have consistently provided high-margin Haynesville wells quarter after quarter, showcasing some of the best in North America. We have strategies in place to hedge and protect our drilling returns and have significantly improved our financial liquidity. A year ago, this was not the case; however, we issued bonds last year and again this year totaling $927 million. We remain committed to reducing our GHG emissions and have been proactive even in supporting our service partners during tough times. Our strong free cash flow enabled us to access the capital markets effectively, raising $1 billion last year and $1.250 billion this year. Moreover, we are strategically positioned near the LNG market, allowing us to export Haynesville gas worldwide. For instance, during the last Olympics in South Korea, our gas was used to power the stadiums, highlighting its global significance. To conclude, our primary goals this year are to enhance our balance sheet, reduce leverage, and lower our capital costs. Achieving these objectives will set us up for success. Thank you for your attention for the remainder of the year.

Thank you and again ladies and gentlemen, this concludes today’s conference call. Thank you for participating, you may now disconnect. Have a great day.