Comstock Resources Inc (CRK) 2021 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Quarter 1 2021 Comstock Resources Earnings Conference Call. Please note that today's call is being recorded. (Operator Instructions)

I would now like to hand the conference over to your speaker for today, Jay Allison, Chairman and Chief Executive Officer. Jay, the floor is yours.

All right. Thank you. Good morning, everybody. Welcome. If you would look to the first quarter 2021 results. 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 entitled 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 Relationship. I know that the four of us will be presenting today, but I always want to take the time to thank all the [204] (corrected by company after the call) 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.

If you flip forward to Page 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

If you flip over to 3, 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 has kind of a highlight of those 10 bullet points that we sent out earlier. We cover the highlights of the first quarter on Slide 3. 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 hedge loss, our first quarter averaged 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 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 4, we recap the March 4 refinancing we completed. We completed two notes offerings to issue a total of $1.25 billion of new 6.75% senior notes due 2029. The proceeds from the 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. Now we'll 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 for the quarter in more detail. Roland?

All right. Thanks, Jay. On Slide 5, 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 were 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% of the quarter. Adjusted EBITDAX came in at $262.1 million, 30% higher than 2020's first quarter. Operating cashflow 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 4 refinancing transaction and an 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 and 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 6, 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 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 7, 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 and plants and 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 8, we detail our operating costs per Mcfe. Our operating costs per Mcfe averaged $0.55 in the first quarter. It's about $0.01 lower than 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 costs of $0.21 per Mcfe.

On Slide 9, we detail our corporate overhead cost per Mcfe and that was -- that averaged $0.05 in the first quarter, which is up about $0.01 from the fourth quarter of last year. We do expect our cash G&A costs to remain in this $0.05 to $0.06 range going forward.

On 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. 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 this Slide 11, where you can see the $1.25 billion of our debt now has been pushed out to 2029. With the 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, operated horizontal Haynesville wells. And we turned 10 of those wells to sales, or 9 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.

Okay. Thank you, Roland. Flip over to Slide 13, you'll see a map outline and summary of the 13 new wells that we've turned to sales since the last call. The new wells were located on our East Texas and DeSoto Parish acreage over in Louisiana. The wells were tested at rates ranging from 19 million cubic feet a day up to 32 million cubic feet a day with an average IP rate of 25 million a day. These wells had lateral lengths ranging from 4,568 feet up to 13,043 feet with an average lateral length of 8,132 feet. This included our longest lateral completed to date at 13,043 feet. This was on a Roberts TTB #2H well that is located in Harrison County, Texas.

We currently have nine additional wells that we have in various stages of completion. We are currently running 6 rigs and 3 frac crews at this time. Like Roland mentioned earlier, we're going to be releasing one of our drilling rigs here in just the next couple of days. And we will be continuing to operate at 5 rigs for the remainder of the year. We'll also anticipate running an average of 2.3 frac crews for the remainder of the year.

Over on Slide 14 is the updated D&C cost trend for our long lateral wells. These are the lateral wells that are greater than 8,000 feet in length. During the first quarter, we continued making progress and pushing our total D&C costs lower. Our D&C cost averaged $1,010 a foot in the first quarter, which is 2% lower than our 2020 average D&C cost.

Our drilling costs in the first quarter dropped significantly to $365 a foot. This represents a 15% decrease from the previous quarter and a 20% decrease versus our full year 2020 average drilling cost. This is a reflection of the increased drilling efficiencies and the faster drill times we have continued to build upon since late last year.

Our completion cost in the first quarter increased to $645 a foot. This represents a 10% increase from the previous quarter and a 13% increase versus our full year 2020 completion costs. This increase is entirely attributed to the larger fracs we resumed pumping late last year, pumping the higher sand and water volumes. By maintaining our industry-leading drilling performance, we have the ability to absorb the higher completion costs associated with the larger stimulation treatments and still be able to maintain our low overall cost structure in the future.

On Slide 15, we highlight our continued improvement in our emission intensity over the past 3 years. In the late 2020, we updated our website to include a sustainability section to highlight our ESG efforts and provide our ESG performance metrics. As a primarily dry natural gas producer, our emission intensity ranks attractively relative to industry peers. Since 2018, our emission intensity has improved to 3.12 kilograms of CO2 equivalent, representing a 38% improvement. Our ongoing focus on greenhouse gas and methane emissions, combined with the use of dual fuel drilling rigs, have been the drivers behind this improvement. We remain focused on continued improvement in our ESG metrics. To that end, we we recently signed a 3-year contract with BJ Energy Solutions to deploy just the second natural gas fuel pressure pumping fleet in the Haynesville as we will discuss further on the next slide.

On Slide 16, we cover our recent partnership with BJ to deploy the second next generation fracturing fleet in the Haynesville starting in early 2022. BJ's TITAN fleet is fueled by 100% natural gas for well completions. This is expected to drive continued improvement in our CO2 and methane emissions, while also improving our well economics by taking advantage of the efficiencies that the TITAN fleet can provide.

With the TITAN fleet, the CO2 emissions are expected to decrease by 25% compared to our conventional diesel-powered equipment. Methane emissions are expected to improve by 60% compared to diesel-only powered equipment and more than 95% compared to dual fuel options. With only 8 pumps required by the TITAN fleet versus 18 in our conventional frac fleets, the new fleet will decrease our required pad size by more than 30% while also meeting the most stringent noise requirements in North America. The 3-year contract locks in current low completion costs that we have, and it provides us the opportunity for cost-saving efficiencies, all while reducing the environmental impact of our future well completions.

I'll now turn it back over to Jay to summarize the outlook for the remainder of the year.

Yes. Thank you, Dan. We noticed that BJ put a press release out today on the relationship that they have formed now with Comstock on this new natural gas-powered completion [fleet] (corrected by company after the call). So it's the second one. It's a nice press release. If you'll now go to Slide 17 -- I direct you to Slide 17 where we summarize our outlook for the remainder of this year. Our operating plan for this year is expected to provide for modest production growth, and most importantly, really to generate, as Roland said, in excess of $200 million of free cash flow.

Our primary focus of this year, this is our drumbeat for the year, it's to do 3 things: one, improve our balance sheet; two, reduce our leverage, and three, lower our cost of capital. Our March refinancing transaction was a strong first step to reducing our cost of capital with the $19.5 million annual savings in interest payments.

If natural gas prices stay at current levels, we would expect our leverage ratio to improve to around 2.5x at the end of 2021 down from about 3.8x at the end of 2020. On an annualized basis, the first quarter is already down to 2.7x. We remained focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns. With our industry-leading low-cost structure, our Haynesville drilling program generates some of the highest drilling returns in all of North America. Our large inventory of Haynesville/Bossier drilling locations provide us with decades of drilling inventory.

We've currently hedged, as Roland said, about 69% of our 2021 production to protect our high drilling returns and we have very strong financial liquidity of $927 million.

So now I'll turn it over to Ron and he can provide some specific guidance for the rest of the year. Ron?

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 to 1.425 Bcf a day range. Our CapEx guidance remains, on the development side, $510 million to $550 million, which has been mentioned a couple of times contemplates the dropping of 1 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 cents per unit range and $0.23 to $0.27 per range -- 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 $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.

(Operator Instructions)

Our first question comes from the line of Derrick Whitfield from Stifel.

I'll start first with your operational guidance on Page 12. You guys are reiterating full year production guidance despite a 1.5 net well decrease in your wells (inaudible). Perhaps that's simply timing, 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 on Slide 12 versus the February conference call, the number of wells turned to sales on an operated standpoint is down about 1.5. And asking -- are you asking how -- to provide some of the drivers as to why the production is still the same despite 1.5 less wells turned to sales.

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

Yes. This is Dan, and I think that's basically just the cadence of the completions. We did have some wells, when we're working with the model, some of those wells just shifted basically to the first of next year from the end of the year. So basically it affects the number of wells that we turn to sales, but it really doesn't affect the production because its production is coming on right at the end of the year. Doesn't affect the production for this year.

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 deficiency 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 it was your first question, it kind of remains to be seen, but I mean, we feel pretty strongly about being able to drill 15,000 foot laterals. I think -- for us, I think the risk of drilling and completing the 15,000 foot laterals, drilling them specially 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, when you get to out to laterals that long, it requires you to use a rig to do any kind of clean outs or anything versus coil.

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 feet And definitely increase value and better returns.

Well, to Dan's point, if we can extend these wells, I mean, we drill wells to 13,000 plus foot this last quarter, but if we can extend our average well to 13,000 to 15,000 foot to lateral, that's like [two] (corrected by company after the call) of the shorter laterals being drilled. I mean, we'd only have to ask to set surface for intermediate. You can get rid of those costs and it's just a horizontal length that you're drilling. So the economics, if the dollars that you're spending it makes a lot more sense to drill a lateral longer, and like Dan said, 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 value -- upside value that's 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.

Next question comes from line of Neal Dingmann from Truist.

This is actually (inaudible) filling in for Neal. The first question, the drilling efficiency gains in 1Q that you saw was -- I think you were guys were talking to faster drilling times. Was that just, while you were drilling or is that in between wells? Was there something driving that more specifically? Just seemed like a large drop quarter report.

So Dan, you might give some statistics that we've been given from some of the service companies on our (inaudible) on drilling with the drillbit, but what you've been able to do.

Well yes, and I mean, this basically is a reflection on our drilling group. I mean, we've got several of the records set for the amount of footage we have drilled in 24 hours and intermediate hole and in the lateral. And it's really just a combination of several things, we get a lot of questions on that front. I mean, we're drilling a lot faster to intermediate case in point. We've really cut down the number of days there, and we're drilling the laterals a lot faster. I mean, our average [number of drilling] (corrected by company after the call) days to TD was probably in the high 20s here just a couple of quarters ago. And prior to that -- and now we're in the high teens to low twenties.

So it is a culmination of everybody's efforts. So it's just things getting better on so many fronts that it got us to this point. We saw glimmers of the actually earlier than that, but until you get your entire fleet operating at this level of efficiency it doesn't show up in your numbers. So we have gotten to that point into the fourth quarter and really in the first quarter. And that's what's driving the percentage of decrease we're reporting on today.

Like Dan said, 18 to 20 days to drill these wells, maybe 30 days to complete them. Most of these wells, we have 2 wells on a pad site. If you look at the frac stages, I mean maybe 3 or 4, 4 or 5 completions per day, we're pretty consistent on that.

Even with more water and more sand, we increased our completion cost a little bit, but we lowered our [total] (added by company after the call) drilling costs to that $1,010 a foot. So I think that's going to be the norm from here on out. And we haven't had a lot of real issues either on the drilling or completion side. So I think that that tells you that we're drilling within the fairway of our footprint, either in Harrison, Pianola or Caddo Parishes or Desoto Parishes. I mean, we've got a really good footprint that acreage that we're drilling in. And, you know, Dan commented at 2021, we've got a great set of inventory we're drilling and we've pushed some of those locations into 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.

Not at all. That's definitely an improvement.

That's a great question though. Yes.

Yes. And then really my second one is just on the BJ Energy agreement. The completion rates that you locked in, was that -- that 365 per foot that your -- sorry, the $645 per foot you show on Slide 14, or is that some sort of -- did the agreement assume some inflation that way you could lock in 3 years, a couple of people (inaudible).

So basically it lets us lock in the horsepower costs for 3 years. So if there's, if you see the gas prices are up and the activity really picks up, like we've seen the rig count this year in the last week picked up, and you see the inflation in the completion costs, I mean, we'll be ahead of the game saving money, cause we'll have these completion costs locked in.

Now you don't lock into core sand, water, stuff like that (inaudible).

We're locking in the horsepower cost, which is the bulk of the job. But sand cost, freight, all our chemicals, those will still fluctuate with the market.

Amazing part of that, the footprint -- environmental footprint is a lot smaller for the BJ crew. And again, we're replacing an existing BJ crew with this new BJ crew coming in early 2022. And you looked at the emissions, how the CO2 or methane emissions, so they're materially better. So those were all positives that we need.

Next question comes from the line of Kevin Cunane from Citigroup.

Just sitting 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 5, your DUCs expanded just that lower walls turned to sales and that's inclusive of already dropping a rig here and 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, a program into 2022 to just kind of get a feel of when you'd be able to kind of reach, read more cash flows through the better drilling efficiency that you've been experiencing?

So we have the special drill times, basically faster cycle times with -- on the drilling side have -- is kind of what's creating our -- 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. To keep our production growth in the, basically in the single digits, 5 rigs looks to be about the right recipe for us.

Yes, Daniel, we said we're going to have modest growth. I think that's what it is. I mean, if you look in 2022, it's 3%, 4% growth, something like that, it's modest that 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 the rig this month, so I think that'll happen. 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's $645 a foot. And then on the drilling side, I would give -- I know (Patrick McGhough) 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 that the good thing is it is very predictable, we're very consistent with these wells. 25 million a day IP rates, we're not trying to trick you with a high IP rate. We drill in all 4 corners of their acreage, and then the 320 plus thousand net acres we have, almost 2,000 locations. I mean, they're really good quality it's decades. And all we do now just this year is give 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 performing like we are doing. Yes, process 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 the Appalachian group is kind of locked in, the swing area may be the Haynesville, because of where LNG is and because of pipelines that are added. All we're trying to do is give you the basic route to tell you this is a great engine and a company to invest in if you're looking for a low cost, high margins and you know, run by Dan and Roland and Patrick and the whole group. So it's a good story.

Next question comes from the line of (inaudible) from KeyBanc.

Just want to see -- do you guys think that the lower number of tools that you talked about earlier in '21 could maybe push you in the lower half of your '21 CapEx guide?

I think it said at $510 million to $550 million.

Now we think that, we think the guidance that out there is pretty good for basically the plan that we have.

You never know what tomorrow brings, but you know, so we advertise today.

You know there's always with the uptick in activity, there's always the chance that you can still see a little bit of material cost increases on the completion side and even the rigs. I mean, if the rig counts is going up, so most of our rigs are on well to well contracts, so that's always a possibility.

The only risk is kind of -- the only longer-term contract we have. And we said this is with BJ. All the rest of them were like Dan said with the drilling company or fracking companies it's just really well done.

Okay. Makes sense. And just to follow up, so could 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 we... I think what we financially get in the first quarter as well. We're going to... We'll have sequential growth here in the second and third quarters and then flattening out, in the fourth quarter based on the cadence and the timing of completions that we currently have modeled. So really the growth from the first quarter will probably be split between the second and third quarter. And the fourth quarter flattens out, even maybe comes down just a little bit just based on the cadence of which wells are turned to sales on which day.

Next question comes from Umang Choudhary of Goldman Sachs.

My first question is, as you look toward 2022 gas futures, the curve appears to be in (inaudible) I wanted to get your thoughts around the expectations of gas prices heading into next year. And then, within that context, maybe if you can touch on your plans to manage risk, with a (inaudible) hedging program.

Well, on gas prices, I think we see a pretty constructive situation building up for the summer, with gas storage being below the 5-year average. Far below where we were a year ago. And then we... Really driven by record exports of LNG and exports directly to Mexico. So that's all been very constructive despite the fact that the weather has not been overly constructive for natural gas this year. Overall the situation looks pretty promising. And, I think you've seen the natural gas futures market, especially for 2021 react, recently firming up to getting closer to that $3 level. As that spills over into 2022, we really, we need to put hedges in 2022. We're kind of at our targets for 2021.

Yes. That's when we'll hopefully build a 2022 position, at a higher kind of support level than we were able to do this year. We're already off to a small start there with about 20% hedged for 2022. So we're patient and that's kind of why we, think over the course of the summer, hopefully gas continues to firm further out than just the current month. But, obviously with our cost structure, our industry leading low cost structure that we have. And very high margins. Margins were 79% here in the first quarter. And those look good, with a better curve that we have. And the second to the fourth quarter of this year, the very better index prices. We see those margins being able to maintain those through this year. So really good backdrop is set out there in our opinion for achieving all our goals for 2021.

And in (inaudible) What we've done and you can see, I mean, the recent hedges we've added in 2022 have been swaps. So 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 2022 hedge book so that we do create, a base level of cashflow, but also have some upside on a significant portion of our hedges when we get to that year.

And, to that point the swaps gave you a little more stability. Because they're at $2.70, the callers give you a little more upside. So as you said, we blend those in kind of like we did in 2021.

And I know the future, we look at the industrial demand is growing in Mexico. I mean, I think 80% of the gas goes to Mexico, which is about 7 Bcf per 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. Bcf per day, probably 10 and a half of that comes from where we are at the Gulf coast area. So we see that as a strong market, we see Asia gas is $7. So gas in Europe at $8, the spreads, a dollar or two, it cost a couple of dollars to liquify 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 the demand growth in Asia. It sets us up for a really good, I think next take 18 to 24 months, really, because I think the public affairs particularly will be disciplined with growth in cap ex. It's associated gas. We're not fearful. It is going to grow, because we think these companies will be given dividends, buying shares back. Returning dollars to their stakeholders. That's exactly what our focus is to improve our balance sheet, reduce our leverage and lower our cost to capital. So I think it's a good drum for this whole sector for 2021, 2022.

Great. That's really helpful. And as my follow-up, as you improve your leverage through free cashflow generation and production growth towards your 2 times goal. And given you a favorable view of natural gas prices heading into next year, I'm wanting to get your initial thoughts around activity levels. Like, what do you think is the most sustainable activity level, which (inaudible) can sustain, over the next few years?

Well, I think -- and Dan kind of referenced it earlier. This kind of 5 drilling rig program is again sustainable. That is the low production growth kind of model that we think the company's steering into. Now, if they start out performing the efficiencies, maybe we can, we scale that back in. But we were freeing up other parts of free cash flow, not just from the CapEx savings, this new interest savings, will create more free cash flow as we don't have to use as much of our margin to service the, our fixed costs. And hopefully, there's more of that in the future. I mean, we've only taken, done half of that work. And we'd like to in the next year. So finish that work and bring down our overall interest burden off of that margin.

So. Yes, we think this will be a great year for building on that foundation. But it's probably a 2 year project to really get the balance sheet to where yes. The market and we want it to be, which is leverage, way below 2 times. So off to a good start. And, but lots of work today.

Well, and the strip looks good. It's $2.90+ ninety something today. You go out 8 or 9 months. It's $3.12, $3.20. I mean, it's just now starting to probably act like we thought it would act. And we're starting the summer months. If you, give us the type strip we have today, I mean, our goal is to get our leverage ratio to the low twos, high ones. That is our goal. I think that the value of this company will explode exponentially.

If we can do that. And if Dan Harrison, his group with Patrick, et cetera, can deliver longer laterals because we have such a huge footprint that we have so many, tier one locations to drill. But that's how we can create tremendous wealth here. And, I think geographically we're located better than any company. If you're looking for dry gas and you're looking to attach it to the LNG export area. I think we're located better than any company, period. I think that's going to be an attractive reason people look at this company, to own equity.

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

Sure. Again, thank you. I want you to know we're like a family here. I mean, you hire us to run a company. You give us money for bonds. You give us money because you believe in equity and we act like that. We've acted like that for 35 years. We've read some notes. I think there's 10 or so analysts that follow us, we've read notes. And I think today, it's one of those kind of tipping point days. I think everybody agrees with what we are giving you. What we're trying to do. And that the outlook is very favorable. Again, we say we have decades of locations in the Haynesville Bossier, that's unusual. Most companies have 10 years, 12 years, 15 years of locations. We have decades. We have industry leading low cost structure. We're not trying to get there.

We have it. We have high margin returns. Haynesville Wells. We give you those quarter, after quarter, after quarter. In fact, we advertised some of the highest [margins] (added by company after the call) in North America. That's a big, big geographical area, but we do. We will hedge, we talked about that to protect our drilling returns. We do have tremendous financial liquidity. A year ago, we didn't, but we issued the bonds. And then we should [do more] (added by company after the call) bond this year. We do now. $927 million in [liquidity] (added by company after the call). And we always have focused on reducing our GHG emissions. We're very proactive with BJ. Even when they went through their hard times it was very proactive. We used them and we supported them because we support the service companies. But we have... We are watching G&A, we generate great free cash flow. That's why we were able to tap the capital markets last year to billion dollars.

And this year for $1.25 billion. And we are near, I think this is the important. We are near LNG market to export our gas around the globe. I said this one time at a conference. If you look at the last Olympics in South Korea, Haynesville gas was used there to generate the power to light the stadiums. That's where some of this gas goes. It's a global market. So we'll leave you with this. Our drumbeat, again, this year, improve our balance sheet, reduce our leverage and lower our cost of capital. If we do that, we've got a blue ribbon coming. So thank you for your time. So we could do the rest 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.