Q2 2021 Comstock Resources Inc Earnings Call

[music].

Good day, and thank you for standing by.

To the Comstock resources second quarter 2021.

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 will need to press star 1 on your telephone.

Please be advised that today's conference is being recorded.

Further assistance, please press star zero.

I would now like to hand, the conference over to your Speaker today, Jay Allison Chairman and CEO. Please go ahead.

Again, thank you for the introduction.

I know there were reporting on the second quarter 2020, once a day.

No debt.

But we're super excited about what we see for the second half.

Of this year.

We advertise that we were front end loading our capex in 2021 through the first half of the year, which we did.

And.

Now, we say and actually have it today.

Corporate record high on natural gas production at Comstock.

Selling it at high natural gas prices.

The world of natural gas looks really solid.

With natural gas trading at $4 range, plus this morning, as I looked on the ticker <unk>.

Especially haynesville dry natural gas. So there is a primary feedstock gas for LNG exports stage in Europe, as well as to Mexico Gulf.

Global demand for natural gas is very strong for industrial power generation as well as electrical demand for drilling and aging while supply.

His low to moderate in part due to the disciplined use of capital expenditure dollars.

Cross the anti oil and gas sector as you're all aware of and this earnings season, and our corporate shrink lies on our best in class low cost structure, which creates our high margins as well as the 19 utter plus net drilling locations within our 3000.

323000, net acre Haynesville, Bossier footprint, which we operate 91% of <unk>.

1 of the major task in 2021 was reduce our cost of capital.

We took modest steps forward with our 575% senior notes being issued in the second quarter 2021, we do feel the wind in our sales as we look at the third and fourth quarter 2021 and 2022.

And want to recommit to you.

Our goal of reducing our leverage ratio to less than 2 times at the end of 2022 or before if possible with our refinancing in place we reduced our interest cost per M. Cfe by 25% this quarter.

So 36 cents on are committed to continue working to reduce debt number by year end 2021, if possible.

The denominator godfather, because our consistent drilling results quarter after quarter after quarter and the tier 1 haynesville Bossier region, which speaks volumes about all of our departments, especially our operations department and through our quality Haynesville Bossier rock that we have decades of that quality rock.

Left to drill.

I know that debt denominators, why Jerry Jones, and his family invested $1.1 billion in Comstock Since August 2018, and we believe that is why you the bondholders banks on equity owners back Comstock.

Proven rock quality proven results over many many years now I'll start the formal second quarter 2021 results.

Welcome to the Comstock resources second 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 Comstock resources Dot com and downloading the quarterly results presentation. There you'll find a presentation entitled second quarter 2021 results on Jay.

Allison Chief Executive Officer, 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. If you go to slide 2 please refer to slide 2 in our presentation and note that our discussions today will include forward looking statements within the meaning of 6.

<unk> 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. Jeff will go over to the second quarter 2021 highlights but cover the highlights on.

The second quarter on slide 3.

And the second quarter, we reported adjusted net income of $55 million 22 per diluted share production for the quarter average approximately 1.4 bcf per day and was 98% natural gas our average daily production for the quarter was 8% higher than the first quarter of 2021% and 6.

Percent higher than the second quarter of 2020 revenues, including realized hedging losses were $325 million, 40% higher than the second quarter 2020.

Adjusted EBITDAX of $251 million was 55% higher than the second quarter 2020.

Cash flow for the quarter was $196 million or <unk> 71 per diluted share for the quarter, we generated $20 billion of free cash flow hedge of preferred dividends and increasing our year to year free cash flow to $53 million.

That's a good start.

Toward reaching our annual free cash flow generation goal of over $200 million with a stronger commodity prices. We're seeing in the second half of the year. We now expect free cash flow to come in well above that goal of $200 million and lastly, we completed the task of refinancing all of our higher coupon senior notes in the second quarter.

<unk>, which substantially reduced our cost per cap going forward keep your turnover to slide 4 we recap the refinancing transaction, which closed on June 28.

We issued 965 million of new $5.87, 5% senior notes, which are due in 2030. The proceeds from the offering were used to redeem the remainder of our non and 3 quarter bonds. The refinancing transaction reduced our reported annual interest expense.

$33 million.

We will save $28 million in annual cash interest payments.

Combined with the March refinancing that we did our annual interest payments were reduced by $48 million.

The lower cash interest expense will also drive significant improvements in our cash interest cost per Mcf per day produced as I've mentioned earlier on a pro forma basis, assuming the refinancing was completed at the beginning of the quarter, our second quarter interest cost per inch DFA would've been 36 cents per Mcf <unk>.

48, <unk> rate in the first quarter net.

In addition to lowering our cost of capital. We also improved our weighted average maturity of our senior notes to 7.6 years up from 6.3 years I'll now turn it over to roll on to review the financial results for the quarter in more detail Roland.

Alright, Thanks Jay.

On slide 5 we summarize our reported financial results for this debt recently completed second quarter, we had a solid quarter and it was driven by that 6% production increase in combination with stronger oil and gas prices than we had last year.

Oil production for the second quarter totaled 100.

Our total production for the second quarter totaled 124 Bcf.

As natural gas and 362000 barrels of oil.

Like Jay said this is 6% higher than.

We had in the second quarter of 2020, and it's an 8% increase over where we were in the first quarter of this year.

Our oil and gas sales as a result, including.

Realized losses from our hedging program increased by 40% to $325 million.

Oil prices averaged $55.82 per barrel.

And our gas price averaged $2.46 per Mcf.

But the best efforts, including the impact of our hedges.

Natural gas prices were 31% better than we realized last year in the same second quarter of last year.

Remember that Nymex, the Nymex contract for the quarter only average $2.83.

I know the recent.

Run up in gas prices is really.

You'll really see those numbers starting in July forward.

Looking at the cost side, our production costs were up about 6% kind of matching the increase in production, our G&A was down 5% and our are noncash.

Depreciation depletion and amortization was up 18% in the quarter.

Our adjusted EBITDAX came in at $251 million to 55% higher than the second quarter of last year operating cash flow was $196 million, 67% higher.

Then the second quarter of 2020.

We did reported a net loss of $184 million in the second quarter or <unk> 80 per share, but that was all due to a very large mark to market loss on our hedge contracts of $205 million.

And a $114 million charge related to the early retirement of the senior notes from our June 28th refinancing transaction.

Adjusted net income excluding debt mark to market unrealized hedging loss.

And the loss on early retirement of debt and certain other.

Other unusual items was a profit of $55 million or <unk> <unk> per fully diluted share.

On slide 6 we summarize the financial results for the first half.

Of this year.

For the first 6 months of the year production totaled 241.5 Bcf.

That includes 688000 barrels of oil.

And thats about 1% lower than our production for the first half of 2020.

But our oil and gas sales, including.

And he realized hedging losses were $657 million, which is 30% higher than the first half of 2020.

Oil prices for the.

For the first half of this year of average $52.6 per barrel.

That's 22% higher than last year, and our realized gas prices average $2.62 per Mcf both of those numbers.

The impact of our hedging.

And that's up 34%.

Over last year.

For the first half of this year.

Reported adjusted EBITDAX of $513 million, 41% higher than the same period last year operating cash flow was $403 million, 47% higher than last year.

And then overall for this period, we reported a loss of $322.5 million per $1.39 per share again this was due to that.

That's the.

The charges for the early extinguishment of debt related to both the March and June refinancings and debt Mark to market unrealized loss on our hedge position.

Excluding those items, our adjusted net income.

Would be a $118 million.

Profit or <unk> 46 per diluted share.

Slide 7 we recap our hedging program.

During the second.

The second quarter, we had 68% of our gas volumes hedged that.

That reduced our realized gas price at that $2.46 per Mcf a day from the actual $2.59 per Mcf and Cfe, we realized from selling our gas production.

We also had about 38% of our oil volumes hedged, which decreased our realized oil price to $55.82 per barrel versus the $61.25, we actually realized.

All our hedging program resulted in realized losses of $18.8 million in the quarter.

The remainder of this year, we have added natural gas hedges covering 976 million cubic feet per day.

Which is around 70% of our expected production in the second half of this year.

59% of those hedges are fixed price swaps.

But 41%, our callers, which give us exposure to the higher prices we are now seeing.

For 2022 or next year, we have about 40% to 45% of our expected production hedged.

And almost half of those are.

<unk>, 49% are in the form of collars, which give us substantial exposure to the higher prices that were kind of in <unk> for next year.

On slide 8 we summarize.

Got it on activity during the second quarter, and we had a good quarter on this front, we had only 52 million a day.

Shut in during the second quarter, which is 3.8% of our production.

And thats debt.

Debt came down substantially from the 6.4% we had shut in in the first quarter. There really were no significant disruptions due to the storms or other matters in the quarter and the shut ins that we had were very routine and related primarily to production to be shut in to conduct offset frac activity.

On slide 9 we detail our operating cost per M. Cfe.

We had a good quarter there are operating cost per Mcf per day averaged 54 in the second quarter, Yes that was 1 set lower than the first quarter rate gathering costs were <unk> 25.

Taxes 8.

On the other lifting cost in the field or 'twenty 1.

Very comparable to the first quarter rates.

Slide 10 on corporate overhead per M. Cfe that again came in at <unk> in the second quarter is 1 of the lowest in the industry and again very very consistent to what we expected and what we've had in the past.

We do expect cash G&A to remain in this 5% to 7 <unk> range kind of going forward.

Slide 11.

Net depreciation depletion and amortization per Mcf a day produced.

That came in at 96 cents in the second quarter. It was <unk> <unk> higher than the 95% rate we had in the first quarter of this year.

Slide 12.

It's a picture of our balance sheet at the end of the second quarter and it.

And it reflects our June 28th refinancing transaction, which closed right at the end of the month right at the end of the quarter.

So we ended the quarter with $475 million drawn on our revolving credit facility, which is a $1.4 billion borrowing base.

We expect to continue to reduce that as we generate free cash flow. The rest of the year. That's really free cash flow is being really designated to continue to reduce our debt.

We now have.

In total about $2.4 $5.9 billion of senior notes outstanding. They are comprised of $244 million of the 7.5% senior notes, which are due in 2025, we assumed as part of the Covey Park acquisition.

125 billion of that of news.

6 and 3 quarter senior notes due in 2029 debt, we issued in March and debt and then the new $965 million of Nu.

5.

875 senior notes due in 2030 that were issued right at the end of the second quarter.

We currently plan to retire the debt.

$25.7 5% bonds.

Probably sometime early next year just.

Using targeting the free cash flow that generated and using that as a permanent debt reduction move by the company.

We do on.

On Slide 12, you can see our new revised maturity schedule and so you can see now that our weighted average maturity of our senior notes is now.

7.6 years after the recent refinancing right at the end of the second quarter.

So we're in great shape on the maturity schedule and as Jay pointed out has substantially improved our our cost of capital and generated substantial annual interest savings on the.

Otherwise would be.

They would have to go for fixed charges on our debt service.

So we did end the quarter with about $20 million on cash on the balance sheet. So our current liquidity is.

At $945 million.

Slide 13, we recap the second quarter capital expenditures.

So in the second quarter, we spent.

$165 million on our development activities and 154.

<unk> 4 million of that relates to our operated Haynesville shale properties.

So we drilled 21 or $15.7.

Net operated horizontal Haynesville wells, and then returned 16% or $14.2 net operated.

Yeah.

Haynesville wells to sales in the recently completed second quarter.

We also spent about $10.9 day on non operated activity and other development activity.

In addition to funding our development program. We have also invested $7.6 million on leasing new exploratory acreage.

Given the tremendous success of that leasing program, we have decided to increase our budget.

A maximum of $20 million to spend on.

On.

Putting new leases and to support our Haynesville shale drilling program in the future.

As we're seeing very good opportunities to do that at attractive terms.

So right now as Dan will go over in a minute. We're currently operating 5 operated drilling rigs for 2021 program and we see kind of maintaining those 5 as we look ahead into 2022.

So we're at a very good consistent level, we think is right for the company.

So based on this current operating plan.

We expect to spend about $525 to $560 million.

On this year's drilling plan, which will drove 55 net wells and turned to sales about 48 net wells.

This is a small increase from what we expected at the beginning of the year. Most of that is really due to changes in the timing of when completions happen.

And then also higher than expected non operated activity.

We definitely are very focused on generating significant free cash flow and with the current gas prices. We now anticipate significantly exceeding our original target of $200 million of free cash flow for this year.

We'll use that incremental free cash flow to accelerate the delevering of our balance sheet.

So now I'll turn it back over to Dan to kind of reported on operations.

Okay. Thank you Roland.

Overall on slide 14, Youll see the map outline.

On the summary of our new well completions since the last call. We have turned 21, new additional wells to sales.

The 21 wells were tested at rates ranging from 15 million cubic feet, a day up to 32 million cubic feet a day with the 22 million cubic feet per day.

Average IP rate.

The wells on lateral lengths ranging from 4580 feet on all the way up to 11388 feet and we had on average for the quarter on for this list of late sales.

251 feet.

So in addition to the wells we have listed here with currently has 13 additional wells that we have in <unk>.

Various stages of completion.

Regarding the activity levels. This past may we did drop down from 6% to 5 rigs that's where we are today, we intend to hold our activity flat at this level for.

For the remainder of the year on into next year.

Our official DUC count currently stands at 23 wells and we're currently.

Actively run and 3 Frac crews.

Overall slide 15 is an updated D&C cost drilling for our benchmark long lateral wells. These are our laterals greater than 8000 feet in length.

Through the end of the second quarter, 73% of all the wells turn to sales. This year have had Dan long lateral wells.

During the second quarter, our total D&C costs averaged $1051 a foot. This represents a 3% increase compared to the first quarter.

And is 2% higher than the full year 2020 total D&C cost.

Our drilling costs in the second quarter increased by 7% compared to the first quarter.

This was primarily attributable to a lower average lateral length versus the first quarter.

But still 15% less than our drilling cost in 2020.

Our completion costs remained relatively flat with only a 2% increase from the first quarter.

But we're still running 16% higher than 2020, and this is due to the large number of the smaller products that were pumped in 2020, which led to the lower cost last year lower completion costs.

For the remainder of the year, we expect our completion costs will remain relatively flat and we do not foresee any material increase in costs.

So by building on our basin, leading drilling performance and keeping our current completion cost in check we expect to maintain our total D&C costs for our bench Mark long lateral wells in this <unk> thousand and 25050 foot range.

I also want to add that we're currently drilling 215000 foot laterals that we spud in June.

As a first for the company.

We expect to complete these wells during the fourth quarter.

We also have 2 additional 15000 foot wells that we will spud later this month.

That will be completed in the first quarter of next year.

These are these longer laterals are going to help bolster our efforts to further increase our lateral lengths in the dropdown our footage cost.

Dropdowns, which cost further than where we've been.

So that summarizes the operations I'm going to turn it back over to Jay to summarize our 2021 outlook, Okay, Dan Thats, the shortage, which usually about 10 pages we've convinced it.

That's good reports and drilling the same here, we'll conclude before we open to questions.

If you looked at the 2021outlook.

I'd like to direct you to slide 16, where we summarize our outlook for the remainder of this year.

Our operating plan for this year is expected to provide for.

Around 8 to maybe 10% production growth and most importantly generate in excess as Roland said 200 million on free cash flow and maybe a lot more than net and on <unk>.

Our focus this year is to improve our balance sheet.

Reducing our leverage and lower our cost to capital, which we've made great strides on net.

Our June refinancing transaction was another significant step to reducing our cost to capital with the $28 million of annual savings and interest payments.

Now, we will primarily focus on absolute debt reduction and we will seek to retire as Roland said, our 2020 pop bonds with free cash flow that we generate to rest of this year.

If natural gas prices stay at current levels, we would expect our leverage ratio to improve to less than a 2.5 times debt to enter 2021 down from 3.8 net down to 2020 based on our current plans and.

And the price outlook, we would anticipate our leverage ratio further improving it.

And 2 times at the end of 2022.

We remain focused on maintaining and improving our industry, leading low cost structure and best in class well drilling returns.

Our industry, leading low cost structure, our haynesville drilling program generates some of the highest drilling returns in all of North America on <unk>.

Large inventory of Haynesville Bossier drilling locations provide us with decades of drilling inventory.

We will also focus on lowering our greenhouse gas emissions and are currently evaluating participating in 1 of their programs to certify our gas as responsibly sourced.

And we have very strong liquidity as Roland mentioned that day.

$945 million.

So Ron I will now turn it over to you to give any specific guidance for the rest of the year wrong.

Thanks, Jay on.

On the guidance page.

We just update the guidance for the remainder of this year.

Guidance remains at the $1.33 to 145 Bcf per.

Per day.

The number that we had previously provided as mentioned on the call our development Capex guidance.

Is $525 million to $560 million and we.

We anticipate on remaining at the 5 rigs that we're currently running over the remainder of the year and at the same time as mentioned earlier, the leasing capital has increased to $15 million to $20 million.

As we continue to add add acreage on the cost side LOE GTC really all the cost items remain unchanged from from the prior quarter and so there is there as we continue to hit all of our targets on the cost side with that I will turn the call back over to the operator to answer to answer.

Your questions from our analysts.

Thank you as a reminder to ask a question you will need to press star 1 of your telephone.

Thank you for your question press the pound key please standby, while we compile the Q&A roster.

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

Thanks, and good morning all.

Good morning.

With by my first question I wanted to focus on your revised 2021 capital budget with the understanding that nearly 40% of the revision was focused on leasing which is arguably the most accretive dollar you could spin could you help frame the remaining components of the increase on the development side.

Sure Derik debt that's a good question.

Yes, it's on.

Modest increase despite.

Overall, but it's really what we are seeing is given that the higher prices in the haynesville, obviously seeing more non operated opportunities we've set a very high bar.

<unk>.

And certainly the ones that have very high returns are we participating in and ones that have a lower return, we actually have been able to sell down to other other investors.

Unfortunately, a lot on have a very high return so yes.

Yes, I'd say its hard to late.

To not participate in that.

We don't really control that level of activity and they'll get great notice on it but given the difference between this year and last year you can understand why that's happening on.

The operating side, where we do control that.

We have a lot of that day.

Actual dollars really depend on when you complete the wells.

We have a consistent drilling operation now and Thats stayed relatively.

The same and we've actually probably achieve a little bit quicker drilling times. So it's really the time and that changes all the time based and so it just really when does the completion dollars fall to they actually hit this year do they go into next year.

It can it can actually be the difference between 10 or $20 million very easily on our budget and we're constantly looking at that I think ron's credit we've also.

Probably.

The past kind of looked at our projects and put them into 3 buckets.

5000 foot laterals, so 7500 foot laterals to 10000 foot laterals and budget it that way and I think we've kind of developed now a very very very exact formula now that takes the exact footage and.

And comes up with really a better estimate and especially when wells fall in between those different numbers. So.

So we do see that working really well now and as and since we.

It's telling us kind of on the numbers that he's giving you guidance on we want to be transparent and communicate that.

Yes, my only comment there is efficiencies.

We manage them, but they've moved.

Forward, probably moving forward quicker than we want so we've tried to manage that.

Being very selective on non op opportunities and then.

Managing 96% of what we own usage BP. So we manage this drilling program, we've kept the rig rig rig count flat.

I think Dan has done a really good job historically on on the completion side you can see that's pretty predictable now on to the drilling side. We've done a lot quicker. So you can move a bunch of these wells forward. That's why we have more ducks today, although we normally have.

But we did increase that budget, a little bit and some of that.

Just adding acreage, which we think will be accretive to comstock into future.

Great makes complete sense to me and really as my follow up I wanted to build on.

Rowlands comments and focus really on the trajectory of your D&C costs per lateral foot.

Referencing slide 15, it makes sense to me that D&C costs are higher per lateral foot when there when youre drilling shorter laterals.

As you look out into the second half of 2021 and further out in the 2022 and laterals will approach 10000 feet.

How should we think about the trajectory the trajectory of your D&C cost assuming a flat price.

Cash activity environment.

Well, if you look at that.

10 to 15000 foot remember, we've got 215000 footers.

We think that again.

It's a little early to predict it but we think those cultural component will be well below $1000 a foot.

A great example is looking at the first quarter and second quarter.

The first quarter happened to be dominated by wells that averaged over 11000 feet and you saw that you can see the impact on the debt.

The significant savings there from the longer laterals so.

As we continue to get more long laterals into the mix.

We can kind of go back to averaging closer to where the first quarter was if we could have that type of lateral.

In excess of 10000 foot lateral average.

Late in the wells being completed.

Dan <unk> you might could comment yes, so we got.

So the comment about the longer laterals. So we got a lot more longer laterals on the pipeline, especially over on the Texas side, where youre not confined by.

123 sections, 1 of those 3 buckets.

And obviously, that's our goal is to get to get longer.

We're already have several wells coming in at below $1000, a foot and if we can get that average upper I mean, we're going to get that number lower as far as performance I think we will still see some slight improvement there I mean I think we're ahead of the back in the Haynesville on drilling times.

Starting probably in the end of 2020 through today, we've shaved off on average of 10 days off our drill times from.

2018, 2019 early 2020 average so.

That's already.

<unk> given us the numbers that we got here.

And.

Then you just got the cost increases from the market on the service cost what are those going on.

We think between now and the end of the year I think those will be relatively modest so.

But next year.

At the higher prices I mean, we know there will be theres going to be upward pressure on prices is just going to be how much well, we will see some inflation on steel and cement and kind of those products. I mean, we will see we've kind of worked into numbers a little bit of some inflation for service costs.

Not particularly on the drilling side, but maybe the completion side.

Very helpful. Thanks for your time guys.

Thank you. Our next question comes from Matthew Harrison with Piper Sandler Your line is open.

Good morning, and thank you for taking my questions.

So good morning first question. Good morning. My first question is on gas differentials. So in Q2 your return to your historical differential range of the mid <unk>.

I was wondering if you could talk about your expectations into Q3, and Q4 and also into 2022.

If I recall correctly you had.

Had some gas being redirected toward the Gulf coast and away from <unk> and I'd like to get a better understanding of the impact to the model.

From.

New arrangements.

Alright, yes, it's a good question.

Obviously, we had the benefit of that.

The premium winter storm prices in the first quarter that that debt.

Sure.

Gave us a much attractive differential on the first quarter back to normal as we thought we would be for this quarter third quarter, we expect to be very similar.

Fourth quarter is when what you alluded to is the.

Hopefully improved marketing opportunities with the Acadian extension, becoming coming into service. It's still planned to come in service in October and we hope to be able to move additional gas.

Away from the <unk> hub, which is kind of that's kind of where you get this kind of $25.20, <unk> kind of differential.

Into a market, that's probably potentially <unk> better.

Now we already have gas.

So will it be moving some percentage of our gas that way and we kind of expected like right now 60% of our gas is really tied to that parallel hub. So it's the major.

That number actually drops down too.

40% kind of hopefully in the in the first and the fourth quarter and definitely into next year. So yeah that has the potential to.

To start shaving the differential down.

Sure.

So we don't really those on.

All moving market, so we don't want to.

Give you an exact number because we can't because all of those markets are could move different directions, but we do know it today youre going to pick up.

Anywhere from 5% to 10 cents on that gas, we're able to move away from <unk> fell down to selling net add.

At our Gulf Coast hub, including <unk>, which will be the new hub that's available to us in that market is just now starting to trade in and we will get more clarity on.

On where that hub is going to trade at.

That's great. Thank you for the color.

Then my next question.

It relates to cost inflation.

You had already you had just shared some detail on some of the pressures that youre seeing today.

As you think about 2022.

Do you have a rough guesstimate of how we should be thinking about cost inflation in aggregate.

A large a large Permian player had throw now 10%.

I would like to get a sense of how you guys are thinking about it.

Yes, I think so just to start off with what we've seen to date, we really hit we've seen we have seen.

If he really small ones and they've been really small like 5% and less so for this year our swaps I think we're pretty good next year.

Based on where we think the markets are going on I think next year, we'll probably on average be little higher than I think 5% to 10% probably is a pretty good number.

We haven't got any indicators from many of our providers that anything really major is coming.

I think just at the macro level Sahara activity. We just you just have to know that it's there but.

I, certainly don't see anything over 10%.

No and again, we see capital discipline, we don't see.

On a whole lot of rigs out there, particularly on the natural gas side. I mean, there was 103 rigs I think drilling for natural gas in the United States. So we don't see that increase I mean, so if it was in a frothy days before Covid you might expect a lot of new rigs.

I think right now with this capital discipline.

We're just not going to see runaway inflation on our side now cost of our our commodity has gone up.

The commodity price had gone up I mean, we probably wouldn't have as many rigs.

Being utilized today, both on the oil side and the gas.

Thank you just going to be it's going to be moderate to be controlled.

And it will probably be a net 5% to 8% range. That's our that's our number and that includes again steel includes some manage includes 2 pillars.

So on inflation on those costs.

Thank you for that that's great and then a final 1 from me if I may.

Just wanted to ask about consolidation just wanted to hear your latest thoughts on.

On consolidation within the Haynesville Bossier area.

Where youre at where your appetite currently is just just any thoughts on I appreciate it. Thank you.

Well I think <unk>.

All of the consolidation I think size is important but also think.

So I think I think Youre high margins.

And your low cost.

Sure.

Probably more important.

And everybody is seeking the kind of the denominator is locations.

Some of these companies.

You have to consolidate because you're running out of locations.

The beauty of Comstock is 2 years ago, when we bought Covey Park for the $2.2 billion and they were larger than we were.

We added those locations with iron locations with the locations.

We've been adding with this leasing program to <unk>.

Have the 19 <unk> hundred 2000 locations in luck.

But we're on a roll of Dan said Departmentalized on those to 5000 foot laterals 75.110000 foot.

So if you are looking at Comstock needing to do some tuck in M&A for locations. You can you can extend box because we don't need to.

If youre looking for Comstock.

<unk> upped our management, particularly from the drilling side and completion side I mean, we drilled and completed more of these wells on anybody.

So you probably don't need to.

The only reason that we would do any M&A transaction is that the.

The acreage is equally as valuable.

And our cost structure materially improves.

And quite frankly, the Jones family owned 60% to 68% of the company.

We would have to be blessed by them.

Because I think what they've invested in right now is delivering great returns per.

<unk>.

On the used size is important.

But the footprint that we have here the Gulf coast with the with the demand for LNG to Asia and Europe.

With the lack of firm transportation commitments that we have and how margins I mean, we're not seeking to do something just to get bigger period.

But we're way beyond that were in great shape on maturity schedule, we were fighting net for a while the expense.

<unk> bonds, we were fighting net for a while.

The series a preferred we refining net for a while.

The 30 million shares or so.

That was issued to.

Private equity was kind of out there is an overhang we secured debt.

We've consolidated the personnel, we're not looking to do that again, we got through the COVID-19 year with lower prices.

We had stretched our RV yield with Covid transaction now we have $945 million.

I mean, we're setting in a sweet spot with solid production upside solid EBITDA growth and stronger than expected realized pricing.

And our hedging into 2022.

Can you can you can not like it.

But I think thoughtful management with the balance sheet, we have on.

Half of our hedges.

<unk> 22 or swaps have program for call on some of those callers go to $6.

We've average like $3.50, 60, whatever but I think it's a safe.

Program in 2022 so.

No, we're not aggressively fishing or looking for anybody now.

The opportunistic sure we are sure we on.

But.

I think it needs to be colored in that line.

Thank you. Our next question is from Charles Meade with Johnson Rice. Your line is open.

Good morning, Jay and Roland on the rest of the team there.

Hi, Charles.

Jay I wanted to.

Pick up a little bit on the theme you were just touching on with locations and ask you about the Bossier.

I think back it was year.

Ours ago, you guys drilled some of the first.

Some of the first really good Bossier wells, it really opened a lot of People's eyes, but.

Since then <unk>.

Is that you guys are really really just focused on the Haynesville zone.

And in the last.

Last couple of quarters have been a few capital markets transactions with.

With other companies, who have half of the remaining locations are more than half of the remaining locations.

In the Bossier, So can you.

Can you give.

And as much details you'd like.

Our view of how how you see the Bossier versus the.

The haynesville both for.

The industry as a whole and this kind of in this footprint of northwest, Louisiana and East Texas.

For Comstock specifically.

Yes, Charles I don't know, how many times, we've met with you face to face to face on how many companies you cover but.

Behind closed doors I think her name is nicknamed design Stein.

To ask the question.

Pretty incredible because we hadn't bought it up we didnt ask anybody to bring it up we don't ask you to bring it up okay. The whole audience station no debt, but if I'm going to turn this over to Dan because he is supposed to be the <unk>.

But I want him to tell you about the 2 Bossier wells that we just just the single best wells were drilled in the quarter nobody brought that up on thank you sniff. It out and then probably half of our locations for Bossier and as you asked on our outside consulting groups.

They really love the Bulge, if you look at a buy in IPO have further upside with Bosch. If you look at Indigo was Bossier, we don't really talk about <unk> that is a great. Great question I won't color with Macquarie on I'll give it to Dan So Dan and you go to slide whatever day in and get over debt Charles Please not youre correct on injection.

Anything, but the correct.

It's below 1.

Yes Charles.

Which I didn't mention it earlier, but on <unk>.

<unk> 2014 on the list of the wells those too.

The best on the App.

We had at the bottom there on our Arrington wells, which are you can see on the map and other further down south or in screen Paresh. Those are in fact, 2 bossier completions. They are the only 2 bossier completions on that list.

We do like the Bossier.

Obviously, it's the southern half of the.

Players, where the Bossier exist and.

The 2 I think this was in the last quarter the 2 longer longest laterals. We've drilled to date are at <unk> 513000.

So that 12500 foot tests, which also Jordan well.

That was a bossier.

Brought there on the acreage on the Desoto Sabine perished border.

And also these next 215000 per laterals, we're getting ready to drill later this month are going to be motors. So.

So we do like the Bossier the Bossier is good.

Charles will remember you go back we kicked off of <unk> and 2015, we've announced to the world. We're just going to drill Haynesville slash Bossier wells, we drilled 9 Haynesville wells in 2015 and in December of 2015, as you well know we've drilled the first Bossier, well, which is the Jordan well on it kind of its.

It's parked all the interest as a public company revenue reported in detail. It did sparking interest and report the Bossier play.

So we're really excited about these 15000 foot laterals.

They will be challenging.

We've got a great drilling recipe.

Of course, a 15000 foot laterals.

Have to get back up the learning curve, a little bit I mean, theyre not routine by any means.

<unk> on the other wells, but.

That's kind of in this kind of our plans as we get these 15000 foot laterals down.

We plan to develop much of our Bossier with those long laterals, yes, just to add 1 more comment on that Charles is that that's what other things we've been thinking about the Bossier too as we work to migrate to the 15000 foot laterals. The Bossier is relatively undeveloped on our acreage and theirs.

A lot more room to do longer laterals, we can convert at a much higher percentage of our voucher inventory into that.

15000 foot laterals.

Can realistically on the Haynesville acreage so that's.

And that also enhances the return so we've been thinking about that more long term because we just have so many wells to drill it's such a large inventory.

It's Ben.

It's been hard day to go to all the different place yet, but it's a great part of.

The inventory and I think the market started to realize that in some of the best wells in the play that are coming out of the Haynesville operators, our Bossier wells now well, it's all going on.

Non op opportunities have been Bossier.

Yes. It is.

Surfacing.

Well, that's a lot of great color guys I appreciate that.

Brian Squirrel funds on Acorn every now and then.

But.

Let me ask another kind of more.

Maybe probably less interesting question.

Is it.

I look at the strip and <unk>, which we still got this 65 drop between March and April and it's been there for a long time on.

Frankly, if you'd asked me a couple of weeks ago or a couple of months ago. Almost said, we'll book Thats going on at those are debt debt spreads have tightened the calendar expense going after partners get closer, but but it hasn't so I'm curious does that.

Does that shape of the curve index steep drop we see.

In the fourth month of or in April of 'twenty 2.

Any of your.

Planning or any of your decisions either either near term or longer term.

Well, that's a good question and I think thats debt debt nature of that is really just the speculation in the gas market in the probably the tightness of the market and the fear that gas could be.

It really short and that does winter months there.

On the longer you go out on the gas curve the less speculations out there so.

A lot of it is going to be.

Out there until winter really kind of shows itself.

So it's kind of hard to plan around that I mean, you could have said you could have looked at that last year and made the same comments that the first quarter of 2021 was going to be what you really want to try to get your gas on line.

January through March it turned out not to be a great strategy because those are going to be some of the lowest price.

So this year of 'twenty, 1 so it's really hard to.

They look at the curve and derail toward it.

We do see that overall, though.

Over the last months, you've really seen that 2022 futures prices improve greatly where they had been stuck at a level that was below 21 for a long time. So a lot of it is just the market trying to figure out what's the supply demand kind of look like later this year and theyre still filling that out so.

We feel great about the gas market.

And.

Producer discipline, that's been a big component on Charles as you looked at them in the next 7 months, we're looking on the strip right now gas is 418, all the way to 400.478 months out.

And then a drop to the $3.37.

If you told me 3 months ago on a 337 natural gas on the Haynesville, well that'd be pretty happy on like for better, but it looks pretty good. So we did front end load 2022, as you look at the hedges to make sure we.

We have really good quarter in the first quarter of 2022, 2023, and I think the other thing we did.

Because of our balance sheet.

I think we properly risk adjusted our hedges.

In hindsight I wish we didn't have any hedges on how businesses are run I think in a moment yet to put whatever the hedges, which was a swap port color and I think we might have a good business decision.

That is to have half of 'twenty 2 in a swap with solid.

Okay something did go those out but then also has the caller digit gas hits poor pumps $6 to get a lot of debt.

And I think our budget is good we've answered the question about on.

Models when you when we when we said that we have 5000 foot 775 on foot 10000 foot laterals, we have done in both the Haynesville and Bossier. So when we start kicking off diesel how long laterals on the Bossier. We also will have those models out too.

And we can talk of this back.

If we need to accelerate a little bit and convert some of the the ducks into PDP I think we're going to be able to do that I think we are going to be able to pay off the coffee bond. If we can do that then our car interest cost per Mcf per day continues to drop.

Wasn't that many quarters ago were 52 cents per <unk> now with 36.

We need to get a 2 well debt not a tree.

We're we're going to we're going on when.

When we opened this third and fourth quarter operating they look really really good I know, we're talking about the second quarter <unk>.

But the second half of the year it looks like it looks like.

But we should really capitalize on all time high corporate production here of natural gas production for.

With a really really favorable natural gas price.

Yes, we see the same thing Jay debt all of that insight is helpful. I appreciate it.

Thank you.

Our next question comes from you may artery with Goldman Sachs. Your line is open.

Hi, good morning, and thank you for taking my questions.

Yes, Sir.

My first question is on your plans on absolute debt reduction.

As you mentioned gas futures on way day favorably.

And if it holds you can potentially generate free cash flow from below $200 million.

You have $47 million outstanding on our credit facility can you talk to your plans to address the remaining maturities.

And once you went to pay down debt borrowings under our credit facility and also if you can talk to your thoughts had on cash are going to shareholders and the right absolute debt level at Mitchell.

You plan to deploy cash back to shareholders.

Those are great questions.

We are now that we've kind of got the cost of the long term debt down and got the maturities.

Great spot, it's really focus on the debt reduction we do have a significant amount of debt that we can retire debt bank facility debt, obviously and then the <unk>.

We purposely did not refinance the.

The remaining.

Bonds outstanding.

Because if we thought that was also a good target for debt reduction so.

Our plans are.

Sometime probably next year or 2 to redeem the remaining 7.5% bonds, we obviously want to.

Create the free cash flow and pay on the bank facility first and then retire those bonds next.

And so that is that over the next couple of years. It gives us a lot of pre payable debt net debt can help us achieve our overall.

Debt reduction goals.

If you look through the windshield our goal in 2014, we gave a dividend.

We're not nearly there in giving your dividend and I think you have to look through the windshield and say where you're going.

And with these higher process I think we can get this leverage down we get the leverage down.

A 1 handle on at 160.700, I'd just take a number and.

We're properly hedged.

I think.

I think I think it would be nice to have aboard moving and say Hey, you know what.

These are real Benjamin.

We're going to go back to the stakeholders are going to be not only a dividend, which you can do with the pioneers of world and start doing on a variable I think debt on.

I think debt is absolutely a possibility within the comstock structure because of where we're located again the demand for our gas <unk> gas to.

Europe and Asia.

And the demand growth as far as these export facilities are being built.

And the fact that we havent encumbered our gas.

Some kind of a strange firm transportation commitments that are below market or our minimum volume commitments that are owners.

So we are absolutely looking at to long balls in the next 18 to 24 months.

And at the same time on our leasing program.

Every year, we drilled 50.60 wells, we try to replenish that with 50 to 60 more locations. So that has to go no I don't want to spook, the bondholders downers anybody coming on.

Never going to be financially reckless periods, you can forget that we are going to be financially aggressive and then once we get this debt pay down and we've got these maturities long it'll have to bondholders have the equity owners and help the analyst and help us so.

So we're all in kind of in the same barrel together.

That's our goal.

That's helpful.

And I guess my next question was that on hedging can you remind us the minimum percentage of production you need to hedge but your covenant and also I wanted to get your thoughts on future hedging.

Sure Yes, yes.

Yes, we're currently required to hedge 50% of our of our proved developed producing reserves at each borrowing base redetermination. So.

That's twice a year so.

Whatever that.

On that next 12 months.

Now usually if you look at our production outlook, 100% doesn't come from proved developed producing reserves at that time so yes.

On a 40% of our expected production.

No more than 45%, yes, we do we do need to hedge in some form it could be in the form of a collar in order to satisfy the credit facility as it is our covenant currently stand. So we're yes, we're at those levels for that next step.

<unk> already.

For 2022, if we choose not to putting more hedges on at all.

So obviously been a huge run up in prices.

We.

We think we're adequately hedged for next year.

No.

I can't tell you, if we're going to add anymore or not but I don't think we will be hedging.

At a real high percentage level of 22, right now based on how we see the outlook.

Great. Thank you so much.

Thanks for your question.

Our next question Bert and Dennis with Truth Bank. Your line is open.

Good morning, guys.

I was wondering in the prepared remarks, you said youre going to hold production flat and I just wasn't sure exactly with the lower spend in the back half whether that might kind of drift down in <unk> and <unk> 22, and then maybe back up in <unk> or <unk>.

Maybe it will truly be kind of a flattish profile.

I don't think day, when you talked about holding production flat, we actually talked about in the.

Basically this year is kind of a.

We're seeing about 8% to 10% growth in production.

We have not really set the goals for 2000.

2 yet and.

And so.

Yes in fact debt that's what we said on the final slide I mean, youll see its on 8% to 10% production growth.

That's what our operating plan calls for.

Alright.

Back half I thought.

Heard you guys, saying that maybe towards the end but.

Either way it is the lower activity, though if there's some sort of quarterly cadence or you just.

You don't want to get ahead of yourself and talk about that yet.

Well I think obviously that youre going to see the third quarter.

That's kind of that at the second half of the year is the higher production levels. So we will see higher production levels in the second quarter level Thats coming up in the next 2 quarters.

But thats a good question.

We're not going to try to pick production to drop at all we're going to trial on level of that on a model in 2022 I think.

We have we have management discussions on that too I think.

What we said today is that we.

Actually we front end loaded debt Capex, we know we have that but we've got a lot of ducks that we can complete.

Can shifts on Capex dollars rounded complete total Doug but today.

$4.410, $20 gas, we actually already on a corporate high on a record natural gas production hedged Comstock and were selling at a higher natural gas price, but we're going to we're going to monitor that in 2022, we won't we don't expect to have.

Peaking on a drop off.

On our goal either.

Okay. That's perfect and then really just my only follow up.

With the higher gas strip I know you guys, maybe talk about cash taxes before being pretty far out there, but just wanted to wondering if you guys could read into that.

Yes, I think we still have a lot to get tax attributes switch.

Yes.

Well to us and.

So we don't really see cash taxes VNS.

Really put out on the radar screen.

For the next several years.

And our goal really is debt.

We try to maximize our taxable income to us.

Carryforwards that we have.

We want to be able to use before they expire.

We have a little bit of.

Just do the structure have a little bit of state cash taxes, Thats, all we kind of see right now.

But that's a fairly modest amount compared to the income we have.

That's perfect. Thanks, guys.

Thank you.

Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

Hey, good morning.

Morning.

Just had a few things.

With the success you've had on the leasing side I was just curious where.

Where those leases that you had had your eye on for a long time, where they something that.

Expiring came available.

Just at this stage in the play's development.

A pleasant surprise to hear that you still can.

Put together significant additional leasing.

This is a result of the combination of <unk> and Comstock when you put the land groups together and then you see what's kind of floating out there that would be accretive to us in the future.

And then we didn't go forward on those programs at all for a while until we had the consolidated management team together and then we said okay. Here are what we call low hanging fruit in our opinion. So we go out and then we spent quite a few dollars on it but we.

It's very favorable.

The terms on the leases.

Great.

Thanks and.

On.

I was also.

Just thinking about the comments you were just making.

And as far as.

Yeah.

Overall efficiency in the cost environment, where do you stand as far as the contracts on your on your Frac spread.

Do you have a horizon past what you have to.

Negotiate on rates or is there.

Or sort of built in.

Newell available to you on what you are paying now.

But of course part of it.

Is that remember we do have 1 new 3 year contract we've locked in the pricing on the new tightened fleet next year.

It goes into service in January so thats.

That has been fixed for 3 years, and then Dan you can kind of talk about the.

We probably need in addition to that we will need 1 to 2 more frac crews.

Yes, so that's right. So we got the bj's, providing the kind of on the Alterra, but natural gas fleet that will start statistic weighted the crude will show up and start worrying about January 1 and it is fixed for 3 years, which we think on.

The current outlook, that's that's going to be a great deal for us the other the conventional fleets.

They typically we have cost.

Their contracts and they day run through the end of this year, but they didnt have language in there where they can make price adjustments depending on what the market's doing so.

On that sense, they're not locked down solid like this like our natural gas fleet will be.

Gotcha. Thanks.

And.

The 32 million a day IP that you.

You had in the quarter I was wondering is is that a record for the company and I was also just curious kind of where you stand on choke management. These days.

So no thats not a record for the company.

But I think a record for the company.

It's up in the mid I think about 36% or 37 million a day is the highest we've ever we've ever shared I mean, obviously, we have wells capable of doing more I think that's the highest we've ever reported.

Management.

Basically we.

Even more so on the higher price environment, we basically hold on hold the rates flat at a high rate until I get down close to line pressure and then basically.

They will start decline on all familiar in that kind of front end load our production and gets us gets us some better return.

Well decline off from month to month 1.

Great.

Okay great.

Brent.

Yes, we do tailor the choke management around the wells pressure performance.

Each well tells us what it can do.

There also could be other.

Our strengths such as how much production can you flow off a pad.

Not every well can always flow optum latest because.

You may have only so much transportation or facilities, you don't overwhelm them.

So we have to manage all of those factors in deciding to flow rates.

Right.

Okay. Thanks, that's all for me.

Perfect. Thank you.

Our next question comes from Leo Mariani with Keybanc. Your line is open.

Yeah, Hey, guys I was hoping you could help out a little bit with your.

Your capex spend here.

You certainly talked about it being more weighted in the first half of the year can you kind of help us with the next couple of quarters should third quarter be sort of at last and second quarter and I noticed you had kind of it looks like just based on the plan for the year kind of not very many completions in the fourth quarter. So as fourth quarter Capex can be down a lot and can you just.

Help us with the trajectory on the spin.

Sure and you can look at debt.

Kind of a.

When level I was looking at the drilling and we were running we.

We were running more rigs.

Through may.

So there is more drilling activity in the first.

January through through May as 6 rigs then down to 2.

To 5 rigs for the rest of the year. There there is also a.

Maybe a couple of months, where we will be actually be running 4 rigs because we've probably got a loan out a rig a little bit again again, just because of the drilling times have been quicker.

<unk>.

Trying to trying to manage overall, how much Henry Ducks, you buildup. So that drilling activity is definitely weighted to the first half the completion activity is weighted more through the first 3 quarters Dan.

Talk about how many frac crews running in the different quarters. So we are currently running 3 frac crews and right now at the end of the year. We got we got dropping down to 1 to 2 frac crews in Q4, and that's basically what's the front end load for the.

For the production profile this year.

And that'll really well.

Obviously youre looking at the current prices that we're at and we do have discussions about do we want to try to pull some more of that for.

<unk> potentially sometimes but but right now we're dropping frac crews towards the end of the year were 3 we should be at 1 in December.

Yes purposely to 1 when we set the budget to say Hey, we want to 1 when you are fracking you have more shut in too so it's kind of a.

Just to optimize.

Production in it.

It's usually the better months.

We kind of designed the program that way.

I think we still.

Right now kind of sticking with that so.

Okay. That's.

That's helpful. I would imagine sorry on the Capex is going to fall all of that activity as you described here.

<unk>.

Yes, I guess, maybe just a follow up I think on the previous earnings call on first quarter, you guys had talked about kind of 3% to 4% production growth in 2020 Q.

Obviously since then we've seen gas prices move up materially you clearly growing a lot faster than 3% to 4% here in 2021 do you have any just kind of early thoughts about how you would approach staying at $3.50 gas price environment. In 2022 is that the type of environment, where you guys would like to maybe leaning a little bit more of a a little.

More growth just because the returns are so good on the drilling or how do you think about that when we plan on keeping the same rig count and we will see what the efficiencies due on the drilling and completion right, Yes, I think.

Well, obviously, we set a goal for free cash flow and again, it's kind of early for us to lock in on to the to.

The 21 program, yet, but right now we're kind of assuming we're going to have these 5 rigs running in.

And yes, it can achieve kind of that that type of production growth you talked about with that program.

So yes, we will continue to look at that debt.

Okay.

But a lot will depend on where we are as we get the leverage down and we will open up opportunities to have other decisions here, but we see the leverage coming down.

Fast in next.

Next year really being under 2 times that our goal for several years.

Definitely want to achieve that before.

Before we start spending it in advance.

Alright, so really just the budget will be design upon price.

Maximizing a lot of that free cash flow and union leverage targets in production and just kind of an output.

Right the production will be a factor, but it won't be the like absolute.

The absolute driver it'll be what maximizes.

Getting to the leverage profile, we want to get we think we have all the tools to get there.

Next year.

So they are right here. So we want to check that box just like we wanted to get rid of those expensive coupon bonds that was the goal. They're gone now so now we're going to focus on overall debt levels and leverage and obviously.

Balance EBITDAX.

Growth with debt reduction is the balancing act on leverage well, we spent a lot of money in 2022 on.

Interest expense per Mcf.

I think we'll get more efficient in 2022 with long laterals.

Price is looked solid so again, it's the same rig count is just efficiencies on.

On those efficiencies along with a higher price of course.

Correct on our balance sheet inflation on our debt.

<unk> RVO and we have really good growth because we have tier 1 area.

So a simple story.

Alright, great. Thank you.

Thank you I appreciate it.

Thank you and this concludes the question and answer session I would now like to turn the call back over to Jay Allison for me.

Any closing remarks, Colorado again, some of you that joined kind of.

The middle of the call.

And again, we're excited about the quarter, but we're more excited about the remaining 6 months of this year.

We did front end load our capex, we advertise that we.

We do have right now as we speak today corporate record natural gas.

Production at Comstock.

And there is a good time to have that because we are selling at high natural gas prices.

So on which you don't know that we've recommitted to cleaned up the balance sheet.

We've got good models that are strong.

Good operations Department.

We are thankful that we have all of us Packers. So thank you.

This concludes today's conference call. Thank you for participating you may now disconnect.

[music].

[music].

[music].

Good day, and thank you for standing by welcome.

Welcome to the Comstock resources second quarter 2021 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 will need to press star 1 on your telephone.

Please be advised that today's conference is being recorded.

Further assistance, please press star zero.

I would now like to hand, the conference obituaries Speaker today, Jay Allison Chairman and CEO. Please go ahead.

Again, thank you for the introduction.

No.

We're reporting on the second quarter 2020, once a day.

No debt.

But we're super excited about what we see for the second half.

This year.

We advertised that we were front end loading our capex in 2021 through the first half of the year, which we did.

And.

Now, we say and actually have it today.

Corporate record high on natural gas production at Comstock.

Selling it.

Natural gas prices.

The world of natural gas looks really solid.

With natural gas trading at $4 range, plus this morning, as I looked on the ticker <unk>.

Especially haynesville dry natural gas. So there is a primary feedstock gas for LNG exports Asia, and Europe as well as to Mexico.

Global demand for natural gas is very strong for industrial power generation as well as electrical demand for cooling and heating oil supply.

His low to moderate in part due to the disciplined use of capital expenditure dollars.

Across the entire oil and gas sector as you're all aware of.

In this earnings season, and our corporate strength lies on our best in class low cost structure, which create our high margins as well as the 19 utter plus net drilling locations where that are 3000.

323000, net acre Haynesville Bossier footprint.

We operate 91% of it.

It was a major task in 2020, 1 was reduce our cost of capital, which we took many steps forward with our 575% senior notes being issued in the second quarter 2021, we do feel the wind in our sales as we look at the third and fourth quarter 2021 and 2022.

And want to recommit to you what our goal of reducing our leverage ratio to less than 2 times that day.

<unk> 2022, or before if possible with our refinancing in place we reduced our interest cost per Mcf per day bye.

About 25% this quarter total.

36 cents on are committed to continue working to reduce debt number by year end 2021 if possible.

Denominator Comstock is our consistent drilling results quarter after quarter after quarter and the tier 1 the Haynesville Bossier region, which speaks volumes about all of our departments, especially our operations department and through our quality Haynesville bow to rock and we have decades of that quality rock.

Net to drill.

No that denominators wide, Jerry Jones, and his family invested $1.1 billion in Comstock Since August 2018, and we believe that is why you the bondholders banks on equity owners back Comstock per.

Moving rock quality proven results over many many years now I'll start the formal second quarter 2021 results oil.

On to the Comstock resources second 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 Comstock resources Dot com and downloading the quarterly results presentation. There you'll find a presentation entitled second quarter 2021 results I'm Jr.

<unk> Chief Executive Officer, 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. If you go to slide 2 please refer to slide 2 in our presentation and note that our discussions today will include forward looking statements within the meaning of secure.

These 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.

We'll go over to the second quarter 2021 highlights but cover the highlights.

The second quarter on slide 3.

And the second quarter, we reported adjusted net income of $55 million per 22 cents per diluted share production for the quarter average approximately 1.4 bcf per day and was 98% natural gas.

Our average daily production for the quarter was 8% higher than the first quarter of 2021% and 6% higher than the second quarter of 2020 revenues, including realized hedging losses were $325 million, 40% higher than the second quarter 2020, adjusted EBITDAX of 251 million.

Was 55% higher than the second quarter 2020.

Operating cash flow for the quarter was $196 million.

<unk> 71 per diluted share for the quarter, we generated $20 million on free cash flow hedge of preferred dividends and increasing our year to year of free cash flow to $53 million.

A good start.

On toward reaching our annual free cash flow generation goal of over $200 million with a stronger commodity prices. We're seeing in the second half of the year. We now expect free cash flow to come in well above that goal of 200 million and lastly, we completed the task of refinancing all of our higher coupon senior notes in the second.

Order, which substantially reduced our cost per capita going forward.

Turn over to slide 4 we recap the refinancing transaction, which closed on June 28, we issued 965 negative new 575% senior notes, which are due in 2030. The proceeds from the offering were used to redeem the remainder of our non and 3 quarter bonds to refinance.

The transaction reduced our reported annual interest expense by $33 million.

We will save $28 million in annual cash interest payments.

Bond with the March refinancing that we did our annual interest payments were reduced by $48 million.

The lower cash interest expense will also drive significant improvements in our cash interest cost per Mcf per day produced as I've mentioned earlier on a pro forma basis, assuming the refinancing was completed at the beginning of the quarter.

Our second quarter interest cost branch DFA would have been 36 per Mcf a day as compared to <unk> 48, right in the first quarter net.

In addition to lowering our cost of capital. We also improved our weighted average maturity of our senior notes to 7.6 years up from 6.3 years I'll now turn it over to roll on to review the financial results for the quarter in more detail.

Alright, Thanks Jay.

On slide 5 we summarize our reported financial results for this debt recently completed second quarter, we had a solid quarter and it was driven by that 6% production increase in combination with stronger oil and gas prices than we had last year.

Oil production for the second quarter totaled 100.

Our total production for the second quarter totaled 124 Bcf.

Natural gas and 362000 barrels of oil.

Like Jay said this is 6% higher than.

We had in the second quarter of 2020, and it's an 8% increase over where we were in the first quarter of this year.

Our oil and gas sales as a result, including.

Realized losses from our hedging program increased by 40% to $325 million.

Oil prices averaged $55.82 per barrel.

And our gas price averaged $2.46 per Mcf a day.

First average, including the impact of our hedges.

Natural gas prices were 31% better than we realized last year in the same second quarter of last year.

Remember that Nymex, the Nymex contract for the quarter only average $2.83. So I know the reset.

Run up in gas prices is really.

You'll really see those numbers starting in July forward.

Looking at the cost side, our production costs were up about 6% kind of matching the.

The increase in production, our G&A was down 5% and our are noncash.

And a $114 million charge related to the early retirement of the senior notes from our June 28th refinancing transaction.

Adjusted net income excluding debt mark to market unrealized hedging loss and the loss on early retirement of debt and certain other.

Other unusual items was a profit of $55 million or 22 per fully diluted share.

On slide 6 we summarize the financial results for the first half.

Of this year.

For the first 6 months of the year production totaled 241, 5 Bcf a day.

That includes 688000 barrels of oil and Thats about 1% lower than our production for the first half of 2020.

But our oil and gas sales, including.

And he realized hedging losses were $657 million, which is 30% higher than the first half of 2020.

Oil prices.

For the first half of this year have averaged $52.6 per barrel.

That's 22% higher than last year, and our realized gas prices average $2.62 per Mcf both of those numbers.

The impact of our hedging.

And that's up 34%.

Over last year.

For the first half of this year.

Reported adjusted EBITDAX of $513 million, 41% higher than the same period last year operating cash flow is $403 million, 47% higher than last year.

And then overall for this period, we reported a loss of $322.5 million or $1.39 per share again this was due to the.

The charges for the early extinguishment of debt related to both the March and June refinancings and debt Mark to market unrealized loss on our hedge position.

Excluding those items, our adjusted net income.

Would be a $118 million.

<unk> or <unk> 46 per diluted share.

Slide 7 we recap our hedging program during.

During the.

The second quarter, we had 68% of our gas volumes hedged that.

That reduced our realized gas price to debt $2.46 per Mcf per day from the actual $2.59 per Mcf and Cfe, we realized from selling our gas production.

We also had about 38% of our oil volumes hedged, which decreased our realized oil price to $55.82 per barrel versus the $61.25, since we actually realized.

Overall, our hedging program resulted in realized losses of $18.8 million in the quarter.

For the remainder of this year, we have a natural gas hedges covering 976 million cubic feet per day.

Which is around 70% of our expected production in the second half of this year.

59% of those hedges are fixed price swaps at 41%, our callers, which give us exposure to the higher prices. We are now seeing.

For 2022 or next year, we have about 40% to 45% of our expected production hedged.

And.

Half of those.

Our 49% are in the form of collars, which give us substantial exposure to the higher prices that were kind of enel <unk> for next year.

On slide 8 we summarize the shut in activity during the second quarter and we had a good quarter on this front, we had only 52 million a day.

Shut in during the second quarter, which is 3.8% of our production.

And Thats.

Debt came down substantially from the 6.4% we had shut in in the first quarter. There really were no significant disruptions due to storms or other matters in the quarter and the shut ins that we had were very routine and related primarily to production to be shut in to conduct offset frac activity.

On slide 9 we detail our operating cost per M. Cfe.

We had a good quarter there are operating cost per Mcf per day averaged 54 in the second quarter, Yes that was <unk> <unk> lower than the first quarter rate gathering costs were <unk> 25.

Taxes 8.

And the other lifting cost in the field or 'twenty 1.

Very comparable to the first quarter rates.

Slide 10 on corporate overhead per M Cfe.

Now that again came in at <unk> in the second quarter is 1 of the lowest in the industry.

And again very very consistent to what we expected and what we've had in the past.

We do expect cash G&A to remain in this 5% to 7 range kind of going forward.

Slide 11 debt.

Depreciation depletion and amortization per Mcf a day produced.

That came in at 96 cents in the second quarter. It was <unk> higher than the 95% rate we had in the first quarter of this year.

Slide 12.

It's a picture of our balance sheet at the end of the second quarter and it.

And it reflects our June 28th refinancing transaction, which closed right at the end of the month right at the end of the quarter.

So we ended the quarter with $475 million drawn on our revolving credit facility, which is a $1.4 billion borrowing base.

When we expect to continue to reduce that as we generate free cash flow. The rest of the year. That's really free cash flow is being really designated to continue to reduce our debt.

We now have.

In total about $2.4 $5.9 billion of senior notes outstanding They are comprised of $244 million on the 7.5% senior notes, which are due in 2025, we assumed as part of the Covey Park acquisition.

125 billion of that of news.

6 and 3 quarter senior notes due in 2029 debt, we issued in March and and then the new $965 million of Nu.

$5.875 senior notes due in 2030 that were issued right at the end of the second quarter.

We currently plan to retire.

The $2025.7 5% bonds.

Probably sometime early next year, just using <unk> targeting the free cash flow that generated and using that as a permanent debt reduction move by the company.

We do on.

On Slide 12, you can see our new revised maturity schedule and so you can see now that our weighted average maturity of our senior notes is now.

7.6 years after the recent refinancing right at the end of the second quarter.

So we're in great shape on the maturity schedule and as Jay pointed out has substantially improved our our cost of capital and generated substantial annual interest savings on to what otherwise would be.

They would have to go for a fixed charges on our debt service.

So we did end the quarter with about $20 million in cash on the balance sheet. So our current liquidity is at $945 million.

Slide 13, we recap the second quarter capital expenditures.

So in the second quarter, we spent.

$165 million on our development activities and 150.

$4 million of that relates to our operated Haynesville shale properties.

So we drilled 21% or $15.7.

Net operated <unk>.

It is on the Haynesville Wells, and then returned 16 or $14.2 net operated.

Yes.

Haynesville wells to sales in the recently completed second quarter.

We also spent about $10.9 may on on non operated activity and other development activity.

In addition to funding our development program. We have also invested $7.6 million on leasing new exploratory acreage.

Given the tremendous success of that leasing program, we have decided to increase our budget.

To a maximum of $20 million to spend on on.

On putting new leases and to support our Haynesville shale drilling program in the future.

As we're seeing very good opportunities to do that at attractive terms.

So right now as Dan will go over in a minute. We're currently operating 5 operated drilling rigs for 2021 program and we see kind of maintaining those volume as we look ahead into 2022.

So we're at a very good consistent level, we think is right for the company.

So based on this current operating plan.

We expect to spend about $525 million to $560 million.

On this year's drilling plan, which will drove 55 net wells and turned to sales about 48 net wells.

This is a small increase from what we expected at the beginning of the year. Most of that is really due to changes in the timing of when completions happen.

And then also higher than expected non operated activity.

We definitely are very focused on generating significant free cash flow and with the current gas prices. We now anticipate significantly exceeding our original target of $200 million of free cash flow for this year.

We'll use that incremental free cash flow to accelerate the delevering of our balance sheet.

So now I'll turn it back over to Dan to kind of report on operations.

Thank you Roland.

Flip over on slide 14, Youll see the map outlines.

And the summary of our new well completions since the last call. We turned 21, new additional wells to sales.

The 21 wells were tested at rates ranging from 15 million cubic feet, a day up to 32 million cubic feet a day with the 22 million cubic feet per day.

Average IP rate.

The wells on lateral lengths ranging from 4580 feet on all the way up to 11388 feet and we had on average for the quarter of before this list debate.

251 feet.

So in addition to the wells we have listed here. We currently have 13 additional wells that we have in various stages of completion.

Regarding the activity levels. This past Monday, we did drop down from 6% to 5 rigs, where we are today, we intend to hold our activity flat at this level.

For the remainder of the year on into next year.

Our official DUC count currently stands at 23 wells and we're currently.

<unk> run and 3 Frac crews.

Overall slide 15 is an updated D&C cost stream for our benchmark long lateral wells. These are our laterals greater than 8000 feet in length.

Through the end of the second quarter, 73% of all the wells turn to sales. This year have had down long lateral wells.

During the second quarter, our total D&C cost averaged $1051 a foot. This represents a 3% increase compared to the first quarter.

And is 2% higher than the full year of 2020 total D&C cost.

Our drilling cost in the second quarter increased by 7% compared to the first quarter.

This was primarily attributable to a lower average lateral length versus the first quarter.

But still 15% less than our drilling cost in 2020.

Our completion costs remained relatively flat with only a 2% increase from the first quarter.

But we're still running 16% higher than 2020, and this is due to the large number of the smaller products that were pumped in 2020, what's led to the lower cost last year lower completion costs.

For the remainder of the year, we expect our completion costs will remain relatively flat and we do not foresee any material increase in costs.

So by building on our basin, leading drilling performance and keeping our current completion cost in check we expect to maintain our total D&C costs for our bench Mark long lateral wells in this <unk> thousand 25050 foot range.

Also want to add that we're currently drilling 215000 foot laterals that we spud in June.

This is a first for the company.

We expect to complete these wells during the fourth quarter.

We also have 2 additional 15000 foot wells that we will spud later this month that will be completed in the first quarter of next year.

Yes.

These are these longer laterals are going to help bolster our efforts to further increase our lateral lengths in the dropdown our footage cost.

Dropdown list, which cost further than where we've been.

So that summarizes the operations im going to turn it back over to Jay to summarize our 2021 outlook, Dan Thats shortens, which usually about 10 pages, we've convinced it.

That's good reports in drone site here, we'll conclude before we open to questions.

If you looked at the 2021outlook.

I'd like to direct you to slide 16, where we summarize our outlook for the remainder of this year.

Our operating plan for this year is expected to provide for.

Around 8 so it might be 10% production growth and most importantly generate in excess as Roland said $200 million of free cash flow and maybe a lot more than net and our primary focus this year is to improve our balance sheet.

Reducing our leverage and lower our cost to capital, which we've made great strides on that.

Our June refinancing transaction was another significant step to reducing our cost of capital with the $28 million of annual savings and interest payments.

Now, we will primarily focus on absolute debt reduction and we will seek to retire as Roland said on 220 pop bonds with free cash flow as our regenerate the rest of this year.

If natural gas prices stay at current levels, we would expect our leverage ratio to improve to less on a 2.5 times debt to enter 2021 down from 3.8 at the end of 2020 based on our current plans and.

And the price outlook, we would anticipate our leverage ratio further improving it.

And 2 times at the end of 2022.

We remain focused on maintaining and improving our industry, leading low cost structure.

Best in class well drilling returns.

Our industry, leading low cost structure, our haynesville drilling program generates some of the highest drilling returns in all of North America on <unk>.

Large inventory of Haynesville Bossier drilling locations provide us with decades of drilling inventory.

We're also focused on lowering our greenhouse gas emissions and are currently evaluating just putting in 1 of their programs to certify our gas as responsible each sourced.

And we have very strong liquidity as Roland mentioned that day.

$945 million.

So Ron I will now turn it over to you to give any specific guidance for the rest of the year wrong.

Thanks Jay.

On the guidance page.

We just update the guidance for the remainder of this year.

Production guidance remains at the $1.33 to 145 Bcf per.

Per day.

The number that we had previously provided as mentioned on the call our development Capex guidance.

Is $525 million to $560 million and we.

We anticipate on remaining at 5 rigs. We're currently running over the remainder of the year and at the same time as mentioned earlier, the leasing capital has increased to $15 million to $20 million.

As we continue to add add acreage on the cost side LOE GTC really all of the cost items remain unchanged from from the prior quarter and so there is there as we continue to hit all of our targets on the cost side with that I will turn the call back over to the operator to answer to answer.

Questions from our analysts.

Thank you as a reminder to ask a question you will need to press star 1 of your telephone.

Thank you for your question press the pound key please standby, while we compile the Q&A roster.

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

Thanks, and good morning all.

Good morning.

With my first question I wanted to focus on your revised 2021 capital budget with the understanding that nearly 40% of the revision was focused on leasing which is arguably the most accretive dollar you could spin could you help frame the remaining components of the increase on the development side.

Sure Derik debt that's a good question.

Yes, it's on.

Modest increase despite.

Overall, but it's really what we are seeing is given that the higher prices in the haynesville, obviously seeing more non operated opportunities we've set a very high bar.

<unk> and.

<unk> said only the ones that have very high returns are we participating in and ones that have a lower return, we actually been able to sell down to other investors.

Fortunately a lot on have a very high returns so.

Yes, I'd say its hard to late.

To not participate in that.

We don't really control that level of activity and I'll get great notice on it but given the difference between the shared on last year, you can understand why that's happening.

On the operated side, where we do control that week.

We have a lot of that the.

Actual dollars really depend on when you complete the wells.

We have a consistent drilling operation now and Thats stayed relatively.

The same and we've actually probably achieve a little bit quicker drilling times. So it's really the time and that changes all the time based and so it's just really when did the completion dollars fall to they actually hit this year or do they go into next year.

It can it can actually be the difference between 10 or $20 million very easily in our budget and we're constantly looking at that I think ron's credit we've also.

Probably.

The past kind of looked at our projects and put them into 3 buckets.

Bob.

Foot laterals, so 7500 foot laterals to 10000 foot laterals and budgeted that way and I think we've kind of developed now a very very very exact formula now that takes the exact footage.

And comes up with really a better estimate and especially when wells fall in between those different numbers. So.

So we do see that working really well now and as and since we.

It's telling us kind of on the numbers that it's giving you guidance on we want to be transparent and communicate that.

Yes, my only comment there is efficiencies.

We manage for them, but they've moved.

Forward, they're probably moving forward quicker than we want so we've tried to manage that.

Being very selective on non op opportunities again.

Managing 96% of what we own usage BP. So we manage this drilling program, we've kept the rig rig rig count flat.

I think Dan has done a really good job historically on on the completion side you can see that's pretty predictable now on to the drilling side. We've done a lot quicker. So you move a bunch of these wells forward debt, while we have more ducks today, although we normally have.

But we did increase that a bunch of little bit and some of that.

Just adding acreage, which we think will be accretive to comstock into future.

Great makes complete sense to me and really as my follow up I wanted to build on <unk> comments and focus really on the trajectory of your D&C cost per lateral foot.

Referencing slide 15, it makes sense to me that D&C costs are higher per lateral foot when there when youre drilling shorter laterals.

As you look out into the second half of 2021 and further out in the 2022 and laterals will approach 10000 feet.

How should we think about the trajectory the trajectory of your D&C cost assuming a flat price.

Cash activity environment.

Well, if you look at that.

10 to 15000 foot remember, we've got $2.15 sales are floaters.

We think that again, it's a little early to predict it but we think those cultural component will be below $1000 per foot.

A great example is looking at the first quarter and second quarter.

The first quarter happened to be dominated by wells that averaged over 11000 feet and you saw that you can see the impact on the debt.

No.

The significant savings there from the longer laterals so at as.

As we continue to get more long laterals into the mix.

We can kind of go back to averaging closer to where the first quarter was if we could have that type of lateral.

In excess of 10000 foot lateral average.

Linked in the wells being completed so Dan volume might could comment so we got.

So the comment about the longer laterals. So we got a lot more longer laterals in the pipeline, especially over on the Texas side, where youre not confined by.

123 sections, you know 1 of those 3 buckets.

And obviously, that's our goal is to get to get longer.

Already have several wells coming in at below $1000 a foot.

And if we can get that average upper I mean, we're going to get that number lower.

<unk> performance I think we will still see some slight improvement there I mean I think we're ahead of the back in the Haynesville on drilling times.

Starting probably in the end of 2020 through today, we've shaved off on average of 10 days off our drill times from <unk>.

2018, 2019 early 2020 average so.

That's already.

Given us the numbers that we got here.

And.

Then you just got the cost increases from the market on the service cost what are those going on.

We think between now and the end of the year unit I think those will be relatively modest so.

But next year at the higher prices I mean, we know there will be theres going to be upward pressure on prices is going to be how much well, we will see some inflation on steel and cement and kind of those products. I mean, we'll see we've kind of worked in our numbers a little bit of some inflation for service costs.

Not particularly on the drilling side, but maybe the completion side.

Very helpful. Thanks for your time guys.

Thank you. Our next question comes from Matthew Harrison with Piper Sandler Your line is open.

Good morning, and thank you for taking my questions.

Yes.

So good morning first question. Good morning. My first question is on gas differentials. So in Q2 your return to your historical differential range of the mid <unk>.

I was wondering if you could talk about your expectations into Q3, and Q4 and also into 2022.

If I recall correctly.

Had.

Some gas being redirected toward the Gulf coast and away from <unk> and I'd like to get a better understanding of the impact to the model.

No.

New arrangements.

Alright, yes, it's a good question.

Obviously, we had the benefit of that.

Premium winter storm prices in the first quarter that that debt debt.

Gave us a much attractive differential on the first quarter back to normal as we thought we would be for this quarter third quarter, we expect to be very similar.

Fourth quarter is when what you alluded to is the.

Hopefully improved marketing opportunities with the Canadian extension, becoming coming into service, it's still plan to come in service in October.

And we hope to be able to move additional gas.

Away from the <unk> hub, which is kind of that's kind of where you get this kind of $25.24 kind of differential.

To a market, that's probably potentially <unk> better.

Now we already have GAAP.

So will it be moving some percentage of our gas that way and we kind of expected like right now 60% of our gas is really tied to that perrigo hub. So it's the major.

The index price you look at when Youre looking at us that that number actually drops down too.

40% kind of hopefully in the in the first and the fourth quarter and definitely into next year. So yeah that has the potential to.

To start shaving the differential down.

And so we don't really.

Those are all moving market. So we don't want to.

Give you an exact number because we can't because all of those markets are.

Move different directions, but we do know it today youre going to pick up.

Anywhere from 5 to 10 cents on that gas, we're able to move away from Perry fell down to Sterling net add.

At our Gulf Coast hub, including <unk>, which will be the new hub that's available to us in that market is just now starting to trade in and we will get more clarity on.

On where that hub is going to trade at.

That's great. Thank you for the color.

And then my next question.

It relates to cost inflation.

You had already you just.

Here's some detail on some of the pressures that youre seeing today.

<unk>.

As you think about 2022.

Do you have a rough guesstimate of how we should be thinking about cost inflation in aggregate.

A large Permian player had throw now 10%.

I'd like to get a sense of how you guys are thinking about it.

Yes, I think so just to start off with what we've seen to date, we really hit we've seen we have seen.

A few really small ones and <unk> been really small like 5% and less so for this year. The swaps I think we're pretty good next year.

Based on where we think the markets are going on I think next year, we'll probably on average be little higher than I think 5% to 10% probably is a pretty good number.

We haven't got any indicators for many of our providers that anything really major is coming.

I think youll see at the macro level just Sahara activity. We just you just have to know that it's there but.

I, certainly don't see anything over 10%.

And again, we see capital discipline, we don't see.

Hum.

A whole lot of rigs out there, particularly on the natural gas side I mean, there was a 103 rigs I think drilling for natural gas.

On a stage.

We don't see that increase.

So if it was in a frothy days before Covid you might expect a lot of new rigs.

I think right now which is capital discipline.

Just not going to see runaway inflation on our side now cost of our our commodity has gone up.

If the commodity price had gone up on me, we probably wouldn't have as many rigs being utilized today.

On the oil side and the gas Jonathan.

I think it's going to be it's going to be moderate you'll be control.

On that it'll probably be a net 5% to 8% range. That's R. M.

On a number of net includes again steel includes manage includes 2 pillars.

Some inflation on those costs.

Thank you for that that's great and then a final 1 for me if I may.

Just wanted to ask about consolidation.

Wanted to hear your latest thoughts on.

On consolidation within the Haynesville Bossier area.

Where youre, where youre appetite currently is just that.

Any thoughts.

Got it thank you.

Well I think a.

A lot of the consolidation I think size is important but also think.

So I think I think Youre high margins.

And your low cost.

Probably more important.

And everybody is seeking the kind of the denominator is locations.

Some of these companies.

You have to consolidate because you're running out of locations.

The beauty of Comstock is 2 years ago, when we bought Covey Park for that $2.2 billion and they were larger than we were.

We added those locations with our locations with the locations.

We've been adding with this leasing program.

19, <unk> hundred 2000 locations in luck.

<unk> on our role as Dan said, we've departmentalized on those to 5000 foot laterals 70.510000 foot.

So if you are looking at Comstock needing to do some type of an M&A 4 locations. You can you can extend box because we don't need to.

If youre looking for Comstock.

<unk> upped our management, particularly from the drilling side and completion side I mean, we drilled and completed more of these wells on anybody.

So you probably don't need to.

The only reason that we would do any M&A transaction is that the.

The acreage is equally as valuable.

And our cost structure materially improves.

And quite frankly, the Jones family owned 60% to 60% of the company.

EBITDA to be blessed by them.

Because I think what they've invested in right now is delivering great returns per.

<unk>.

On size is important.

With the footprint that we have here the Gulf coast with the with the demand for LNG to Asia and Europe.

With the lack of firm transportation commitments that we have and how margins I mean, we're not seeking to do something just to get bigger period.

But we're way beyond that we're in great shape, our maturity schedule, we were fighting net for a while the expensive bonds, where refining net for a while.

Series, a preferred we reported net for a while.

On the 30 million shares or so.

There was issued.

So private equity was kind of out there is an overhang we secured debt.

Consolidated the personnel, we're not looking to do that again, we go through the Covid year with lower prices, we had stretched our <unk> with the Covid transaction net we have $945 million.

I mean, we're setting in a sweet spot with solid production upside solid EBITDA growth and stronger than expected realized pricing.

On our hedging into 2022.

Can you can you can not like it.

But I think Bob per management with the balance sheet, we have on half of our hedges in 2022 or swaps half of them per call on some of those callers go to $6.

We've average like $3.50, 60, whatever but I think it's a safe.

<unk> 2022 so.

No, we're not aggressively fishing or looking for anybody now while we opportunistic sure. We are sure we on.

But.

It needs to be colored in that line.

Thank you. Our next question from Charles Meade with Johnson Rice. Your line is open.

Good morning, Jay and Roland on the rest of the team there.

Hi, Charles.

Jay I wanted to.

Pick up a little bit on the theme you were just touching on with locations and ask you about the Bossier.

I think back.

<unk> ago.

<unk> drilled some of the first.

Some of the first really good Bossier wells, it really opened a lot of People's eyes, but.

Since then my approach.

Is that you guys are really really just focus on the Haynesville zone.

And in the last in the last couple of quarters, there's been a few capital markets transactions with.

With other companies, who have half of the remaining locations are more than half of the remaining locations.

In the Bossier, So can you.

Can you give.

And as much details you'd like.

Our view of how how you see the Bossier versus the.

The haynesville both for.

The industry as a whole and this kind of in this footprint of northwest, Louisiana East, Texas and for Comstock specifically.

Yes, Charles on all how many times, we had met with you face to face to face on how many companies you cover but.

Behind closed doors on I think her name is nicknamed design Stein.

Ask that question.

Pretty incredible because we hadn't bought it up we didnt ask anybody to bring it up we don't ask you to bring it up okay. The whole audience station no debt, but if I'm going to turn this over to Dan because he is supposed to be the <unk>.

But I want him to tell you about the 2 Bossier wells that we just just yet the single best wells were drilled in the quarter nobody bolt it on thank you.

You sniff it out and then probably half of our locations for Bossier and as you asked on our outside consulting groups.

They really love the budget if you look at Avaya on IPO after their upsize as Bob Schieffer Indigo was Bossier, we don't really talk about Bossier debt is a great. Great question I won't color with Macquarie on I'll give it to Dan So Dan and you've got on to slide whatever day anecdote Charles Please not youre correct on Jerry.

Anything about the correct.

It's a below 1 so John.

Yeah, So Charles.

Which.

I did mention it earlier, but on <unk>.

Slide 14 on the list of the wells too.

The best on the App.

We had at the bottom there on our earning 10 wells, which you can see on the math on other further down south or on screen parish. Those are in fact, 2 bossier completions. They are the only 2 bossier completions on that list.

We do like the Bossier.

Obviously, it's the southern half of the.

Players, where the measure exist and.

The 2.2 I think this was in the last quarter. The 2 longer longest laterals. We've drilled to date are on <unk> 500 on a 13000 so.

12500 foot tests, which also Jordan well.

The Bossier.

Right there on the acreage on the Desoto Sabine parish border.

And also these next 215000 per laterals, we're getting ready to drill later this month are going to be boaters.

So we do like the Bossier. The Bossier is good and Charles will remember you go back we kicked off of <unk> and 2015, we've announced to the world. We're just going to drill Haynesville slash Bossier wells, we drilled 9 Haynesville wells in 2015 and December 15, as you well know we drilled the first Bossier, well, which is the Jordan well on.

It kind of its.

It's parked all the interest as a public company revenue reported in detail. It did sparking interest net rebirth of Bossier play.

So we're really excited about these 15000 foot laterals.

They will be challenging.

We've got a great drilling recipe.

Of course, a 15000 foot laterals.

Have to get back up the learning curve, a little bit I mean, theyre not routine by any means.

On for Darryl on the other wells, but.

That's kind of in this kind of our plans as we get these 15000 foot laterals down.

We plan to develop.

Much of our Bossier with those long laterals, yes, just to add 1 more comment on that Charles is that Thats..1 other things we've been thinking about the Bossier too.

What day migrate to the 15000 foot laterals. The Bossier is relatively undeveloped on our acreage.

There is a lot more room to do longer laterals, we can convert at a much higher percentage of our voucher inventory into that 15000 foot laterals.

Probably can realistically on the Haynesville acreage so that's.

And that also enhances the return so we've been thinking about that more long term because we just have so many wells to drill in such a large inventory.

Yeah.

It's Ben.

It's been hard day.

Go to all the different players yet, but it's a great part of.

The inventory and I think the market started to realize that in some of the best wells in the play that are coming out of the Haynesville operators, our Bossier wells now.

Non op opportunities have been Bossier.

Yes. It is.

Surfacing.

Well look that's a lot of great color guys I appreciate that.

Brian Squirrel funds on a corner now on that but.

No.

I ask another kind of more.

Maybe probably less interesting question.

Is it.

I look at the strip and you still got this 65 drop between March and April and it's been there for a long time on.

Frankly, if you'd asked me a couple of weeks ago or a couple of months ago. Almost said, we'll book Thats going on at those debt spreads have tightened a calendar spreads going on to tighten as you get closer but it hasn't so I'm curious does that.

Does that shape of the curve index steep drop we see.

In the fourth month of or in April of 'twenty 2.

<unk> any of your.

Planning or any of your decisions either either near term or longer term.

Well, that's a good question and I think thats debt that nature of that is really just the speculation in the gas market in the probably the tightness of the market and the fear that gas could be.

It really short and that those winter months there.

On the longer you go out on the gas curve the less speculations out there so.

A lot of it is going to be.

Out there until winter really kind of shows itself.

So it's kind of hard to plan around that I mean, you could have said you could have looked at that last year and made the same comments that the first quarter of 2021 was going to be where you really want to try to get your gas on line.

January through March it turned out not to be a great strategy because those are going to be some of the lowest price.

So this year of 'twenty, 1 so it's really hard to.

Look at the curve and derail toward it.

We do see that overall, though.

Over the last months, you've really seen that 2022 futures prices improve greatly where they had been stuck at a level that was below 21 for a long time. So a lot of it is just the market trying to figure out what's the supply demand kind of look like later this year and they are still filling that out so.

We feel great about the gas market.

And.

Producer discipline, that's been a big component on Charles as you looked at on the next 7 months. We're looking on the strip right now gas is 418, all the way to 400.478 months out.

And then a drop to the $3.37 I mean.

If you told me 3 months ago on a 337 natural gas on the Haynesville, well that'd be pretty happy on like for better, but it looks pretty good. So we did front end load 2022, if you look at the hedges to make sure we.

We have really good quarter in the first quarter 2022, 2023, and I think the other thing we did.

Because of our balance sheet.

I think we properly risk adjusted our hedges on.

In hindsight I wish we didn't have any hedges potentially on how businesses are run I think in a moment you had to put whatever the hedges, which was a swap port color and I think we might have a good business decision.

That is to have half of 'twenty 2 in a swap which is solid.

And did go those out but then also has the caller digit gas hits $456 to get a lot of debt.

And I think our budget is good we've asked a question about.

Our models when you when we when we said that we have 5000 foot 7.5 on foot 10000 foot laterals, we have done in both the haynesville and the Bossier. So when we start kicking off diesel how long laterals on the Bossier. We also will have those models out too.

And we can talk of this back.

If we need to accelerate a little bit and convert some of the the ducts into PDP I think we're going to be able to do that.

We are going to be able to pay off the coffee bond. If we can do that then are our interest cost per inch BFA continues to drop.

That many quarters ago, we were 52 cents per Mcf they are now with 36.

We need to get a 2 will net.

<unk>.

So we're we're going to we're going on.

We opened.

This third and fourth quarter operating it.

Look really really good I know, we're talking about the second quarter.

But the second half of the year it looks like.

It looks like.

But we should really capitalize on all time high corporate production here natural gas production with a really really favorable natural gas price.

Yes, we see the same thing Jay debt all of that insight is helpful. I appreciate it.

Thank you.

Our next question comes from you may artery with Goldman Sachs. Your line is open.

Hi, good morning, and thank you for taking my questions.

Yes, Sir.

On my first question is on your plans on absolute debt reduction.

As you mentioned gas futures on very favorable.

And if it holds you can potentially generate free cash flow of $200 million.

You have $75 million outstanding on our credit facility can you talk to your plans to address the remaining maturities.

And once you went to pay down debt borrowings under our credit facility and also if you can talk to your thoughts had on cash are going to shareholders and the right absolute debt level like Mitchell <unk>.

That you plan to deploy cash back to shareholders.

Yes, those are great questions.

We are now that we've kind of got the cost of the long term debt down and got the maturities.

On a great spot, it's really focused on the debt reduction we do have a significant amount of debt that we can retire the bank facility debt, obviously, and then we kind of we purposely did not refinance debt.

The remaining.

Bonds outstanding.

Because if we thought that was also a good target for debt reduction so our plans are.

Sometime probably next year or 2 to redeem the remaining 7.5% bonds, we obviously want to yes.

Create the free cash flow and pay on our bank facility first and then retire those bonds next.

And so that is that over the next couple of years gives us a lot of pre payable debt net debt can help us achieve our overall.

Debt reduction goals.

If you look through the windshield our goal in 2014, we gave a dividend.

We're not nearly there in giving a dividend of and I think you have to look through the windshield and say, where you're going and with these higher process. I think we can get this leverage down we get the leverage down.

Got a 1 handle on it 167 hundred I'd just take a number.

And we're properly hedged then.

<unk>.

I think I think it would be nice to have a board meeting and say Hey, you know what.

These are real Benjamin.

We're going to go back to the stakeholders are going to be not only a dividend, which you can do with the pioneers of world and start doing on a variable I think debt.

I think debt is absolutely a possibility within the comstock structure because of where we're located again the demand for our gas <unk> gas to.

Europe and Asia.

And the demand growth as far as these export facilities are being built.

And the fact that we havent encumbered our gas.

Some kind of a strange firm transportation commitments that are below market or our minimum volume commitments that are owners.

So we are absolutely looking at the long balls in the next 18 to 24 months.

And at the same time on our leasing program.

Every year, we drilled 50.60 wells, we try to replenish that with 50 to 60 more locations. So that is the goal now I don't want to smooth the bondholders downers anybody coming but we're never going to be financially reckless periods. You can forget debt, we are going to be financially aggressive.

And then once we get this debt pay down and we've got these maturities long it'll have to bondholders have the equity owners and help the analyst and help us.

So we're all in kind of in the same barrel together.

That's our goal.

That's helpful.

And I guess my next question was that on hedging can you remind us the minimum percentage of production you need to hedge but your covenant and also I wanted to get your thoughts on future hedging.

Sure Yes, yes.

Yes, we're currently required to hedge 50% of our of our proved developed producing reserves at each borrowing base redetermination. So.

That's twice a year so.

Whatever that.

The next 12 months.

Now usually if you look at our production outlook on 100% doesn't come from proved developed producing reserves at that time so yes.

On a 40% of our expected production.

No more than 45%, yes, we do we do need to hedge in some form it could be in the form of a collar in order to satisfy the credit facility as it's as the Covenant currently stand so where we're at those levels for the next step.

Already.

For 2020 day, if we choose not to put any more hedges on at all.

So obviously been a huge run up in prices.

We.

We think we're adequately hedged for next year.

No.

I can't tell you, if we're going to add any more or not but I don't think we will be hedging.

At a real high percentage level of 22, right now based on how we see the outlook.

Great. Thank you so much.

Thanks for your question.

Our next question from Bert and Dennis with Truth Bank. Your line is open.

Good morning, guys.

I was wondering in the prepared remarks, you said youre going to hold production flat and I just wasn't sure exactly with the lower spend in the back half whether that might kind of drift down in <unk> and <unk> 22, and then maybe back up in <unk>.

Maybe it will truly be kind of a flattish profile.

I don't think that when you talked about holding production flat, we actually talked about in the.

Basically this year is kind of.

We're seeing about 8% to 10% growth in production.

We have not really set the goals for 2000.

2 yet and.

And so.

Yes in fact, Thats, what we said on our final slide I mean, youll see its on 8% to 10% production growth.

That's what our operating plan calls for.

Alright.

Back half I thought.

Heard you guys, saying that maybe towards the end but.

Either way it is the lower activity, though if there is some sort of quarterly cadence or you just.

You don't want to get ahead of yourself and talk about that yet.

Well I think obviously that youre going to see the third quarter.

That's kind of that at the second half of the year is the higher production levels. So we will see higher production levels in the second quarter level coming up in the next 2 quarters.

But thats a good question.

We're not going to try to pick production to drop at all we're going to trial on level of that on our model in 2022.

We have we have management discussions on that too I think.

What we said today as it was.

Actually we front end loaded debt Capex, we know we have that but we got a lot of ducks that we can complete.

Can shifts some capex dollars rounded complete dose docs.

<unk>.

$4.$410.20 gas.

We actually already on a corporate high on a record natural gas production hedged Comstock and were selling at a high natural gas price, but we're going to we're going to monitor that in 2022, we won't we don't expect to have.

Peaking on a drop off.

On a go either.

Okay. That's perfect and then really just my only follow up.

With the higher gas strip I know you guys, maybe talk about cash taxes before being pretty far out there, but just wanted to wondering if you guys could read into that.

Yes, I think we still have a lot to get tax attributes, which we.

Are able to use and Inc.

So we don't really see cash taxes being something.

Really put on on the radar screen.

For the next several years.

And our goal really is debt.

We try to maximize our taxable income to us.

Carryforwards that we have.

We want to be able to use before they expire.

We have a little bit of.

Just day to structure have a little bit of state cash taxes Thats, all we can see right now.

But that's a fairly modest amount compared to the income we have.

That's perfect. Thanks, guys.

Thank you.

Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

Hey, good morning.

Good morning.

Just had a few things.

The success you've had on the leasing side I was just curious where those leases that you had.

Ed your eye on for a long time, where they something that.

Expiring came available.

Just at this stage in the play's development.

It's a pleasant surprise to hear that you still can.

Together significant additional leasing there.

This is a result of the combination of <unk> and Comstock when you put the land groups together and then you see what's kind of floating out there that would be accretive to us in the future.

And then we didn't go forward on those programs at all for a while until we had the consolidated the management team together and then we said okay. Here are what we call low hanging fruit in our opinion. So we go out and we spent quite a few dollars on it but we.

It's very favorable.

The terms on the leases.

Great.

Thanks.

What's also.

Just thinking about the comments you were just making.

As far as.

Overall efficiency in the cost environment.

Where do you stand as far as the contracts on your on your Frac spread.

Do you have a horizon past what you have to.

Negotiate on rates or is there.

Or sort of built in renewal available to you on what you are paying now.

But of course part of it is the preface that remember we do have 1 new 3 year contract we have locked in the pricing on the new tightened fleet that's next year.

Probably goes into service in January so that's that has been fixed for 3 years and then Dan you can kind of talk about the.

We probably need in addition to that we will need 1 to 2 more frac crews.

Yes, so that's right. So we've got the <unk>.

Bj's provided.

Kind of the Alterra, but natural gas fleet that will start to anticipate the crude will show up and start worrying about January 1 and it is fixed for 3 years, which we think on the <unk>.

Current outlook, that's net as can be a great deal for us the other the conventional fleets.

They typically we have cost.

The contracts and they day run through the end of this year, but they didnt have language in there where they can make price adjustments depending on what the market's doing so.

On that sense, they're not locked down solid like this like our natural gas fleet will be.

Gotcha. Thanks.

<unk>.

The 32 million a day IP that you.

You had in the quarter I was wondering is that a record for the company and I was also just curious kind of where you stand on choke management. These days.

So no thats not a record for the company.

But.

I think a record for the company.

It's up in the mid I think about 36 or 37 million a day is the highest that we've ever we've ever shared I mean, obviously, we have wells capable of doing more I think that's the highest we've ever reported.

<unk> management.

Basically we.

Even more so on the higher price environment, we basically hold on hold the rates flat at a high rate until I get down close to line pressure then basically.

They will start decline on all familiar in that kind of front end load our production and gets us gets us a better return.

Well decline off from month month 1.

Great.

Oh, sorry go.

Brent.

Yes, we do tailor the choke management around the wells pressure performance.

Each well tells us what it can do.

There also could be other.

Our strengths such as how much production can you flow off a pad.

Not every well can always flow optum latest because.

You may have only so much transportation or facilities, you don't overwhelm them.

So we have to manage all of those factors in deciding to flow rates.

Right.

Okay. Thanks, that's all for me.

Perfect. Thank you.

Our next question comes from Leo Mariani with Keybanc. Your line is open.

Yeah, Hey, guys I was hoping you could help out a little bit with <unk>.

On your Capex spend here.

Certainly talked about it being more weighted in the first half of the year.

Can you kind of help us with the next couple of quarters should third quarter be serve it last and second quarter and I noticed you had kind of it looks like just based on the plan for the year kind of not very many completions in the fourth quarter. So it's fourth quarter capex can be down a lot, but can you just kind of help us with the trajectory on the spin.

Sure and you can look at this kind of a.

On 1 level, it's likely that the drilling and we were running.

We were running more rigs.

Through may.

There's no more drilling activity in the first really January through through May as 6 rigs then down to 2.

To 5 rigs for the rest of the year there Theres also a.

Maybe a couple of months, where we would be actually be running 4 rigs because we've probably got a loan out a rig a little bit again again, just because of the drilling times have been quicker.

And.

Trying to trying to manage overall, how much Henry Ducks, you buildup. So that drilling activity is definitely weighted to the first half the completion activity is weighted more through the first 3 quarters, Dan So EBITDA.

Talk about how many frac crews running in the different quarters. So we are currently running 3 frac crews and right now at the end of the year. We got we got dropping down to 1 to 2 frac crews in Q4, and that's basically what's the front end load for the.

For the production profile this year.

And that'll be.

We obviously on Youre looking at the current prices that we're at and we do have discussions about do we want to try to pull some more of that for.

<unk> potentially sometimes but but right now we're dropping frac crews towards the end of the year.

3 we should be at 1 in December.

Yes, purposely that 1 when we set the budget to say Hey, we want to 1 when you are fracking you have more shut in too so it's kind of a.

Just to optimize.

Production and AD.

What's usually the better months.

We kind of designed the program that way.

I think we still are.

Now kind of sticking with that so.

Okay.

That's helpful. I would imagine sorry on the Capex is going to fall all of that activity as you described here.

Right.

Yeah, and I guess, maybe just a follow up I think on the previous earnings call on first quarter, you guys had talked about kind of 3% to 4% production growth in 2020 Q.

Obviously since then we've seen gas prices move up materially you clearly growing a lot faster than 2% to 4% here in 2021 do you have any just kind of early thoughts about how you would approach day at $3.50 gas price environment. In 2022 is that the type of environment, where you guys would like to maybe leaning a little bit more of a a little bit.

More growth just because the returns are so good on the drilling or how do you think about that when we plan on keeping the same rig count and we'll see what the efficiencies due on the drilling and completion right, Yes, I think.

Well, obviously, we set a goal for free cash flow and again, it's kind of early for us to lock in on to the.

Yes to the 'twenty 1 program, yet, but right now we're kind of assuming we're going to have these 5 rigs running in.

And yes, it can achieve kind of that that type of production growth you talked about with that program.

So yes, we will continue to look at that but.

A lot will depend on where we are as we get the leverage down and we will open up opportunities to have other decisions here, but we see the leverage coming down fast.

Next year really being under 2 times that our goal for several years and we definitely want to achieve that before.

Before we start spending it in advance.

Alright, so really just the budget will be design upon on maximizing a lot of debt free cash flow and hanging on leverage targets than production and just kind of an output.

Right the production will be a factor, but it won't be the like absolute.

The absolute driver it'll be what maximizes.

Getting to the leverage profile, we want to get we think we have all the tools to get there.

Next year.

So they are right here. So we want to check that box just like we wanted to get rid of those expensive coupon bonds that was the goal. They're gone now so now we're going to focus on overall debt levels and leverage and obviously.

Balance EBITDAX.

Growth with debt reduction is the balancing act on leverage well on save a lot of money in 2022 on.

Interest expense per Mcf.

I think we'll get more efficient in 2022 with long laterals.

Process looked solid so again, it's the same rig count is just efficiencies on those.

Efficiencies along with the higher process of course.

Correct on our balance sheet at finished on our debt.

Florida bonds, our RVO and we have really good growth because we have tier 1 area.

So a simple story.

Alright, great. Thank you.

You bet. Thank you I appreciate it.

Thank you and this concludes the question and answer session I would now like to turn the call back over to Jay Allison for any closing remarks, Colorado again, some of you that joined kind of.

On the middle of the call.

And again, we're excited about the quarter, but we're more excited about the remaining 6 months of this year.

We did front end load our capex, we advertise that.

We do have right now as we speak today and our corporate record natural gas production at Comstock and.

And there is a good time to have that because we are selling at high natural gas prices.

On which you don't know that we've recommitted to planned up this balance sheet.

We've got good models that are strong.

Good operations Department.

We are thankful that we have for all of Us Packers. So thank you.

This concludes today's conference call. Thank you for participating you may now disconnect.