Q3 2020 Comstock Resources Inc Earnings Call

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20, Comstock resources Inc. earnings Conference call at this time, all participants are in listen only mode. After the speakers presentation. There will be a question and answer session to ask a question during the session you'll need to press star one on your telephone as a reminder, todays program maybe recorded I would now like to introduce your host for today's pro.

Graham Mr., Jay Allison, Chairman and Chief Executive Officer. Please go ahead Sir.

Thank you. Thank you for introduction this morning, it out again I want to thank everybody does.

Taking their time to listen to the story today I know we have a lot of you. We know a lot of your really good friends have been forever and ever and ever. So today is an important day in our and I really in our corporate life we.

You know, we're all human and you know we do understand the third quarter results were somewhat disappointing quite frankly.

Oh, and I can speak for me and for everybody else the management team we hate it.

And you know there they are disappointing for the reasons that you're aware of I mean, they're all logical reasons are still disappointing show dance curtailments related to hurricane Laura.

Non op curtailments, and there's a litany of other small reasons.

You know I think our goal. This morning is to share what we see you.

For the fourth quarter 2020, as well as 2021 or 2022 and to show you.

Our stakeholders, how we plan to de lever our balance sheet in those years by using our strength.

Of our peer leading how margins are low cost we've created in the haynesville.

In a period of time, but frankly, when the outlook for natural gas is extremely bullish.

Really the most bullish it has been in over 10 years.

Our job in the next 45 minutes.

Really today is to avoid any disappointments in the future.

And show you, how our high margins in the Haynesville, coupled with the right size the capital program over the next years can de lever the balance sheet and expand.

Our trading multiples so that we all are winners.

All based on the commodity gas process looked at we see today.

So thank you for trusting us and if we have dented that trust any please.

Please note that the entire Comstock team will work hard to earn it back in even more by giving you a 100% of our best as we always have.

I will now start into our third quarter results and then we'll get to the Q a day and we will answer any questions that you have and be accountable for.

Welcome to the Comstock resources third quarter, 2020 financial and operating results Conference call. You can view a slide presentation during or after this call by going to our website at www Comstock resources Dot com and downloading the quarterly results presentation, there you'll find a presentation entitled third quarter 2200 results.

I am Jay Allison Chief Executive Officer of Comstock, and with me as Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Ron Millos, Our VP of finance and Investor Relations. Please refer to slide two in our presentation to note that our discussions today will include forward looking statements.

Within the meaning of securities laws, while we believe the expectations in such statements to be reasonable there can be no assurance that such expectations will prove to be correct. It.

If you are following this you can turn to slide three.

On slide three we discuss the highlights of the third quarter November is the first month, where we finally exited the period of very low natural gas prices broad honed by the warm winter. We had has really November natural gas price closer to that almost $3 after hitting a low.

Over $1.50 this summer the.

The loan production levels brought on by the actions of disciplined natural gas producers combined with the decline in associated gas, resulting from low oil prices.

Have caused a 2021 future natural gas prices to improve substantially.

Since January of this year, we have been focused on reducing our drilling activity and deferring completion activity those actions allowed us to generate free cash flow, even with a very very low prices. We are receiving for our production. The reduced activity. We had in the first half the year combined with the third quarter Hurricane.

Activity in our region negatively impacted our production this quarter as you see.

With the stage is set for higher prices later, this year and into 2021.

We collectively decided that we would go back to work in the third quarter.

We added two additional operated drilling rigs to bring our working rigs back up to six which is where we work to be ended the year and currently have three frac crews working to catch up on the backlog of drilled and uncompleted wells since.

Since our last report we have put 15, new wells on production, which have a par well IP rate of 26 million cubic feet per day, we did have a rocky quarters on Mitch on the production front, which partially was self inflicted.

Has the ramp up of activity drove a higher shut in percentage up to 7% in the quarter.

The higher spending in the quarter reflects restarting a program we put on hold in the second quarter, but it is the right move as we look forward to improved gas prices that were in we did achieve our goal of reducing well cost to just under $1000 per lateral foot, which is significantly lower than any other haynesville operator.

With recent changes to our completion design, we expect well costs to increase a little bit as Dan Harris, who will go over later.

While it made sense to bring well cost down as low as we did with weak gas prices. This year with gas prices closer to $3 plus now it makes sense to invest in a little more proppant as we believe the wells will have a higher return.

As we will discuss more today, we recently decided to increase our completion activity planned in the fourth quarter by running an additional frac crew, which moves up the completion of seven wells that we plan to complete in 2021, the additional investment will pay off in 2021 to allow us to have a little higher production.

Action to take advantage of the higher gas prices.

And the third quarter, we completed a follow loan $300 million notes offering to further pay down borrowings on our bank credit facility, we have reduced our outstanding bank borrowings from 57% of availability to just 36% of our availability.

By freeing up the bank credit facility, we increased our financial liquidity to $928 million.

The low oil and natural gas prices combined with loan production in the quarter did that impact the profits we generated in the quarter.

Oil and gas sales, including hedges were $212 million.

Our adjusted EBITDAX came in at $148 million and our operating cash flow was $93 million or 38 cents per share. We reported an adjusted net loss of 13.8 million or six cents a share.

With higher production and stronger natural gas prices, we anticipate returning to profitability in the fourth quarter, which is now.

Ill have rolled and go over the financial results in more detail Roland Alright. Thanks Jay.

On slide four we summarize our financial results for the third quarter of this year our production for the third quarter totaled 103.

Half of natural gas from 354000 barrels of oil total production of 105 Bcf He was 4% higher than the third quarter of 2019, our oil and gas sales, including realized hedging gains were $212 million, which was 15% lower than.

And 2019, and this was all driven by the lower oil and gas prices, we had in the quarter.

For prices in the quarter averaged $33.52 per barrel.

And thats with the hedging gains we had.

In the quarter, and our realized gas price, including hedging gains was $1.95 per Mcf.

Our natural gas price realization overall was down 14%, which offset the production growth that we had in the quarter.

Adjusted EBITDAX came in at $148 million, which was about 22% lower.

Than the third quarter of 2019, and operating cash flow of $93 million was about 35% lower.

We did report a net loss of $130.9 million for the third quarter or 57 cents per share, but most of that loss is attributable to the $155.6 million unrealized loss on the mark to market of our hedge positions.

That is our caused by they substantially improve at the futures the future natural gas prices since the end of the second quarter.

Our adjusted net income ex.

Excluding the unrealized mark to market hedging loss and then certain other unusual items was a loss of $13.8 million or six cents per diluted share for the quarter.

Slide five we summarize our financial results for the first nine months of this year.

Production for the first nine months totaled.

At 349, DCF FY, Inc.

Including about 1.2 million barrels of oil, which is 90% higher than our production for the first the same period in 2019.

Course, most of this increase is due to the acquisition of heavy Park energy, which we completed in July of 2019.

Oil and gas sales, including.

Realized hedge gains were $716 million, 40% higher than the same period in 2019.

Oil prices.

So far this year have averaged $39.84 per barrel and our gas prices $1.96 per mcf and both including the hedging gains we had.

Overall, this is 18% lower than the prices we had it for natural gas in the same period in 2019.

Our adjusted EBITDAX came in at $511 million, which was 35% higher than 2019 operating cash flow was $367 million and thats, 31% higher than the 2019.

We did report a net loss of $160.9 million for the first time much this year or 77 cents per share again. This was due to the mark to market loss, the unrealized mark to market loss on our hedge book.

Adjusted net income, excluding the unrealized hedging losses and other unusual items was $12.9 million or a net income of six cents per diluted share.

Third quarter production was adversely impacted by higher Chad at level than normal as you can see on slide six.

7% of our natural gas production machete and in the third quarter as compared to 4% in the second quarter.

Much of that.

Shut in as due to offset frac activity, either by our simultaneous operations or other haynesville operators, but we also temporarily shut at a portion of our production over the course of about a week.

Due to the impact of Hurricane Laura that caused wad, Pat widespread power outages in our region.

And then also in September.

For a good part of the month of September then carried over really into the first.

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12 to 14 days or so of October we did experienced wide differentials in the daily cash market at Kearney Vale and then other and in other index is at our kind of region in the <unk> that the.

Southern kind of Gulf region, and this was all data concerns that the natural gas market had over the high storage levels as we've been we've been as we exit the period of storage injections.

So the only gas it's really impacted by these daily prices is what we call our swing natural gas that was not sold during did weaken in that part of our base load sales.

So we chose to restrict some of the new wells that were coming on in September and then and then.

All production, which is primarily located in the Bakken region. Also has continued to exceed experienced substantial curtailments, which carried through in the third quarter. We had about 12% of our oil production that was shut in by the operators that operate it due to the very low oil prices or other issues in the Bakken region.

On slide seven we cover our hedging program.

Yes for the first nine months of this year, we had 50% of our gas volume hedged, which increased our realized gas price to $1.96 per Mcf fee from the dollar 60 that we actually received from selling our production.

We also had 86% of our oil volumes hedged, which increased our realized oil priced at $39.84 versus the $30.35 per barrel that we actually received over.

Overall during that period, we we had realized hedge gains of $133 million.

But with the improvement in future natural gas natural gas prices.

But.

We also took that opportunity to continue to add to our hedge book, but but really at higher levels than we'd hedge before and then also using collars.

So we've added about 10 million a day of natural gas for the fourth quarter. Since we last reported earnings and we added about 38 million a day of natural gas collars in 2021, and about 12 million a day.

Collars in 2022, which gives us a good protection level, but also gives us exposure to the higher prices.

So as you look ahead for the fourth quarter of 2020, we have 663 million cubic feet of our gas.

And about 2800 barrels per.

Per day of our oil hedged.

The weighted average floor for price of our remaining 2020 gas prices is $2.61.

And for 2021, we have natural gas hedges covered about 836 million cubic feet of our 2021 production. So we're on target to having 60, 70% of our 2021 production hedged and we'll also work as we have this improving gas strip to work with.

Hedge our 2022.

Volumes appropriately.

On slide eight we detail our operating cost per Mcf produced.

And overall these are pretty comparable to the second quarter. So our operating cost averaged 55 cents in the third quarter as compared to our second quarter rate of 54 cents gathering costs were 21 cents production AD valorem taxes averaged nine cents in field level costs were 25 cents.

One thing we did do this quarter in order to improve the comparability.

Yes, and other producers.

As to two Reclass, our AD valorem taxes that used to be showed as part of just lifting cost and include those in production taxes. So you will see that if you're kind of tracking the old numbers that sets really about one cents.

So not a big change, but we think that this makes us more comparable to our peers.

On slide nine we detailed our corporate overhead per Mcf fee and our cash DNA costs were seven cents in the third quarter.

Which is slightly up from the second quarter, but that's mainly due to the lower production level in the quarter.

Slide 10, we detail the depreciation depletion and amortization per Mcf produced.

Our DDNA averaged 95 cents in the third quarter, which was about eight cents higher than the second quarter.

And most of that impact is due to the the much lower kind of FCC type prices that are kind of backward looking that we use to do amortization math.

On slide 11, we recap our third quarter and the first nine months of 2020 capital expenditure program.

So we spent a $110 million on development activities in the third quarter and 94 million of that was related to our operated Haynesville shale properties.

For the third for all of 2020, so far we spent $316 million, including $259 million on the operated Haynesville properties.

We have drilled 36 or 28.6 net operated horizontal haynesville wells. So far this year and we also completed.

9.6, net wells that we drilled in 2019.

We've spent $56 million on non operated activity and for other activity. So far this year.

We generated $367 million in cash flow for the first nine months of this year, resulting in free cash flow of $30 million. After we pay the dividends on the preferred shares.

After drop on our operated rig count to four rigs in April which was down from six back in January we've increased our operated rig count back to six rigs in the fourth quarter, we expect to spend about $150 million to $170 million. This year to drill 17 or 16.4 net operated Haynesville wells.

Cells, and then to turned to sales 22, or 17.6 net haynesville wells.

We made the decision recently to keep a third frac crew busy in the fourth quarter, which we originally planned to release and then bring back in early 2020. This.

This does add about $30 million to our 2020 spending, but there and the reason for it was to accelerate the completion of seven wells that before we plan to complete in 2021.

And this is in order to take advantage of the higher gas prices, especially that we see for the first quarter of 2021.

And it was just it was a decision based on if we have kept our original schedule.

We could we compare that to.

To.

To keep it in this third rig, which was performing well for us and our.

Operations ask us to look at that and we said, we actually make $15 million more by accelerating.

That completion into kind of the pricing.

The highest gas price Matson, the futures curve and so we said thats the right thing to do.

If you look at the full year for 2020, if you combine the fourth quarter with that we now expect to spend about $450 million to $500 million. This year, which would have drilled 53 or 45 net operated haynesville wells and turned 55 or 42.2 net operated Haynesville wells.

The sales.

We also participated.

We exit or plan to participate in 18 or 1.3 net non operated Haynesville wells.

And in turn to 3.8 net wells.

To sales.

At the end of the.

This year, we now expect to have about 16 or 15.4, net ducs are drilled and uncompleted wells.

So as you look ahead to 2021.

We expect to increase spending a little bit over the 2020 level and in response to these higher natural gas prices that we see and we expect to spend between $525 million to $575 million and trail 70, or 56.5 net operated Haynesville wells and turned 65.

Of those wells are 56.6 net wells to sales in the year.

Our initial plans right now are to add a seventh operated rig and we would do that in the second quarter of next year, obviously as we get to that point, we'll assess it.

The natural gas market in our region and decide if thats still a great course of action if not it's it's as we've shown in the past we don't have long term commitments for drilling or completion services or or any kind of volumes to meet so it's clearly an economic decision.

What happens when we spend the capex and.

Yeah.

And we can react as we did this year. We can we can we can react to the market and adjust our level of spending as is appropriate.

But we still remain focused on generating significant free cash flow would we see next year.

As having a bounty of that with the plans, we have and we target to have a minimum of at least $200 million of free cash flow.

As we plan for any future capital spending.

On slide 12, we show our balance sheet at the end of the third quarter and during the third quarter as Jay mentioned, we issued $300 million of new unsecured notes to term out a portion of the borrowings outstanding under our credit facility. So we ended the quarter with about 500 million drawn on our credit facility and we do expect to continue.

You to pay that down with free cash flow generated during the rest of 2020 and into to 2021.

With a quarter ending cash position of $28 million, our current liquidity now stands at $928 million.

We have just over two point.

Two $5 billion of senior notes outstanding and Thats comprised of 619 million of our 7.5% senior notes due in 2025 and $1.65 billion of our dine in three quarters senior notes due in 2026.

So I'll now turn it over to Dan to cover the third quarter drilling results in more detail okay.

Okay. Thanks Roland.

Overall slide 13. This is just our updated outline of our current acreage position, which is increases this quarter up to 309000 net acres.

We control the majority of the acreage with a 91% operated position and have an average working interest in the acreage of 81%.

We currently have 1943 net future drilling locations identified only acreage was 96% of the acreage is currently held by production.

Since resuming our completion program.

The very end of June we have turned 15 additional wells to sales.

This now brings our total DNC count up to 252 wells since early 2015.

I will let Roland mentioned, we have added two additional rigs since our last call and we're now running a total of six rigs.

Due to the the bike in the Frac activity in Q2, we started out the third quarter with a total of 21, Doug we've seen.

Since worked that down to 16 wells currently.

Our go forward DUC count should remain roughly at this level through year end and into next year.

We started out the quarter with two frac crews, we ramped up to three frac crews in early September.

We will continue to run these three frac crews through the end of the year.

Based on our current six rigs scheduled to seven rigs next year, we anticipate running on average 2.4 frac crews in 2021.

Over on slide 14.

This is our latest Haynesville bowser.

Optimized drilling inventory at the end of the third quarter.

Our gross operated inventory currently stands at 2401 locations with our net operated inventory at 1763 locations.

This represents a 73% average working interest owner operated inventory.

Our non operated inventory is at 1352 gross locations with the net non operated inventory at 180 wells.

And this represents a 13% average working interest.

For the gross operated inventory, we have 494 short laterals 905 medium laterals in 1002 long laterals.

Breaking this down by the gross the gross operated inventory buys zone, we have 54% of our locations are in the Haynesville.

46% or in the Mosher.

We are focused on converting or short laterals to long laterals, while the total number of locations has not grown the number of 8000 foot and longer Haynesville laterals.

As increased to 420 up from 389 at the end of the second quarter.

This inventory provides the company with over 30 years of drilling locations boasting about current activity levels.

Slide 15 is a map outline in summary of the 15, new wells that we've turned to sales since the last call.

The new wells were spread out fairly evenly across our Greenwood wall steel, our Logan sport and Elm Grove, It Ambrose acreage the.

The wells were tested rates of 16 million a day to $35 million today.

With a 26 million per day average IP.

Wells were drilled with lateral lengths ranging from 6049 feet up to 9869 feet and.

And we averaged 9000 89088 feet for the quarter.

All of these completions were completed with 2800 pounds per foot.

As mentioned earlier, we have three frac crews working today, and we will maintain that level of completion activity through the end of the year.

The current DUC count as before stands at 16 and that should maintain through the end of this year and into next year also.

Slide 16 is a chart. This illustrates the progress we continue to make driving down our DMC calls.

These results track only our medium to long term laterals, that's half the lateral links of greater than 7000 feet.

Our DNC cost continue to trend down in the third quarter and is starting to flatten.

We again achieved our low lowest all end DNC cost to date at $998 a foot.

Contributing to this low DNC costs were two record low cost wells at average less than $900.

This DNC cost is 17% lower than the same quarter, a year ago and it represents a 2% cost reduction from the previous quarter.

The story is really the same current service costs, coupled with our really high completion efficiency and the smaller jobs has really been the driver.

For the low cost.

Since the last call we generated enough production history on earliest wells completed with the reduced frac intensity to evaluate to evaluate performance. We have observed a slight reduction in our eurs, which we expected to a small degree and it was made sense at the low gas price environment. We're in earlier in the year.

Starting in September we have shifted back up to our original job size in the 35 to 3600 pound per foot range as we have entered a much better gas market.

Based on our most most recent well costs, we're still aiming to keep our costs relatively flat in the 1000 1050 foot range.

Going forward the market demand on services will play a large part in our cost structure.

That being said, we do believe our current cost structure will maintain through the end of the year, but we acknowledge that that us and the rest of the industry may be facing some upward pricing pressure in 2021.

That kind of recap the operations are now going to turn it back over to Jay for some final comments. Thank you Dan and also Roland. Thank you if everybody would go to slide 17.

I'll go over this slot and then turn it over to Ron for some guidance I'd like to direct you to slide 17, where we summarize our outlook for the rest of this year and our initial thoughts on next year.

For the first half of this year, we remain primarily focused on free cash flow generation and managing the company through the low oil and natural gas price environment Weve been in a while natural gas prices remain relatively low through October due to elevated levels of gas and storage to the outlook for natural gas has improved substantially for later.

2020, and 2021, driven by expectations for significant declines of natural gas supply due to continued reduction in natural gas directed drilling and completion activity and less associated gas production from related activity in oil basins, resulting from the collapse of oil price.

Yes.

Starting in the third quarter, we went back to work and resume completion operations were three frac crews and order work through the backlog of Ducs. It to Dan had talked about and we've added two additional drilling rigs to generate production growth.

This year and more importantly in 2021 that coincided with improved natural gas prices. We also recently made the decision to accelerate well completions originally planned.

In 2021 for.

We're keeping a third frac crew working in the fourth quarter, which moves about $30 million.

Through our 2020 budget from 2021 in order to complete seven wells three months earlier.

The rationale is that we can produce the gas related to these wells earlier in 2021 in a higher gas price months the strength that we lean on this year is our industry, leading low cost structure and well economics.

With all our focus on reducing activity and delaying startup of the new wells, we expect to have about a 2% pro forma production growth. This year next year, we expect a balanced growth of probably 6% to 8% while generating substantial free cash flow. So we will use to pay down our debt and reduce our financial.

Average, we've hedged almost half of our production over the remainder of 2020 and 64% of our 2021 production and have strong financial liquidity of $928 million. Following our recent bond offering so with that now I will turn it over to Rob provide some specific guidance.

For the rest of the year Ron Thanks.

Thanks, Jay on Slide 18, we provide financial guidance for the fourth quarter of 2020 in our initial guidance for 2021. This guidance reflects the impact of the timing of our drilling completion schedule as well as the shut ins discussed earlier in this call but.

For the fourth quarter, we anticipate spending $150 million to $170 million on our drilling and completion activities, which can result in 2020 total spending being $450 million to $500 million.

Thats higher than we discussed in the second quarter call due to.

Laterals getting longer some additional workover activity.

Non operated activity and some minor leasing costs.

Fourth quarter 20 production is expected to average 1.15 to 1.25 Bcf per day.

In our 2020 production is expected to average at the low end of our prior guidance of 1.25 to 1.3 Bcf a day, despite the impact of of the shut ins and hurricane impacts previously.

Previously discussed looking ahead to next year, we're providing initial capex guidance of $525 million to $575 million and production guidance of 1.325 to 1.425 Bcf a day.

A day.

We anticipate the addition of a seventh rig by the middle part of next year.

Lee is expected to average 21 25 cents.

Gathering and transportation costs are expected averaged 23% to 27 cents.

That production and AD valorem taxes are expected to average eight to 10 cents.

Our DDNA rate is expected to be 90 cents to one dollar and the cash DNA is expected to be in the 5% range, 5% to 7% range on a unit basis.

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For the past the call, we'll just we'll turn it over for questions and answers.

Certainly ladies and gentlemen, if you have a question at this time. Please press Star then one.

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

Thanks, and good morning all.

Good morning.

All right with with regard to the 2021 outlook would it be fair to assume you'll see minimal production from the seventh straight you're adding in 2021 and the real impact will be felt in 2022, where that activity increased could sustain growth in that call it 6% to 8% range.

Yes, yes. This is Roland Derek and that's a good observation I think really if you look at that.

The way that said shell companies, especially that how were developing.

Yes. The shale you note the capital that we spend today really doesnt generate production until four to six months later on because we always drill on pads, just because it increases the drilling efficiency. So much. So you have two to three wells kind of waiting before they come online so.

And given that we are looking at.

I think as we look ahead and India.

Yes, the end to 2022.

We wanted to create some guidance.

That even though it didnt add a lot of production to 21 and probably the action we did to actually to spend additional dollars in the fourth quarter, probably has a great impact on on 21.

But but that adding the extra rig it really doesnt there really isn't a lot of production that gets out in time to really move the numbers by what it does I think we have a we have set the stage for various sustainable program into 2022.

Versus having a higher growth rate in 21, and then going back to have hardly any growth and 22, So I think.

But given the outlook for gas and the.

Companies kind of.

Exiting this period of very low gas prices and be very defensive but wanted to set kind of a more sustainable program out there that makes sense for the overall achievement of our goals, which is to get leverage below two and.

And use the straight like Jay pointed out at the very high margins that these wells can generate in this gas price environment, we do we're sensitive it back to the market it doesnt like.

Additional spending and growth, but I think you know I think if you focus really on that where a natural gas company and the outlook is somewhat stronger next year, where it's not the same cases that will accompany this looking at a more uncertain commodity in that.

And not a favorable kind of future. So I think we are at we think that we.

We think it's the best actually for the company as to how we achieve our goals and it also sets expectations into something that we think we can really outperform next year and also outperform in 2022 and that is not overly short term focused on just.

Getting the maximum results next year well on again, our goal is to figure out on a quarterly basis how.

How we should spend our capital dollars. That's why we've looked at 2021 commodity prices.

We've looked at the fourth quarter 2020, we should we we should keep a frac crew busy we should lean into 2021, because again, if you look at the advantage we have humming.

How many we have advantaged access to the demand market or the Gulf coast were favorably exposed to Henry hub right. So when we look at that we need to lean into that that market that we have and you see the LNG exports I mean, they are at an all time high right. Now. So we think we're the weather where it is or where commodity prices really arent.

Where our leverage where it is.

And our low cost remain near the end is given this low cost and high margins.

We've got a good view and outlook for the fourth quarter as well as 21 22. So we don't have any disappointing quarterly results to you again period, that's what we're doing today, we're correcting everything.

Thanks General and that certainly makes sense and and as my follow up referencing slide six you guys were clearly impacted by several uncontrollable events and in Q3 as you look out to Q4 and then into 2021, how do you. In addition that shut in metric trending over that period.

Yes, Thats a good question I mean.

A large impact is always is always the simultaneous operations switches.

Happens now because we do you have to protect tier offset production from from offset frac activity, either we created or one of our neighbors creates it. So yes, I think it's you know it's probably.

Yeah realistically at our 5% number you know pretty flat I mean, especially as we if we keep a more consistent program I think it stays more consistent and doesn't have the kind of gyrations and that unknown is their power issues. Our pipeline issues that are caused by other events.

And then you know I think what what what for the first time ever.

Really in this.

This late September October period.

Yes. It is a major producer in the Haynesville basin, we for the first time, they withheld gas from the market because of the market is struggling with the storage levels before it became comfortable with that level and at the same thing that the large producers stayed at Apple Asia, and it's our responsibility to do that and our actions allow that market to recover pretty quickly and.

And also.

Yes.

Allowed us to realize instead of realizing a very low price for the gas to save it and then produce at a week later at a higher price. So I think we're also going to have to be mindful of that and in the end you know.

Controlling that the flow of gas, especially the swing gas Thats opened.

And.

And to market.

Every year. So far you know there has been a sensitive period for gas as it exits the.

Injection into period in storage fills up and this October is is just it's been that transition now we had at last year and 2019, but not as severe in that this year too but the good news is we is it seems like we've made to get adjustment through it and operators like us.

Uh-huh responded and very proactive to given the you know to keep it in that situation workable. Thank you again to you won't see the impact of the private equity backed haynesville players.

They will have the same top showed an issue I think the good thing for Comstock you noticed we.

We did add about 4000 additional acres to our footprint. So we've got 309000 net acres, we do spread our drilling program, our Kendall North South East West both in Texas, and Louisiana, and when you know when you look at our drilling program. We've begun to have a pool of information from the offset operators, we figure out when they are going to drill when theyre going to complete.

And we try to toggle all of our programs around because of our large footprint. So not to have quite as much exposure to these shutdowns, but again I think.

Dan will tell you that theres, probably 5% bolt on slide five.

And that's that's kind of where we are right now with our footprint. There will we put out our model and our guidance Ron has done that and these kind of stuck that top of handicap in for the future.

And we didn't focus on it much Derek at our conversation earlier like we normally do but we do have initiatives going on in 21 that were going to be able to to really get less and less gas sold at Perryville, which as you know that's that's get more vulnerable to especially for gas coming out of basin like it did in disrupting that basis. So we've all.

He's had a goal of removing ourselves from that market and I think next year Theres several initiatives. The big one obviously is the Kt Atlanta opened it up but we also have we've also been working with our midstream partners to give us some other ways to bypass perryville and get it and move gas you know more to the goal.

Off.

At least have the flexibility to respond to that.

Thats great extremely helpful. Thanks for your time guys.

Yes. Thank you.

Thank you. Our next question comes from the line of John Mcintosh Sunrise. Your question. Please.

Good morning, Jay Thanks for that one.

Right so far out of the question.

A question I understand the pickup in activity in that attack and leverage can be a little easier from the EBITDA side sometime so how under this new program, where do you see leverage over 21 and 22 and.

Yes targeting that we talked about two and half times on into next year, but getting down into that two times is does this get you there faster or.

Yes. It does we were wrong, we'll give you some numbers on thank God, but we will de lever faster.

And it's all because of the market demand and the process. We are good at Henry hub now we do deliver week when we when we had all of our one on one conference calls we said.

The only reason, we would add a rig or or complete wells earlier is it allowed us to de lever quicker, but thats. The reason you do it. So Roland you have a number here I think we get very close to getting down to our two times by the as we finish up 22 with this plan and I think.

By investing a little bit end to 21, it actually allows us to take to hit that goal there versus just being shy of it. If we look at 22, just have kind of under and having more of a flat production profile.

Again, we're we're.

It's been it's been erratic for the company, obviously go from growing at a 34% rate back.

You know in 2018% to 2%. This year is probably what is going to end up.

With all that and then back.

Back to more sustainable levels.

The 6% to 8% in it but we're really targeting to try to get to more of a 5% growth that to balance some growth to improve EBITDAX to get that leverage ratio down faster at the same time, though also.

Also reduced the overall level of debt and keep keep a lot of free cash flow as a as a big target and.

The strip today gives us that opportunity to achieve all of that data with this program in this two year period.

And then that gives us for growth in 2022, it might be 5%. So what our goal today again, it's to reset the program for the fourth quarter 20, and for 2020 122, that's exactly our goal. So those are great question. It is all about delevering.

Worth where we are and the locations, we have and the profits that we make.

All right. Thank you and then from a follow up on the you mentioned in the call maybe move into a little bigger.

Bigger profit.

Yeah.

Where.

What are the what are kind of the drivers behind that decision is that more into your base or is that more to bring bring volumes on faster at the front of the curve kind of trying to capture this this higher price environment that we will go ahead and then too.

Yes. This is Dan so you hit on it there that first point I made us all he wore driven.

Well, it's basically a hand in hand with our performance when we so.

Smaller jobs, we were in the lower gas prices and we did anticipate maybe a 5% reduction in New York, which we ran the numbers you know that made sense to basically test that SaaS.

We were seeing the yours more like maybe 8% to 10% smaller for and this is really for the wells might be.

Moreover, in that state line area, the Greenwood Wasco Maria.

And so when you run it at the higher gas prices I mean, it's clearly you know you need to pump the the bigger jobs, which also means you're pumping more water.

It's just it's just a matter of the economics I mean, the wells deliver better PV 10 value when you do that at the higher gas prices.

Yeah, I think it's a good question for Tim because we essentially will shift the book as we look at companies that use 567000 pounds of proppant. We we didn't think that would be what we need to do we dropped down to the lower both ends of this 24 five 600 pounds.

And water like Dan said, and so we've kind of tested the bottom at a low gas Frost and you should do that because you do say precious dollar dropped upfront, but when you have a gas process. You know 293, three tenthreetwenty in you look to PV value and you looked at how quick these wells payout and increased volume that it's easier to.

So you know the the right thing to do is spend a little bit more money and we're still in that thousands of thousand 50 per completed foot.

I have a much better performance, which dropped our leverage right. So it's our job to tell you that too we didnt try to hide that we should we should probably go back up there because we did test it and we know we need to do it.

Great question.

Hi, Thank you all.

Thank you. Our next question comes from the line of Bank Chowdhry from Goldman Sachs. Your question. Please.

Hi, good morning.

You mentioned that gas prices are having or decision to grow EBITDA to meet our leverage goals.

Philosophically talk to what would drive a.

Shifting to lower activity and spending in FY would have more free cash flow is then a gas price point at which you would reduce activity and how has that price point evolved given recent reductions to my cost.

Well I think that it is definitely gas prices that that are a factor that in and how we look at the whole picture and obviously gas prices are are not what the futures market is anticipating for 2021 and they underperform that.

We would definitely reassess our spending because I think that free cash flow goal, we're going to maintain it and.

So I think that that is definitely a big factor in I think we.

We think we've gotten.

Overall as the market seems to be fairly comfortable that at least in 21. At this stage is set for those $3 kind of area gas price.

And we will certainly reassess, adding a rig by mid year next year, if it's not at that level anymore.

So we're not we're not at all locked into one strategy.

But we wanted to present more of.

[music].

A balanced program that did and just focus on 21, and an absolutely maximize 21, which the six rig program really can do but.

But it could that comes at the expense of.

22, and you use you stop making the progress towards.

Your leverage goals and 22, if you don't make any investment for it so that that was the goal of today.

John I think in the beauty is we don't we don't have any farm transportation obligations or call just to drill we don't have any minimum volume commitments to call just to drill 96% of our acreage is held by production. So our capex budget is just driven internally by.

What we need to do to to.

To improve our balance sheet and pay down our debt and I will be very reactive to the changing environment.

So we will wait and as we were this year and playing defense in the first.

Half of this year, we can be very reactive because we don't have long term obligations that that dry.

Asked to have to drill any wells at all.

Yes, the other thing people forget him and our denominator is the consistency of our wells. We have 30 years of inventory at this rate I mean, we.

Usually before about the quality of your locations.

Nobody ever ask us about that so we've taken that off the table, let just say how can you de lever I mean, how can you de lever and the you know where we are we're the only pure Haynesville SaaS company of this size.

We should I wealth again, our our advantages this access to the Gulf Coast and we do have Greg gas process. So, let's let's use our shrink we can act like another company in another basin. We've got backlog definitely we are in our base.

And that's why we've got to tell you we're going to reset the whole program.

For the fourth quarter of this year and 21 22 would also tell you that whatever we need to do to if we need to shut in those when gas because the process were long you've now seen and we've done that we demonstrate the week, we will do that.

Yes, we need to go back to lower profit crosses are lower we'll do that we need to go back to higher profit there.

And we'll do that again, our goal is to be very transparent with you as a partner as we we create a even a greater company.

Thank you for the color Thats really helpful. Thank you.

Thank you for the time and the question.

Thank you and as a reminder, ladies and gentlemen, if you do have a question at this time. Please press Star then one.

Our next question comes from the line of Kevin cutting from Citi. Your question. Please.

Hey, good morning.

Just a quick one on 2021 expectations.

Obviously as you know a few others increased growth next year in light of higher prices. What are you looking at as far as non op spending for the year and are you seeing any of those private equity backed companies kind of gearing up for our production growth next year as well.

Yes, we don't see yeah, we have very limited touch points with other companies that are not part of our portfolio has always been fairly small and basically that we.

We.

We really like to do acreage trades to try to even make it smaller and I think that we actually finished some really good acreage trades.

That you saw kind of come through the location numbers and acreage numbers, this quarter, which geosouthern and indigo that really improved our overall lateral lengths overall.

And reduced our non op you know potential active.

Activity in the future and also actually gave us more locations in our very very best in show.

Lowest transportation cost area. So it was really a big win and I'm sure that.

We also met their goals Hino and things they were trying to accomplish and so yes, we still see non op is a very not a big part of our budget and debt and frankly, if not project doesn't meet our high expectations. You know we've now got good partners that want to buy those interest and so we're we're very tuned on saying hey.

If we can generate a really good return from non up you know what.

It will sell down the wellbore to people that are Ericsson invested in that so.

I think we probably always have budgeted I mean, Ron you might say that we have a potentially.

$35 million to $40 million of non op activity that we kind of always expect to have let's start right.

Is typically average kind of in that 6% to 8% of the total budget, but we're very proactive it trying to disarm that before it becomes a big number.

Because nobody that we just never like being in our properties generally.

Right understood Thats. It from me. Thank you for the time.

Thank you. Our next question comes from the line of Phillips Johnston from capital One your question. Please.

Hey, guys. Thank you I also wanted to ask about the 21 program I think it was only a month or two ago you guys are talking about running so.

Six rigs throughout next year and growing only by 3% to 5% for about 450 million in Capex.

Now it sounds like you're you're talking about adding a seventh rig in the second quarter spending closer to $550 million and growing by 6% to 8%.

Sounds like that the change in tact, mainly relates to just the stronger gas prices that you're seeing on the strip and obviously that that that helps your leverage ratio.

If the strip plays out but of course, that's that's only at the strip sort of holds true or if you actually hedge.

The strip so I guess my question is.

Why chase those higher prices that you're seeing with higher activity why not just let the higher prices slow.

Hello.

Straight to the bottom line in terms of additional free cash flow and if you. If you like the prices and actually want to grow by that amount why not just hedge the majority of your production for both 21 and 22.

I think it's because I think you got I think for 21 I think here.

Your suggestion would be a way to optimize it but we think thats very short term thinking and if you're focused on 22 is I think that if people become more focused on it as we get into middle of 21, you know yes.

He had done under investment really.

Means.

No growth in production and 22, and so I think that we're really making an additional investment really for 22.

And you know we can defer if we if the if so if the prices are weaker we won't add the seventh rig we're not we're not committing to it ended in.

And advance at all.

But it is to present you with a more balanced program in 21 that sustainable versus a program than 21, Thats, absolutely just maxed out to produce short term results because before.

Before you know it you'll be in 22, and then also I know they like well.

These are you're no longer making any progress toward toward de levering because.

You Havent made to get enough investment. So we thought we would level. It now again thats accelerating a little bit of Capex from the fourth quarter to level out at the beginning of 2021 be really consistent when prices are high right now we have 64% hedge and 2021 and then propel you over into 2022 is a five.

Percent production growth at the same time, we do think that we balance two things we balanced the growth properly and that we delivered quicker at the same time. So it's not that we have to make a big correction sometime in the latter part of it.

2021 to change what we're doing to 222, because if you don't spend a decent amount of money drilling year production will drop off any.

Any of the shell companies, where they're at.

Later or are more oil doesn't matter you do have to have a decent amount of spending and where were located.

It tells us that we need to we need to balance this budget today and reset at today.

Philip and you've been very nice in your writings, but what would you expect us to do and again, we don't want to disappoint antibody and we want to make sure everybody knows why we're laying this out and knowing yet.

We can change it we need to change it we can change it crosses go a little higher were changes if they go lower we change it.

But we think this is a rock this is the right way for the next.

So two years in two months.

Yes.

Free cash flow without being sacrificed any given these hot at the prices that we see now we are still going to have have very substantial free cash flow at the same time have made the right investments. So then you look up and say you know what 22 looks pretty good too it's not like this as a one year wonder and that and I think that's that's the opportunity but.

Likewise as we answered the question before we're looking at prices every day both at the we're looking at the Nymex prices in the future strip or you cant hedge and that also you know the cash prices and you know we will be very reactive to that and.

And not and.

And and not end up.

Accelerating capital expenditures into a declining price environment, that's something we would definitely want to do.

Yes, I mean, I guess I guess the concern is that was only less than 30 days ago, we're shutting in volume because of low spot prices right and then we're talking about adding up.

Additional rig next year. So I guess my my follow up would be would you look to hedge more 21, I'm sorry, 22 volumes before you added that seventh rig I'll definitely hi, Angela and then by the time, we add you know that they're hedged physicians need to be more established for 22 million. There are acquisitions, we want to be at the.

Point, 50, and 70%, yes, maybe 60% to 70% over the next 12 months. So yes, Hello, Philip you are really not going I guess, we will not be going into it.

Hedge basis, so we will continue to.

To deliver on the hedges in the timeframe that we continue that we promise, which is at 12 to basically 12 months, but 12 to 18 months out yet and if we can't we have to be able to establish those to support that rig if not it won't happen, yes with the leverage we have Ami. We will you have to hedge we should do that so yes those are coming.

Good luck to you.

Okay.

Makes sense and then maybe just also if I could just I guess theres theres been some obviously some large corporate mergers announced in the last 90 days or so.

I wanted to get your latest thoughts on this potential comp consolidation in the Haynesville.

Well you know our goal is we hopefully today, we've reset the program and our execution will be what we as a happy meetings.

I think that if we continue to execute I think the stock price will perform.

I think that you're going to have some trended haynesville of producers that we'll need to do something hopeful.

Hopefully what we've done so look we've set our self in the middle of kind of the square where.

To go to exit you Gotta alleged talk does for look at us and we can evaluate.

If there is an opportunity for us to grow and then have a higher market cap and more size, but the same time continue to de lever and to continue to have our high margins.

And if we can't do that and we were not interested in any of those opportunities I think.

We've been smart enough to say, yes on the company parts of the World.

And some others and we were not going to lose that age that we have.

Does that edge is everything, but we're not going to lose it and yet we're not we're not going to go set in the corner not looked at opportunities to expand that if in fact those Mike.

Of the equity owners stronger and the bondholders stronger at our back stronger.

So we're going to we'll keep shopping all the time and we will keep executing.

Sounds good thanks, guys appreciate it.

So.

Thank you. Our next question is from the line of Kashy Harrison from Simmons Energy Your question. Please.

Good morning, and thank you for taking my questions.

So just one a one or two quick ones for me sorry.

So I was wondering if you could give us a refresher on how to think about.

Corporate base declines I'm, assuming since you pretty much shutdown activity over the last few months you have improved visibility on to what that corporate decline looks like and then maybe how we should think about that expectation. Your your corporate decline expectations over the next several years.

[music].

What weve, what weve message in the past it said that the the corporate decline rates about 40% upper thirtys to 40%.

If we look out over the course of the next year, it's around that 40% level in then it'll improve kind of.

By 5% to 10% in the in the second year, and then continue to flatten out as as we have more of the established production base in Ed.

At a at a lower decline.

So that in terms of the first 12 months kind of.

That plus or minus 40% going down to.

I guess.

25% to 30%.

And then and then kind of flattening out there.

Got it got it that was it for me. Thank you.

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

Yes, sure and again, everybody that stayed the whole hour on the call. I mean, we are you can imagine opening for we are that led to this huge fit that are with us and again our goal.

As to reset the program for the fourth quarter of this year and then a 2021 2020 to give you something that that we think we can can really beat.

And we want to adjust as capex structure to maximize our advantaged access this to this demand market than we have in the Gulf Coast Thats a great advantage, we have it's a it's a material geological advantage we have.

We're just to have some great exposure to Henry hub prices right now we want to use that.

If we do if we need to change this budget it will be pull back.

But but it's real that is reset and it's good to.

And again, we thank you for being a partner with us on that.

Thank the brighter days are ahead of us in our rearview mirrors pretty small in the windshields really big and gas process looked really good and you've got a really good team you're committed and we take that theres. Good. They are bad day, we take whatever the day is work Cannibal to you. So thank you. Thank you for giving our best.

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

[music].

[music].

[music].

Ladies and gentlemen, thank you for standing by and welcome to the third quarter 2020, Comstock Resources Inc. earnings Conference call. At this time all participants are in listen only mode. After the speakers presentation, there will be a question and answer session.

A question during the session you'll need to press star one on your telephone as a reminder, taste program may be recorded I would now like to introduce your host for today's program Mr., Jay Allison Chairman and Chief Executive Officer. Please go ahead Sir.

Thank you. Thank you for introduction. This morning again I want to thank everybody that's taking their time to listen to the story today I know we have a lot of your we know a lot of your really good proud to have been forever and ever and ever. So today is an important day yet are not really in our corporate lot where are you.

You know, we're all human and you know we do understand the third quarter results were somewhat disappointing quite frankly.

And I can speak for me and for everybody else the management team we hate it.

And you know there they are disappointing for the reasons that you're aware of I mean, they're all logical reasons are still disappointing show dance curtailments related to hurricane Laura.

<unk> curtail much then there's a litany of other small raised so.

You know I think our goal. This morning is to share what we see.

The fourth quarter 2020, as well as 2021 or 2022 and to show you what our stakeholders, how we plan to de lever our balance sheet and those fears by using our strength.

Of our peer leading how margins are low cost we've created in the Haynesville and a period of time, but frankly, a one the outlook for natural gas is extremely bullish [laughter] Oh really the most bullish here just bad that over 10 years.

Our job and the next 45 minutes or so.

Really today is to avoid any disappointments in the future.

And show you, how our high margin so nice work coupled with the right size.

Capital program over the next years can de lever the balance sheet and expand our trading multiples whether we all are winners.

All based on the commodity gas across outlook that we see today.

So thank you for trusting us and if we have dented that trust any place.

Please know that the Entercom thought table work hard to earn it back and even more by giving you a 100% of our best because we always have.

I will now start into our third quarter results and then we'll get to the Q and I will.

We will answer any questions that you have and be accountable for it.

Welcome to the Comstock Resources' third quarter 2020 financial and operating results Conference call. You can view a slide presentation during or after this call by going to our website at <unk>.

That'd be a W. W. Comstock resources Dot com and downloading the quarterly results presentation. There you'll find a presentation entitled third quarter 2012 results I am Jay Allison Chief Executive Officer of Comstock and with me as Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Ron Millos our.

BP of finance and Investor Relations.

Please refer to slide two in our presentation to note that our discussions today will include forward looking statements within the meaning of securities laws, while we believe the expectations in such statements to be reasonable there can be no assurance that such expectations will prove to be correct.

If you are following this you can turn to slide three.

On slide three we discuss the highlights of the third quarter November is a four month, where we finally exited the period of very low natural gas prices brought on by the warm winter we had as late November natural gas price closure.

Got almost $3 after hitting a low of $1.50. This summer.

The low production levels are brought on by the actions of disciplined natural gas producers combined with the decline in associated gas, resulting from low oil prices.

Of course, the 2021 future natural gas process to improve substantially so.

Since January of this year, we have been focused on reducing our drilling activity and deferring completion activity those actions.

Allowed us to generate free cash flow, even with a very very low process, we're receiving for our production the reduced activity. We had in the first half the year combined with the third quarter hurricane activity in our region.

Actively impacted our production this quarter as you say.

With the stage it set for higher prices later, this year and into 2021.

We collectively decided that we would go back to work in the third quarter.

We added two additional operated drilling rigs to bring our working rigs back up to six which is where we work can be ended the year and currently have three frac crews working to catch up on the backlog of drilled and uncompleted wells since.

Since our last report we have put 15, new wells on production, which have a par well IP rate of 26 million cubic feet per day, we did have a rocky quarters I mentioned on the production front, which partially was self inflicted.

As a wrap up of activity drove our shut in percentage up to 7% in the quarter.

The higher spending in the quarter reflects restarting a program we put on hold in the second quarter, but it is the right move as we look forward to improved gas prices that were in we did achieve our goal of reducing well cost to just under $1000 per lateral foot, which is significantly lower than any other haynesville operator.

With recent changes to our completion design.

We expect well costs to increase a little bit as Dan Harris, who will go over later.

While it made sense for bringing well cost down as low as we did with weak gas prices. This year with gas prices closer to $3 plus now it makes sense to invest in a little more proppant as we believe the wells will have a higher return.

As we will discuss more today, we recently decided to increase our completion activity planned in the fourth quarter by running at additional Frac crew, which moves up the completion of seven wells that we plan to complete in 2021, the additional investment will pay off in 2021 to allow us to have a little higher.

The action to take advantage of the higher gas prices.

The third quarter, we completed a follow on to $300 million notes offering to further pay down borrowings on our bank credit facility, we have reduced our outstanding bank borrowings from 57% of availability to just 36% of our availability.

Bob freeing up the bank credit facility, we increased our financial liquidity to $928 million.

The low oil and natural gas prices combined with loan production in the quarter did this.

Impact of profits were generated in the quarter.

Oil and gas sales, including hedges were $212 million.

Our adjusted EBITDAX came in at a $148 million on our operating cash flow was $93 million or 38 cents per share. We reported an adjusted net loss of 13.8 million or six cents a share.

With higher production and stronger natural gas prices, we anticipate returning to profitability in the fourth quarter, which is now.

We'll have rather than go over the financial results in more detail Roland alright, Thanks, Jay on.

On slide four we summarize our financial results for the third quarter of this year our production for the third quarter totaled 103.

CF of natural gas from 354000 barrels of oil total production of 105 Bcf He was 4% higher than the third quarter of 2019, our oil and gas sales, including realized hedging gains were $212 million, which was 15% lower than.

2019, and this was all driven by the lower oil and gas prices, we had in the quarter.

For prices in the quarter averaged $33.52 per barrel.

And thats with the hedging gains we had.

In the quarter and are realized.

Gas price, including hedging gains was $1.95 per Mcf.

Our natural gas price realization overall was down 14%, which offset the production growth that we had in the quarter.

Adjusted EBITDAX came in at $148 million, which was about 22% lower than.

In the third quarter of 2019, and operating cash flow of $93 million was about 35% lower.

We did report a net loss.

$130.9 million for the third quarter or 57 cents per share, but most of that loss is attributable to the $155.6 million unrealized loss on the mark to market of our hedge positions.

Well that is our caused by they substantially improve at the futures the future natural gas prices since the end of the second quarter.

Our adjusted net income.

Excluding the unrealized mark to market hedging loss and then certain other unusual items was a loss of $13.8 million or six cents per diluted share for the quarter.

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Slide five we summarize our financial results for the first nine months of this year.

Auction for the first nine months totaled.

At 349 Bcf fee.

Okay, and about 1.2 million barrels of oil, which is 90% higher than our production for the first the same period in 2019.

Course, most of this increase is due to the acquisition of heavy Park energy, which we completed in July of 2019.

Oil and gas sales, including.

Realized hedge gains were $716 million, 40% higher than the same period in 2019.

Oil prices.

So far this year have averaged $39 at 84 cents per barrel and our gas price is $1.96 per mcf, both including the hedging gains we had.

Overall, this is 18% lower than the prices we had it for natural gas in the same period in 2019.

Adjusted EBITDAX came in at $511 million, which was 35% higher than 2019 operating cash flow was $367 million.

Thats, 31% higher than the 29 team.

We did report a net loss of $160.9 million for the first time much this year or 77 cents per share again. This was due to that mark to market loss, the unrealized mark to market loss on our hedge book.

Adjusted net income, excluding the unrealized hedging losses and other unusual items was $12.9 million or a net income of six cents per diluted share.

Third quarter production was adversely impacted by higher shut at level than normal as you can see on slide six.

7% of our natural gas production, which had it in the third quarter as compared to 4% in the second quarter.

Much of that.

Shut in as due to offset frac activity, either by our simultaneous operations or other haynesville operators, but we also temporarily shut out a portion of our production over the course of about a week.

Due to the impact of Hurricane Laura that caused wad, Pat widespread power outages in our region.

And then also in September.

Good part of the month of September then carried over really into the first.

Yes.

12 to 14 days or so of October we did experienced wide differentials in the daily cash market at Perryville and then other and other index is at our kind of region in the southern.

Southern kind of Gulf region, and this was validated concerns that the natural gas market had over the high storage levels as we've been we've been as we exit the period of storage injections.

So the only gas it's really impacted by these daily prices is what we call our swing natural gas that was not sold during bid weaken in that part of our base load sales.

So we chose to restrict some of the new wells that were coming on in September and then and then.

Given thats very low price that they this extra swing gas was getting.

And these high differentials in the month of September and also the declining overall index prices and that volatile, but did caused our overall differential in the quarter to widen about 10 cents in the third quarter.

Yes. This situation did continue into October really only the first couple of weeks of October.

And then we took action in that very first part of October two two actually curtail for price reasons 300 million a day of our production and overall, we did this for about 11 days.

That action along with.

The startup of evidence of LNG facilities coming back after the Hurricanes.

But really helped.

Reduce the concerns about storage fill it up and then we saw that the.

About mid October we saw the.

Yes, the daily cash prices go back into a normal relationship and differentials narrow and then we put all that gas really back into the market.

So I think as as October has finished out and as we entered November we've we've seen a very healthy situation.

It depends which has been supported by.

Yes, very favorable kind of injections to storage and even today withdraw.

We.

We also saw that you're obviously, our non operated oil production, which is primarily located in the Bakken region. Also has continued to exceed experienced substantial curtailments, which carried through in the third quarter. We had about 12% of our oil production that was shut in by the operators that operate at due to the very low oil prices are.

Other issues in the Bakken region.

On slide seven we cover our hedging program.

Yes for the first nine months of this year, we had 50% of our gas volume hedged, which increased our realized gas price to $1.96 per Mcf fee from the dollar 60 that we actually received from selling our production.

We also had 86% of our oil volumes hedged, which increased our realized oil priced at $39.84 versus the $30.35 per barrel that we actually received.

Overall during that period, we we had realized hedge gains of $133 million.

But with the improvement in future natural gas natural gas prices.

But.

We also took that opportunity to continue to add to our hedge book, but really at higher levels than we'd hedge before and then also using collars.

So we've added about 10 million a day of natural gas for the fourth quarter. Since we last reported earnings and we added about 38 million a day of natural gas collars in 2021, and about 12 million a day.

Collars in 2022, which gives us a good protection level, but also gives us exposure to the higher prices.

So as you look ahead for the fourth quarter of 2020, we have 663 million cubic feet of our gas.

And about 2800 barrels.

Per day of our oil hedged that.

The weighted average floor for price of our remaining 2020 gas prices is $2.61.

And for 2021, we have natural gas hedges covered about 836 million cubic feet of our 2020 wind production. So we're on target to having 60, 70% of our 2021 production hedged and will also work as we have this improving gas strip to work with.

Hedge our 2022.

Volumes appropriately.

On slide eight we detail our operating cost per Mcf produced.

And overall these are pretty comparable to the second quarter. So our operating cost averaged 55 cents in the third quarter as compared to our second quarter rate of 54 cents gathering costs were 21 said production AD valorem taxes averaged nine cents in field level cost were 25 cents.

One thing we did do this quarter in order to improve the comparability.

Yes, it other producers.

As to two Reclass, our AD valorem taxes that used to be showed as part of just lifting cost and include those and production taxes. So you will see that if you're kind of tracking the old members that sets really about one stat.

So that's a big change, but we think that this makes us more comparable to our peers.

On slide nine we detailed our corporate overhead per Mcf fee and our cash DNA costs were seven cents in the third quarter.

Which is slightly up in the second quarter, but thats, mainly due to the lower production level in the quarter.

Slide 10, we detail the depreciation depletion and amortization per Mcf produced.

Our DDNA averaged 95 cents in the third quarter, which was about eight cents higher than the second quarter and.

Most of that impact is due to the much lower kind of FCC type prices that are kind of backward looking that we use to do amortization.

On slide 11, we recap our third quarter and the first nine months of 2020 capital expenditure program.

So we spent a $110 million on development activities in the third quarter and 94 main of that was related to our operated Haynesville shale properties.

For the for all of 2020, so far we spent $316 million, including 259 million on the operated Haynesville properties.

We have drilled 36 or 28.6 net operated horizontal haynesville wells. So far this year and we also completed.

9.6, net wells that we drilled in 2019.

We've spent $56 million on non operated activity and for other activity. So far this year.

We generated $367 million in cash flow for the first that much this year, resulting in free cash flow 30 million. After we pay the dividends on the preferred shares.

After dropping our operated rig count to four rigs in April which was down from six back in January we've increased our operated rig count back to six rigs and the fourth quarter, we expect to spend about $150 million to $170 million. This year to drill 17 or 16.4 net operated Haynesville wells.

Cells, and then turned to sales 22 or 17.6 net haynesville wells.

We made the decision recently to keep a third frac crew busy in the fourth quarter, which we originally planned to release and then bring back in early 2020. This.

This does add about $30 million to our 2020 spending, but there and the reason for it west accelerate the completion of seven wells that before we plan to complete in 2021.

And this is in order to take advantage of the higher gas prices, especially that yes, we see for the first quarter of 2021.

And it was just as it was a decision based on if we have kept our original schedule.

We could we compare that to.

Two.

To keep it in this third rig, which was performing well for us and opt.

Operations ask us to look at data. We said you know, we actually make $15 million more by accelerating.

That completion into kind of the prime.

The highest gas priced lots on the futures curve and so we said that's the right thing to do.

If you look at the full year for 2020, if you combine the fourth quarter with that we now expect to spend about $450 million to $500 million. This year, which would have drilled 53 or 45 net operated haynesville wells and turned 55 or 42.2 net operated Haynesville wells.

The sales.

We also participated.

We exit or plan to participate in 18 or 1.3 net non operated Haynesville wells.

And in turn to 3.8 net wells.

To sales.

At the end of <unk>.

This year, we now expect to have about 16 or 15.4, net ducs are drilled and uncompleted wells.

So as you look ahead to 2021.

We expect to increase spending a little bit over the 2020 level and in response to these higher natural gas prices that we see and we expect to spend between $525 million to $575 million and trail 70, or 56.5 net operated Haynesville wells and turned at 65.

Of those wells are 56.6 net wells to sales in the year.

Our initial plans right now are to add a seventh operated rig and we would do that in the second quarter of next year, obviously as we get to that point, we'll assess it.

The natural gas market at our region.

And decide if thats still a great course of action if not it's as we've shown in the past we don't have long term commitments for drilling or completion services or or any kind of volumes to meet so it's clearly an economic decision on what happens when we spend the capex and.

And we can react as we did this year. We can we can we can react to the market and adjust our level of spending as is appropriate.

But we still remain focused on generating significant free cash flow would we see next year.

As having a bounty of that with the plans, we have and we target to have a minimum of at least $200 million of free cash flow.

As we plan for any future capital spending.

On slide 12, we.

We show our balance sheet at the end of the third quarter and during the third quarter as Jay mentioned, we issued $300 million of new unsecured notes the term out a portion of the borrowings outstanding under our credit facility. So we ended the quarter with about 500 million drawn on our credit facility and we do expect to continue to pay that down with free cash flow generated during.

The rest of 2020 and enter 2021.

For the quarter, ending cash position of $28 million, our current liquidity now stands at $928 million.

We have just over two point.

Two $5 billion of senior notes outstanding and Thats comprised of $619 million of our 7.5% senior notes due in 2025 and 1.65 billion MSR died in three quarters senior notes due in 2026.

So I'll now turn it over to Dan to cover the third quarter drilling results in more detail okay.

Okay. Thanks Roland.

Overall slide 13. This is just our updated outline of our current acreage position, which is increases this quarter up to 309000 net acres.

We control the majority of the acreage with a 91% operated position and have an average working interest in the acreage of 81%.

We currently have 1943 net future drilling locations identified on the acreage was 96% of the acreage is currently held by production.

Since resuming our completion program.

Very end of June we have turned 15 additional wells to sales.

This now brings our total DNC count up to 252 wells since early 2015.

I'll, let Roland mentioned, we have added two additional rigs since our last call and we're now running a total of six rigs.

Due to the the bike in the Frac activity in Q2, we started out the third quarter with a total of 21 Ducs we've said since.

Since worked that down to 16 wells currently.

Our go forward DUC count should remain roughly at this level through year end and into next year.

We started out the quarter with two frac crews, we ramped up to three frac crews in early September.

We will continue to run these three frac crews through the end of the year.

Based on our current six rigs scheduled to seven rigs next year, we anticipate running on average 2.4 frac crews in 2021.

Overall slide 14.

This is our latest Haynesville bowser.

Optimized drilling inventory at the end of the third quarter.

Gross operated inventory currently stands at 2401 locations with our net operated inventory at 1763 locations.

This represents a 73% average working interest owner operated inventory.

Our non operated inventory is at 1352 gross locations with the net non operated inventory at 180 wells.

And this represents a 13% average working interest.

For the gross operated inventory, we have 494 short laterals and 905 medium laterals in 1002 long laterals.

Breaking this down by the gross the gross operated inventory buys zone, we have 54% of our locations are in the Haynesville.

46% are in the merger.

We are focused on converting or short laterals to long laterals, while the total number of locations has not grown the number of 8000 foot and longer Haynesville laterals.

As increased to 420 up from 389 at the end of the second quarter.

This inventory provides the company with over 30 years of drilling locations most in our current activity levels.

Slide 15 is a map outline in summary of the 15, new wells that we've turned to sales since the last call.

The new wells were spread out fairly evenly across our green with Wall Street, our Logan sport and Elm Grove, It Ambrose acreage the.

The wells were tested rates of 16 million a day to $35 million today.

With the 26 million per day average IP.

Wells were drilled with lateral lengths ranging from 6049 feet up to now.

1869 feet and.

And we averaged 9080 9088 feet for the quarter.

All of these completions were completed with 2800 pounds per foot.

As mentioned earlier, we have three frac crews working today, and we will maintain that level of completion activity through the end of the year.

The current DUC count as before stands at 16 and that should maintain through the end of this year and into next year also.

Slide 16 is a chart. This illustrates the progress we continue to make driving down our DMC calls.

These results track only our medium to long term laterals, which have the lateral lengths of greater than 7000 feet.

Our DNC cost continue to trend down in the third quarter and is starting to flatten.

We again achieved our low lowest all end DNC costs to date at $998 a foot.

Contributing to this low DMC tell us for to record low cost wells at average less than $900.

This DNC cost is 17% lower than the same quarter, a year ago and it represents a 2% cost reduction from the previous quarter.

The story is really the same current service costs, coupled with our really high completion efficiency and the smaller jobs has really been the driver.

For the low cost.

Since the last call we generated enough production history on the earliest wells completed with the reduced frac intensity to evaluate to evaluate performance. We have observed a slight reduction in our yours, which we expect it to a small degree and that it was made sense the low gas price environment. We're in earlier in the year.

Starting in September we have shifted but up to our original job size in the 35 to 3600 pound per foot range as we have entered a much better gas market.

Based on our most most recent well costs, we're still aiming to keep our costs relatively flat in the 1000 1050 foot range.

Going forward the market demand on services will play a large part in our cost structure.

That being said, we do believe our current cost structure will maintain through the end of the year, but we acknowledge that that us and the rest of the industry may be facing some upward pricing pressure in 2021.

Kind of recap the operations are now going to turn it back over to Jay for some final comments. Thank you Dan and also Roland. Thank you if everybody would go to slide 17.

I'll go over this slide then turn it over to Ron for some guidance I'd like to direct you to slide 17, where we summarize our outlook for the rest of this year and our initial thoughts on next year.

For the first half of this year Weve remained primarily focused on free cash flow generation and managing the company through the low oil and natural gas price environment Weve been in a while natural gas prices remain relatively low through October due to elevated levels of gas in storage at the outlook for natural gas has improved substantially for later.

2020, and 2021, driven by expectations for significant declines of natural gas supply due to continued reduction in natural gas directed drilling and completion activity and less associated gas production from related activity in oil basins, resulting from the collapse of oil price.

Yes.

Starting in the third quarter, we went back to work and resume completion operations were three frac crews and order work through the backlog of Ducs. It to Dan had talked about and we've added two additional drilling rigs to generate production growth.

This year and more importantly, and 2021 that coincide with improved natural gas prices. We also recently made the decision to accelerate well completions originally planned out.

And 2021 for.

We're keeping a third frac crew working into fourth quarter, which moves about $30 million.

Through our 2020 budget from 2021 in order to complete seven wells three months earlier.

The rationale is that we can produce the gas related to these wells earlier, and 2021 and the higher gas price much the strength that we laid on this year as our industry, leading low cost structure and well economics.

With all our focus on reducing activity and delaying startup of the new wells, we expect to have about a 2% pro forma production growth. This year next year, we expect a balanced growth of probably 6% to 8% while generating substantial free cash flow there will use to pay down our debt and reduce our financials.

Average, we've hedged almost half of our production over the remainder of 2020 and 64% of our 2021 production and have strong financial liquidity of $928 million. Following our recent bond offering so with that now I will turn it over to Rob provide some specific guidance.

For the rest of the year Ron Thanks.

Thanks, Jay on Slide 18, we provide financial guidance for the fourth quarter of 2020 in our initial guidance for 2021. This guidance reflects the impact of the timing of our drilling completion schedule as well as the shut ins discussed earlier in this call for the fourth quarter, we anticipate spending 152.

$170 million on our drilling and completion activities, which will result in 2020 total spending being $450 million to $500 million.

That's higher than we discussed in the second quarter call due to.

Laterals getting longer some additional workover activity.

Non operated activity and some minor leasing costs.

Fourth quarter 20.

Production is expected to average 1.15 to 1.25 Bcf per day, and our 2020 production is expected to average at the low end of our prior guidance of 1.25 to 1.3 Bcf a day, despite the impact of the shut ins and the hurricane impacts.

Previously discussed looking ahead to next year, we're providing initial capex guidance of $525 million to $575 million and production guidance of 1.325 to 1.425 Bcf Andy.

A day.

Which anticipates. The addition of a seventh rig by the middle part of next year.

Lee is expected to average 21 25 cents.

Gathering and transportation costs are expected average 23 to 27 cents.

Production and AD valorem taxes are expected to average eight to 10 cents.

Our DDNA rate is expected to be 90 cents to one dollar and the cash DNA is expected to be in the 5% range, 5% to 7% range on a unit basis.

For the past the call, we'll just we'll turn it over for questions and answers.

Certainly ladies and gentlemen, if you have a question at this time. Please press Star then one.

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

Thanks, and good morning to all.

Good morning.

All right with with regard to the 2021 outlook would it be fair to assume you'll see minimal production from the seventh straight you're adding in 2021 and the real impact will be felt in 2022, where that activity increased could sustain growth in that call it 6% to 8% range.

Yes, yes. This is Roland Derek and that's a good observation I think really if you look at the way that that shell companies, especially that how were developing.

Yet the shale you know the capital that we spend today really doesnt generate production until four to six months later I guess, we always drill on pads, just because it increases the drilling efficiency. So much. So you have two to three wells kind of waiting before they come online so.

And given that we are looking at that.

So.

I think as we look ahead and.

Yes, the end to 2022.

We wanted to create some guidance.

That even though it didn't add a lot of production to 21 and probably the action we did to actually to spend additional dollars in the fourth quarter, probably has a great impact on 21.

But but that adding an extra rig it really doesn't end there really isn't a lot of production that gets out in time to really move the numbers by what it does I think we have a we have set the stage for a very substantial program into 2022.

Versus having a higher growth rate in 21, and then going back to hardly any growth and 22, So I think.

Given the outlook for gas and the.

Companies kind of.

Exiting this period of very low gas prices and be very defensive but wanted to set kind of a more sustainable program out there that make sense for the overall achievement of our goals, which is to get leverage below two and.

And use the strays like Jay pointed out at the very high margins that these wells can generate in this gas price environment that we do we're sensitive it back to the market Doesnt like.

Additional spending and growth, but I think you know I think if you focus really on that where a natural gas company and the outlook is somewhat stronger next year, where it's not the same cases that well company. That's looking at a more uncertain commodity in that.

And not a favorable kind of future. So I think we are we think that we.

We think it's the best actually for the company as to how we achieve our goals and it also sets expectations into something that we think we can really outperform next year and also outperform in 2022.

And that is not overly short term focused on just.

Getting the maximum results next year, well and again our goal is to figure out on a quarterly basis.

How we should spend our capital dollars. That's why we've looked at 2021 commodity prices.

We've looked at fourth quarter 2020, we said, we we should keep a frac crew busy we should lean into 2021, because again if you. If you look at the advantage we have.

We have advantaged access to the demand market or the Gulf coast were favorably exposed to Henry hub right. So when we look at that we need to lean into that that market that we have and you see the LNG exports I mean, they are at an all time high right now so we think where the weather where it is or where commodity prices really our world.

Leverage where it is.

And our low cost them a near the end is given this low cost and high margins.

We've got a good view and outlook for the fourth quarter as well as 21 22. So we don't have any disappointing quarterly results to you again period, that's what we're doing today, we're correcting everything.

Thanks, Jane Rolling that certainly makes sense and as my follow up referencing slide six you guys were clearly impacted by several uncontrollable events and in Q3 as you look out to Q4, and then into 2021, how do you envision that shut in metric trending over that period.

Yes, that's a good question I mean.

A large impact as always.

As always the simultaneous operations switches.

Yep.

Happens now because we do you have to protect your offset production from from offset Frac activity, either we created or one of our neighbors creates it. So yes, I think it's it's probably.

Realistically at our 5% number you know pretty flat I mean, especially as we if we keep a more consistent program I think it stays more consistent and doesn't have the kind of gyrations and that unknown as their power issues or pipeline issues that are caused by other events.

And then you know I think what what what for the first time ever.

Really and.

This late September October period.

Yes. It is a major producer in the Haynesville base and wait for the first time withheld gas from the market because of the market is struggling with the storage levels before it became comfortable with that level and it's the same thing that the large producers did at Apple Asia, and it's our responsibility to do that and our actions allow that market to recover pretty quickly and.

And also.

Yes.

Allowed us to realize instead of realizing a very low price for the gas to save it and then produce at a week later at a higher price. So I think we're also going to have to be mindful of that and.

Controlling the flow of gas, especially the swing gas Thats open.

And.

And to market.

Every year. So far you know that there has been a sensitive period for gas as it exits the.

Injection period in storage fills up and this October is is just it's been that transition now we had at last year and 2019, but not as severe and then this year too but the good news is we is it seems like we've made to get adjustment through it and operators like us.

Uh-huh responded and very proactive to keep and you know to keep it in that situation workable. Thank you again to you won't see the impact of the private equity backed painesville players but.

They all have the same thought showed an issue I think the good thing for Comstock you noticed.

We did add about 4000 or so acres to our footprint. So we've got 309000 net acres, we do spread our drilling program out to you know north South East West both in Texas, and Louisiana. When you know when you look at our drilling program.

Kind of a pool of information from the offset operators, we figure out when they are going to drill when they're going to complete and we try to toggle all of our programs around because of our large footprint. So not to have quite as much exposure to these shutdowns, but again I think.

Dan will tell you that it's probably 5% although slide five.

And that's that's kind of where we are right now with our footprint that will we put out our model and our guidance Ron has done that and these kind of stuck that top of handicap in for the future.

And we didn't focus on it much.

Eric at our conversation earlier like we normally do but we do have initiatives going on in 21 that were going to be able to really get less and less gas sold at very avail, which is that's that's get more vulnerable to especially for gas coming out of basin like it did in disrupting that basis. So we've always had a goal of removing ourselves.

From that market and I think next year.

There's several initiatives the big what obviously is that Kt Atlanta opening up but we also have we've also been working with our midstream partners to give us some other ways to bypass prevail and get it and move gas you know more to the golf.

Or at least have the flexibility to respond to that.

Thats great extremely helpful. Thanks for your time guys.

Thank you.

Thank you. Our next question comes from the line of John Mcintosh.

Thanks for your question please.

Good morning, Jack Thanks for that one.

Right so far.

Hey.

Question I understand the pickup in activity and that attacking leverage can be a little easier from the EBITDA side sometime so how under this new program, where do you see leverage over 21 and 22 and.

Targeting that.

Talking about doing that downstream into next year, but getting down into that two times. It does this get you there faster or.

Yes, it does but Rob will give you some numbers out thank god, but we will de lever faster.

And it's all because of the market demand in the process. We are good at Henry hub now we do de lever we when we when we had all of our one on one conference calls we said.

The only reason we would add a rig are complete wells earlier is it allowed us to de lever quicker, but thats. The reason you do it. So Roland you have a number here I think we get very close to getting down to our two times by the as we finish up 22 with this plan and I think by.

By investing a little bit end to 21.

It actually allows us to hit that goal there versus just being shy.

Shy of it if we look at 22, just have kind of under and having more of a flat production profile.

Again, where we're at.

It's been it's been erratic for the copy obviously go from growing at a 34% rate back.

Yes in 2018% to 2%. This year is probably what is going to end up with all the and then back.

Back to more sustainable levels.

The 6% to 8% and that but we're really targeting to try to get to more of a 5% growth that to balance some growth to improve EBITDAX to get that leverage ratio down faster at the same time, though also.

Also reduce the overall level of debt and keep keep a lot of free cash flow as a as a target and.

The strip today gives us that opportunity to achieve all of that with this program in this two year period.

And then that gives us a growth in 2022, it might be 5%. So what our goal today again, it's to reset the program for the fourth quarter 20, and for 2020 122, that's exactly our goal. So that was a great question. It is all about delevering.

Worth where we are and the locations we have in the profits that we make.

All right. Thank you and then for my follow up on the you mentioned in the call maybe move into a little bigger.

Bigger profit.

Yeah.

Yes.

What are the what are kind of the drivers behind that decision is that more on the U.R. base or is that more to bring bring volumes on faster at the front of the curve to kind of try to capture this this higher price environment that we will go ahead and then too.

Yes. This is Dan so you hit on it there that first point I made us all larger Ellen.

Well, it's basically a hand in hand with our performance when we.

So back earlier this year when we went down to these.

Smaller jobs, we were in the lower gas prices and we did anticipate maybe a 5% reduction in New York, which we ran the numbers you know that made sense to basically test that SaaS.

We were seeing the yours more like maybe 8% to 10% smaller for and this is really for the wells might be.

That are over in that state line area, the Greenwood Wasco Maria.

And so when you run it at the higher gas prices I mean, it's clearly you know you need to pump the the bigger jobs, which also means you are pumping more water.

It's just it's just a matter of the economics I mean, the wells deliver a better PV 10 value when you do that at the higher gas prices.

Yeah, I think it's a good question favor because we anticipated which hit the book as we look at caffeinated use 567000 pounds of profit. We we didn't think that would be what we need to do we dropped down to the lower book to handle this 24600 pounds.

And water like Dan said, and so we kind of tested the bottom at a low gas for us than you should do that because you do save precious dollars brought up front, but when you have a gas process to 93 three tenthreetwenty in you look to be valued and you looked at how quick these wells payout and increased volume that it's easier to say.

You know the the right thing to do is spend a little bit more money and we're still in that thousands of thousand 50 per completed foot.

I have a much better performance, which dropped our leverage right. So it's our job to tell you that too we didn't try to hide that we should we should probably go back up there because we did test it and we know we need to do it.

Great question.

Hi, Thank you all.

Thank you. Our next question comes from the line of length Chowdhry from Goldman Sachs. Your question. Please.

Hi, good morning.

You mentioned that gas prices are having their decision to grow EBITDA coming to leverage cause Ken.

Ken if you'd also skewed talk to what would drive a shift to lower activity and spending in FY <unk> multinational is then a gas price point at which you would reduce activity and how has that price point evolved given recent reductions to make cost.

Well I think that that is definitely gas prices that that are a factor that and and how we look at the whole picture and obviously gas prices are are not what the futures market is anticipating for 2021 and they underperform that.

We would definitely reassess our spending because I think that free cash flow goal, we're going to maintain it and.

So I think that is definitely a big factor and I think we we think we've gotten.

The overall as the market seems to be fairly comfortable that at least in 21. It at this stage is set for those $3 kind of area gas price.

[music].

And we will certainly reassess, adding a rig by mid year next year, if it's not at that level anymore.

So we're not we're not at all locked into one strategy.

But we wanted to present more of.

[music].

A balanced program that did and just focus on 21, and an absolutely maximize 21, which the six rig program really can do but.

But it could that comes at the expense of.

22, and you use you stop making the progress towards.

Your leverage goals and 22, if you don't make any investment for it so that was the goal at today.

And again the beauty is we don't we don't have any farm transportation obligations that calls us to drill we don't have any minimum volume commitments. The call just to drill 96% of our acreage is held by production. So our capex budget is just driven internally by.

What we need to do to to.

To improve our balance sheet and buy down our debt, but I will be very reactive to the changing environment.

So we will wait and as we were this year at play and Dave Defense in the first.

Half of this year, we can be very reactive because we don't have long term obligations that that dry.

Asked a half to drill any wells at all.

Yes, the other thing people forget him and our denominator is the consistency of our wells. We have 30 years of inventory at this rate I mean, we.

Usually before about the quality of your locations.

Nobody ever ask us about that so we've taken that off the table, let's just say how can you de lever coming out can you de lever and the you know where we are we're the only pure Haynesville SaaS company of this size.

We started wealth again, our our advantages this access to the Gulf Coast and we do have great guest process. So, let's let's use our strength. We can act like another company in another basin. We've got Aklog definitely we are in our base and.

And that's why we've got to tell you we're going to reset the whole program.

For the fourth quarter of this year and 21 22, we also tell you that whatever we need to do to we need to shut in those swing gas because prices are low you now seeing that we've done that we demonstrate to we will do that.

We need to go back to lower profit crosses are lower we'll do that we need to go back to our profit.

And we'll do that again, our goal is to be very transparent with you as a partner as we we create a even a greater company.

Thank you for the color that sweet answer thank you.

Thank you for the time and the question.

Thank you and as a reminder, ladies and gentlemen, if you do have a question at this time. Please press Star then one our next question comes from the line of Kevin getting from Citi. Your question. Please.

Hey, good morning.

Just a quick one on 2021 expectations.

Obviously as you and a few others increased growth next year in light of higher prices. What are you looking at as far as non up spending for the year and are you seeing any of those private equity backed companies kind of gearing up for our production growth next year as well.

Yes, we don't say, yes, we have very limited touch points with the other companies that are not part of our portfolio has always been fairly small and basically that we.

We.

We really like to do acreage trades to try to even make.

Make it smaller and I think that we actually finished some really good acreage trades that you saw kind of come through the location numbers and acreage numbers, this quarter, which geosouthern and indigo that really improved our overall lateral lengths overall.

And reduced our non op potential.

Activity in the future and also actually gave us more locations in our very very best.

Lowest transportation cost area and it was really a big win and I'm sure that.

We also met their goals and things they were trying to accomplish and so yes, we still see non op is a very not a big part of our budget and debt and frankly, if not project doesn't meet our high expectations. You know we've now got good partners that want to buy those interest and so we're we're very tuned on site.

Hey, if we can generate a really good return from non up what will sell down the wellbore that people that our efforts and invested in that so I.

I think we probably always have budgeted I mean, Ron you might say that we have a potentially.

$35 million to $40 million of non op activity that we kind of always expect to have let's start right.

Typically average kind of in that 6% to 8% of the total budget. So were very proactive it tried to disarm that before it becomes a big number.

Because nobody wants to be just never like being a non properties generally.

Right understood Thats. It from me. Thank you for the time.

Thank you. Our next question comes from the line of Phillips Johnston from capital One your question. Please.

Hey, guys. Thank you I also wanted to ask about the 21 program I think it was only a month or two ago you guys are talking about running.

Six rigs throughout next year and growing only by 3% to 5% for about 450 mining capex.

Now it sounds like you're you're talking about adding a seventh rig in the second quarter spending closer to $550 million and growing by 6% to 8%.

Sounds like that the change in tact, mainly relates to just the stronger gas prices that you're seeing on the strip and obviously that that that helps your leverage ratio.

If the strip plays out but of course, that's that's only at the strip sort of holds true or if you actually hedge.

The strip so I guess my question is.

Why chase those higher prices that you're seeing with higher activity why not just let the higher prices slow.

Hello.

Straight to the bottom line in terms of additional free cash flow and if you. If you like the prices and actually want to grow by that amount why not just hedge the majority of your production for both 21 and 22.

I think it's because I think you got I think for 21 I think here years.

Your suggestion would be a way to optimize it but we think thats very short term thinking and if you're focused on 22 is I think that if people become more focused on it as we get in the middle of 21, you know.

Yes that under investment really.

That means.

No growth in production and 22, and so I think that we're really making an additional investment really for 22.

And then our weekend differ if we if the if so if the prices are weaker yeah, we won't add to seventh rig we're not we're not committing to it and it in.

In advance at all.

But it is to present to a more balanced program in 21 that sustainable versus a program. Then 21, that's absolutely just maxed out to produce short term results because.

Before you know it you'll be in 22, and then also I know they like well.

These are you are no longer making any progress toward toward de levering because.

You Havent made that get enough investment. So we thought we would level et al again, thats accelerating a little bit of Capex from the fourth quarter to level out at the beginning of 2021 to be really consistent when prices are high right. Now we have 64% hedge in 2021, and then propel you over into 2022 of the five per.

Sent production growth and at the same time, we do think that we balanced Tuesdays, we balance the growth properly and that we de levered quicker at the same time. So it's not that we have to make a big correction sometime in the latter part of 2021 to change or do it at 222, because if you don't spend the additional amount of.

Money drilling year production will drop off any.

Any of the shell companies, whether they're Hep ledger bar or oil doesn't matter you do have to have a decent amount of spending and where were located.

It tells us that we need to we need to balance this budget today and reset at today.

Philip and you've been very Nash and your writings, but will put you expect us to do and then we wouldn't want to disappoint antibody, we want to make sure everybody knows why we're laying this out and knowing yet.

We can change it or need to change it we can change it crosses go a little higher we're excited as they go lower for changes.

But we think this is a rock this is the right way for the next.

Two years in two months.

Yes.

Free cash flow, it's not being sacrificed I mean, given that the prices that we see we are still going to have a have very substantial free cash flow at the same time have a the right investment. So then you look up and say you know what 22 looks pretty good too it's not like this as a one year wonder and that and I think that's that's the opportunity but.

Likewise as we answered the question before.

We're looking at prices every day, both had the we're looking at the Nymex prices in the future strip or you cant hedge and then also get out.

The cash prices and we will be very reactive to that and.

And not and.

And not end up.

Accelerating capital expenditures and declining price environment, that's something we would definitely want to do.

Yes, I mean, I guess I guess the concern as it was only less than 30 days ago, we're shutting in volume because of low spot prices right and then we're talking about adding up.

Additional rig next year. So I guess my my follow up would be would you look to hedge more 21, I'm sorry, 22 volumes before you added that seventh rig I'll definitely hi, Angela and then by the time. We added you know that they're hedged physicians need to be more established for 20 to Medicare our acquisitions, we want to path.

Between 50, and 70%, yes, maybe 60% to 70% over the next 12 months, so you're absolutely filthy rarely not going I guess, we will not be going end at on a hedge basis. So we will continue to.

That deliver on the hedges in the timeframe that we continue that we promise which is at 12 to basically 12 months, but 12 to 18 months. So yes, and if we can't we have to be able to establish those to support that rig if not it won't happen, yes with the leverage we have we have to hedge we should do that.

So I guess, that's a commitment to you.

Okay.

Makes sense and then maybe just also if I could just I guess, there's theres been some obviously some large corporate merger, we announced in the last 90 days or so.

Just wanted to get your latest thoughts on this potential consolidation in the Haynesville.

Well you know our goal as we hopefully today, we've reset the program and our execution will be it will be as a happy meetings.

I think that if we continue to execute on the stock price will perform.

I think that you're going to have some trended haynesville of producers that we'll need to do something it will help.

Hopefully what we've done so look we set our shelf in the middle of kind of the square where.

To go to exit you Gotta alleged talk does for look at us and we're going to evaluate.

If there is an opportunity for us to grow and then have a higher market cap and more size, but the same time continue to de lever and to continue to have our higher margins.

And if we can't do that we're not interested in any of those opportunities I think.

We have been smart enough to say, yes on the covey parts of the world.

And some others and we were not going to lose that edge that we have.

Does that edge is everything, but we're not going to lose it and yet we're not we're not going to go set in the corner not look at opportunities to expand if in fact those Mike.

Of the equity owners stronger and the bondholders stronger at our back stronger.

So we're going to we'll keep shop and all the time and we will keep executing.

Sounds good thanks, guys appreciate it.

So.

Thank you. Our next question comes from the line of Kashy Harrison from Simmons Energy Your question. Please.

Good morning, and thank you for taking my questions.

So just one a one or two quick ones from me.

So I was wondering if you could give us a refresher on how to think about.

Corporate base declines I'm, assuming since you pretty much shutdown activity over the last few months you have improved visibility on what that corporate decline looks like and then maybe how we should think about that expectation. Your your corporate decline expectations over the next several years.

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What weve, what weve message in the past that that the the corporate decline rates about 40% upper thirtys to 40%.

If we look out over the course of the next year, it's around that 40% level in then it'll improve kind of.

By 5% to 10% in the in the second year, and then continue to flatten out as as we have more of the established production base in.

At a at a lower decline.

So that in terms of the first 12 months kind of.

That plus or minus 40% going down to.

I guess.

25% to 30%.

And then and then kind of flattening out there.

Got it got it that was it from me. Thank you.

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

Yes, sure and again, everybody that stayed the whole hour on the call. I mean, we are you can imagine Atlanta, we are the tools.

It's a huge fit that are with us and again our goal.

As to reset the program for the fourth quarter of this year and then a 2021 2020 to give you something that that we think we can do and really beat.

And we want to adjust as capex structure to maximize our advantaged access this to this demand market that we have in the Gulf Coast Thats a great advantage, we have it's a it's a material geological advantage we have.

For just the some great exposure to Henry hub prices run now we want to use that.

If we do if we need to change this a budget it'll be pull back.

But but it's real and it's reset and it's good to.

Then again, we thank you for being a partner with us on that.

Thank the brighter days are ahead of us in our rearview mirrors pretty small in the windshields really big and gas process look really good and you've got a really good team you're committed and we take.

Theres good they are bad day, we take whatever the day is we're accountable to you. So thank you. Thank you we'll give you our best.

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