Q4 2020 Comstock Resources Inc Earnings Call
Ladies and gentlemen, thank you for standing by and welcome to the fourth quarter 2020, Comstock Resources, Inc. Earnings Conference call. At this time all participants are in a listen only mode. After the speaker's presentation. There will be a question and answer session to ask a question. During the session you will need to press star one on your telephone as a reminder, today's Brooklyn M is beauty.
Recorded I would now like to introduce your host for today's program, Jay Allison Chairman and Chief Executive Officer. Please go ahead.
Jonathan Thank you for.
Forgiving you said warm welcome as most of you know our home offices in Frisco, Texas, which is just north of Dallas.
And today, if you looked at on Windows, you would think that we were in snowy, Alaska or reporting from the ski slopes in Colorado in fact, Alaska is probably warmer than the recent sub zero temperatures are we've seen here with the windshield factor.
Losses have been closed for three days now and only probably for bus for here today reporting from the office.
This Arctic freeze on Texas in the mid continent creates challenging days in a world of natural gas, we've experienced idle frac fleets idle drilling rigs due to the freeze offs as well as record demand just to keep the power on Aero homes.
Fact measures are still without power as we speak.
With 99 percentage of our reserves being natural gas, which is the cleanest fossil fuel and a world class Haynesville Bossier gas fields being located in close proximity to the Gulf Coast, LNG market and near major petrochemical plants and close to the industrial demand car doors I can tell you that Comstock is well positioned to help meet the exist.
<unk> and future needs for predictable and reliable energy again America, where 'twenty 'twenty being such a whipsaw year play.
Pleased at all 200 for employees of Comstock you work for you have delivered solid results for the year and expect 2021 to be outstanding. Thank.
Thank you for trusting us as we continue to seek to close out every day as a stronger company.
With that I'll start to welcoming part welcome for the Comstock resources fourth quarter, 2020 financial and operating results conference call.
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 fourth quarter 2002 on our results.
I am Jay Allison as Jonathan said earlier, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Ron Mills, our VP of Finance and Investor Relations is joining us on the phone. Please refer to slide two in our presentation note that our discussions today will include.
Forward looking statements within the meaning of securities laws, while we believe the expectations for such statements to be reasonable there can be no assurance that such expectations will prove to be correct.
I'll turn it over to slide three we will recap some.
Nearly all but some of our 2020 accomplishments the.
For the most significant accomplishment is our successful navigation of one of the most difficult years for our industry effort.
Despite realizing a $1 80 for our gas and $32 36 for oil, we still were able to return and profitable financial results.
Excluding unrealized hedging losses.
Completed and accretive $207 million equity offering in May which is the first natural gas common equity offering since 2016 day offering allowed us to redeem our series a preferred stock and save $21 million per year from the elimination of dividend payments the $41 3 million.
On shares we issued in the offering eliminated the need to deliver 52 5 billion shares in the future.
For the conversion of the preferred we also completed two successful senior notes offerings totaling $800 million to repay bank debt. This increased financial liquidity from a $166 million.
$930 million, we also reduced our usage of our bank credit facility from 88% to 36%. We had another year of strong results from our 2020, Haynesville Bossier shale drilling program, we drilled 55 or $46. One net successful wells are we on.
Right. We returned 54 or <unk> 49, net operated wells to sales for an average IP rate of 25 million cubic feet per day, and 2020, we were able to lower our well cost by 16% or two mile laterals, which Dan will talk about in a minute averaged $1026.
For completed lateral foot in 2020 versus 1215 in.
In the prior year. This allowed us to grow our proved reserve base by 3% at a low and finally cost of 66 cents per Mcf per day.
Spot having to use very low prices to determine our SEC proved reserves.
They grew by 3%.
To five six Tcf Harvey.
Our reserve additions replaced 159% of our 2020 production if you go over to slide four.
We cover some of the highlights for quarter one slide for.
We resume completion activities on the third quarter and our natural gas production increased by 6% from the low third quarter level on production in the quarter were still impacted by high shut in level of six 6%. Now. This is mainly due to actions. We took on October to shut in 300 million a day.
Of our operated production in response to very low natural gas spot prices, we turned 22 or 16 forward net haynesville wells to sales with an average lateral length of 8899 feet in the fourth quarter. We are well positioned for continued production growth in the first quarter 2021 and two.
Throughout the remainder of the year of 2021, our conservative operating plan in 2021 is focused on reducing our leverage ratio by both growing EBITDAX and reducing debt, we're targeting to generate over $200 million on free cash flow in 2021, the higher production and improve.
For oil and gas prices allowed us to return to profitability in the fourth quarter, we reported oil and gas sales for $277 million. Our EBITDAX came in at $211 million and we generated $155 million.
<unk> 56 per share on operating cash flow, our adjusted net income for the quarter was $35 million on <unk> per share.
Lastly, we ended the year with very strong for niche liquidity of $930 million. So now I'll turn it over to roller rather than to cover our financial results in more detail Roland.
Alright, Thanks day on.
On slide five we summarize our reported financial results for the fourth quarter of 2020, our production for the fourth quarter totaled 109 Bcf of natural gas and 340000 barrels of oil. This is 11% lower than production from the fourth quarter of 2019.
Our oil and gas sales, including realized hedging gains for $277 million about 10% lower than 2019 due to the lower production level.
Oil prices in the period average $44.47 per barrel and our realized gas price average $2 40 per mcf, including <unk>.
Hedging gains.
So our overall of our natural gas prices were up 4% in the quarter.
And our oil prices were down a little bit.
Looking at the cost side, our lifting costs were down 11% in the quarter and our depreciation depletion and amortization.
And G&A were both down 7% in the quarter.
Our adjusted EBITDAX came in at $211 million or 10% lower than the than then.
2019 fourth quarter.
Our operating cash flow was $155 million, which was 18% lower than 2019, and we reported a net profit of $77 $5 million for the fourth quarter or <unk> 30 per share.
The net income for the quarter did include $82 million unrealized gain from the mark to market of our hedge positions, which was mainly driven by the change in natural gas prices.
Since September 30th.
Adjusted net income excluding the unrealized hedging gain and certain other unusual items was a profit of $34 6 million or <unk> 14 per diluted share for the quarter.
On slide six we summarize the financial results for all of 2020.
Our production for the for two that for 2020 totaled 468 Bcf.
Which that includes one 5 million barrels of oil at 49% higher than 2019 production.
The increase mainly reflects the acquisition of Covey Park that we closed in July of 2019.
Pro forma for the Covey Park acquisition, our production increased 2% year over year.
Our oil and gas sales, including realized hedging gains for $993 million, which was 21% higher than 2019 oil prices, including hedging average $40 for 88 cents in 2020.
And our realized gas price, including hedging to average $2 seven per Mcf, which was 12% lower than 2019 adjust.
Adjusted EBITDAX for the year was $722 million, an 18% increase over 2019 operating cash flow was $521 million, which was 11% higher than 2019.
Overall, we did report a net loss of $83 million.
For the year or <unk> 39 per share of debt loss was entirely due to the mark to market unrealized losses on our hedge positions.
Excluding unrealized hedging losses and other unusual items, we had a net profit of $49 6 million or <unk> 23 per diluted share for 2020.
Despite a year of very low oil and gas prices, we were able to have a profitable year and we did not have any impairments or other write downs of our assets, which is I think on unusual.
Compared to many other companies in our industry that says a lot about the quality of our assets and our low cost structure.
On slide seven we cover our hedging program and during 2020, we had 51% of our gas volumes hedged, which increased our realized gas price to the $2.07 per Mcf I mentioned as.
As compared to the $1 80 that we actually receive from selling our production. We also had 84% of our oil volumes hedged debt.
Net debt increased our realized oil price to the $40 88 per barrel versus the $32 30.
Per barrel, we actually received.
Overall, our realized hedging gains.
<unk> totaled $134 $5 million in 2020.
With the continued strength in natural gas prices, we've continued to add to our hedge book since.
Since we last reported earnings we've hedged another 90 million cubic feet of our production for the second half for 2021, and another 100 million per day for the first half of 2022.
For 2021, we have natural gas hedges covering almost 900 million on the day.
Of our gas production, which is around 65% of our expected for 'twenty one production the weighted average floor price of our 2021 gas hedge is $2 51 sets going forward, we're primarily focused on adding to our 'twenty 'twenty two hedge position, we continue to target having 55% to 70.
Percentage of our production hedged.
For the upcoming 12 to 18 month period.
Slide eight.
We recap how much of our production was shut in during that during the day last quarter. The fourth quarter. So we had six 6% of our natural gas production shut in in the fourth quarter compared to the seven 2% we had in the third quarter.
As we had talked about at our third quarter call in early October we voluntarily shut in 300 million a day of our production. It really during the first two weeks of October due to the very low spot market gas prices.
The remaining of the shut in in the fourth quarter is really due to offset frac activity.
We also had 2% of our oil production curtailed or shut in in the quarter.
Which was a that's a big decrease from how much was shut in earlier in the year.
On slide nine we detail our operating costs per M. Cfe produced our operating cost per Mcf per day averaged 56 cents in the fourth quarter as compared to the third quarter of <unk> 55.
Gathering costs for 'twenty six.
Our taxes average nine cents and our field level cash.
Costs to average 21 sets.
The fluctuation between our lifting cost and gathering cost is related to where the new wells were completed during the quarter, but we continue to expect those costs to remain within.
Our guidance ranges that we have been providing.
On slide 10, we detail our corporate overhead for M. Cfe, our cash G&A cost in the quarter were four cents per M. Cfe, which is down for the third quarter, primarily due to year end accrual adjustments, we do expect our cash G&A cost to return to a more normalized level of 5% to success going.
Forward.
On slide 11, we detail the D T net depreciation depletion and amortization per M. Cfe produced.
Our DD&A average 94 cents for the fourth in the fourth quarter.
<unk> lower than the 95% rate, we had in the third quarter.
Slide 12 shows the balance sheet at the end of 2020, we currently have $500 million drawn on our $1 4 billion revolving credit facility and we do expect to use our free cash flow that we are targeting to generate in 2021 to continue to pay that.
Down.
We have just over $2 billion to $5 billion of senior notes outstanding comprised of $619 million of our seven 5% senior notes due in 2025 and $1 65 billion of our nine and three quarter senior notes due in 2026.
With a quarter end cash position of $30 million or current financial liquidity stands at $930 million.
On slide 13, we summarize our fourth quarter and full year 2020 capital expenditures we.
We spent $169 million on development activities in the fourth quarter of which a 151 was spent on the operated Haynesville shale properties. We also spent $6 5 million to lease new haynesville acreage in the quarter.
For the full year, we spent $484 million on all development activities, including $410 million.
Which was spent on our operated Haynesville shale properties.
We drilled $46 one net operated horizontal haynesville wells and we turned 40.9 net operated.
Horizontal haynesville wells to sales in 2020.
We also spent another $82 million in 2020 on non operated wells and other development activity and we spent a total of $7 9 million in.
In 2020 on leasing new Haynesville acreage.
So right now we're currently utilizing six operated rigs for our 2021 drilling program, but we do expect to drop one of our operated rigs later this year due to the faster drilling times that we're achieving as Dan is going to go over with his operating results.
Based on our current operating plan for 2021.
We expect to drill 51 net operated Haynesville wells and turned about 55 net operated wells to sales in 2021.
At the end of 2021, we expect to have about 17 point.
Net debt to carry on into 2022.
We estimate our total development capital expenditures or come in between $510 million and $550 million in oil.
We are also.
Budgeting to spend an additional $7 million to $10 million on net leasing program.
Yeah.
We remain focused on generating significant free cash flow and we will continue to target over $200 million of annual free cash flow generation as we plan our drilling activity.
On slide 14, we summarize our oil and gas reserves at the end of 2020.
We grew our proved reserves from five four tcf at the end of 2019 to five six Tcf on.
On an SEC basis at the end of 2020.
Our 2020 drilling activity added 366 Bcf to our proved reserves and we had 367 Bcf of positive performance related revisions driven by the strong well performance of our Haynesville wells.
The positive reserve revisions more than offset negative price related revisions, which were 86 Bcf.
That related to using that low first of the month 2020 average prices to determine reserves.
Our oil and finding cost for 2020 came in at a very attractive 75 per M. Cfe.
Or <unk> 66, if.
If you exclude the price related revisions.
Our reserves were not.
99% natural gas and then 36% of our reserves for developed.
95% of our proved reserves are in the Haynesville Bossier, 2% are in the Bakken and 3% or in other regions.
The PV 10 value.
Of our proved reserves was $2 billion using the SEC prices of $1 99 for gas and $39 57 for oil.
And 67% of that PV.
<unk> is related to our developed reserves.
Using a nymex reference price of $2 75 for gas.
And $50 for WTS oil, which is more reflective of our current price outlook. The PV 10 value of our proved reserves increases to $4 4 billion.
And the quantities of proved reserves.
With those prices would increase to $5 eight tcf.
Using that $2 75, and $50 reference prices.
But in addition to those proved reserves we have an additional two four Bcf a day of proved undeveloped reserves, which are not included in our proved reserves as we are not currently expecting to drill those within the five year window required by the SEC rules.
We also have another $4 six tcf.
<unk> or probable reserves.
And six eight tcf of Threep or possible reserves for a total reserve base of $19 six Tcf.
On a P three basis.
I'll now turn it over to Dan to cover the fourth quarter drilling results in more detail. Okay. Thank you Roland.
If you flip over to page slide 15.
This is going to be an outline of our current acreage position, which is now increased in the fourth quarter to 323000 net acres.
We do control the majority of the acreage with a 91% operated position and have an average working interest in the acreage of 82%.
We currently have 1953 net future drilling locations identified on this acreage with 93% of the acreage currently held by production.
Since starting our high intensity completion program in 2015, we've now turned 272 wells to sales with an average IP rate of 24 million cubic feet a day.
We're currently running a total of six operated rigs we do plan to release one of our rigs in May of this year and continue with five rigs for the remainder of the year.
We're currently running three frac crews and we anticipate running an average of just two two frac crews for the full year of 2021.
We currently have 25 ducks on our schedule, we anticipate our DUC count staying in the 20% to $25 range for the remainder of the year.
Overall slide 16. This is our latest haynesville bossier drilling inventory as of the.
Year end 2020.
Our operated inventory currently stands at 2214 gross locations and one 719 net locations.
This represents a 78% average working interest on our operated inventory.
Our non operated inventory consists of 1585 gross locations and 234 net locations.
Which represents a 15% average working interest on the non operated inventory.
On a gross operated locations. We currently have 485 short laterals 799 medium laterals and 930 long laterals.
If you split these out the 202214 gross locations about zone.
We have 52% of our locations in the Haynesville and 48% are in the Bossier.
This inventory provides the company with over 30 years of drilling locations based on our current our current activity levels.
Sure.
On slide 17.
Outline in summary of the 20, new wells that we've turned to sales since the last call.
The new wells were mostly located on our east, Texas and southwest Desoto parish acreage and we did have one well completed over on a round growth acreage.
The wells were tested at rates ranging from 18 million a day up to 33 million a day with on the 24 million cubic feet per day average IP rate.
The wells were drilled with lateral lengths ranging from 6751 feet up to 12760 feet.
With an average lateral length of 9288 feet.
And they were all completed with 3500 pounds per foot sand loadings on our fracs.
We drilled and completed our longest lateral ever during the fourth quarter at 12716 feet on the Jordan 16, nine for number one oil.
Which is down in the southwest Desoto parish acreage.
We are currently completing a 13000 plus foot lateral that will be turned to sales during the first quarter and this will be our new record long well at that time.
On slide 18, and on the next three slides are on the D&C cost trends for our different lateral lengths buckets.
Here on slide 18 shows the D&C cost trend for a long lateral wells.
Which are wells that had lengths greater than 8000 feet.
On a long lateral wells in the fourth quarter, we experienced a 5% increase on our total D&C costs due to a 15% increase in our completion costs.
This was primarily due to the resumption of pumping larger frac design of 3500 pounds per foot in the fourth quarter. After pumping our smaller frac design on a 2800 pounds per foot in the second and third quarters.
We were able to offset a portion of our increased completion costs with lower drilling cost in the fourth quarter due to an increase in drilling efficiency.
With this increase in drilling efficiency, we have reduced our drilling cost further in the first quarter.
And we do expect to maintain a lower drilling costs for the remainder of the year as we drive our drilling costs down to historic lows.
This will help to offset the higher completion costs that we anticipate as a result of the increase.
And industry activity and higher associated service cost.
Since 70% of the wells, we drilled in 2021 will be long laterals, our cost performance in this category is the major driver in the success of our drilling program.
Due to the higher drilling efficiency, we are confident that we will be able to maintain our D&C costs relatively flat in this one and 1050 foot range for our longer laterals.
Ultimately the gas price environment and market demand for services will determine where I'll call settle out in this range.
On slide 19 is the D&C cost for our medium lateral wells. These wells before links between 6000 8000 feet long on.
Our medium lateral wells in the fourth quarter, we had a total D&C cost of $11 26, a foot this.
This represents a slight decrease of 3% from the previous quarter.
While our completion cost also increased for our medium length laterals due to resuming the larger frac design in the fourth quarter, we were able to still achieve lower lower D&C cost in the fourth quarter.
While driving our drilling costs down by 10% with our increased drilling efficiencies.
Same as our long lateral wells, we have reduced our drilling <unk> further until the fourth quarter.
This year and expect to maintain this lower drilling cost throughout the rest of the year.
Yes.
On slide 20. So this is the D&C cost trend for our short lateral wells. So these are the wells that had lateral lengths less than 6000 feet.
As you see here, we have not completed any short lateral wells for the last two quarters, which is by design. Since these wells have a higher cost and inferior economics compared to the longer laterals.
When we do drill a short wells with tempt to drill them as part of multi well pads with longer laterals to reduce costs and enhance our returns.
Same as with the longer laterals on the previous two slides, we continue to substantially drive down our cost.
On our short lateral wells.
Yes.
Over the course of the last year, we have successfully converted many of the short lateral wells in our inventory.
It's a longer lateral wells and the acreage trades with other operators and also with some small bolt on acreage acquisitions.
We continue to pursue these opportunities to this day, where they are where there are opportunities.
To reiterate on our operations. We are confident we can maintain our current low D&C cost structure by capitalizing on the drilling efficiencies, we've been able to achieve to date.
And building on these going forward.
These lower drilling cost will help to offset the higher completion costs that we anticipate for the remainder of the year.
As a result of increased industry activity and the associated higher service calls.
It summarizes things up on the operation side I am now going to turn it back over to Jay Alright, Dan Ralph. Thank you. If you would let's go to slide 21 for will summarize.
But we think as our outlook for really a fabulous 2021.
We remain focused on maintaining and improving our industry, leading low cost structure and best in class well drilling returns our inventories as Dan had mentioned 1953.
Net haynesville Bossier drilling locations provide us with decades of drilling inventory.
Our operating plan for the year is expected to provide production growth and generate in excess of $200 million of free cash flow as rolla net pointed out.
In 2021 were focused on improving our balance sheet as we told everybody for for months and months, reducing our leverage and lowering our cost per capital.
With current natural gas prices, we would expect our leverage ratio to improve to.
Around two five times at the end of 221 down from three eight in 2020.
With our industry, leading low cost structure, our haynesville drilling program generates some of the higher drilling returns in North America.
<unk> currently hedged approximately 65% of our 2021 production to protect our high drilling returns were very strong financial liquidity or debt $930 million, so with that I want to turn it over to Ron. So he can provide some specific guidance for the rest of the year. So Ron.
Thanks, Jay on Slide 22.
We provide financial guidance for 2021.
The updated guidance from our November call reflects the impact of the timing of our drilling and completion schedule as well as the shut ins that we discussed earlier on the call looking at 2021, our development Capex guidance is $510 million to $550 million.
And that budget anticipate release of one of our offer a rated rates in may as Dan mentioned.
We also anticipate spending another $710 million on on leasing activities. Our production guidance is $1 33 to one for two five Bcf per day.
Our lease operating costs are expected to average 21% to 25 per Mcf in 2021, and our gathering and transportation costs are expected to average $23 27 per Mcf.
Production in April on taxes expected to remain in the eight to 10 cents per Mcf range in our DD&A rate is expected to average 90 cents to one dollar per Mcf.
As mentioned earlier, we believe our GAAP G&A rate is expected to return to a more normal five debt.
Two seven per Mcf for your range I'll now turn the call back over to the operator to answer questions on the call.
Certainly ladies and gentlemen, if you do have a question at this time. Please press Star then one on your Touchtone telephone for your question has been answered and you'd like to remove yourself from the queue. Please press the pound key are for.
First question comes from the line of Derrick Whitfield from Stifel. Your question. Please.
Thanks, and good morning, all and certainly congrats on a strong quarter and positive outlook.
Referencing.
Slide you guys were clearly impacted by several uncontrollable events in Q3, and Q4 and on imagine Q1 could simply be impacted by the current weather.
Tom do you have a sense of weather related outages for Q1 and more broadly beyond Q1.
Would you envision that shut in metro trading based on your 2021 outlook.
Yes, that's a great question Derek.
The.
Yes, some of the shut ins, obviously for the fourth quarter.
Were voluntary.
We didn't want to accept really low spot prices. So some of R. R.
Our gas that wasn't nominated Thats in our swing gas, we decided to shut in in the first part of October.
So, but I think as you go into 2021.
We haven't had those type of issues <unk> had very good it really very very good spot prices. So far all throughout 'twenty, one and then obviously in the last.
The last with all the events in Texas in the last week.
Obviously incredible spot prices for our swing gas.
Our marketing Department.
With the index prices kind of being set lower at the beginning of the month and the rising gas prices. Both in January and February that we've experienced.
We actually were a little bit less.
Expose yourself more to the spot market.
Normal and that's going to pay off I think.
Handsomely.
An improved price realizations in the first quarter.
Especially whatever gas we've been able to sell over the last.
Ever since last Thursday.
Phenomenal pricing opportunities, which hopefully will.
It will probably continue through the week now.
The negative debt that is.
Is there going to be shut in production due to the weather.
Through through Tuesday, We could've said no we were really full production all the way through.
Tuesday, and then starting yesterday, we started too.
So you see some issues with that.
Water haulers really can't common service to service the wells because of the road conditions in North Louisiana.
So we.
We see some shut ins now that are close to 20%.
Of our normal production levels.
That's only going to be in place for.
For a few days it really depends on that.
Win win road activity can resume and then once road activity resumes, we can hopefully get back to normal production activities.
So derik one other good things.
Dan and Patrick and it really is the people on the field have done a really great job.
Some of the wells that we had shut in.
Because when we were fracking some wells since since the Frac crews were frozen out.
Everywhere.
We were able to bring that shut in production outline so Dan Harrison might want to comment on that and again, it's our field people that did such a phenomenal job on net and as Rolla mentioned the marketing people.
Alex Whitney et cetera, the whole group.
But I think they've really delivered good results Dan income, yes, I'll, just basically add to what's what you said Jay or are people here on office NFL have done a fantastic job.
Our frac crews have been down since roughly probably Saturday morning.
We did have a substantial amount of gas that we put back on production when the frac crews shut in for offset Frac protection and we did get that production back on from Saturday.
Tuesday, So we actually had a lot higher.
We had a lot more gas production from Saturday through Tuesday, when the when the prices spiked.
Starting to see the effects of that really just start on yesterday.
Roland mentioned, we just can't get the water haulers to service our wells on all our tanks for filling up for the water.
And a little bit of downtime with the midstream <unk> treating plant also.
Not really freezing problems per se at the wells, but just kind of those two things I mentioned is what is starting to get us really just start in yesterday. So.
Probably through the remainder of this wait till we get counted them above for reason temperatures.
I think we will have is where we'll see the effects.
So a lot of Rollins said I think our process will be a little higher I don't think will have a huge impact.
On shut ins.
We don't give any guidance, but if anything it should lean towards the positive.
And keep in mind, Derik, and then normal in a normal quarter you will always have.
Anywhere from 3% to 5%.
Shut in around.
Around our completion activity. So that's yes.
What's abnormal as when we go to 7% or 6% and so we'll have to see how the first quarter.
Ultimately shakes out.
There could be more pluses and minuses from the from the storm as far as overall profit for the company.
We'll know more I guess in a week or two to really sum up.
The impact, but right now we think that we might.
Overall, it could be a very positive impact on the first quarter.
We'd like to get back to norm, but you know 2020, you had COVID-19 debt what norm. When you have all the storms on what norm you had.
We had.
We had this weather coming in for 2021, so that's not norm. So I guess, we should just learned to live with that outside the norm, but these numbers in 2020, even though again is like we said, it's a whipsaw year they were real.
Good numbers in 2022 on starting out like this with weather issues, where we are with this demand.
The performance on the field people.
Thank you will be pleased with the results that hopefully we can show you.
Thank you.
This week highlights what's unique about Comstock, one where in the Gulf region. So we were really able to take advantage of these some of these really super premium prices and two we are we don't have huge.
Midstream commitments, we have a lot of flexibility to our marketing and so we were able to.
To move gas to some really great premium opportunities and I think our marketing group is working overtime. During this spotting these opportunities to truly started showing up last Thursday.
It will probably continue through this week.
But that's the unique thing about Comstock has the flexibility have on marketing strength I think in.
And then we have the strength like we showed in the in October.
To pull that gas off the market and not not have to sell it at a very low price. So I think I think that's a strength in both sides. Both on again, we've mentioned earlier. This LNG LNG pullback from 11, two days to about six or seven days because.
The governor of the Texas Governor called <unk>.
Freeport and Corpus Christi, and said, we need we need we need that gas to keep these homes warm.
Even with the LNG pulling back the export to Mexico pulling back two or three days.
You still see were where the challenges of this meeting this demand. So we're in the right area for a couple of hundred miles from this corridor, where you need to be debt for these transportation calls for or a lot cheaper than if you are in Appalachia for probably $1 dollars 50 cheaper in certain areas, we have pipelines available there.
If you do need more gas.
We can really supply if we really do needed in the long run period.
Got it thanks for the very comprehensive response for that question as my follow up.
Perhaps for Jay in light of the more construction for gas backdrop that we're seeing and your success in adding acreage during the quarter could you comment on the current state of the A&D market.
Yes.
We think.
Sure.
And so we still think youre going to have consolidation.
I think that.
Wall Street should not allow for <unk>.
<unk> production growth I mean kind of like Devon announced today, they've got a variable dividend.
First company to give a variable dividend I think all of these companies.
Their leverage ratio needs to be down the bank borrowings related to be down.
We think that the new norm.
As per course cleaner energy.
Thats why Jerry Jones Investor Day is a 1 billion plus on the Comstock.
We do have the cleanest fossil fuel I mean, we can we can clean it up more we're going to do that.
I think that bigger is better if you keep for quality and if you keep your costs down most of these deals as you know they were done with stock for net assumption of debt.
Except maybe the Chevron deal with EQT and I think that was a blend of stuff.
But if you're looking in the Permian I think the challenge in the Haynesville is you've got a lot of private equity backed companies. So you don't have a really a numeral denomination as far as value and you do on publicly traded companies. So.
I think there'll still be a push for some.
Some of these companies will.
There will come a little more gas here, because they probably should.
And I think we're kind of in that sweet spot there that debt. If we can multi big $2 2 billion transaction with Kobe.
And it was tier one the whole way and like Roland said, we've for one of the very few companies is pretty thin air where you don't have any impairments.
On a $1 99 gas price and you've got a really low oil price you don't have any impairments.
Then we had all these adjustments for reserves for successful.
Successful operations this year so.
If you can continue to do that then I think you should you should see an active M&A market.
We expect it we expect the haynesville to get.
Fewer in number as far as companies this year.
And then all the other basins.
But we we try to withdraw its your money net.
Your company.
We try to not just growth for the cycle grow and you have to grow not to make a lateral movement to make.
Forward.
Port on movement.
And you have to decrease for leverage when you do it.
So that's a market we're in.
And that's what we see for the future.
2018, or 19 banks that have guidance, we probably half a dozen research analysts had followers. We're thankful for that we added more than 2020.
We've been on the bond market as Robin said two times for this last year $500 million in June and.
$300 million in August so we've got very good allies, there and they tell us the truth on what we need to be doing or not so I think we're going to have access for the things we need it.
The opportunities are there, particularly with the backing of the Jones family.
On smart money and smart business smart products. So.
That's where we are is just a little bit of rambling, but you have to ramble on the world of oil.
The public as you know.
Very helpful guys. Thank you for your time.
Thanks Derek.
Thank you. Our next question comes from the line of Dun Mcintosh from Johnson Rice. Your question. Please.
Good morning, Jay.
Morning.
Maybe for Dan, but 'twenty, one guidance, you've got capex on activity down a little bit in production kind of modestly up despite call at five <unk> turn in lines.
I appreciate the increasing efficiency, you're seeing on the drilling side, but what are some of the things that you are seeing that give you confidence in hitting that production number despite for you.
Our return on lines I mean is it you can be targeting some high return areas or is it more driven on the.
Shifting back to higher intensity completions any color there would be helpful.
Ill, let Dan answer that then I'll cleanup, if I needed okay Doug.
We're really encouraged by what we've seen on the drilling side.
It's been pretty sustained we see it getting better actually going forward.
We are going to try to get longer on our laterals, which are going to give us better returns.
The activity as far as where the wells are going day are still a pretty good spread across all of our acreage.
We we mentioned in here, we have gone back to the larger Frac jobs. We did meet all on I think it will still.
The right call to go in.
Trial, the lower Frac jobs were really not really low gas price environment.
We got some production history on them.
They didn't look terrible but.
We don't like across the board and this was really kind of the east, Texas far count on North Caddo areas. We may be 0.2 Bcf per thousand kind of we saw the.
Short for the smaller jobs.
We really havent never we've never really changed our job size over on the better areas of like rank and Logan sport and AUM growth.
So I would say a little better performance from going back to the larger frac jobs getting longer and basically drilling faster getting cheaper.
Yes, Dan and I think the biggest factor towards the more efficient.
2021 planned for when we when we even looked at it in the third quarter is the drilling time, that's been the it's a little bit so basically wells are coming on quicker.
I was just a more the capital Youre spending is generating production a little bit faster because of these really good drilling times debt.
Net debt the operations groups, achieving and you might maybe give some example, that's one reason we tried to break out.
We take you along this journey with us because it's again your time and money on 18, 19, and 20, we might be the only company that has as gallon debt micro with kind of the shovel nose.
Double there to go into what we look like with greater than 8000 foot laterals shorter than 6000 foot in between six and eight and what we've been able to do is Dan.
Sunday Monday Tuesday on the Hill snap his fingers you said, we used to drill those 4500 foot wells pretty quick and now we've drilled those 10000 foot laterals Nielsen App. This fingers pretty quick and predictable. If you look right now we're at 12000 13000 foot in.
Quite frankly.
We don't want to get people too excited but the longer. These laterals are we can get them 13, 14 15000 feet. These.
These economics for really really are favorable.
And again I don't think Theres any company.
You put everybody together all 200 Forbes together no company has drilled completed more extended lateral has completed the haynesville and Bossier wells, where we have so.
Dan might give a little paper, but gift giving.
A few examples for <unk>.
Examples.
How much the drilling time has changed on the long lateral well on like on average.
The 10-K lateral before let's just say you.
Spud to rig release, you were at 28 to 30 days I mean if.
If you get those down to 'twenty two 'twenty three days you apply that across five rigs across an entire year.
Turning on a lot more wells to sales that's a lot more frac jobs is more cement job on this more strings of casing that youre buying so.
Your budget goes up right I mean with the same.
For a range or actually spend a lot more money so.
It allows us to dial it back drop a rig.
Basically you get the same results with less rigs right. The production comes on earlier and you use less equipment to get the same type of results. So I think that's it.
I think thats, a little bit on what you see in the outlook.
For 'twenty, one versus really three months ago, but you go over where east to drill those 40 follow up on for laterals were drilled 500 feet. A day. If you look at the wells we drilled in the last three or four months, we've gone from anywhere from 6000 feet per day, which is anomaly to two or 3000 feet a day, which is kind of the norm right now so that day.
Net is the difference and we use the <unk>.
Couple of thousand feet, a day, we will get a little more than that on some of these but we'll have we'll have a hiccup for two so that is really the answer and we're we're comfortable enough to start kind of advertise on that.
On the low side. So we will hopefully we can meet this.
Alright, great. Thank you for all that color and then just for a quick follow up.
One of your bigger competitors are you seeing coming out of bankruptcy in the basin.
You could just remind us kind of how much exposure you all have to them for a non op perspective.
Have to imagine you've been been in conversations with those guys.
Do you have for kind of what they have planned for this year and what that could mean for for you, yes. They spun out the 50000 acres to the south.
Williams zones at <unk>.
And Williams is trying to do something with that.
Public is for the bankruptcy.
And then.
85%.
Chesapeake their budgets in gas.
In the Marcellus of it's Nigel I think theyre going to keep two or three rigs busy.
Know them really well.
We're glad that they came out.
As aggressive as they did in as clean as I did getting rid of debt seven or $8 billion of debt and.
And we will make the sector look good now, but I don't think theyre going to drill too many wells to upset the balance of supply.
I think the board will will no doubt and your question was share of them. We don't have a lot of exposure to Chesapeake operated projects.
And we were that actually there are rigs that day.
They are running.
What they are talking to investors about is not very different than what they were doing while they were bankrupt said their activity level is not that materially different in the haynesville.
<unk>.
We don't have a lot of exposure to their operated projects.
<unk> wells, where we had exposure to oil bolt on acreage.
And renegotiated the firm.
And drill several wells.
So all positive, but we don't have our exposure on our numbers to them is miniscule.
Okay. Thanks for that.
Thank you. Our next question comes from the line of Neal Dingmann from Citic.
Securities Your question please.
Good morning, Jamie a question for you today on I'm looking at that slide and Derek kind of touched on this a little bit on slide 15, just shows the massive footprint could you give an idea just.
On cadence I know you were talking about I guess, what I wanted to try to be clear Dan was talking about maybe some of the larger jobs I'm just trying to get a sense of.
With the five rigs running this year, maybe geographically, where and kind of what what size or what.
Type of wells Youre going after.
Well I think I think debt overall.
As a percentage of the wells are going to be the long laterals, probably 80% or so 75% 80% of our budget will be just like it has been in the last couple of years will be for laterals over 8000 feet and I think that overall averages are probably going to go up because of these.
Extra long lateral wells that were doing 12000 13000 feet.
But we still plan to drill wells across our footprint.
And not any not concentrated in one part of our large footprint in the haynesville.
Something I would add is you got to be careful.
On a really just focused on one area because you got we have to look at our midstream capacities on where we can get rid of the gas also so sometimes you.
You can't bring on a real high peak volume of gas in one specific area because the.
The midstream cant handle it all at one time so.
We'd like to try to minimize that shut in time for offset frac. So if we always drilled wells at our very best area, we'd never be able to produce our best wells and so it.
Part of the part of that part of the whole.
Billing plan is also looking at how do we.
Optimize.
Overall production from the different areas looking at midstream looking at chat ends.
So it's all if you look at you try to blend all of these things together to create the best program for the dollars, we want to spend and I think that's.
Kind of what we have in store for 'twenty, one and I think that goes back to the quality inventory.
We tiered all tier one to three five I mean, it depends upon what the price is with the midstream looks like et cetera, et cetera, the cost of debt.
But we have the last three or four years I mean, we drilled all parts of our inventory and you can see what the numbers looked like it is not just leaning on tier one tier one tier one tier one plus the.
For the numbers, we gave you it's a pure a blend of our total footprint from North South East West that's very important on a PDP component shows that on the last several years. We've had some joint ventures that were we were earning acreage based on drilling and we also did a.
A special kind of a program with our majority stockholder.
These are in Caddo parish area and some of that.
That was some of our more northern acreage.
One time, it was very extensional to the play.
But most of that has all been fully developed now and so we were drilling there.
Finished that up now we typically didn't have high working interest in those projects, but all of those projects have been finished and so I think what you look ahead.
What you see is more just havent free reign to go anywhere on our footprint and everything we're doing is probably a fairly high working interest.
That's a little bit of a change overall from maybe if you just look at our historical deal I think there'll be there'll be positive from the standpoint.
Higher ownership overall in each well, we drill because where we.
We've finished those joint venture opportunities that will drop our rig count like we said right and Thats part of it part of the reason why I can have a little bit lower rig count.
Because were not drilling.
Low interest wells with one of those rigs like we might have been in the past to kind of finish up R. R. R. R. R joint ventures for our partners.
We think we've got a good hedge book starting in for 'twenty, 165% in <unk>.
<unk> said, we will be in the 55% to 7% range.
As others Walter collars in 2022 is our goal.
No that was great great detail, Jay and enrollment and Dan I appreciate that and one follow up I'd like for you guys are being I guess, Mike My question is with the five rigs plus.
You definitely shelled out great returns that you have.
Jay you were rolling maybe talk about what I appreciate is versus some folks that are trying to go out for free cash flow.
We really tried to drop all rigs.
On generate the near term free cash flow, which you know they can I think youll have seem to have much more sustainable type plan I'm just wondering as you've mapped out the plan for this year was five rigs could you discuss that a little bit how you arrive at that.
What we did in 2020 again it was give us trades here I mean, we we came off a huge acquisition of 19 2020 was a very disruptive year for everybody. I mean, we go to two and half months without a frac crew working and we dropped our rig count from six five for <unk>.
Even with that we ended up with a really good year.
I think 2021 is a settling year.
Some of the JV that we had there gone.
The longer laterals are we become more and more and more comfortable debt. That's why we broke that out on page 18 1920.
I think the marketing group has done a good job so youre going to see some increased production in 'twenty, one only because it's kind of a catch up from what we did at the latter part of 'twenty and then I think when you roll into 'twenty two.
Youll see to that 3% to 5% growth, but since our cost per load Thats why were able to have this 200 plus million of free cash flow.
And like for like Ron said, we have more on dedicated gas natural than any other company, we market about two BS a day, we sell 1213, plus one for on our own.
So I think all of those things combined.
All of those things combined give us this 2021, I mean really good solid fuel where you see a lot of these companies.
If you keep your budget flat easier production goes down.
If you increase it a little bit your production may stay flat.
The one great thing we have we can keep this $510 million plus with the with these ducks that we have kind of rolling over but we can have really good production growth in 'twenty. One we will have great free cash flow in 'twenty, one and will carryover debt at <unk>.
'twenty two and its debt.
You can see it works, but it's an anomaly in the whole the whole world of energy, Yes, I think Jay said debt.
And we did it we did it was it was kind of going from a high growth company in 2019 with after the Covey Park acquisition, you had the low price as a 'twenty, we reacted KOL day rigs way back.
And then searching for that level of sustainability like yes, I think that did take us a little time to think through and and I think really adapt to the new drilling times and so I think we look to head looking ahead, we do kind of look at a sustainable kind of free cash flow number, which we can continue to grow on.
Growth from but that five rigs kind of cemented in two kind of providing that kind of longer term growth. So.
We we catch up here in the first quarter with the catching up the <unk> from last year end.
And then we decided hey, this five rigs is a sustainable program that can go into 'twenty, two and go into the future create kind of that what we're really looking for which is we do want to focus on free cash flow.
And then have modest growth of production, but we wanted to do it from a position of strength. So we had to get back to our full strength after really playing defense.
<unk>. So I think that we were really pleased with where the outlook is now and we certainly don't even with higher prices. We just look at that as an opportunity to get.
Caught up really quick on the balance sheet, that's the major goal of the company and.
We wanted to.
Put the production level at a level, that's sustainable but also at a proper level for <unk>.
For.
The leverage we have and we've accomplished that in the first quarter and then we can kind of sustain and then we're really focused on free cash flow in the future.
And I think we have all the tools to do it so one related to.
<unk> 'twenty 'twenty one.
I would say that we've kind of digested covey in 2020, even with Covid. So.
I think our model is a lot better I think David Terry has done a really good job working with Ron.
Working with Dan and Patrick Madhu, and others to get our model.
It does on a model looked like what are the drilling costs, where all the sticks.
Ours are almost 2000 sticks on a map, which ones will we drill you gave for the marketing group and site.
Can we sell our product there.
Our model is so much better now than it was even in third quarter. That's why we're so positive on our tone in our numbers.
How far we've taken this company in a short time, but the model is so important.
And again.
I'll really give ron the credit on that because he piece accountable for really the model and the numbers to the analysts.
Great Great details. Thank you all.
Thank you. Our next question comes from the line of Leo Mariani from Keybanc. Your question. Please.
And just one quick question for me and perhaps this is for Ron potentially just a question on the guidance. What can you tell us about kind of the cadence for Capex and production and just thinking on kind of on a quarterly basis here in 'twenty one.
Ron you got a shadow.
Yes.
Yes.
We only really provide the annual guidance.
For.
That's the typical.
Guidance I would tell you that.
With the carryover for some of those ducts debt that were mentioned earlier in the call.
The first quarter's going to be the highest spending level.
The fourth quarter is going to be.
The lowest and then the segment third quarters will be somewhat.
In between.
And then in terms of the.
Cadence on the production side.
We'll see.
We will see.
<unk> steady growth over the over the first.
Three quarters, and then that flattening out a little bit in the fourth quarter.
Given given the.
Current status or or schedule of completion cadence in the fourth quarter.
Okay. That's great color very helpful. That's all for me. Thanks.
Yeah.
Thank you. Our next question comes from the line of <unk> Chaudhry from Goldman Sachs. Your question. Please.
Hi, Good morning, and thank you for squeezing me in.
I have a quick question gas.
Gas futures have improved wanted to get your thoughts on what you see from non operated block notes with respect to activity levels and also I guess I Wonder what price point would you actually consider adding activity.
If the gas basis, keeping moving here.
Yes. Good question net we're probably not a good one to ask about.
Non operating partners because that's just such a small part of the company. We just don't have a lot of exposure, we have a little bit to some of the private companies in the haynesville a little bit to Chesapeake.
But we see their activity level being very fairly similar to where they've been.
As far as we really aren't looking to use the extra revenues that probably coming for these improved prices because.
Because we like the growth profile, we have in place now and so we would we would just use that to accelerate our de levering.
And.
Because thats our major goal so.
Again, 91% of what we have we operate to read on operating any of the Bakken that would be the right that we have part that we don't operate right weight on a really abacus has become a very small part of the company's day of 2% of the company. So it's not that significant to us, but but overall, yes, we will use it.
Hopefully the higher prices.
Two distinct achieve our goal of getting under two times levered faster because that's really the major goal of the company has everything else is.
Is how do you get there and we think we think that we've got the right production profile that fits the company well and so now it's really like.
The leverage is not where we want it to be.
The next two years, our goal is to really come back and be able to tell you at the end of two years debt. We have the balance sheet debt, we want and the cost of capital that reflects.
That in.
That we would consider that a big success.
On the analysts say.
We're a low cost producer for high margins for good and favorable inventory.
The weakness Oems our cost to capital.
We did incur debt, although we added equity and de Levered with the companies.
Added expense of bonds.
But mainly the high cost of capital So we've got to deal with that in the future but.
So I think we can do that internally the next year or so.
That makes sense. Thank you so much for the color.
Thank you good questions.
Thank you. Our next question comes from the line of Noel Parks.
But for others. Your question please.
Hey, good morning.
Morning.
Sorry, if you touched on this already but.
On the.
The amount you spent for new acreage leasing on fourth quarter I think it was about $6 5 million was that just.
Bolt on.
Acreage you've had your eye on for a while.
We're opportunistic all the time, if we could add haynesville acreage that we think will other linked on our laterals or give us good drilling locations on the future I mean, we're always opportunistic on that we always have been.
Given that and we think theres not a lot of competition for that type and so we've really been working that hard and have a lot of looking across the whole landscape.
Of the prospective haynesville.
And trying to find any kind of open leases and go after them. So that's something we've allocated some dollars to do in 'twenty. One also.
Great and.
You talked a good bit about the gas environment and.
We already have an Ida hedging in 2022.
Just looked at the futures curve.
I'm just wondering do you think 22.
It is still relatively low considering the demand profile I'm kind of wondering if we we have another leg up you're thinking.
Cancel button here.
We think definitely and we think that 'twenty two I mean, it's not a it's a problem that we've had for a long time the longer term curve just reflects a lot of the illiquidity of the natural gas futures contract.
So people talk about on why don't you hedge out five years, what Theyre just if.
If youre a large producer it's hard to do you take and.
And so that's why our 12 to 18 months kind of cycle as our hedging.
We we.
We do think 'twenty two is.
That price stride in our opinion, but we're mainly going to be able to hedge, though we're pretty attractively using collars more in 'twenty. Two so we could have some of the exposure to the upside debt probably shows up I mean, the gas market in our opinion is going to be pretty tight this summer.
And I think the.
People have been.
Non believers in gas and really really torture gas with the warm winter, but I think they could end up with a pretty big.
Very tight market, that's what everybody's telling us for this summer.
We think the 'twenty 'twenty twos goes many legs as incentive pay going upwards.
We definitely think it's positive not negative.
Great and.
One thing I noticed in the.
In the reserves.
I noticed you had.
300, almost 350 bps.
Positive performance for vision can you just talk about those.
Yes, we're pretty proud of that and I think you know in a.
A year when.
If youre using a low price typically you're fighting.
That but these wells have such a low cost structure that we didnt really suffer from.
Having a bunch of non economic reserves, we always lose a little bit of reserves from using a very low price in the tail.
But overall I think we've been very conservative on our reserve bookings for undeveloped wells and I think as they are.
They're booked fairly conservatively and then as they are.
As they're drilled.
We obviously have additions there.
At a higher number than they were booked at plus just we actually had overall positive revisions on our PDP at all our reserves from the performance of the wells.
So I think it's it's.
0.2, the good job operations do but it's also I think that.
It's a testimony to we're very conservative and preparing those numbers.
And.
And so we're conservatively booked so when they actually become real wells Theyre typically have.
The upside to them once they are really drilled.
And I think debt.
Yeah look back historically, and we haven't had negative performance revisions.
And long long time, and I think that's a testimony to the quality of the properties and the conservative bookings that they were booked at.
That's a great question too because most people don't see that don't I never asked that question. It's a great question to have 367 Bcf for <unk>.
<unk> revisions added in a terrible year for pricing.
So thats again.
That's a good marker that we're solid on that.
Yes, and just to.
Give me some perspective, so sort of what vintage of bookings worthy that youre seeing the performance revisions is that sort of stuff from.
For five years ago, where the.
The client isn't as steep.
Steve as you thought or is it just outperformance of more recent wells.
I think it's the overall haynesville well and it's also the fact that it's hard to see in the numbers, but generally what's happened to our inventory as we've turned.
Short laterals into long laterals.
Some more economic and Theres been a lot of re mapping of the inventory.
And we had I think.
I think we.
I'd just close Covey Park. So there was a little bit of integration to kind of really get all that done and probably didnt have that optimized at the end of 2019 and our reserves, we probably had a.
And I think as we were able to work through an.
Redraw on the laterals and et cetera, and the performance of the wells overall and the lower on the lower development costs that day that will have compared to what we expected in 2019, a lot of positive factors kind of contributed to that.
To that but.
Including just the actual wells their actual performance was better than what they were in the reserve report for so I think all of those together.
As another good year of positive revisions, which we had last year also.
Terrific. Thanks, a lot.
Thank you.
Thank you. Our next question comes from the line of cash you Harrison from Simmons Energy Your question. Please.
Good morning, all thanks for taking my question I'll keep it simple just one quick one for me can you discuss on what proportion of gas in the quarter would typically be sold on bid week versus the spot market. Thank you.
Yes. Good question I mean, typically we target.
To have.
About 75% to 80% and sell.
On the index basis, because thats kind of how are.
The index prices match steps match up well with our hedging program alright, the spot prices might not because of that and so but we can't go we don't want to go to a much higher percentage because we have a lot of new wells coming on and there is.
Production issues can come and go so we don't want to ever be caught having to buy gas to fill it.
With time, we can't deliver on so that's our basic rule Darren I'll take there is there are some times when we just say.
They just said that I think we took we probably went lighter on index selling.
Selling into the index market for the first quarter, so far and we were more I think we were more at.
What was our exact number day.
And do you have it there I think we're I think we're more 35% in the spot market.
For.
Yes. Thank you.
So right now, yes, 35% to 40% actually for the month of February.
And that was a little bit lighter than the month of.
January.
So we're a little bit more in the in the spot market.
<unk> than normal.
A lot of it that we do have a big ramp up in production going on in the first quarter. So that's part of that.
You want to be conservative as you're bringing on a lot of wells because you don't have the exact timing.
But I think thats paid off pretty well in both January and February because prices have been moving up and.
Obviously this week is like hitting the debt.
The jackpot.
Some of these incredible prices I mean.
Frankly, we were able to we were able to sell get super premium prices for a material amount of production anywhere from $15, an mcf to maybe some even at a $179 an mcf so debt.
Those are the spot prices that are out there.
But to answer your question on <unk>, 70% to 80% that's kind of the norm norm, that's where we'd like to be for.
Debt, we might be in February is a little unusual.
Alright Thats. It for me, Thank you and looking forward to seeing those on realizations.
When gas you on earnings.
Yes that would be what we're interested to see how it all shakes out on the end too.
Good question.
Thank you. Our next question comes on line of Phillips Johnston from capital One your question. Please.
Hey, guys. Thanks, just one for me as well on its really just a follow up to ron's comments on the leverage ratio target.
It looks like you guys have probably hit that number.
Two times target, probably about mid 20 to ourselves and strip holds.
You mentioned Devin paying variable dividends I'm wondering if you could.
Addressing the boards preferred method of returning cash.
Returning cash to shareholders once you've sort of achieve that leverage ratio goal.
Well you know.
As you will know I mean at the end of <unk>.
Probably 2014, we were a dividend issuing company.
I think we issued $12.05 per quarter. So we did that and of course I mean, the wheels fell off the sector in the first quarter of 2015 so.
<unk> every company should have a goal of being in a position to have giving a dividend period I don't.
I don't think we have enough shares to be buying shares back. So we don't see doing that at all we need to get more shares and float.
I think we've got great inventory, we need to get the stock price performance, we need to be.
<unk> can hook on the dividends is not high enough question. So that's our goal we want if we want to be in a position to be able to give a dividend.
Periods.
We're addressing the leverage first because you want to have the right balance sheet. We have started to do that and hopefully we can do that in 'twenty, one and 'twenty two.
Yes.
I agree 100% is there anything.
About variable dividends that you see as maybe being a drawback.
No I think once you if you've got the size of the company that you need and you've got the inventory I mean.
David just did a big acquisition or consolidation I mean, they've got the ball they've got market GAAP.
Got low cost per capital they've got inventory I mean.
We don't have any but right now we don't have any any issues as far as where our acreage is located.
Drilling permits that are.
Cereal at all so our acreage is well positioned.
In good areas. So they are not kind of politically charged issues around them I think that's good.
But no I think.
Pioneer came out with a variable concept in Devon issued one.
I think thats, the new business plan I mean, you've got a that goes back to the question of M&A do you do you need M&A I think you're doing you have to have bigger that day.
Be more predictable you can't you can't rely upon cash.
For for Wall Street to feed a company, that's not making any money you have to have free cash flow I mean, all of those things I believe we're going to give you on <unk>, giving you.
Kind of at the end of the funnel is you need to have a company.
That can give a dividend period thats just another sign that you are healthy and we will be able to.
Since we're going to work on our balance sheet like you said for this year next year, we'll be able to see how the variable versus fixed dividend.
On.
Work with these other with our other peers and so on.
We were able to kind of look to see if the market.
Which which method they like better and so we will study that to make a real decision on the structure for the first.
First job number one is getting the balance sheet to where everybody is very comfortable saying, yes, you should be paying a dividend and so we're focused on job one absolutely. We've always said that we've got to get our cost GAAP. The lower we've got to get our leverage down you'd love to be on the one time I mean, we're at three eight we want to be in the.
Low twos by the end of 'twenty, one and then lower in 'twenty two but then I think you have to have something in your scope around the corner net is you want to be able to.
The flexibility.
To have what kind of hedges, we need or don't need and the leverage needs to be down leverage average or get you in trouble time is on your side, we've got long term bonds, that's favorable our leverages.
As to our cost of capital too.
Yes.
I agree with all those comments thanks guys.
Yes, Sir.
Thank you. This does conclude the question and answer session of today's program I'd like to hand, the program back to.
Jay Allison for any further remarks.
Alright, Jonathan I, just have one closing remark and it's kind of on house cleaning item.
We received a notice from.
On the New York Stock Exchange this week thanking us for 25 years of listing partnership with the alma.
They attach to customized listed handblown, highlighting comstock to milestone.
So it's kind of a thin air to be an NYSE company for 25 years I mean, even for some of the most recognized as largest companies in the world, but we are there.
You have time to go to the Comstock website to see the emblem. Please do are.
Do you want to turn to page 22 on our corporate presentation day, you can see it but.
But again wanted to thank you for trusting us with your time on with your money and.
And we want to we want to close every day as a stronger company. If we can so great questions growth support.
So warm everybody.
Thank you, ladies and gentlemen for your participation on today's conference. This does conclude the program you may now disconnect good day.
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