Q4 2023 Comstock Resources Inc Earnings Call
Okay.
Thank you for standing by and welcome to the Comstock Resources fourth quarter 2023 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 this session you will need to press star one on your telephone if your question has.
Been answered and you'd like to remove yourself from the queue simply press star one again.
As a reminder, today's program is being recorded and now I'd like to introduce your host for today's program, Jay Allison Chairman and CEO. Please go ahead Sir.
All right, Jonathan I Love that broadcasting voice.
Kind of starts a day off price.
Uh huh.
Our corporate team at 255 strong I want to thank you for joining the call. This morning, and we wish you a happy Valentine's day.
Being a pure play natural gas company in a sub $2 natural gas market calls for decisive actions to weather the volatility.
And at the same time continue positioning comstock to benefit from the longer term growth in natural gas demand in the foreseeable future.
America will lead to deliver an additional 10 billion cubic feet of natural gas per day to the LNG facilities currently under construction in the next few years.
Actions taken so far as we batten down the hatches to protect our balance sheet number one.
January release type Frac crew.
Number two several months ago, we gave notice to release two rigs and they will both be finished their work by the end of this month.
Number three we suspended our quarterly dividend until natural gas prices improve.
And before we continually evaluate our activity level as we planned upon our drilling program within operating cash flow if possible.
Number five we formed our midstream joint venture last year that allows us to build out.
The western Haynesville midstream assets to be funded by the midstream partnership and not burden our operating cash flow at Comstock number six position Comstock to have very few rigs needed to hold all of our corporate acres, including the 250 plus thousand net acres in the western.
Haynesville number seven.
We're bullish on the long term outlook for natural gas and are growing our resource base and the advantage proximity to the Gulf coast market.
Alright last slide.
Our western Haynesville quote box ship chocolate on this Valentine's day allow.
It allows us to materially grow our drilling inventory organically.
First is through the M&A market.
I can also assure you that our majority stockholder the Jerry Jones family using 100% approval of all of our prior actions as well as our recent moves to protect our balance sheet in this volatile natural gas market. They are in the cockpit with us helping fly this plane with a steady.
Hand on the throttle looking into the future where global natural gas markets are counting on our U S gas to provide needed clean energy.
Our goal is to look back on this point in time in the future years, and say, where you handled it well and continued to create corporate value and a weak period for natural gas.
Now I'll go over to the corporate trip.
Welcome to the Comstock resources fourth quarter, 2023 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' dotcom and downloading the quarterly results presentation.
There you will find a presentation entitled fourth quarter 2023 results I am Jay Allison Chief Executive Officer of Comstock with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Board Mills, our VP of finance and Investor Relations. Please.
Please refer to slide two in our presentations and note that our discussions today will include forward looking statements within the meaning of securities laws, while we believe the expectations in such statements to be reasonable there can be no assurance that such expectations will prove to be correct.
Fourth quarter 2023 highlights on slide three we summarize the highlights of the fourth quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices oil and gas sales, including hedging or $354 million.
In the quarter, we generated cash flow from operations of 207 million or <unk> 75 per share and adjusted EBITDAX was $244 million. Our adjusted net income was 10 cents for the quarter. We continue to have very strong results from our drilling program and the.
Fourth quarter, we drilled 14 or 13, three net successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 8994 feet.
Since the last conference call. We are connected 22 or six to eight five net operated wells to sales with an average initial production rate of 24 million cubic feet per day, and an average lateral length of 11966 feet or 2023 drilling program replaced 100 at <unk>.
9% of our 2023 production with new proved reserves ads.
We're continuing to make progress on our western Haynesville exploratory play we added 23000 net acres to our expansive western haynesville acreage position in the fourth quarter alone increasing our total acreage position in the play to over 250000 net acres, we recently turned on.
Our eight wells to sales.
Later, well was completed in the Haynesville formation and is currently producing at 31 million cubic feet per day.
Additional wells the Harrison glass and poorly wells are expected to come on production by the end of the first quarter.
I will now have Roland go over the fourth quarter and annual financial results Roland.
Thanks, Jay on slide four we cover our fourth quarter financial results.
Our production in the fourth quarter of one five.
The CFA per day increased 6% for the fourth quarter of 2022 and grew 8% from the third quarter.
Low natural gas prices resulted in our oil and gas sales in the quarter coming in at $354 million declining 37% from 2020 twos fourth quarter, despite the higher production level.
EBITDAX for the quarter came in at $244 million, and we generated $207 million of cash flow.
In the fourth quarter, we reported.
Adjusted net income of $28 million for the fourth quarter or <unk> 10 per share as compared to.
Net income of $12 million in the third quarter of 2000, 22023 and $288 million in the fourth quarter of 2022.
Slide five we show the financial results for the full year 2023, our production.
<unk> averaged one four Bcf per day, which was a 5% increase from the prior year oil and gas sales in 2023 totaled one $3 billion and we are.
41% lower than our sales in 2022 due to the lower gas prices we realized.
Our EBITDAX in 2023 was $928 million can be generated $774 million of cash flow for the year, we reported net income of $133 million.
For 2023 as compared to net income of $1 billion in 2022.
Slide six we show our natural gas.
Price realizations that we had in the quarter during the fourth quarter that correlate Nymex settlement gas price averaged $2 88, which was <unk> <unk> higher than the average Henry hub spot price in the quarter of $2 74.
Our realized gas price during the fourth quarter averaged $2 48.
Reflecting a 40 <unk> differential to the sell by price.
And a 32% differential to our reference price.
The differentials were wider in the quarter starting in October which is normally occurs as we reached the end of storage injection period.
In the fourth quarter, we were 16% hedged and that improved our realized gas price for the quarter to $2.51.
Also been using some of our excess transportation in the Haynesville to buy and resell third party gas.
We generated about $4 $4 million of profits in the fourth quarter net improved our gas price realization by another three SaaS in the quarter.
On slide seven we detail the operating cost per Mcf.
And our EBITDAX margin, our operating cost per Mcf averaged 81 for the fourth quarter, 4% lower than the third quarter.
Lower gathering costs were offset though by higher production and AD valorem taxes are gathering costs were down three to 33.
During the quarter and our lifting cost per ounce of one set lower.
And then the third quarter rate at 23.
Our production and AD valorem taxes increased three <unk> in the third quarter from the third quarter level and G&A came in at two per Mcf, which was <unk> <unk> lower than the third quarter.
Our EBITDAX margin after hedging came in at 68% in the fourth quarter.
Up from the 65% level, we had in the previous quarter.
On slide eight we recap our spending on drilling and other development activity.
In 2023, we spent a total of $1 $3 billion at our development activities, including.
$1 2 billion on our Haynesville and Bossier shale drilling program spend.
Spending on other development activity, including installing production tubing, offset frac protection and other workovers totaled $54 million.
And 2023, we drilled 67 wells or 55, five wells net to our interest.
And turned 74 or $55 seven net operated wells to sales.
These wells had overall average IP rate of 25 million cubic feet per day per well.
On slide nine we cover our natural gas and oil reserves that were determined using the acquired the required SEC prices.
Our SEC proved reserves decreased 26% in 2023% to $4 nine Tcf.
Due to the low gas price used to that determination.
The required FCC gas price decreased 60%.
For 2023 to $2.39 per Mcf down from the $6 <unk> that was used in 2022.
Our 2023 drilling activity added 571 Bcf of proved reserves.
Our year end reserves, which replaced 109% of our 2023 production.
But we also had one eight <unk> of negative revisions due to the lower proved undeveloped reserves caused by a reduction in drilling activity and the low natural gas price that was used to determine.
Determine which drill.
Drill locations, we would drill.
In addition to the total of $4 nine <unk> of SEC proved reserves that we had at the end of the year. We have another half a tcf of proved undeveloped reserves that aren't included.
As they are not expected to be drilled within the five year required time period required by the SEC rules.
Also have another almost <unk> or probable reserves and four six tcf of threep fee or possible reserves for a total reserve base of around 10 nine Tcf.
It kind of P. Three basis, all determined at the low SEC pricing.
On slide 10, we've used <unk>.
IMAX gas price of $3 50 per Mcf to determine their reserves to show you the impact of the low prices on the year end reserves.
Using this price our proved reserves would have been similar to last year at six six tcf.
In addition, our overall reserves, we would have had an additional.
There are two tcf of proved undeveloped reserves.
That are outside the five year period.
And then we would have two five tcf of two P of probable reserves and another eight seven tcf of Threep or possible reserves for a total overall reserve base of $19 eight <unk> three basis.
Determined at $3 50, Nymex gas price, which in our view lined up closer to the long term futures prices for natural gas.
On slide 11, we recap our balance sheet at the end of 2023, we did end the quarter with $580 million of borrowings under our credit facility, giving us a total of $2 7 billion in debt.
Net.
Including our outstanding senior notes.
Our borrowing base for our bank credit facility is currently at $2 billion of which we have an elected commitment at $1 5 billion of that amount.
So we ended the year with overall financial liquidity of just over $1 billion.
I'll now turn it over to Dan to discuss our operations in more detail.
Okay.
Overall slide 12.
It shows where our current drilling inventory stands at the end of the year into the fourth quarter.
Our inventory is split between our Haynesville and Bossier locations.
We haven't divided up into four buckets are short laterals.
Run up to 5000 feet or medium laterals run between 5000 8500 feet.
We have a long laterals between 80 510000 feet.
And then our extra long laterals extending out beyond 10000 feet.
Our total operated inventory currently stands at 1706 gross locations and one 303 net locations.
This equates to a 76% average working interest across our operated inventory.
Our non operated inventory has 1253 gross locations in 160 net locations.
This represents a 13% average working interest across the non operated inventory.
If you break down our gross operated inventory, we have 291 short laterals 347 medium length laterals.
438, long laterals and 630 extra long laterals.
The gross operated inventory has split 51% in the Haynesville and 49% in the Bossier.
37% of our gross operated inventory or 630 locations.
Laterals greater than 10000 feet.
63%.
Gross operated inventory has laterals exceeding 8500 feet.
The average lateral length in our inventory now stands at 8971 feet and this is up slightly from 8949 at the end of the third quarter.
Our inventory provides us with 25 years of future drilling locations.
On Slide 13 is a chart outlining our progress to date on our average lateral length of drilled based on the wells that we've turned to sales.
During the fourth quarter, we turned 17 wells to sales with an average length of 11870 foot.
And this is vital to the continued success of our long lateral drilling program.
The individual lengths range from 5736 feet up to 15243 feet.
While our record longest lateral still stands at 15000 702006 to eight.
During the fourth quarter, 12% to 17 wells, we turned to turned to sales head laterals exceeding 10000 feet.
Including seven of those wells longer than 14000 feet.
To date, we have drilled a total of 80 wells with laterals over 10000 feet long and.
In 28 wells with laterals over 14000 feet.
During the fourth quarter, we Didnt turn any wells to sales on our new Western Haynesville acreage.
To date in 2024, we have turned one rail barrels in the western Hinesville and we do expect a total of four wells.
It will be turned to sales by the end of the first quarter.
In 2023, we turned a total of 74 wells to sales with an average lateral length of 10820 feet.
And this is up 8% from our 2022 average lateral lengths of 9989 feet.
Slide 14 outlines our new well activity.
We have turned to sales and tested 22, new wells since the time of our last call.
The individual IP rates range from 9 million a day up to 42 million a day with an average cap rate of.
24 million cubic feet a day.
The average lateral length of 11966 feet with the individual laterals ranging from 5736 feet.
Up to a 15243 foot lateral.
The Hamilton of our Hailand be number two well located in east, Texas, which had a $9 million a day IP.
P rate suffered mechanical casing failure during completion, which resulted in this well producing from only half of the completed lateral.
In addition to the first seven wells producing in the Western Haynesville at the end of 2023.
We recently placed our eighth well online.
Neil and number one was drilled in the Haynesville and today, it's currently producing 31 million cubic feet a day.
This well is still in the process of being tested and cleaning up.
We do anticipate three additional wells being turned to sales by the end of the first quarter.
We currently have two rigs running on our western Haynesville acreage and we are currently planning to keep two rigs running in the western Haynesville for the remainder of the year.
On slide 15 summarizes our D&C costs through the fourth quarter.
For our midst mark long lateral wells that are located on our legacy core.
East, Texas, and North Louisiana acreage.
This covers all of our wells, having lateral is greater than 8500 feet long.
During the quarter, we turned 17 wells to sales that were one of our core East, Texas, and North Louisiana acreage <unk>.
13 of the 17 wells were our benchmark long lateral wells.
In the fourth quarter, our D&C cost averaged $1482 a foot.
On the 13th benchmark loan lever oils.
And this reflects a 5% decrease compared to the third quarter.
Our fourth quarter drilling cost averaged $610, which is a 15% decrease compared to the third quarter.
The lower drilling cost reflects a slight downward trend on pricing we've experienced throughout 2023.
And also our drilling costs in the third quarter was abnormally higher due to some drilling issues, we had in that quarter.
Our fourth quarter completion costs came in at $871 a foot.
Which is a 3% increase compared to the third quarter.
The increase in completion costs were primarily attributable to some slightly higher plug drill out.
Cost in the fourth quarter due to the longer laterals.
We currently have seven rigs running and we are in the process of releasing one rig.
This weekend.
End of the month early next month will be released in the second rig.
We currently expect to run five rigs for the rest of 2024.
On the completion side, we are currently running two frac crews and we do it.
To maintain a one to two frac crews running for the remainder of the year.
I'll now hand, the call back over to Jack.
Thank you Dan. Thank you Roland if Youll turn to slide 16, we'll summarize our outlook for 2024.
We remain very focused on proving up our western Haynesville play and continuing to add to our extensive acreage position in this exciting play.
At the end of 2023, our western Haynesville acreage position totaled over 250000 net acres.
Following the creation of our midstream joint venture late last year, the capital costs associated with the build out of the midstream assets in Western Haynesville will be funded by the midstream partnership and will not be a burden.
On our operating cash flow.
We believe that we are building a great asset and a western haynesville that we'll be well positioned to benefit from the substantial growth in demand for natural gas in a region that is on the horizon driven by the growth in LNG exports that begins to show up in the second half of next year.
We are actively managing our drilling activity level to prudently respond to the current low gas price environment. We have already released one of our three completion crews as Dan said in two of our operated rigs on our legacy Haynesville footprint.
<unk>, our total operated rig count to five rigs of which two are drilling in the western Haynesville.
We are focused on preserving our balance sheet in this gas price environment, we will continue to evaluate our activity level as we plan to fund our drilling program within operating cash flow.
We're going to suspend our quarterly dividend until natural gas prices improve.
Our industry, leading lowest cost structure is an asset in the current natural gas price environment as our cost structure is substantially lower than the other public natural gas producers.
And lastly.
We will continue to maintain our very strong financial liquidity, which totaled around $1 billion at the end of the fourth quarter I will now have raw provide some specific guidance for the rest of the year Ron.
Thanks, Jim on Slide 17, we provide.
The updated financial guidance for the first quarter of this year and the full year.
First quarter D&C Capex guidance.
Guidance is $225 million to $275 million in the full year D&C Capex guidance is $750 million to $850 million, the lower spending versus last year related to the announced release of two drilling rigs in our press release last night in response to low gas prices.
We've continued to see signs of some deflationary pressures on service costs, including improvement in our completion cost per stage.
We anticipate spending an additional $30 million to $40 million.
On lease acquisitions in the first quarter and $40 million to $50 million over the course of the year capital expenditures related to pinnacle cash services will be funded by our midstream partner and are expected to total $30 million to $40 million in the first quarter and $125 million to $150 million for the full year.
First quarter and the full year LOE is expected to be in the range of $24 28 per Mcf.
<unk> are expected to be 32 to 36 cents per Mcf.
And production and AD valorem taxes are expected to average 16 to <unk> 20 per Mcf.
DD&A rate is expected to average $1 30 to $1 40 per Mcf this year.
In the first quarter, our cash G&A is expected to total of $7 million to $9 million.
And 30% to $34 million for the full year.
In addition, we will have noncash G&A in the first quarter of $2 $73 million in $10 million to $12 million for the full year.
With the increase in <unk> and our current debt levels.
Cash interest expense is now expected to total $43 million to $47 million in the first quarter and $195 million to $205 million for the year, while noncash interest will remain approximately $2 million per quarter.
Effective tax rate will remain in the 22% to 25% range and we continue to effect to defer 95% to 100% of our reported taxes. This year I will now turn the call back over to the operator to answer questions from analysts who follow the company.
Certainly one moment for our first question.
And our first question for today comes from the line of Derrick Whitfield from Stifel Financial Your question. Please.
Good morning, all and thanks for your time.
Yes, Sir.
Let me first commend you on our strong year end and your decision to reduce capital outflows in the current depressed gas price environment.
With respect to your 2024 outlook could you speak to the average gas price that underpins your spending within cash flow you any additional steps you would likely take it.
To further reduce capital as gas continues to deteriorate.
Yes, Derrick I mean, yes of course, that's a moving target where gas prices are and I think that.
Okay.
Probably.
Where the gas price.
Whereas in the market, maybe about two or three weeks ago was probably exactly kind of where that's in balance.
It's going to be a kind of a volatile deal, but I think the other things that we'll continue to monitor our what our service costs are trending down a little bit as far as the.
Some deflationary actions kind of happening on that side.
But the other levers that we can pull or continue to look at dropping another rig that's the most effective way to.
Reduced capital expenditures that has that.
Most impact on.
Creating net operating cash flow.
And so that's what we'll continue to monitor the activity like we do.
Each year.
Look the Titan tightened up the ship wherever we can to kind of maximize the operating dollars that we have.
Terrific.
Follow up I wanted to shift over to the lesser Gainesville with the understanding that it's a long game resource could you speak to the gains you're experiencing in operational efficiency. The degreed youre expecting your breakeven to improve over time, and if youre expecting a meaningful difference in the breakeven between the Haynesville and Bossier intervals.
So Larry this is Dan I would say, we're definitely gaining ground.
Going up the curve still faster on our western Haynesville wells.
We are.
We're drilling our first two well pad actually currently.
We know what the second rig is going to its first two well pad next that's going to definitely help our efficiency there.
We still have had some things that we've.
Guiding down on the drilling front that still increasing our drill times, so we and we still see a little bit more running room, there to get faster.
So I think we definitely are seeing an increase there on the western Haynesville wells and we're seeing those costs come down.
In the core area, probably as far as the move in the needle own efficiency, probably not as much I mean, we've been there for a long time, it got everything pretty streamlined but.
Down to the two frac crews same vendor we see some.
Some savings there just really really good solid performance.
We brought in some three three new rigs.
<unk>.
Newbuild rigs just I think we're going to have some better performance there just kind of overall.
So I think we will and of course, we're seeing the cost savings come down with the activity.
Levels would probably down 10% or so this year since the beginning of last year.
And obviously difficult times.
<unk>.
I think everybody gets pretty streamlined and pretty efficient in the costs come down but.
Obviously, we'd like to see maybe prices will be a lot higher.
It can be battling some of those things, but that's where we're at.
Very helpful. Thanks for your time.
Thank you one moment for our next question.
And our next question comes from the line of Charles Meade from Johnson Rice. Your question. Please.
Good morning, Jay to you and your whole team there Comstock.
Good morning.
Dan I'm going to start with just a really quick clarifying question with you I think I heard you say in your prepared comments that youre planning on running.
Between one and two completion crews for the remainder of the year did I catch that right.
That's right. So if you look if you just do the math I mean, we've got to kind of a two dedicated fleets to us, but if you do the math with the number of wells, we're going to turn to sales that comes out like $1. Seven Frac crews is what will need this year.
Got it got it and then one.
One running full time and one with some gaps in between.
Got it and then my follow up Jay.
Recognize that this is kind of a.
Maybe the simplistic way to start this but.
I recognize you guys look at a lot more data and have a lot more consideration than than somebody sitting in my chair dose.
So, but but in my chair and I look at that I look at the.
The futures curve here and we don't get above.
Two bucks until July and so from my seat it looks to me like the right number of completion crews to be running right now for at least the next several months is zero.
I recognize that's not a realistic case, but can you bridge the pieces.
To kind of bridge view it looks like the right number zero, but why the right number for you guys is is one seven or one to two for the next several months.
But I think Thats a really good question number one I think if you look at our proactive we've been.
Typically on a conference call like this you are going to release, a frac crew, we've already done that.
Second of all maybe you have contracted to have that Frac crew and you have to use and we don't have any contracts.
A well by well.
And I think the other thing just as far as cost I mean, usually in a conference call like this year going.
<unk> released two rigs and it takes two or three or four months to release those rigs and we were proactive back in December.
To give notice and as Dan has said we will have both of those released.
By the beginning of March is our goal.
The growth was asked a question about the price of natural gas to stay within operating cash flow, which is kind of your question.
What we tell you is it.
That is our goal is to tell you that we do.
Don't plan on spending as much money on acreage procurement as we have in the past.
It tells you that probably.
Probably half of our acreage that we own right now is western Haynesville as a core in.
And it tells you that we're not inventory store.
So we don't have to do deals in the market whether gas prices are high or low in order to buy inventory. So then you come and you look at it.
At the cost and we look at deflation I mean, Dan goes over some of the cost savings that we've had from the the Frac company, so far and some of the cost savings would be pad drilling or completing the wells I think all we can do is tell you that that we've looked at those numbers we've looked at hedging.
We've hedged about 28% of our production of 24% to $3 50 Pops swap.
Think that we need to be in the 50% range now when will we get there I don't know, but I think you and the market need to note that it is a corporate goal that we have.
And the reason, we use kind of batten down the hatches a theme.
Because if we need to delay some projects, we see that in the next month or so and I think we can do that.
We need to lay down another rig will have the optionality to do that.
So again I think your goal is how are you going to protect this thing.
And that's one reason I always say if you look at the major shareholder.
Who owns 65% of this if anybody is trying to protect it.
The Jones family is in there well involved with what we do.
And then I think you have to look at it any minimum volume commitments or from firm transportation agreements that you have and say are we impacted by reducing the rig count and your answers were not <unk>.
You have to look at all of those things too and you ask that question, but we're going to continue to manage this just like we've managed it for a while.
We as a group.
We recognize pain.
Some groups haven't recognized because I havent experienced it we do so it is a good thing it's an indicator.
Whatever we need to do to drive this shift that's what we plan on doing so.
Great question.
Thank you for that elaboration that was helpful. Jeff.
Yes, Sir.
Thank you one moment for our next question.
And our next question comes from the line of Fernando Zavala from.
<unk> Energy partners your question please.
Hey, guys. Good morning, going back to your comments around evaluating dropping another bray.
Where would that come from would have come from the western Haynesville or.
Haynesville.
If we dropped another rig it would be in the core it would not be the western haynesville.
Okay got it and then can you talk a little bit about that as my follow up the trajectory of production in 2024.
It seems like the implied.
24 guidance is in line with first quarter, So just more color there.
Yes.
If you think about the timeframe related to dropping a rig and starting to show up in terms of impacting production.
Dan mentioned, we were dropping the first of those two rigs here. This weekend in this in the second rig within the next.
Within the next two to three weeks I think he said.
So just.
Two.
Production. So that's why the first half of the year production should remain relatively flat and you start to see a little bit of a decline in the third quarter end and a little bit larger decline in the fourth quarter.
As you start to feel the full brunt of of running five rigs.
Sure.
Okay. That's helpful. Thank you.
Thank you one moment for our next question.
And our next question comes from the line of Jacob Roberts from Tpa <unk> Company. Your question. Please.
Good morning.
Good morning, good morning morning.
I think previously you had some commentary about growing commitments in HBV provisions on the Western Haynesville can you speak to the impact of running.
Running those two rigs for 2024, and any needed extensions or perhaps catch up provisions to be needed in 2025.
Now, we feel like that at that.
Not running the three rigs like Youre originally anticipated this year that that's not going to put us that far behind and we won't really have to alter our future plans.
By taking this one.
I love it slower approach in 'twenty four.
Yes, but over a longer period of time, we have a lot of acres to that term acreage that has to be.
We have to drill to hold so but there is that given that they.
The actions were taking this year, we're not really changing.
Yes.
Changing.
Having to have now that we have to extend leases et cetera, we still can keep all of these kind of on track.
And in fact, I think this slowdown is a positive and that and the western Haynesville that as Dan said earlier.
Most of the wells will be drilling now will be two wells per pad, we had been drilling one well per pad I think it lifts our land group.
Now getting ahead, a little bit for 25% and 26, because we have added a lot of acreage within a small window.
It lets us.
<unk> our wells.
Better in 2004, and 200 card to de risk.
A lot greater Walt of acreage.
With fewer wells.
So it really has been the slowdown has served our land group.
Well and as Robin said and Dan will tell you it is not impacted.
Really the drilling do you think we will add another rig in 2005.
We were going to do in 2004.
But the results will speak for themselves and so far the.
The results have been really good they've been stellar.
For the acreage that we have in the area that we've de risked.
Which is probably from the heel to to our northern well, probably 'twenty three or four miles.
We've said that publicly we've got a lot of acreage we've derisked there.
So it looks it looks good and I think this environment is favorable for us to slow that down.
Thank you for that.
Second question is around the leasing program seems to have bled over from 2003 to 2024.
We focused in the first quarter of the year can you just provide any detail.
What caused some of those conversations to fall into this year has the process become more competitive and maybe if you can a sense of the scale of the remaining track transactions in the pipeline. Thank you.
The process definitely has not become more competitive with the weak gas price environment.
But it's just a it's a.
We are leasing from a lots of different parties, it's there's lots.
Lots of reasons why.
Close something Youre working on so it is not.
If there is any significant trend there but.
But we are kind of rounding up where we've captured a lot of the acreage in the areas that we take care of that most prospective for the play and so that's really driving the program forward.
Anything else suggests we're finishing up.
Great appreciate the time.
Well, we've stated that we average about $550 an acre and in fact.
$1 61 gas, which is where we are right now, which I don't think ive read that we have.
Haven't been disposed in spring of 2016, so eight years.
I can promise you. There is there is no competition out there to $1 61.
At all.
Thank you one moment for our next question.
And our next question comes from the line of per ton down from <unk>. Your question. Please.
Hey, good morning, guys.
Good morning morning, Alright.
This one might be a little bit weird and I'm, not saying if necessary, but if it did become necessary is there any ability to negotiate with quantum on the minimum volumes. It seems like you guys have a mutual interest in even when they revert to 30%, there's probably an interest and properly managing asset instead of just kind of hitting a number that would inkjet a different gas.
Right, but it was purely out of curiosity.
But that level is set so far.
Far far lower than our forecast and even our production level now.
It's not even a question.
Any thoughts tag.
We found that very distinct and then.
Another one just to keep them a little bit weird is there was there any consideration instead of 10.
Technically suspending the dividend.
Ted going to a kind of variable David I, just don't know management has a view on whether or not that has a place or no place or maybe it just matched with the with the corporate view.
No we didn't consider that.
Sounds good I appreciate the answers thanks.
Great questions.
Thank you one moment for our next question.
And our next question comes from the line of Phillips Johnston from capital One Securities. Your question. Please.
Hey, guys. Thanks. My first question is on your three five times Max leverage ratio Covenant.
At current strip prices our model shows that you might be close to reaching that later this year would you also see that as a possible risk and if so how easy would that how easy would it be to get a waiver from the.
Thanks.
We don't see that so we don't think.
That we come that close to that so I think we just debt.
Continue to monitor our spending level in that.
And not use much more of the credit facility.
Okay sounds good.
To make sure our models are calibrated as we think about the plaza.
Yes.
What would you expect the net well count to look like for the year in terms of both wells drilled and wells turned to sales.
<unk> got that number thats in the press release data.
So you would have read it there yet.
This 40.
Okay.
Hang on.
Yes.
Let's see.
Okay.
Yes.
Okay.
So.
First as it says in the press release, we plan to drill 46, gross and turn and Thats about 36 net.
Wells and turned to sales 44 gross 38 net.
Okay, sorry about that I completely missed that.
Thank you.
One moment for our next question.
And our next question comes from the line of Leo Marinara from Ross Your question. Please.
Okay.
I just wanted to quickly follow up on some of the prepared answers here that you guys had given here.
Ron you talked about production kind of flattish in the first half of the year, a little bit of a third quarter decline and then more of a fourth quarter.
Klein and of course, I'm sure, it's pretty obvious you folks and thats a bit inverse to what the futures curve is suggesting we're clearly prices are expected to be lower early in 'twenty, four and a higher as you get towards those winter months.
24, So you certainly expressed the.
I believe that you want to be flexible and sort of do what you can to kind of maximize cash.
Cash flow so is there some.
Some thought to pushing some of those turn in lines out towards those later quarters and perhaps trying to Ed.
The production a bit so it's a little bit lower this summer and maybe higher next winter and is there any operational reasons, maybe why you couldnt do that maybe some of the western Haynesville stop has provisions or well have to come online at a certain point in time, but any color you have there would be great.
Well I think it's difficult to under shale, if I understand the timing of shale production in the way that that the wells are drilled all that to try to be super precise and bringing production on.
What the futures curves as it could be now which it could be different when you get there.
I mean is that I mean.
After that can give consideration to it.
We can give consideration in the field if we have low.
Spot prices that we.
Yes, not turn out well on that day definitely so you can manage these kind of around that.
I don't know that you can think that you can direct it.
Rail precise level, because your assumptions could be wrong in two plus it takes.
It takes a lot of resources to.
<unk>.
In preparation to bring these on and you don't have all of those available at depth.
You can't snap your fingers and get all the wells turned out on one day and so it's just really balancing all of that and balancing that with what you have.
So you have at the time so.
Yes, I guess, because we presented a plan and budget that mean, it's going to happen exactly that way. So we'll adjust as we go through the year.
What's going on.
And the markets and what's available in the spot market or the index market et cetera.
I'll add specifically to the western Haynesville are two frac crews are actually for.
Bracken wells there now.
Now in the Western Haynesville, So there's really only one other well.
Right behind those and we don't have anything else coming on in the Western Haynesville till the end of the year because.
Like I mentioned earlier, we got both we've got one rig that just started a two well pad a couple of weeks ago.
And our other rig is getting ready to move to a two well pad and obviously the western Haynesville wells.
Take more days to drill so with two well pads that will be drilled in all through the spring and summer and fall.
Got it Okay. That's helpful color guys I know you can't get enough.
Your fingers like you said rolling in but it sounds like maybe there is some flexibility to kind of manage this a little bit on yours, and im sure youre going to be watching it very closely as the year progresses here.
Yes.
A follow up on the Western Haynesville you obviously had your reserve report out can you can you give me any color around like what some of these western Haynesville wells, we're getting booked at maybe like in terms of reserves per thousand feet or whatever you guys want to presenting here.
Yes, generally we don't and we.
I don't have a lot of bookings because where we're not trying to get beyond the direct offset as far as booking anything in the western Haynesville, It's still early and we only had seven.
Seven producing wells.
In total in the play so there's a limited number of locations in the reserve report, but I would say overall the average is.
The average kind of reserve bookings are in that three five bcf per thousand feet of completed lateral.
Only really one well has.
Pretty significant track record of performance, which is the first one that circle him in.
It was upwardly revised with this it's kind of outperform that the rest of the wells don't have near the number of months to production. So kind of left them, where they are but the reserves are trending nicely.
And the play for the first wells that we drill.
Okay. That's.
That's great color and certainly appreciate that and just.
Lastly for me here just.
Obviously, I don't think gas is turned out like anyone expected.
In 2024 here.
It sounds like the plan is to really not kind of add that from what im hearing from you or Roland and I guess just to the extent that for whatever reason, let's say next winter is warm and it's kind of a weaker start.
To the year hopefully that's not the case, but if that is the main.
Are you still in a position where you don't want to add that or do you have to have maybe a little bit more activity next year because then.
Holding some of the western Haynesville and would there be any consideration to maybe putting in some I'll call. It near term, putting the kind of gets you over the gap here until markets improve later in 'twenty five 'twenty six.
I think we positioned ourself right now so that.
The things that we've done to allow us to protect our balance sheet.
I mean, if you just segregated and you look at the Western Haynesville like Dan said.
These wells will be slower to to reach production. So.
Even though we didn't add a third rig in may as Rolla mentioned, we're not going to have any issues with our midstream quantities.
So I don't see an issue there and then I think as far as any obligations, we have to drill to complete wells. We don't have any obligations are and as we said we were very very proactive even in December much less January February.
Got some cost.
So I think we're just monitored like that through if we need to lay down another rig if we need to defer completions all of those things.
Those are those are all in the Hopper there, we'll look at to do so.
Even in a very tough market.
I think we've got a lot of the switches to pool.
Where we are and our bottom line is.
We're just so rich in inventory yet.
We just have to protect what we already own.
Period, we don't have to reach the 10th commandment and cover it everybody everybody else's inventory.
Just have to continue to perform on the <unk>.
Western Haynesville.
Rollins said I mean, the EUR looks solid Dan said the costs are coming down it's still early innings.
But we've character a lot of acreage and we'll just see what the historic book tells us in the future.
Okay I appreciate the color.
Sir.
Thank you one moment for our next question.
And our next question comes from the line of Noel Parks from Tuohy Brothers investment Research. Your question. Please.
Hey, good morning.
No.
I just wanted to.
Touching again on the Western Haynesville I'm, just wondering can you talk a little bit about what kind of science, you're doing on the latest western Haynesville wells sort of like what are you most interested in and learning about next as far as just.
Youre drilling.
Practices.
Well, let me wait so we've.
I think we've stated before you know probably the biggest.
A difference between the western Haynesville and our core is the temperature.
The depth I mean, obviously they are a little bit deeper.
Just look at the Tvs of the wells.
And of course with that comes temperature.
And we've just really done a really good job at managing the temperature and when I say that manage it getting our.
Bottom hole assemblies to perform and stay on bottom longer.
Faster rfps.
Less trips in and out of the hole to get the lateral drill. So we've made a lot of gains there and then just up top on the <unk>.
Obviously, a longer vertical section to drill.
Made some modifications to our casing design, we've seen that.
Our penetration rates pick up up top also so.
You just kind of got attack you got to attack everything and we don't have all of those things.
Yeah.
Totally.
Kind of maxed out like we do in the core the core and we just kind of make some tweaks a little bit here and there and you pick up a day or two but were taken up bigger chunks down here in the western Haynesville just figuring this thing out.
And.
Are you at a point where.
Productivity of the rock.
It's pretty much not a surprise anymore.
Learning things there.
I will tell you where the rocks turned out I mean, we knew everybody knows that the gas is there.
There were two old wells drilled back in 2010, and 2011 that we got data on.
They had all kinds of problems that varian for your completions put on them, but still with that.
Still a decent amount of gas so we knew the gas was there.
Really a matter of economics.
The wells.
They do treat at higher pressures, one way for AG, but they also frac very consistently the pressures don't just.
Go up and down and go all to replace that would be obviously make a lot more difficult.
Very consistently.
Which makes it easier.
To frac them at the high pressures.
So we've been.
We've had pretty good costs theyre not cost fluctuation on the consistent on the call US also on the completion side.
We also have.
Three years ago, we started drilling these long laterals will snubbing units using stick pipe.
You can basically handle higher pressured wells with that then with coil tubing.
And so we've had great success in that regard also.
<unk>.
To help us out with these wells.
So really I mean, the completion side everything is just clicking along really good.
We will get some cost savings from our vendor there.
And then really on the drilling side, it's just the gains we're seeing just the.
Basically shave days off these wells.
Great. Thanks, a lot.
Yes sure good question.
Thank you one moment for our next question.
And our next question comes from the line of Paul Diamond from Citi. Your question. Please.
Thank you and good morning, thanks for taking the call.
Quick I wanted to touch base on some of the D&C costs on slide 15, just wanted to get an idea of your guys' view on how much of that shipped in shutdown and drilling is deflationary or how much should we think about that is sticky and kind of embarrassed or completions, how much should we expect that to be sticky going forward.
So going forward. This year I think we're still obviously with the activity, we're going to still see the deflation.
Occurring I mean, we still are seeing might be another 10% cost into this.
This year.
Versus last year.
I'd say more owned.
On the completion side is a little bit more.
Predictable I would say just need to get this is going to basically be lower process from everybody.
The drilling side, because the western Haynesville is going to be a big component of our program. This year. It's also going to be on the <unk> side just the.
Increased performance less days to TD.
For the cost savings along with just the.
Vendor pricing coming down.
Understood and just kind of circle back on that towards the western Haynesville.
As far as like drilling days and these operational improvements are we towards you guys. You are we towards the end of that.
That improvement trend or is this kind of just the beginning is how can we.
While we've made some pretty good improvements.
But we still got a lot of them in the pipeline.
Comment I mean, we're in the middle of some of those we're at now and we definitely see a lot more days getting cut off as well as from even where we're at today.
So I am sorry.
As far as trying to say in the middle I would say, maybe that's probably maybe.
Somewhere in there in the middle <unk>.
Probably shaved off 20 days off these things since the first couple of wells, we drilled and we still see.
That kind of potential going forward.
Got it so another potential 20 days decline in the drilling time.
Yes.
Yes, Sir.
Thanks for your time.
Thank you.
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.
First of all I'd like to thank all of you for your questions Mike.
Make us better managers.
Hopefully we've shown you that we've started.
And I think.
We've been very proactive.
Batten down the hatch to protect our balance sheet.
We were very proactive on our operations arena to release, the Frac crew in the two rigs.
The underlying denominator of everything is stellar drilling performance.
Our inventory in our core area.
That area, we operate and you look at the Western Haynesville <unk>.
Half of our footprint Corporately is in western Haynesville.
Those wells look very promising.
So.
Again.
Know that this is a stressful time.
But we do want to assure you that we're going to continue to manage this company with a steady hand.
And we want to wish you all a happy Valentine's day. So thank you for your time.
Thank you, ladies and gentlemen for your participation in today's conference. This does conclude the program you may now disconnect good day.
Yes.
Okay.
Yes.
Okay.
[music].
Okay.
Yes.
Okay.