Q4 2022 Diamondback Energy Inc Earnings Call
[music].
Okay.
Good day, and thank you for standing by and welcome to the Diamondback Energy fourth quarter 2022 earnings conference call at.
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 one on your telephone Thats Star one one.
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Please be advised that today's conference is being recorded.
I would now like to hand, the conference over to your Speaker today, Adam Lawlis VP of Investor Relations. Adam go ahead.
Thank you, Eric and good morning, and welcome to Diamondback Energy's fourth quarter 2022 conference call. During our call today, we will reference an updated investor presentation, which can be found in David likes website.
Presenting diamondback today are Travis Stice, Chairman and CEO , Keith Creel President.
President and CFO and Danny Wilson.
During this conference call. The participants may make certain forward looking statements relating to the company's financial condition results of operations plans objectives future performance and businesses.
We caution you that actual results could differ materially from those that are indicated in these forward looking statements due to a variety of factors.
Information concerning these factors can be found in the company's filings with the SEC.
Additionally, we'll make reference to non-GAAP measures reconciliations to the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.
Now I'll turn the call over to Charlie Thank you, Adam and welcome to Diamondback <unk> fourth quarter earnings call.
2022 was another great year for Diamondback.
With success successfully executed on our capital program accelerated our return of capital plan.
Generated record cash flow.
I am very proud of all that we were able to accomplish and look forward to what I believe will be another strong year for the company.
Looking back at last year, we produced over 223000 barrels of oil per day exceeding our production expectations.
This is primarily the result of our well performance, which continues to trend in the right direction as our normalized oil production in the Midland basin improved by 6% year over year, and nearly 20% when compared to 2020.
We continue to optimize our multi zone co development strategy, which we pivoted to prior to the pandemic.
Tweaking, our frac designs spacing assumptions and landing zones to maximize our returns.
On the operation side, we've also built out substantial water infrastructure, which allows us to implement some will frack completions across our position.
This type of completion is consistently more efficient than a traditional zipper frac design, because we can complete approximately 80 wells per year with just one crew.
When you add in the additional efficiencies, we're seeing from our Halliburton easily.
Our completion savings of approximately $50 a foot.
Last year was not without its challenges.
Significant inflationary pressures, particularly in the casing equipment availability and weather related downtime.
We would all our operational team did what it always does deliver best in class execution.
Our ability to hold our capital budget plan and stay within our original guidance range.
While also exceeding our production target is something you should expect from Diamondback has.
As we push to deliver differentiated results quarter after quarter.
Financially, we generated over $7 billion in EBITDA and $4 6 billion in free cash flow or nearly $26 per share both records for the company.
We made significant progress on a return of capital plan, increasing our cash return commitment in the middle of the year to return at least 75% of free cash flow to stockholders.
In total we returned 68% of our free cash flow in 2022, which equates to $3 1 billion through a combination of our base and variable dividend and share repurchase program.
Buying back nearly eight 7 million shares at an average price of $126 per share for a total of $1 1 billion. This represents 5% of our shares outstanding when we announced our program in September of 2021.
An additional 2 billion was returned to our base and variable dividend with a total dividend growth of nearly five times.
Third to 2021 in total.
Turning to let $1 31 per share.
In the fourth quarter alone, we returned over $860 million or five.
$5 65 per share with a total dividend yield of nearly 9%. This.
This included an increase to our annual base dividend of <unk> 20 centers now.
Now $3 20 per share annually or 80 cents per quarter, representing 54% year over year growth.
We also announced multiple strategic transactions in the fourth quarter that better position us for the long term.
We made two Midland basin acquisitions, Larry on Firebird, both of which are now closed and can seamlessly integrated that added over 500 high quality opportunities.
83000 net acres to our portfolio.
This additional inventory along with the associated production and cash flow.
Has solidified our size and scale in the Midland Basin, giving us a strategic advantage as we execute on our capital programs for the decades to come.
Last summer we bought in all of the outstanding units of Rattler, which gives us additional flexibility to think strategically about our existing midstream portfolio.
We now have the ability to monetize assets that trade at a higher multiple than our upstream business and use the proceeds to strengthen our balance sheet or acquire additional upstream assets. The first example of this was the sale of our 10% interest in the Gray oak crude oil pipeline to Enbridge.
We achieved a $1 75 multiple on our invested capital and use the proceeds to partially fund the cash portion of the <unk> acquisition as.
As we evaluate both our ratner operated assets and equity method investments. We've also monetize multiple noncore upstream positions.
We have now divested nearly $600 million in upstream assets since the third quarter of last year, which includes two recent deals in southeast Glasscock and ward and Winkler counties.
These assets simply cannot compete for immediate capital within our portfolio.
We have now increased our non core asset target sale from 500 million to at least 1 billion by the end of this year.
Last year, we improved our leverage ratio now below one times and also pushed the tenor of nearly 90% of our debt past five years with over 2 billion due in 2015 at an average coupon of below 5%.
We will continue to use free cash flow and proceeds from our noncore asset sales to lower our overall debt profile continually improving our financial position.
As we move into 2023, we expect to deliver relatively flat pro forma production year over year.
When you account for the 11 months of <unk> and a full year of Firebird production contribution our guidance reflects.
260000 barrels of oil a day and $2 6 billion in Capex, while running 15 rigs and for Sam will Frac crews.
In closing 2022 was an outstanding year for the company.
We generated record free cash flow and distributed nearly 70% of it to our shareholders.
And with our balance sheet.
Extended our inventory runway.
To produce one of the highest margin barrels in the industry.
Looking ahead, our business model is working and we're confident in our 2023 outlook and our ongoing ability to continue generating peer leading returns for our stockholders.
With these comments now complete operator, please open the line for questions.
Okay. Thank you, yes, we will conduct a question and answer session as a reminder.
To ask a question you will need to press star one one on your telephone and wait for your name to be announced to withdraw your question Press Star one again.
Okay. Please standby, while we compile the Q&A roster.
Okay. Our first question comes from Neal Dingmann from tourists Securities Neil Your line is open.
Good morning, and thanks for all the details Travis My first question is just on shareholder return type of Azure.
More of that I think has now been maybe even two years ago, certainly more than a year ago you mentioned.
Way back that you thought once the macro supply demand was more in balance you would consider potentially more growth I'm. Just wondering has this thinking changed based on what we know of continued investor shareholder return or other factors that continue to drive sort of the environment. We're in today.
Yes, Neil I don't think the macro conditions are dictated in any kind of production growth currently and then you still have on.
And uncertain fed action, you've got uncertainty around the China Covid demand recovery, you still got Russian barrels that we're still finding their way into the market. So it doesn't appear to me that the macro conditions have fundamentally changed and certainly the feedback and perhaps most importantly, the feedback.
We get from our shareholders.
<unk> is to continue to embrace.
Shareholder return model.
Yes, I think I'll also on top of that Neal, we're going to be growing oil production per share significantly in 2023 through two well timed acquisition and a significant amount of buybacks in 2022, so per share metrics continue to improve we continue to invest in high return projects, while not having to change our.
Activity plan on a monthly basis trying to follow the crude price. The plan is the plan in this steady state of activity has has produced good results to date and no no need to change that while it's working right now.
Good point cases.
It leads to my follow up just on capital efficiency.
When I look at by our calculation you all pumped out more free cash flow per barrel of oil than any E&P and I'm just wondering.
When you look at this driver is is that base is that driven largely on this.
Co development that you've talked about as a capital efficiency I'm. Just wondering you all just most recently seem to be hitting all the right numbers.
But I'm wondering when I look at this all important metric.
Travis Your case would consider maybe some of the drivers of that.
Yes, it's certainly not just one thing Neal it's really a combination of all of the things that we focus on.
Multiple times a day.
When it comes to executing our programs certainly well productivity enhancements add to that but that's really an output of a very difficult decision. We made in 2019 to pivot away from.
The best two zone development strategy and embrace.
The multi zone full full.
Full section development strategy, which we're seeing benefits up today.
You also hear saw frequently about our cost structure and that cost structure is made up not only the expense side, where whether it's G&A or other way, but also on the capital efficiency side, where we continue to push the envelope, particularly on the variable cost side of things.
Simply doing more with less and.
All of those things combined.
I think put us consistently.
Towards the top of the most margin efficient producer in the basin.
Great answer thanks, guys.
Thanks Neil.
Please standby for our next.
Color.
Okay. Our next question comes from Neil Mehta from Goldman Sachs. Neil Your line is open. Please go ahead.
Yes, good morning, Travis case and team.
The first question I had was around non core asset sales and you.
You did bump your target from half a billion $1 billion by year end 2023 can you give us a little bit more color around.
What are the natural strategic assets and what the market looks like.
First asset sales right now.
Yes, Neil Great question, you know I think we announced two <unk>.
E&P asset sales non core asset sales this quarter that I think fit the mold of what.
The market looks like right now and Thats.
Assets that don't compete for capital in our capital plan.
For many many years and a little bit of PDP associated with those assets, but generally a buyer that is looking to develop those assets a lot faster than than we're planning and so these two deals the buyers are going to.
Get aggressive developing these two assets right away, which.
And our capital Allocators.
It's just a good capital allocation from our perspective going into it we expected to sell more midstream assets.
Then E&P assets. So that's why we bumped the target and we still have some strategic midstream investments that are nearing.
The point, where they should be monetize gray oak I think it was a great example, we retained all of our commercial benefits of the of the transaction, we still move our barrels to the Gulf Coast, which is that from a financial perspective.
Pipeline was a great investment and it worked and we monetize it to the partners. So I would expect more and more on the midstream side. We did highlight what we have from a midstream perspective in the deck for the first time.
But we're going to be patient.
When it comes to selling assets.
Yes, that's great perspective, and then as a follow up is the oil volume guide for the full year.
Solid Q1, a little bit softer. So maybe you could just talk about the cadence of production over the course of the year and just Uh huh.
How we should be thinking about that the path for oil production in particular in 2023.
Yes, good question as well I think the plan when we acquired Firebird Firebird is producing 17000 barrels of oil a day, we guided to that asset producing 19000 barrels of oil a day for the year 2023, So clearly some some growth on that asset we're already seeing.
Youll see the majority of that benefit going into Q2 to Q4, and then on top of that obviously clothing malaria acquisition on January 31 that immediately adds.
Fixed thousand net barrels a day or sorry, subtract 6000 net barrels a day from Q1, because we didn't get to count those volumes in January So base case plan is.
As to grow steadily.
From Q1 through Q4, and we got the projects.
Back that up.
That's great.
Standby for our next question.
And our next question comes from Aaron Xyrem from J P. Morgan Securities. Aaron Your line is open. Please go ahead.
Yes, good morning, gentlemen.
You mentioned in your prepared remarks, how the company is really optimize its multi zone co development strategy over the last couple of two or three years I was wondering if you could provide a little bit more.
Detail around kind of what Youre doing today I know on slide 16, you gave us a lot of great detail on the amount of.
Net lateral footage by zone, but I wonder I understand what you're doing to maybe mitigate some of the issues. We're seeing from the industry in terms of.
<unk> parent child interference and impacts from delayed targets.
And just your thoughts on sustaining.
The level of well productivity gains that you generated last year into the future.
Yes, good question Arun.
In 2018, and early 2019 were really studying this co development strategy intently and.
The significant observation that we've made from our analysis was that.
Essentially all of these zones talk to each other.
And if they talk to each other which makes you actually have pressure communications during the fracking operations, which subsequently also managed as you kind of share there.
Our reserves as a individual wells produced that if you don't get them.
<unk> initial.
The initial development that when you go back in later Youll find those zones have experienced some depletion and that the depletion degrades the efficiency of your stimulated rock volume, which ultimately changes that production profile.
And so in order to in order to address that.
We examined our.
Spacing assumptions, both side to side and top to bottom and made adjustments to try to minimize those.
Frac pressure interference.
Spread some zones out further spread some zones above and below further but essentially went into a section.
Half a section that time was our development strategy and completed all the wells at one time and then brought them all on at one time.
That was a painful decision that gives us a lot easier in fact, I've been I've said it before that.
Ill fated criticism from drilling the very best zone, but we found out that that actually wasn't derived development strategy and we took some time for that in 2019, but as you can see we put some details on our <unk>.
On slide 16, as you alluded to.
In the Midland Basin, well results are equivalent to what we're seeing in 2017, so very proud of the technical team and their diligence to try to crack a very difficult problem and then the courage to stay with that decision.
Through periods, when we requested about that development strategy. So I hope that answers your question or.
That's helpful.
And maybe just a follow up.
I wanted to get.
Some thoughts on some of the initial well results from Firebird.
I believe in that transaction.
You guys under wrote just over 350.
Gross locations.
But you highlighted some potential upside based on co develop opportunities I was wondering.
Thoughts on maybe some of the initial results in the Wolfcamp, a which I don't think that was part of your original.
Yes.
Assessment of locations that you paid for it.
Yes, great Great question Arun.
I think firebird at the end of the day is the quintessential Diamondback deal, where we know the space and like the back of our hand and had been communicating with the firebird team as they tested their position further west in the basin and others have in the past.
And we follow the results closely and posted a couple of recent results that I think confirms confirm a couple of things, but also give us some help on upside in the central prospect and Theres a couple wells than accretion may vary on the far west side. This was probably the farthest west test to date.
Not an area, we underwrote and you have a very good wolfcamp a result.
Far West and then in the southern portion of the position you have the Sally sorry, you have the.
Four corners, two wells Wolfcamp, a and the lower sprayberry, and we will underwrite lower sprayberry with Wolfcamp, a upside across the central prospect and it's looking more like you can have lower sprayberry with Wolfcamp a co development across that position. So early days, yet but definitely a.
Positive signs from the.
The fiber deal and our technical teams work in and getting that deal across the finish line.
Thanks, a lot gentlemen.
Thank you Lynn.
Then by for our next caller.
Yes.
Our next question comes from David <unk> from Cowen David Your line is open. Please go ahead.
Okay.
Yes.
Yes, and good morning.
My first question was really.
It could be the first question is really as a follow up on her around.
Questions.
And as you saw.
<unk>.
We've seen a somatic of your peers testing additional zones. This year, maybe can you give us a sense of that 330 to 350 wells Youre doing this year.
Okay.
Right.
Due to the then current inventory.
Yes, David you were breaking up a little bit there so I'm going to try to repeat what I thought you said, which is what other zones are we testing outside of our traditional development zones across the basin is that is that correct.
That's correct sorry about that.
Yeah no problem. So generally the majority of our capital is going to be allocated to the best zones co development.
Big development this year and kind of the sale of Robinson Ranch isn't the central Martin County area. So Thats, where the majority of capital is getting deployed certainly there are deeper tests going on throughout the basin, we have our limelight prospect.
Which covers that.
Those deeper zones, a tariff structure on the <unk>.
Eastern side of the Midland Basin.
We're going to be developing some woodford and Barnett.
Generally.
Probably going to drill three or four wells. There. This year I don't think it's going to be.
10, 15, plus but.
<unk> generally promising results from the deeper zones across the basin and the benefit of.
Our position is that we hold a lot of those deeper zones and we have a significantly large mineral company that owns mineral rights to the center of the Earth forever and all of those zones. So if those don't start getting leased up it's a great benefit to Diamondback Viper relationship.
I appreciate that and then.
Okay.
To the question.
Our third year now of being in relatively a maintenance mode or low growth mode have you seen noticeable differences year over year benefits from perhaps improved base declines.
And how does.
Decline.
Right.
On 'twenty, two or 'twenty one.
Yes, I didn't break it up a little bit, but talking about base decline I think the base business. Obviously the base decline continued to decrease since being in maintenance mode. From 2020, we did add two acquisitions and Firebird and Mario where they had built a lot of rate vary.
Quickly.
Those two deals have a higher decline rate than the base business, but I think we can manage that in our guidance and also manage that.
And how we're going to complete wells across the pro forma position. So it's certainly base declines coming down, but I really think the best benefit of this.
Lower lower growth environment is that we can grow per share metrics, while not having to change our development plan with every $10 move in oil price right.
Our plan is the plan right now shale has certainly become longer cycle with these bigger pads and so we're not having to put a stress on the ops teams to move pads around if oil moves five or $10 a barrel.
Thanks for the answers guys I'm sorry for the receptor.
No problem.
Okay standby for our next caller.
Our next question comes from the line of Janine way from Barclays Jeanine. Your when your line is open. Please go ahead.
Hi, good morning, everyone. Thanks for taking our questions.
Hello, gentlemen, good morning.
Our first question, maybe just following up on David's question, there on capital efficiency.
Capital efficiency with Great Q4, and you turned to sales about 55 net wells in the oil and your guidance.
I'd like 73 net wells so that's great.
For 2023, the number of wells to sales looks a little bit higher than that.
We would have expected if we just.
The amount of wells you did in 'twenty, two and then we added malaria on the Firebird Gol.
So are we looking at that math correctly for 2023 and any color you would have would be helpful.
The divestitures, we still think the 'twenty three outlook looks conservative.
You mean that the priority is really to beat on Capex in that volume.
Yes, Judy.
A couple of things like Q4 was going to be a great quarter going into December we had obviously, we all have a winter storm here.
Diamondback did not announce a winter storm impact, but certainly the winter storm did impact our production so going into the last 10 days of the quarter. We felt very good about about where we sat and still hit guidance and therefore from a pop perspective.
Move some wells from Q4 into Q1 to get a head start on on POS it's not a huge capital impact, but it is a number where we guide to first production. So there's a good amount of Pops in Q1 2023, because we were ahead of it.
I had a schedule in Q4 and feeling good about where we started Q1 this year.
Okay, great. Thank you and then maybe just going back to return of capital.
Looking at just the buyback plus a variable amount for this quarter. The buyback was about 44% between the two of those is that rough split kind of indicative of what we should be expecting in the future or is it really just more opportunistic every quarter or just really just checking in and if there is any change in how youre viewing the variable part.
The buyback. Thank you, yes, yes no.
No change in in really the variable is the output of how many shares we didnt buyback any particular quarter and the buyback is still going to be very opportunistic and I think you.
I think now that we've kind of gone through this for four or five quarters, you can see that we step in and buy back when things are weaker there's still been a lot of volatility in the space, we're going through a period of that volatility right now.
So you look back at a quarter like Q4 bought back less shares in October and November , but you hit the buyback very hard in December and I think you can expect us to keep doing that and then having the variable.
The output of what base dividend plus buyback doesn't get through in a particular quarter.
Alright, Thanks, gentlemen.
Thank you Jeanine and thanks to me.
Eric are you there.
Next question Eric.
Pardon me Derrick Whitfield from Stifel has our next question Derek. Please go ahead. Your line is open.
Good morning, all and congrats on a strong year end.
Thank you Dara Thanks Derek.
Building on an earlier question I wanted to focus on your well productivity aside from the development sequencing impacts are there 1% to two primary drivers that would explain the improvement you observed in well performance year over year.
I think the biggest the biggest benefit Derek is not only.
The assets, we acquired from QEP and guide on I think.
That deal was done at a tough time.
Hit exactly what Youre looking for in a transaction that we allocated more capital to those assets than we would have allocated to the business.
Prior to the deals so we're seeing a little benefit there.
Assets are also in areas, where you have three or four or even five zone development and so we're having massive.
<unk> pads come on in high return areas with a little bit of a benefit on the Viper side with high mineral interest across that position so space as Travis mentioned earlier in the call.
Taking a closer look at spacing learning from other operators in the basin, what to do and what not to do and implementing that very quickly into our plan is paying dividends.
Perfect.
Follow up I wanted to focus on your 2023 capital program.
We were to assume a flat commodity price environment, where are your greatest headwind and tailwind from a service cost perspective.
The biggest headwind over the last six quarters has been has been casing costs now we can certainly see.
Around the corner that maybe we're seeing some softening there.
I'm not going to count on it until we see it but casing has moved up from let's call it 40 or $50 a foot to $110 a foot if 20% of our Midland basin, well costs now and that's a significant headwind over the last six quarters I think that headwind is going to ease.
That's a little bit out of our control, but the things that we can control are the efficiencies gained from simultaneous operations.
We will probably have four simultaneous crews running by Q2 of this year, which is highly efficient saved about $30 a foot versus conventional crews and on top of that two of those crews are going to be the halliburton each fleet Zeus crews and those.
Use less fuel, but also run on on cheap cheap Baja gas right now and so that saved another 15 or $20 a foot. So we're doing what we can do to cut costs and keep costs as well as possible.
Inflationary environment.
Perfect well done guys. Thanks for your time.
Thanks, Derek Thanks Derek.
And our next question.
Our next question comes from Roger read from Wells Fargo Securities. Roger Your line is open. Please go ahead.
Yes. Thank you good morning.
Good morning, Roger Good morning, Roger.
I'd, just like maybe dive into the the gas takeaway question and how how your I understand how youre positioned not to not to have basis risk for the most part but.
What are you looking at in terms of flow assurance this year and to the extent you can say next year.
Yes. Good question, Roger I don't think flow assurance is going to be an issue for us.
But we are exposed to the wall Hot price based on how the contracts are written through the history of Diamondback were been very acquisitive and when we acquire things that comes with contracts and so all of those contracts.
Private equity backed or some of the.
Public gas gatherers and processors in the base and so I feel really good about our our flow assurance and our contracts. The issue is going to be price and while we've seen in the basin is some tightness coming out of the basin on Wahoo.
When pipeline would have gone up or gone down over the last six months, but really there's a lot of processing capacity. That's now coming on in the early part of 2023, particularly with two of our Midland Basin gatherers and processors and I think that generally is going to move the issue further downstream. So it's gonna be a tie.
Tight gas market in the Permian.
Henry hub prices, obviously arent, helping as well, but we feel good that the gas will move in and we're well hedged financially to protect from that downside.
Okay I appreciate that.
<unk>.
The other question I wanted to follow up on.
I'm just looking.
Right page.
Yes page 23 on the hedge summary.
Yes.
Any thoughts on.
If we're looking at where Q1 is hedged Q2 really kind of similar.
What you'd want to do ultimately for the back half of the year as we draw closer and it becomes more financially.
Reasonable to do that or are you at this point more comfortable going a little less hedged.
Just given the overall.
The structure of the balance sheet, presumably with these.
Dispositions coming in a little more cash coming in.
Great Great question Roger.
We don't believe in no hedges I think primarily because our our balance sheet is a hedge our cost structure as a hedge but we consider our base dividend debt right. Our base dividends now three to $3.20 a share it's almost $550 million of the outflows a year, we think it's well protected.
Today at $40 a barrel but.
We don't want to put that in harm's way. So we buy puts as fire insurance and we basically use the front.
<unk> to extend duration three or four quarters out we try to be 50% to 60% hedged going into a particular quarter on oil down to zero percent hedge for five quarters out so.
We continue to expect us to do that and your observations are.
100% correct that in the back half of the year will grow as as we go through the year.
Okay, Great I appreciate it thanks.
Thank you.
Thus, bringing our next caller up.
Okay. Our next question comes from Jeffrey <unk> from Perella Weinberg partners.
Jeffrey Your line is open. Please go ahead.
Hey, good morning, everyone. I appreciate you all taking my questions.
Good morning, Jeff Hey, Jeff.
Just a couple from me follow ups on the service cost environment and Diamondback read through specifically I guess first I appreciate the comments on what you're watching for how diamondback is positioned to really maximize with chocolate control, but I wonder if you could speak a little more broadly to what youre expecting in terms of year over year changes on inflation I think.
I'll speak to 15% as the base case and really more so how that compares to what youre seeing on a leading edge basis, and then I guess last on this how we should think about the bounds of the Capex guide for this year in that context, and then the second part of my question is just looking for a snapshot of our.
Well cost today on a per foot basis are tracking relative to the full year guide range and also relative to the mid November snapshot that we got with last quarter's earnings.
All good questions, Jeff I think generally.
We guided to this year being around 15% year over year, well costs sub 10% from what we highlighted in November .
Say generally those numbers still fit.
Today, I would say, we're probably in the upper half of our well cost guidance for both.
Midland and Delaware today, but generally there are some things coming our way outside of service cost deflation and Thats.
Halliburton is easily.
Moving to four sawmill fracs versus last year, we ran three in a spot crew so that last summer frac add some efficiency.
I kind of put the budget two ways. This year I think if we see deflation, we're going to be closer to the lower half of our guide and if we stay flat would be the midpoint to the higher end.
But I think generally the anecdotes are coming in that.
Some things are heading our way from a service cost perspective, and unlike last year not everything not every line item will go up in the ASC.
Perfect sounds like a better outlook. Thank you.
Thanks, Jeff Thanks Chip.
Standby wide connect the next caller.
And our next question comes from Scott Gruber from Citigroup. Your line is open. Please go ahead.
Yes, good morning, I wanted to circle back on the completion efficiency comments.
<unk>, obviously brings a very good fuel savings given the gas diesel spread here and obviously, we are especially the ESG benefits but.
But do you think E frac additions will be additive to the improvement in cycle times and go above and beyond what you're seeing from simultaneous.
Yes, I think generally Scott they complete a similar amount of lateral feet.
Simultaneously crews.
As we're seeing early time, but on top of that the fleets on a fuel efficiency basis, not just the type of fuel that the efficiency of the fuel used is.
He had been a positive surprise I think the last thing I would add is that it does it.
It does operate on a much smaller footprint. So maybe your moves or are smaller, but you do have some electrical infrastructure associated with those those those fleets and Danny you want to add anything on that yes, I think.
We've already been running the first creative for about six months and.
We've been really impressed with the performance thus far.
Outperformed our other fleets kind of on the margin but.
Not seeing measurable we do believe that over over time Youll see that.
That gap widen and performance.
Really believe that the maintenance.
Acquired around the equally and equipment will be substantially less so.
We're excited to learn through that with Halliburton.
And you know recognize some added efficiencies on profit just fuel savings as we go forward.
Got it and.
Service costs.
Start to slip in the Permian with Haynesville rigs and Frac crews coming out Margaret over.
How quickly do you think.
That'll hit your D&C costs.
If that starts to kind of pivot.
Here in the near future isn't an ability for you to realize that in the second half or are we really talking about 2024 benefit just given your current contracts in place at this juncture.
Yes, I mean, we don't really have any.
Any long term.
Contracts in place.
We kind of have.
Sorter cycle pricing agreements.
I think generally we're exposed to market pricing.
Cross the board and.
You can certainly have some protections in place on some of our consumables, but if we start seeing.
The market soften which which.
We feel like is a pretty good likelihood with with where we see gas prices today that should trickle down into the.
The oil basins.
Particularly on the drilling services side of things first in.
We certainly not seen a lot of upward pressure on pricing in the first part of this year, it's been pretty pretty quiet.
And hopefully we'll start seeing some some help on the inflation front here through the second and third quarter.
Got it.
Great that color. Thank you.
Standby for one moment.
Our next question comes from Kevin Mccurdy from Pickering Energy Partners. Kevin. Your line is open. Please go ahead.
Thanks.
Congratulations on the great free cash flow quarter, it looks like cash taxes came in well under our expectations and the guidance for 2023 cash taxes was below our model.
I Wonder if you can talk about what is driving the cash taxes, lower and any benefits you may be receiving from acquisitions.
Yes. Good question, Kevin Yes, the biggest benefit we did receive in the fourth quarter obviously.
Alrighty prices came down quarter over quarter Q3 to Q4, so that was.
Surprised to the positive on cash taxes, I guess that hurts the overall, but the biggest deferral. We got was when we closed the firebird deal.
<unk> was about $100 million of midstream assets and some other fixed assets that we are able to depreciate right away and so that allowed us to defer more taxes into 2023.
As we've modeled 2023.
We still have about $1 billion of NOL that will be exhausted. This year on top of that also clothing.
The fire or the <unk> transaction, which added some.
Midstream and fixed assets as well. So generally this is kind of our last year before being a full cash taxpayer.
But two well find deals.
Push out a little more cash.
It's not the reason why we do the deals, but it's a nice tangential benefit.
Great that's nice to see that cash going directly to the shareholders as well. Thank you for my question.
Thanks, Kevin Thanks, Kevin.
Standby.
Our next question comes from Leo Mariani from Roth and km.
Line is open. Please go ahead.
Yeah, Hi, guys I was hoping you could talk about LOE trends just looking at the guide here.
Three enhance our expecting <unk> to come up a little bit kind of versus where it was in 2010, I mean, just a little color around what youre seeing there.
Yes, I think.
Just a couple things that are that are impacting Natalie first week.
Fairly close to the power market.
And we rode through the back half of last year fairly unhedged through the <unk>.
We're up in gas prices and that's that really impacted our real time power pricing and you're seeing kind of real time power pricing kind of stay a little elevated through.
The first part of 2023 here and so.
Trying to trying to trying to guess, where we're going to land with with respect to power and.
We have an opportunity to get edge to protect ourselves but.
It's adding about a dime and then you've got another.
Impact from the Firebird acquisition with.
About 900 vertical wells, which adds another dimer too to our consolidated <unk>. So between the two things youre looking at about a quarter and we.
We're probably running in the lower end of the guide today and if we see some things come our way, we think we could potentially be under the guide that we're not baking that into our guidance.
Okay I appreciate that and then just on M&A, obviously, you guys were.
Helpful. In terms of talking about some of these noncore asset sales, but you did mention in your prepared comments that perhaps some of those proceeds could go to bolt ons out there in the space I was hoping you guys could just give us a little color in terms of what Youre seeing are there bolt ons available that are kind of in and around your asset base.
How would you kind of characterize the market now do you think that generally speaking expectations from sellers are reasonable. These days just trying to get a sense of whether or not there's a decent chance my pick something up here in 'twenty three.
Yes, I don't know if sellers ever reasonable Leo but generally I do think the two larger transactions did happen because <unk> cost structure was differential in the second half of the year and going into 2023, right. We're drilling wells to three $4 million cheaper than the Midland basin than then.
Than peers and that is when you underwrite pods that drives value to the sort of the good guys. Even if youre not running strip oil pricing. So I think I think generally that's what's happened.
Theres less and less large opportunities like the two that we announced last fall. So that's relatively quiet at the moment, but some of the smaller things that tend to trend with.
The large deals like the blocking and tackling the couple of other deals that Firebird and Maria we're working on.
When they sold so that's the kind of stuff that we're focused on right now.
Okay. Thanks.
Thank you Leah.
Yeah.
Hi.
Bringing our next caller on.
Okay. Our next question comes from Paul Cheng from Scotiabank. Paul Your line is open. Please go ahead. Thank you good morning, guys.
Good morning.
Okay.
Your presentation, you show a number of the.
Appalachia ownership.
That's in the pipeline and gas processing I'm, just curious if any of those that we've kind of stated targets.
The important point.
Uh huh.
Michelle.
On that I mean, just trying to see that I mean, what does the annual plan.
That's.
Important to you.
Good question.
When when you're looking at your inventory back at all.
For those you can see that over 10000 feet.
Thank you our velocity they call it 55 countries.
Just wanted to see if we can.
Drilling may have been more into that and a one.
Well you can actually scale, maybe thinking miles and what does that does the opportunity for Chinese swap that you think you may be able to improve on that thank you.
Great. Thank you Paul I'll take the first one on the JV and we did highlight all these JV I think generally.
All sat at our rent rattler entity.
Before consolidating it.
Generally from a financial perspective, I think they're all.
Good investments that eventually will be monetized at higher values than what we paid.
We put in.
But the strategy behind why we did these things is that we got commercial agreements and benefits locked in with the financial piece. So whether it's like the gray oak pipeline rate. We gave 100000 barrels a day of space on the pipeline, that's not changing even though we sold our equity interest in the pipe on the gas.
Processing side, you know, we invested 20% into W. T G.
We and our partners decided to build to 200 million a day.
<unk> plans to immediately after closing the deal and that is alleviating a lot of the gas flaring in gas processing issues in the northern Midland Basin. So we tried to drive value through molecules committed to these investments, but generally at some point it makes sense to monetize them.
On the inventory side, we try to drill 15000 feet wherever we can.
I think most of our land in the in the Midland Basin is pretty.
Pretty locked up from a lateral length perspective, I think generally if we had four sections north to south of you drill to 10000 foot laterals.
<unk> five sections, north to South, which is which is where we would drill two sets of 12500 foot laterals and if we had three sections, we would drill 15000 foot laterals over $2 7500 foot laterals. So when we underwrote the firebird deal with a lot of 15000 footers because that is a big contiguous block and on the other side.
<unk> pretty landmark.
In the center of Martin County, with a lot of competitors around so we kind of had to live with the <unk>.
Lateral lengths as they represented.
Great. Thank you.
Thanks, Paul.
Sure.
If you have a question. Please press star one on your telephone.
I will see bigger hand is raised.
Our next question.
Standby.
Our next question comes from Doug Leggate from Bank of America, Doug. Your line is open. Please go ahead.
Thanks, guys. So obviously I think there was a case I think.
You did touch on the M&A line of sight I Wonder if I could just dig into that little bit more particularly on.
The remaining asset sales and one of those our midstream weighted.
Do you see additional opportunities in front of you the our midstream group.
And if so are you basically were looking to pair back your midstream exposure.
Guess I'm really trying to understand how that impacts the cash will be in <unk> business.
Yes. Good question, Doug I would say generally we were.
Were a surprise.
The amount of E&P assets, we sold relative to initial expectations of $500 million of noncore asset sales.
Because we raised that to $1 billion at 750 to date.
Logical that most of those.
Most of the rest of the $250 million or more come from noncore asset sales comes from midstream assets.
I will say if there is going to be harder for us to sell operated midstream assets versus non op midstream assets like the JV is that we highlighted in the back of our deck.
Like you inferred operated midstream assets do have an impact on <unk> financials, whereas non operated assets. You have do you have a cash flow impact from less distributions from those assets, but not as meaningful to the parent co. So I think its logical that more non op stuff is.
It's top of mind, but for the right value.
Some operated stuff what would be on the table just.
We'd be cognizant of what that would do to our operating metrics.
Okay.
I guess, we'll watch and see how the raise is obviously a positive so thanks for the clarification.
Guys I apologize for being predictable and I'm going to put myself in the cross hairs, a little bit and go back to the cash tax question because it's.
We also had a bit of a lift to be perfectly honest.
It's about 50% bigger than the P&L tax on what we are trying to figure out as well.
M T kicks in which I guess would be the end of this year, because you have about $1 billion, but earnings presumably for three consecutive years.
Soon the $45 million of deferred tax that's about sort of your free cash flow.
What do you think the normalized level of the tax would be if the conditions were the same is not an easy question to answer.
Yes, I mean, I guess the answer would be.
We're going to get through all of our NOL.
NOL in 2023, so that'll be exhausted so it will be.
A full cash taxpayer, although as you mentioned, we will be able to defer some with respect to intangible drilling costs and.
The capex spend of the business, so I guess it'll be dependent upon where you know.
Obviously, where commodity prices are in 2024 and second to that where Capex is I think we're obviously in a world where we're going to be spending continue to spend less and we make so it's logical that there will be a tax burden.
There's too many variables right now to predict 2024.
Okay, I know, it's a tough one to answer thanks Hans.
Thanks, Doug.
Okay with no further questions I would like to hand, it back to Travis Stice, Chairman and CEO for closing remarks Travis.
Thank you again to everyone for participating in today's call. If you have any questions. Please contact us using the information provided.
Keith.
Okay.
Okay. That's it for today's conference. This does conclude the program you may now disconnect. Thank you.
The conference will begin shortly to raise and lower Johan.
During Q&A you can dial star one one.
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