Q1 2021 CNX Resources Corp Earnings Call
Good day and welcome to the CN next resources first quarter 2021 earnings Conference call. All participants will be in a listen only mode should you need assistance. Please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions to ask a question. You May Press Star then one please debt does this event is being written.
I would now like to turn the conference over to Tyler Lewis Vice President of Investor Relations. Please go ahead.
Thank you and good morning to everybody welcome to <unk> first quarter conference call. We have in the room today, Nick Delius, our president and CEO, Don Rush, our Chief Financial Officer, Chad Griffith, Our Chief operating officer, and Yummy I can't keep day, our Chief Excellence Officer.
Today, we will be discussing our first quarter results. This morning, we posted an updated slide presentation to our website also detailed first quarter earnings release data such as quarterly E&P data financial statements and non-GAAP reconciliations are posted to our website and a document titled one Q2 thousand 21.
Earnings results and supplemental information on <unk> resources.
As a reminder, any forward looking statements, we make or comments about future expectations are subject to business risks, which we've laid out for you on our press release today as well as on our previous Securities and Exchange Commission filings.
We will begin our call today with prepared remarks by Nick followed by Chad Dawn and then Yummy and then we will open the call up for Q&A with that let me turn the call over to you Nick.
Thanks, Tyler and good morning, everybody and then a focus on my comments on the first two slides of the debt that we posted this morning before turning it over to Chad Griffith, our CFO to discuss our hedging strategy and gas markets and then moving over to Don Rush, Our CFO talk about the financials and then I'll wrap things up to talk about.
Some thoughts on ESG that we've got.
Starting now on slide two there's one main theme that I think is important to highlight and the theme there is steady execution.
First quarter was another example of steady execution and it's illustrated by us generating $101 million on free cash flow. This is the fifth consecutive quarter.
That the company generated significant free cash flow are similar to last quarter, we use some of that free cash flow to pay down debt that helps build further liquidity and we use some of the free cash flow to buyback our shares on your open market at attractive pricing. So for the quarter, we repurchased one 5 million shares at an average price of $12.26 per share.
On a total cost of $18 million, we still have ample capacity of around $240 million under our existing stock repurchase program.
As a reminder, that's not subject to an expiration date.
Also in the quarter, we upped our free cash flow guidance by $25 million to $450 million, that's $2.04 per share compared to the previous guidance of $1 93 per share our steady performance drives our confidence in continuing to execute upon our seven year free cash flow plan and we continue to expect will generate over 3 billion.
Over those seven years again this is done by steady execution, each and every day. Our long term plan is largely day rest through our hedging program that supports a simple or operational program. It consists of one rig and one frac crew.
Worked hard to get the company to where we are today on our focus is going to remain on successfully executing that plan.
I want to jump over now to slide three this is a slide that we showed for the past few quarters now, but I think that it's a really powerful on a competition or investor capital is not so much among just our appalachian peers, but more so across the broader market.
As you can see by three of the main financial metrics that we track C. N X screens incredibly well across various metrics in indices. We believe that these things matter most to generalist investors along with what is becoming much simpler differentiated story.
<unk> is a differentiated company due to the structural cost advantage, we enjoy compared to our peers, mainly because we own our midstream infrastructure. In this mode provides us with superior margins that drive significant free cash flow, which in turn puts us in a unique position to flexibly allocate capital across the full spectrum of shareholder value creation opportunity.
East.
While our near term focus is to continue to reduce debt and opportunistically acquire shares we continually evaluate all are all on alternatives that we've got.
So last in that regard with respect to the often asked about potential M&A activity. Our view remains consistent from last time, we spoke our two key screening metrics or the ability to deliver long term free cash flow per share accretion and having good risk adjusted returns the strength of our company affords us the ability to be patient on this front to ensure.
That we avoid M&A missteps too often permanently can destroy shareholder value with that now I'm going to turn things over to Chad.
Thanks, Nick and good morning, everyone I'm going to start on slide four which highlights some of the key metrics that makes <unk>, an incredibly attractive investments day, particularly relative to our peers from.
It begins on the upper right quadrant, where we illustrate our peer leading production cash flow cash costs.
Our Q1 result of 66 is up roughly five quarter over quarter for stroke, where we're still more than 11 cents better than our next closest competitor.
It's also worth noting that <unk> <unk> increase was driven predominantly dominantly by some reworking of our ft book.
Which allowed us to eliminate some unused ft and exchanges for some F. T that is better matched up with our production locations.
As Don will go into more details momentarily, our low production cash costs allow us to generate more operating cash flow per Mcf P. At a given gas price relative to our peers.
And this operating margin creates this operating margin advantage creates many other advantages from CNS.
First we will generate more EBITDA per Mcf P, which means we need less daily production to achieve the same level of EBITDA compared to our peers.
This allows us to maintain that level of EBITDA with less maintenance drilling, thereby consuming fewer of our acres each year.
The operating margin advantage also enhances each wells return on capital, which means a greater subset of our net acres are in the money. So.
So fewer wells each year from a broader amount of net acres into will be able to sustain this formula for decades to come.
By the way the lower number of new wells required to maintain our EBITDA means that less of that EBITDA is consumed by maintenance capital expenditures.
That is how we generate on average $500 million per year of free cash flow over the next six years at strip pricing.
Wrapping up this slide you can see that we continue to trade at very attractive free cash flow yield on our equity, while continuing to pay down debt and returning capital to shareholders.
Slide five is another illustration of our cost structure. When you look at it on a fully burdened basis.
That means that this cost illustration includes every cash costs that exist in our business. We expect costs to continue to improve primarily driven by a reduction in the other expense bucket, which consists primarily of interest coming down and additional unused ft rolling off.
We are expecting around 10 million of unused firm transportation to roll off in 2021 a modest amount next year in 2022, and then another $20 million rolling off across through 2023 through 2025.
These are simply contractual agreements that are expiring.
So with these changes and assuming all future free cash flow goes towards debt repayments.
We would expect fully burdened cost to decrease to around 90 cents per Mcf P. And then lower in years beyond 2021.
Before handing it over to Don I wanted to spend a couple of minutes on our operations the gas markets and provide a hedge book update.
During the quarter, we turned in line five Marcellus wells when we're on the process of drilling out another 13 that will be turned in line within the next two weeks.
It was 18 wells had an average lateral length of just over 13000 feet and had an average all in cost of less than $650 per foot per lateral foot.
Also during the quarter, we brought on line two southwest P. A Utica wells the majors will 12 walls P.
Deep Utica costs have continued to come down with the oil linked capital cost for these two wells averaging $1420 per lateral foot.
Production from these wells are being managed as part of our blending program, but we're very encouraged by the data we're seeing.
As we regularly discussed we only have four additional swap of Utica wells on a long term plan through 2026.
But based on what we're seeing so far on major hold 12, we're excited about the deep Utica potential as either a growth driver if gas prices improve.
Or is it a continuation of our business plan for years into the future.
As for our CPA Utica region. As a reminder, we continue to expect about a pad a year through the end of the 2026 plan.
This continues to be an area that we are very excited about.
Shifting to the gas markets, we saw weakening of the near term Nymex and weakening through the curve has been based on markets.
As a gas producer, we're always rooting for stronger prices.
Unfortunately, our cost structure and hedge book make higher prices of luxury Christy on X instead of a necessity as it is for many of our peers.
The way we see it there are four fundamental drivers of gas price that need to be in our favor to actually see higher gas prices.
One moderate production levels to lower storage levels, three higher weather related demand for sustained levels of LNG export.
With all four hit expect gas prices to search.
But despite our optimism and others dire need.
Coming less like we each year that all four of those factors line up in favor of strong gas prices.
As an example, just last year, everyone was expecting all four factors to line up in 2020 one on the forward curve surged.
But a mild winter lack a strong winter storage straw and a growing drilling completion activity have weighed on 2021 price.
The difficulty in having all four factors lineup of favorite strong gas price is why we will continue to focus on being put on low cost producer and protecting our revenue line through our programmatic hedging program. That's why we do not rely on bulk commodity cases to make projections or investment.
Instead, our free cash flow projections and investment decisions are based on the forward strip.
Speaking of our hedging program. During Q1, we added 136 Bcf of Nymex hedges 15.5 Bcf of index hedges and 61, three bcf of basis hedges.
For 2020. One we are now approximately 94% hedged on gas based on the midpoint of our guidance range and after backing out 6% for liquids.
And that 94% include both Nymex and basis hedges before we cover volumes, which are hedged at 248 per Mcf.
What is the true realized price of oil that we will receive in the year.
We are also now fully hedged on in basin basis through 2024.
We will continue to programmatically hedge our volumes before we spend capital locking in significant economics, which are supported by our best in class cost advantage.
That I'm going to turn it over to Don to review, our financials and guidance.
Chad and good morning, everyone.
I'm going to start on slide six which highlights our steady execution. The Nic touched on in his opening remarks, Q1 was the fifth consecutive quarter of generating significant free cash flow and consistent execution of our plan.
Our confidence in future execution supports a $25 million increase in our 2021 free cash flow guidance and our continued expectation to generate over $3 billion across our long term plan.
Slide seven is a new slide.
Highlights our superior conversion of production volumes and the free cash flow.
The top chart highlights it's the Nx is able to convert production volumes and EBITDA more efficiently than our peers.
As a result of our low cost structure generating higher margins.
Bottom chart further highlights the superior conversion cycle through a reinvestment rate metric, which is simply capital divided by operating cash flow.
As you can see.
<unk> has an incredibly low reinvestment rates, which supports our expectation to generate average annual free cash flow of $500 million across our long term plan.
Our profitability profile allows us to generate an outsized free cash flow per M. C. F P of gas and per dollar of capital spending.
Also this low reinvestment rate demonstrates the company's commitment to generating cash to use towards investor friendly purposes, which include balance sheet enhancement and returning capital to shareholders.
Slide eight highlights our balance sheet strength.
Have no bond maturities due until 2026.
So we have a substantial runway ahead of us that provide significant flexibility.
In the quarter, we reduced net debt by approximately $70 million and after the close of the quarter, we completed our simple semiannual bank Redetermination process.
Reaffirm our existing borrowing base lastly, as you can see on the slide our public debt continues to trade in the 4% to 5% range.
Now, let's touch on guidance that is highlighted on slide nine.
There are a couple of updates on this slide the first is the pricing update which is simply a mark to market on what Nymex and basis are doing for Cal 2021 as of April seven compared to our last update which was which was as of January seven 2021.
We also increased our NGL realization expectations by $5 per barrel.
As a result of the increase in expected NGL realizations as we have already highlighted we are increasing free cash flow for the year by $25 million.
Lastly, there are a few other guidance related items to highlight that are not captured on this slide that I would like to address advance of questions. We expect production volumes to be generally consistent each quarter throughout the rest of the year with a very slight decrease expected in the second quarter.
As for capital cadence, we expect capital to have a bit more variation.
Specifically, we expect our first half capital to be more than our second half capital. So Q2 should be near Q1, and Q3 and Q4 a bit less.
But as we have said previously quarterly Capex cut offs are difficult to predict since a pad going a bit faster or a bit slower can change the period numbers materially without changing our long term plan and forecast at all.
That I will turn it over to Jeremy.
Thanks, Dawn and good morning, everyone.
I mean, it came of age of Chief banking officer here at Siena.
A few of you may be wondering what exactly this rolling.
The short answer is I oversee and manage all operational and corporate support function within the company.
The longer answer is what I want to speak about in more details a day.
Briefly mentioned in his opening remarks last quarter, we are the leader in tangible impactful ESG performance in our space. We've been focused on the underlying tenants of ESG on its benefit with generation. This isn't a fad or a means we only talk about dependent to certain interests for short term, Matt that's not leader.
Instead, the concept was part of our fabric long before the current management team joined the company and it will be part of our fabric long after the call.
With that backdrop, let's talk for a minute, where we have been and where we're heading on this front our philosophy. When it comes to ESG is simple and can really be summed up in three words tangible impactful low we've been the first moving across both across the board and I just want to highlight a few of our significant accomplishments.
Over the years.
We proactively reduced scope, one and two C O two emissions over 90% since 2011, something that few if any of any public company and claim to.
We werent be early adopters and innovators of commercial scale Coalbed methane capture in the 19 eighties. This resulted in historical mitigation of cumulatively over 700 Bcf P. Bcf of methane emission that would've otherwise been invented into the atmosphere.
Annually, we captured nearly as much methane from this operation on the nation's largest waste management company does from Atlanta landfill.
That ingenuity and leadership on a key tenant of ESG as what ultimate we bought this company you see today.
Three we weren't the first to fully deploy an all electric.
Frac spread in the Appalachian Basin. This improved our emission footprint increase our efficiency and support our best in class operational cost performance elimination of diesel fuel in these operation is equivalent to taking 23000 passenger vehicles off the road for years.
We recycled 98% of produced fluid in our cooperation this prevent on necessary water withdrawal and eliminate the need for disposal.
Our unique pipeline network decreases the need for water trucking, which has the dual benefit of reducing community impact of trucking, while reducing overall air quality emissions.
These achievements are important and impactful, but ESG is not just about proven track record to us. It's about what we are doing now and how we will continue to push the envelope grew tangible impactful and local accomplishment.
Committing to targets or goals decades into the future without a concrete path to accomplish that and without accountability for those words in our opinion is the epitome of floor on corporate governance.
On a forward looking basis.
Your goals and results are directly linked to driving efficiency.
We've gotten on license to operate reducing our risk and growing intrinsic value share of the company. These are the strategies that have allowed <unk> to thrive.
150 years, and they will continue to drive our success, let me introduce a few of our efforts this year.
We introduce methane related kpis into our executive compensation program, we've committed to make substantial multi year community investment of $30 million over the next six years to widen the path for the middle class in a local community while growing the local talent pipeline.
We've redoubled our efforts to spend local and hire locally 100% of our new hires will be from our area of operation I will maintain that we will maintain at least 90% local contract workforce, we committed to 6% of our contract spend to local diverse and businesses in 2021 on dedicated.
40% of the look of the total of <unk> small business bank.
Two companies within the Tri State area.
We adopted the task force on climate related financial disclosure with Tcf day framework and the FASB standards for both our E&P and midstream operation.
In addition, the transparency on the financial sustainability of our business is second to none.
One year into our seven year of free cash flow generation plan, we have a low risk balance sheet driven by most of the most efficient lowest cost operation in the base.
Lead stream dependence from equity and debt market when pursuing value creation finally, while you'll hear more about this in the weeks and months ahead I wanted to take the opportunity to announce that <unk> has developed an innovative proprietary solution in combination with a few commercial solution that allows us to significantly minimized from.
From a blow down and nomadic devices, which make up about 50% of our emission source. The blowdown solution onto development will also allow us to recirculating methane, which will which would have otherwise been emitted into the atmosphere back into the gathering system. This is yet another leadership staff or company that continues to lead and deliver.
Tangible impactful ESG performance.
That is reducing risk and creating sustainable value for our shareholders.
Tangible impactful local ESG is a brand of ESG, we don't follow the herd we charter on course and do what we know is right on impactful over the long term for employees our community on our shareholders with that I'll turn it over to Chuck power for Q&A. Thanks.
Thanks, Jimmy and operator, if you can please open the lineup for questions at this time Sir.
We will now begin the question and answer session to ask a question you May Press Star then one on your Touchtone phone.
If youre using a speakerphone please pick up your handset before pressing the keys to withdraw your question. Please press Star then two and at this time, we will pause momentarily to assemble the roster.
Okay.
And our first question today will come from Jack Paar Ham with J P. Morgan. Please go ahead.
Hey, guys. Thanks for taking my question I.
I guess, Chad maybe one for you can you give us a little color on the strength in NGL prices.
You reported over $29 per barrel on <unk> raised the guidance to $20 per barrel for the year I mean, just based on what Youre seeing now do you view that guidance is still conservative, but maybe just a little color on kind of what youre seeing in net NGL market.
Yeah sure. Thanks for the question.
So youre right, so about $29 a barrel realized for Q1.
I think I think our view is is that historically ngls have been incredibly volatile.
They're there they really are over the place where less and less on a quarter removed from 2020, where Ngls average just about $13 a barrel.
And in fact, if you go back to 2019 2019 was a year in which Q1 I think our our NGL barrels with somewhere in the upper Twenty's 27, and $20 a barrel, but then the full year ended up averaging right just under $20 a barrel so.
Based upon the volatility we've seen historically.
Really the difficulty in hedging those NGL markets from the NGL sales that we have I feel like $20 for the full year is still a pretty good estimate of what we think the full year could come in at I think on the NGL side more what we're focused on is being able to react as spot prices change.
We sort of demonstrated that by moving up our two surely fracs and being that bring those two those two pads on line.
In order to take advantage of the strong NGL prices that were seeing in 'twenty one.
And similarly, the flexibility that the midstream system that we own in southwest P provides us.
To be able to move.
Damp volumes between dry outlets and processing plants that depending upon the spread between gas and Ngls and I think if you look at the volume you'll see that on a relative NGL yield came down during Q1, well that's because we are optimizing that crack spread and what happened as NGL prices generally stayed where they were low gas prices improved.
Relatively in Q1, so we moved some of those called marginal volumes back to dry out let's take advantage of the Btu uplift.
Now that we've gotten through that strength of Q1 gas and gas price would come back down to.
Where they are for the balance of the year, we will likely move some of those marginal volumes back to processing to again take advantage of the strong NGL prices.
Yeah.
Got it thanks for that color I guess, just one follow up given that Phoenix is a consistent free cash flow generator now when do you see cash taxes, becoming a drag on free cash flow and maybe just a little color on on how you were able to continue deferring taxes.
Yeah. So this is Don so thanks for the question as we've stated before our plan through 2006 were not material cash taxpayers door and door in that plan most of it the way, we treat sort of the Nols and utilize those as regards to.
The the cash taxes that we'd have to pay in managing and optimizing that versus sort of the <unk> and the other attributes that you have on the tax side. So.
We've given to date has no material cash taxes through 2006.
Correct.
Alright, Thanks, guys. That's it from me.
Our next question will come from Leo Mariani with Keybanc. Please go ahead.
Hey, guys wanted to follow up on a few of your prepared comments here you guys talked about production dipping a little bit in second quarter, but the same time I guess it sounded like you had 13, new wells in the Marcellus coming online I was just looking for a little color on around why the production is dipping a little bit here and I guess the follow.
Up to that would be would you expect production to start to rise again as we got into the third quarter.
Yeah, and you know I did not not materially as this is the way I would sort of say it. So the the rest of the year is fairly consistent obviously you had we had a big whole bunch of new wells turned online in November then you had these other wells that are just getting turned on line and getting to their their line rates now so again nothing sort of production.
Should be spent mostly similar throughout the year, but.
Sorry, if I gave the impression that Q2 is going to be a big difference.
Very slight if any.
Okay and then just.
Question on the Capex, you guys talked about Capex being higher in the first half versus second half.
Does this materially higher or are we talking like 60% on the spend in the first half or is it you know maybe just over 50% just trying to get a sense of how that plays out.
Yeah, I'd say, just a I'd say.
Probably just slight as another way to sort of describe it and part of that is as Chad mentioned, we put ups and we pulled up some activity to take advantage of the the higher NGL prices. So brought in a spot crew to go ahead and get those things online sooner just because you don't know how long.
<unk> prices stay goods. So the best thing we can do is try to we've been working on is kind of call. It quickly react and set up perfectly predict because it's very difficult to burfoot perfectly predict so again, it's not on.
On a meaningful manner, but we put up some stuff that was going to be in the back half of the year to the front half of the year. So you just way to think about it.
Okay, and obviously you guys were nice enough to talk a little about kind of NGL prices and the inherent volatility I guess, if we're in a world over time where oil.
Oil prices and NGL prices, just stay on a significantly higher <unk>.
Relative to gas would you guys consider changing up the plans over the next couple of years to maybe focus a little bit more on some of the winter areas as you look at your ops.
Okay.
Yeah, No I think like I said, we predominantly our acreage footprint is drive we do still have some some wet areas and yes, they will get pads ready and we're reacting to NGL prices staying good I mean the.
The sequencing you know like we've talked to the P.
<unk> that we're going to do over the next six or seven years are fairly static, but the sequencing and order you do on you would obviously try to change them and get some of the water ones moved up and have that some of the drier ones move back a little bit. So again, it's not going to materially change the production mix at that <unk> has but make it making a margin.
And moving things on the margin its real dollars I mean, it's meaningful dollars that were able to increase our cash flows by managing it that way.
Thank you.
And our next question will come from Neal Dingmann with Truest. Please go ahead.
Okay.
Good morning, guys. My question really just on capital allocation you guys more recently it really done a good job on the on the buybacks I would say.
Thoughts on it's always a nice option to have is as you know free cash flow continues to ramp like this you know.
No you've got I forget the exact amount, but still a bit left on that current buyback plan just your thoughts on buybacks versus dividends. There's a lot other folks out there doing more Alex you know the allocation towards variable dividends and all so.
Nick for any you Don I'm, just just wondering how you guys think about that.
Yeah, No I think the way we've talked about it is we clearly want to go ahead and reduce our absolute debt and net that remains a focus of the business here over the next several quarters to get to that level that we want to achieve and we've talked about having the wherewithal to go ahead and return capital to shareholders, along the way pending on sort of how free cash flow yield.
<unk> is moving or not moving balancing with sort of patience and prudence, just because as we've talked with Ngls the same with equity or gas prices and volatility is something that I think is here to stay in.
China build capacity to take advantage of that volatility is low.
Is the proper way to think about it going forward as well as far as dividends you know what we would look through there would be day to get the balance sheet closer or where it wants to be first before we would entertain that then second I think you'd have to just look at the other factors that are that are there at the time with what our free cash flow yield is doing.
Determine if returning capital to shareholders via share buybacks or dividends as a as a smarter or investment.
Neil Dawn summed it up really well there you got right now first focus with free cash flow allocation to strengthen the balance sheet reduce debt, but at some point quickly here right, we get to a leverage ratio liquidity debt profile that we're more than happy with.
Then on the return to shareholder side, and we do think that you know a good sustainable business model for an E&P.
And a manufacturer so to speak of methane is to be able to have a component of your free cash to a generate free cash flow would be have a component that does go back to shareholders.
Share buybacks versus dividends as long as we're at these yields on free cash flow the rate of return so to speak of a buyback is very compelling relative to a dividend if and when that changes.
On that closes on free cash flow yield and value GAAP than something like a dividend makes I think much more sense.
Yes, great great that color to add there <expletive>.
Just one second here on a follow on.
Well they had a little bit maybe different spin on cadence a little bit you guys. You continue to see just out there natural gas price are obviously always a bit seasonal and I'm. Just wondering you know I guess Chad from maybe you were done when you guys think about cadence I think there's what 37 or so till this year or even on.
On a go forward basis do you know you guys are pretty highly hedged. So I'm, just wondering maybe or maybe not this matters. When you. When you know because of the seasonality that we continue to have with natural gas prices does that impact how you sort of think about the cadence throughout a typical year like this year or you know so I don't know maybe you could just talk cadence a little bit this year that'll.
Give me an idea of how you all think about it through just the typical seasonality.
Sure. Thanks.
Chad I'll start and maybe Don Phil on the sort of LASA or anything.
Certainly we're generally one rig one frac crew. So that's that's generally pretty consistent throughout the year.
So as far as timing drilling or completions activity, it's sort of you know.
Just sort of marks along through the year.
I think your question more comes along the lines of like what we did last year, where we we saw last year. The summer winter arbitrage was probably the widest that I think I can ever remember seeing it and so we curtailed some volumes we shape some volumes.
Cash in some hedges layered in additional winter hedges and take it and took advantage of that strong summer wintertime price arbitrage by timing the production surged to sync up with the strong winter prices.
We're not seeing that big of a of a summer winter arb going into this coming winter yet.
But that is certainly something that we obviously keep an eye on every day and if we see that arbitrage begin to widen to the point that it makes sense at the time production. Then we will absolutely do that just like we did last year, but right now we don't have any active plans to do that based upon what the way the forward strip currently looks.
I have said, we were always looking to maximize the value of our molecules.
And so if that arbitrage comes back into the money then we'll absolutely be all opened a timing volume. So it's like we did last year, yes, I'd only add on I think similarly, I keep repeating volatility, but I think volatility is going to be higher going forward just looking at the relative storage versus the you know the production supply demand balances that you have on all of the factor.
That did go into this stuff and Chad talked a lot about the <unk>.
We will delay production and delay some timing to kind of catch a contango when prices are weak and then prices are better, but we've done the opposite do somewhere with Ngls, we've done it with dry gas prices. If there is a a bit of a spike in dry gas prices will go ahead and get things online quicker, we have a bit of slack in the system to kind of do either one sort of delay it a little bit or poor.
Up a little bit depending on what those gas prices do because I think they're going to continue to be.
Volatile both directions up and down in shaping shaping it.
Quickly is something that we've got the ability to do and I think that'll be up a pretty.
Good tool to use for the next several years as these things move pretty pretty volatile.
No Greg do yourselves, thanks for the time guys.
Okay.
And our next question will come from Michael <unk> with Stifel. Please go ahead.
Yeah, Hi, good morning, everybody.
On a follow up on a previous question. Don You said you don't expect the cash taxes before 2026 net.
Change at all by the administration.
<unk> is successful and eliminating the intangible drilling credits or is it completely shielded with Nols at this point.
No I think I'd add just to make sure I clarify no material cash tax payments through 2006, so there'll be there'll be some but not material yet so the way we think I mean, obviously the bottom plan. There is a lot of moving pieces and where that actually settles and what gets approved is kind of to be determined.
Following it closely and sort of some of the characteristics on the ITC changes that they might be utilizing could change when we would get into the cash taxpaying mode by year. So I'd say, it's the easiest way to sort of think through it.
The profitability, we do have as a business I mean, clearly we have the $1 billion worth of Nols debt to help offset any kind of change to the tax provisions, but the easiest way to think about it as a year or so change and when we would be a cash taxpayer if steady state business plan through 2006, as we've laid out we continue on.
Okay. Good thanks and.
Chad you mentioned the costs on the most recent Marcellus and Utica wells pretty significant different surge. Once you have other terms compare between those and any other factors you'd looked at on your.
And to allocate capital between the two.
Yes, so certainly.
We believe that debt all of those areas generate returns.
Attractive returns, it's just becomes to us to prioritize our investment into the highest greater risk adjusted rate of return first.
So a lot of that has to do with taking advantage of existing infrastructure.
We made a huge investment into midstream and water infrastructure in southwest P. A.
It really 2018 early 19, and now really going into cash harvest mode utilizing that infrastructure in southwest P E and developing.
The slip on Marcellus assets that we have in that area.
Leveraging those existing infrastructure assets.
The best returns on our portfolio.
And that will sustain us predominantly through the six year plan.
Through 2000 26027 at this point with a little bit of deep Utica sprinkled in I think what we're talking about now is about 75% Marcellus from about maybe 25% Utica sort of sprinkled in.
Moving out of that area, you know, obviously going up the CPA. Those are those are tremendous producers up in CPA deep Utica. The Bell 0.6, while that we've talked about I think the latest public numbers, we put out there on the four four and a half bcf per thousand foot type production levels.
When you combine that with the recent capital efficiency that we've seen in the swipe of deep Utica you. The returns will be again very attractive I think CPA.
The plants like I said, we will probably be about a pattern here.
Through the long term plan until we build some we need some capital investment into our midstream system to truly unlock that area and right. Now I think we're just trying to assess what the proper timing of that is just sitting there ready to go in the event gas prices.
Justify increasing production or trying to grow and swept the Utica is sitting there again.
By all intensive purposes with cost we've seen in the production levels. We're seeing on the most recent most recent pad, where we believe that those returns will be in the money as well.
Like I said in my prepared remarks that that's sitting there ready to quickly take advantage of and a strong gas price environment utilizing those existing assets infrastructure assets, we havent slipper or it'll be there to tack on to the tailings and sustain our business plan for years to come yeah. So just to finish off what Chad said, so a best return areas right now are to the south.
<unk> P a central Marcellus in the CPA Utica.
We're planning on doing about a pad at a year and the CPA Utica, that's kind of what can fit in the pipeline systems that are up there in that mix as you know that's the 25 percentage Utica. It's it's predominantly the CPA Utica as Chad mentioned, we only out for southwest PA Utica is in the plan just for blending purposes, and although you know the economic.
To work on our we're focusing on our best two areas.
Sure definitely the near term and through the plant.
It sounds good thanks for the color guys.
And our next question will come from John Abbott with Bank of America. Please go ahead.
Good morning, Thank you for taking my questions.
The first question is on buybacks.
You've previously indicated that you could potentially allocate as much as $500 million of free cash flow towards potential buybacks over the next three years if.
If you continue to perceive a future free cash flow yield is on underappreciated. However, a number of times on this call you've mentioned <unk> come.
Modesty volatility when you think about that how do you think about buybacks at this point in time that 500 that potential $500 million target versus repurchase paying down debt.
Yeah, and just so I was just so we're clear I mean, we didn't lay out a $500 million target. We just said we had we had the wherewithal and the cash flow that we're generating there is theirs.
Extra money that will have to utilize for other other things that are not debt pay down and it's hard to have a complete exact science with the volatility that we've talked about on equity markets debt markets. The political environment, there everything else that's out there with it. So we will we will try to do is balance patience and being prudent with.
Being opportunistic with share.
Share buybacks and returning capital to shareholders on along the way to our our call it balance sheet targets.
How much in the pace of those will be to be determined based on the facts and circumstances as they change over time.
So the.
Obviously, the effectiveness and impact on us of growing per share value of buybacks really comes down to in large part on timing right. The price did obviously you acquire at and how it's discounted relative to fair value.
And as Don said, the volatility really lends itself to so many twists and turns on being able to react quickly there's power in that optionality on the second thought is that as we deploy free cash flow toward debt reduction.
Building liquidity that is stored capacity, so it's a bit different and in our minds from drilling the next pad or doing an acquisition on where those are sunk capital decisions. This is not a necessarily a sunk capital decision, it's building liquidity and storing capacity to deploy it if and when circumstances dictate.
I understood.
And then my second question on is on an M&A. Nick you did a really good job in terms of addressing that during your opening remarks.
Just one follow up question on that I mean, M&A is such a high hurdle for you just given your low cost structure.
Is there a scenario, where some dilution would be acceptable to you.
Yeah I mean this is Don so I mean, obviously when you look at these things Holistically right. When you look at accretion dilution math on on per share on per enterprise value cost structure, how much inventory sort of over there on the risk profile of what it is you're buying the payback periods that the risk adjusted returns so.
We do look at all the components.
Now together when we're making these assessments. So if it's one piece of the components arent good but the other ones are really good then you know you can kind of overlay to make the decision on this so yeah. We do look at it on all the all the factors and you know with the ultimate goal of just increasing the intrinsic per share value for our shareholders. So I think you know we.
We continue to assess all the all the pieces, we're just going to be making sure that it advances the value for <unk> shareholders and I think to that.
You know the term we often used to describe our approach on M&A just ruthlessly clinical we just it's just a simple matter of math, we follow math.
And we're looking at both.
The acquisition cost in Hollywood finance that as well as the math of what we're acquiring in terms of the value on what we don't ever want to do is get into one or two positions, one where we acquired something and we sort of fall back on that and classic descriptor on a strategic acquisition, which is typically code for something that's destroyed value.
Or to you know something that is largely are hugely speculative on a gas price SKU.
This is where the forward strips are so if you follow the math on your clinical about it typically more often than not the vast majority of times you avoid those two situations. If you don't sometimes you get caught up in those and maybe it comes out okay, but oftentimes it doesn't and it doesn't end well for shareholders. So we want to avoid those those two types of <unk>.
Scenarios.
Yeah.
Thank you very much guys.
Got it.
And our next question will come from Ballparks with Tuohy Brothers. Please go ahead.
Hi, good morning.
Okay.
Good morning.
Just noticing that.
In the release, you sort of repeated the detail on on your planned lateral lengths where.
Just about everything is 12000 feet or better.
I was wondering.
As far as the inventory you have that might be might only allow shorter laterals with a with gas as strong as it is we're on.
260 or better through 2023 I was just curious.
What are the economic on what would the economics be like on on some of the shorter laterals and just wondering if those would have.
Any appeal cleaning up some of those during the time that you didn't have to support or support a price deck out there.
Yeah, No. We obviously look at all the components of the rate of return math whenever you're looking at dispatch and wells and optimizing lateral lengths and via leasing or swapping or any other of these pieces is just something that we're always sort of looking at and focusing on whats the optimal lateral kind of changes depending on a low.
It's a facts and circumstances, but yeah I mean, as you say as you as gas prices rise just more things become in the money period, whether it's shorter.
Short or longer laterals or whether it's you know call it tier two or tier three areas are packaged gas prices go up a little bit more C. P. M. Wells you know start being you know economic and developable at that point in time. So we look at all of these these things and you know some of the assets.
It kind of dispatch at higher gas prices and if that's a doable and that's something we just look at like we would anything else.
Okay and I was just wondering.
Among your inventory can you just sort of ballpark, how many locations might fall into that that shorter you know mile mile or less.
And.
Whether those are sort of.
Scattered across your acreage position or whether you just have some.
In places where the.
There's some geographic or or at least with constraints that keeps you from going longer.
Yeah look I mean, I guess there is most of the way we handle the development over our patterns and inventory and well profiles well into the future. We're always kind of built in and getting to where the pads optimize inefficient starting many many years in advance so net net from like geological constraints or something like that theres really not on.
Not a restriction on being able to continue to call. It manage a pad build to efficient levels going forward.
And just a follow up or are you considering pushing your your lateral lengths.
Even longer you know where the lease allows.
Yes, so what we've done both we've done I can't remember what the longest lateral we've done is.
Yes, close to the 20000 foot laterals. So we've done longer ones like I said, it's facts and circumstances. It's you know the topography like where you can get pads and how the lease boundaries set and sort of where the right way to to develop the area in connection with where the midstream systems are and for the for the top on.
Or fee that you have out here, so like I said it's.
The average is around $12 more at we kind of have some that are longer we have some that are a bit shorter and like I said it'll be facts and circumstances to kind of optimize you know all the pieces we have to get these called.
<unk> drilled in the most economical fashion.
There is a point of diminishing returns on it when you start talking about long laterals.
I always look at it to make sure we optimize on it based off of the available technology to actually complete those things efficiently.
Right.
Great. Thanks, a lot.
And once again, if you'd like to ask a question. Please press Star then one our next question will come from David Heikkinen with Heikkinen Energy Advisors. Please go ahead.
Good morning, guys and thanks for taking the question one of your Appalachian peers highlighted that they are drilling new wells from over 250 existing pads.
And that's taking their well costs below $600 a foot I was curious as you think about your inventory and being able to utilize like you said your existing midstream infrastructure.
You know as you as you try to continue to drive down costs below your $6 50 a foot.
Can you just give us some thoughts of how you would react to being able to use existing pads on existing infrastructure and really continue to drive down your your lateral cost per foot.
Yeah, Yeah, and some of that yes. Some of that we do we do do as well clearly we don't have that many pads, where the availability to do that would be there and part of the southwest P. A beautiful strategy. However, it plays out in the future. It will have a lot of that would be going back to existing pads and kind of use.
On that same phenomenon, but yes, the Marcellus we have pads. It will do two trips on and we've kind of done that same phenomenon in a pad pad build not happened to build a pad again is obviously saves you money in the overall you know D&C per foot of the well and you know that's something that will optimize on we just don't have as many legacy pads to do that.
As others.
Got you so really as you think about the 25% of the Utica in the future or if you ever come back to adding Utica that would be.
Drive down some of your cost per foot on those well that's helpful. Thanks, guys. Yeah, Yeah, and then you know up in the CPA area you know the CPA Utica is more economic.
On the CPA Marcellus, but the CPA Marcellus is as good CPA, South Marcellus I mean theres some.
From third parties drilling up there currently in the new well results are a really phenomenal actually with the new completion designs and stuff so that opportunity exists for us both in the southwest P. A area and in the CPA area, Yeah, David I think the way to think of our footprint in that context is is the new <unk> that type of.
Behavior dynamic over over years and decades, so for us in southwest, Pennsylvania. It. It's the Utica right, taking advantage of all that shared infrastructure pad water and midstream on the Marcellus and then in CPA for US. It's the Marcellus there would be doing the same taken advantage of the existing infrastructure thats been capitalized because of the.
On the Utica. So those are really the drivers of the rate of return and the math behind two of our four horizons in a big way.
Yep.
Thanks, guys.
And this will conclude the question and answer session I'd like to turn the conference back over to Tyler Lewis for any closing remarks.
Yeah. Thanks, operator, and thank you everyone for joining US today, we look forward to speaking with everyone on throughout the quarter. Thank you.
Okay.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
Yeah.
Okay.