Q3 2023 Southwestern Energy Co Earnings Call
Okay.
Okay.
Good morning, ladies and gentlemen, and thank you for standing by.
Welcome to southwestern Energy's third quarter 2023 earnings call.
Management will open the call for a question and answer session. Following the prepared remarks.
In the interest of time, please limit yourself to two questions and re queue for any additional questions.
This call is being recorded.
I will now turn the call over to Brittany Rayford southwestern Energy's Vice President of Investor Relations you may begin.
Thank you good morning, and welcome to the southwestern Energy third quarter 2023 earnings call. Joining me today are Bill way, Chief Executive Officer, Clay Carroll, Chief Operating Officer, Carl Giesler, Chief Financial Officer, Dennis <unk>, Senior Vice President of marketing and transportation.
When we get started I'd like to point out that many of the comments. We made during this call are forward looking statements that involve risks and uncertainties affecting the outcome. Many.
Many of these are beyond our control and are discussed in more detail in the risk factors and forward looking statements section of our annual report and quarterly report.
I hope that the Securities and Exchange Commission.
Although we believe the expectations expressed are based on reasonable assumptions they are not guarantees of future performance.
The results or developments may differ materially and we are under no obligation to update them. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers for any non-GAAP measures. We use a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release on our website now I'll turn the call over to Bill way.
Thank you Britney and good morning, everyone.
We appreciate you joining us today to discuss our third quarter operating and financial results before.
Before I begin I'd like to express my thanks to our dedicated team consistent lay delivering on our priorities and driving improvements to our business and value for shareholders quarter after quarter.
During the third quarter, we continued our disciplined optimization of free cash flow generation and capital investment.
This approach underscores our strategic priorities of both reducing debt and maintaining the companys productive capacity.
We believe we have materially improved our capital efficiency and position the company for enhanced through the cycle price realizations with a more moderate go forward hedging practice.
Our progress on these priorities. This year has further strengthened the business and positions us for differential differentiated value capture as we shift towards an improving macro environment, driven primarily by growing LNG demand.
We've been encouraged by the industry wide discipline and activity reductions in response to this year's natural gas prices.
Rig counts remain well off their highs from the beginning of the year, particularly in the Haynesville, where rig counts are down approximately 40% year to date.
Given the production profile of wells in the Haynesville, we expect overall Haynesville basin production to decline at least into early next year, giving us further confidence and a strengthening macro view.
Beyond reduced activity and the slowdown in supply growth would suggest LNG exports are up over two bcf per day year over year recently exceeding 14 Bcf per day, while weather adjusted power demand is up two Bcf a day in exports to Mexico were up almost one Bcf a day these.
Factors have helped to significantly dampened the end of season starts surplus with new LNG in service dates beginning next year.
By the end of 'twenty four we expect LNG exports to grow to 16 Bcf per day over 90% of which is located along the Texas and Louisiana Gulf Coast.
When we acquired our Haynesville assets, one of our guiding tenants was firm access to markets of choice.
Both of our Haynesville acquisitions included strategic connectivity to advantaged markets, along the Gulf coast, including two LNG, which we increased shortly after closing.
With a portion of that expanded capacity already in service and additional capacity expected to go into service by next year.
We are well positioned to supply the next wave of LNG facilities as the largest current supplier of natural gas to LNG exports.
As we look ahead to 2024, we expect new LNG facilities to increase demand throughout the year. However, we believe strip prices are not yet high enough to incentivize production growth.
Given this dynamic we intend to continue optimizing free cash flow and capital investment to meet our dual priorities are progressing towards the three and a half million top end of our target debt range, while maintaining the flexibility and optionality in the business.
Our unique asset base provides capital allocation flexibility between basins commodity windows as well as assured firm market access we.
We will continue to optimize investment with the Optionality to add back in the back half of 'twenty four should market fundamentals support.
We believe this approach to managing the business in a volatile commodity environment is prudent and will best position swing to sustainably return capital to shareholders.
Our hedging strategy helps ensure debt reduction while also providing upside commodity risk exposure as we move through 24 and 2025.
We continue to target a range of 40% to 60% of natural gas price protection when entering a new year.
Basis protection is also key to commodity risk management.
With the physical sales agreements and financial basis hedges, we expect to continue our practice of proactively protecting basis during.
During the third quarter, our basis hedging program helped to offset wider Appalachian basis differentials and we expect to continue layering on additional protection for future periods as we look to next year.
While commodity prices in 'twenty three are well off the highs we experienced last year, we have successfully progressed our key enterprise priorities.
Strategic adjustments to our development plan are resulting in free cash flow, while maintaining our productive capacity with this free cash flow along with the proceeds from noncore asset sales, we have already reduced debt by approximately $300 million in a year when natural gas prices are expected to average less than $3.
Additionally, our team is driving further operational and capital efficiency improvements, especially in Haynesville, which is helping to continue lowering our enterprise cost structure.
We're also proud to have progressed, our leading sustainability programs and initiatives, including reducing our emissions as outlined in our recently released 10th annual corporate responsibility report.
As we look forward to 2024, and we are well positioned to build on the successes of <unk> 23, and continue to drive sustainable shareholder value.
I'll now turn the call over to clay for some operational updates.
Thank you Bill and good morning.
The team delivered another strong quarter, while progressing our key operational initiatives.
Production totaled 425 Bcf fee during the third quarter.
Consisting of four Bcf per day of natural gas and 104000 barrels per day of liquids, including over 14000 barrels per day of oil production.
During the quarter, we invested $454 million of capital and placed 23 wells to sales.
In Appalachia, we placed 15 wells to sales with an average lateral length of more than 16200 feet.
This included a company record long lateral in Brooke County, West, Virginia, with a completed lateral length of over 24000 feet.
Well as our 25th producing well in Appalachia with lateral lengths greater than 20000 feet.
Of the total wells to sales in Appalachia. This quarter 11 ran our liquids rich acreage in West, Virginia and Ford.
Four wells were across our dry gas areas in Ohio and Pennsylvania.
Most of our liquids rich wells went to sales during September.
Which we expect to result in fourth quarter oil production returning to approximately 15000 barrels per day.
In Haynesville, we placed eight wells to sales with an average lateral length of approximately 9100 feet.
Six of the wells were in the Middle Bossier interval and two were in the Haynesville.
We continued to progress our drilling execution and efficiency gains and recently drilled and cased two of our longest laterals to date at approximately 15000 feet.
Capital investment for the quarter came in below expectations, driven by some minor changes in our development program that shifted activity end of the fourth quarter combined with efficiency gains and some moderating inflation impacts.
Our program remains on track with activity levels and expected investment within our previously updated full year guidance ranges.
Looking ahead to 2024, we remain optimistic about service cost deflation.
We're currently in the process of securing goods and services and have approximately half of our services already contracted putting us well on our way to securing our 2024 development plan.
Overall, we're seeing a softer oilfield service market driven by the nearly 20% reduction in the industry wide rig count.
With the recent strengthening in the oil market, we see industry expectations of deflationary savings in 2020 for moderating a bit.
But overall, we believe costs should be down next year.
We expect to lower Haynesville, well costs, approximately 15% to $1800 per foot next year and see the potential for Appalachia, Appalachia, well costs to decline as much as 5% as we continue to capture efficiencies and reduce costs.
Given our expectation for increasing LNG demand, particularly in the back half of 2024 and into 2025, we anticipate a similar level of capital investment next year with a range of two to $2 $3 billion and increased activity offsetting deflation.
<unk> and efficiency gains.
Our capital program is typically front end loaded with higher capital investment and the first half of the year, resulting in higher production in the second half.
Next year will likely follow that same profile with production expected to step down in Q1 before stepping back up to current levels in the second half.
This production cadence also aligns with our view that the macro will strengthen during the year as additional LNG goes into service.
We continue to exhibit strong flexibility to moderate activity and manage through volatile commodity prices.
And we believe the company is well positioned for 2024 and beyond.
Now I'll turn the call over to Carl.
Thank you Clive.
System with our front end weighted development program capital investments step down during the third quarter, which helped to generate modestly positive free cash flow.
As expected free cash flow was more than offset by typical seasonal working cap seasonal working capital reverses.
Resulting in a small increase to our revolver.
<unk> and debt balance this quarter.
We ended the quarter with $4 1 billion of debt.
A level, which we expect to hold through year end down through the $4 4 billion dollar level at year end 2022.
Based on current strip prices, we still expect to achieve the top end of our target debt range in either late 2020 for early 2025.
After which we plan to complement continued debt reduction.
With sustainable return of capital to shareholders.
While our leverage has ticked up modestly to one six times due to the price impact on trailing EBITDA and we fully expect to return to our target one five times to 1.0 times leverage range next year.
As Bill mentioned, our debt reduction objectives are supported by our hedging program.
Implementing our hedging our approach has been to set production protection at or above our key economic thresholds.
<unk> enterprise free cash flow breakeven levels, while also allowing for asymmetric upside participation.
This practice also preserves for our shareholders the benefit of the higher relative operating tour of our dual faced an asset base to natural gas prices.
Capitalizing on the volatility we've seen we layered in some additional protection for 2024 and 2025 using predominantly three way collars.
Based on strip pricing, we plan to end the year near the middle of our target hedging range of 40% to 60% for 2024 and with a base 20% layer for 2025.
Operator, please open the call for questions.
Thank you we will now begin the question and answer session.
If you'd like to ask a question. Please press Star then one on your telephone keypad.
To remove yourself from queue. Please press Star then two and as a reminder, in the interest of time, please limit yourself to two questions.
Today's first question comes from Charles Meade with Johnson Rice. Please go ahead.
Yes, good morning, Bill Clay, Karl and into the rest of the southwestern team there.
Good morning.
Bill I wanted to I wanted to follow up on your on your prepared comments about about 24 and also especially in light of what what clay offered on on the cadence for 24 so.
Bill I think I heard you say that that there's a possibility to add activity in the back half of 'twenty four if if prices warrant and clay said well, we're going to have the usual.
Our front end loaded capital program a gain.
In 24, so if I put those two pieces together does that does that mean that the base cases, the front end loaded capital program leading to roughly.
You know roughly flat volumes year over year and in that and that.
Theres, a possibility to add perhaps a rig or maybe two rigs in the back half of year that we'd been bias you towards the high end of that that capital guidance range is that the right way to think about it.
Yeah.
Okay.
Later comments in on this.
We are front loaded that's traditionally how we invest capital.
We expect that as we move through the year.
And manage our free cash flow generation.
Along with our capital investment kind of in a dual.
Dual priorities that we would be able to.
Both.
Again reduce debt, but also look at.
Production levels overall for the year to be two that still are to be estimated right around like the end of 'twenty two.
Yeah, So Charles Youre, right that shape will be kind of growing through the year in 2024.
Tied to the vet, we believe very constructive commodity price going into 2025, maybe that happens earlier in 'twenty four and we have the optionality within the program.
To take advantage of that as we balance all the all the priorities of the company, but we're well positioned if commodity prices play out that way.
Got an IMAX guide these decisions economics drive these decisions. So there's a lot of discipline involved in making sure that value is being created.
And a lot of cars left to see also.
And then clay.
Your your comment about the the 24000 foot lateral and in Appalachia I Wonder if you could talk a little bit more about that obviously you said, it's an achievement to successfully get off a lateral that long, but I'm wondering if you could talk about what youre seeing as far as productivity from that well and if it encourages you to.
Do more of either even tried to extend further or alternatively, maybe max out around 20, just can you give us the bigger contracts there.
Sure.
You've been pretty methodical over the years, maybe earlier than others in Appalachia, where we've been extending our laterals are our average program is around 16000 feet. This year, where we recognize the benefits of the longer laterals on lowering well costs.
Enhancing economics and.
Our team does a really good job of it and this well based on the land position.
Enabled us to go longer we have many checks and balances when we drill these long laterals to make sure that everything is operating within the parameters we expect.
And this is another example of that it's one of our Super Rich wells in in Brooke County, the production from the well on a on a three phase initial production was a little over 27 million cubic feet equivalent a day included in that was close to 17 <unk>.
<unk> barrels a day of condensate and so.
Typical really.
Highly economic well and our liquids rich Appalachia that we're able to get even greater economic benefits by going longer the well was drilled in 19 and a half days spud to rig release for over 30000 foot measured depth.
And it has obviously benefited by our vertical integration assets were using our company rigs the well was fracked with our company Frac fleets and so all of that is part of the recipe where I included the comment about we've now got 25 wells that are greater than 20000 foot lateral link.
That that program has been working for us for a while and given their sweat employees, the knowledge transfer well to well and the application of knowledge and learnings is quite high.
That is great detail, thanks Clay Bill.
And our next question today comes from Bertrand honest with Truest. Please go ahead.
Hey, good morning, guys.
I'm I'm doing a little bit of acreage pinpointing here, but it looks like you guys have some eastern Guernsey acreage in one of your peers now touting our high liquids cut.
Location count there. So I just wanted to address do you guys have an inventory count. They are you seeing similar things on your acreage in and I know, it's not a large part of your portfolio, but maybe how many.
Location, we might expect next year or a run rate.
Yes, so we're very knowledgeable about the area and our mines.
A continuation of the geology through the product windows of the liquids rich acreage that we have in southwest Appalachia and.
Some of it is indicative of the type of well performance, we have been deliberate in our liquids rich assets. So.
Not a surprise to us.
We are drilling a pad there Kurt.
Currently we don't have a large acreage position there, but we have made the largest acreage position in the highest yielding liquids rich acreage in west Virginia.
With our position there and so we like it.
It continues to.
Very resilient economics as you move through the price cycles.
That's great and then just.
Second one.
Some of your peers have started getting very creative on the LNG.
Portfolio side, and you guys have almost it seems pointedly chosen to take a step back and let the rest of the guys create a market. So is there any changing.
Pricing change that or is there an evolution of the negotiations out there that are maybe making it more attractive for you guys.
Sure.
Take that as you know we are strategically positioned to supply the growing demand for lower carbon energy.
With our access to the Gulf Coast.
And our access to the LNG corridor.
As you said, we are actively engaged in talks with a variety of buyers under a wide range of different commercial structures.
We certainly see the value in portfolio diversification.
And gaining direct access to more volatile international price indices.
But we're taking a maybe more disciplined approach to evaluating and managing the risk associated with these transactions.
So in that respect we have a pretty high threshold for transactions of this size complexity and duration.
As currently structured I think many of the commercial arrangements involving domestic gas supply priced off of international benchmarks push most if not all of the risk on to the upstream gas supplier.
And our intention is to enter into internationally price transactions when those risks become more balanced.
And when we have the tools available to us that are necessary to effectively manage our exposure.
As you know are the currently the largest supplier of natural gas to LNG exporters, and we intend to retain and potentially grow our portfolio of Henry hub base.
Agreements in addition to considering incremental internationally priced arrangements.
The one distinction I think we might make at this point.
Amongst.
Our approach against our peers is where.
We're taking a slightly different approach targeting binding transactions on post FIV facilities as opposed to non binding hoa's with facilities that may or may not have reached yet and so as I suggested that that does raise the bar on the complexity of the negotiation.
So.
I think I think our disciplined approach explains why we're moving at the pace, we're moving and when we do enter into a deal Youll know that we will have the tools to evaluate the risk and manage it.
That's great. Thanks.
Thank you and our next question today comes from Doug Leggate with.
Bank of America. Please go ahead.
Thanks, Good morning, everyone.
Tom.
Good morning, Bill I Hope I've got a couple of questions one of them a lot of training and as delicate to monitor as possible, but claim maybe I can go to your first the reduction in capital in the Haynesville, 15% drop in well costs.
$800 per foot big step down obviously, you've signaled to us that that could be on the cards, but I'm curious if there's if this is a deflationary move is it a well design change what's the what was the moving parts and how much further do you think you can get it done.
So it's a combination of efficiency gains that we've achieved them, we expect to continue to achieve on the drilling and completion side of the business.
As.
Reduced inflation and it has longer laterals and so the kind of the same recipe we've always used them that we used in Appalachia.
Is what we're using here and we think that we're going to continue to drive those efficiency gains.
I think overall, we have room to move the lateral lengths in the play it's not going to be equal to the averages in Appalachia, but room to keep benefiting from that to where over time I think we can keep bringing those well costs down.
The only wildcard in there will be if commodity prices were to jump in if we got back into the.
Ultra high inflation Arena, then that would put some pressure against those efficiency gains, but I think we're going to continue to keep gaining on execution and the longer laterals.
Yeah I appreciate the answer Craig we'll watch with interest.
Bill our advanced income between any confidence is by suggesting that you're you've made no secret.
Secret after your desire for southwest wants to get bigger over time.
I've watched you skew your share price too I've set of the blip last year, the highest level in six years.
And obviously M&A is topical so I'm just curious if you could frame.
Whatever message do you think is appropriate how you see southwest one rule and M&A, especially in light of for example, the <unk> news this morning.
Thanks, Doug for that question.
As Ive said before well timed well executed well integrated M&A that add sustainable value to shareholders should be evaluated.
Our framework for creating shareholder value long term.
And what we've also demonstrated as is the fact that our three.
Well timed well executed well integrated.
Acquisitions in Haynesville in Appalachia.
Met those objectives, certainly that raises the bar and.
For quality, it's not just about getting bigger as your question, it's about adding real tangible sustainable value.
And capturing the benefits of the scale you create.
By by doing that in a very disciplined way so.
Given our assets our capabilities our people, we've got great confidence in the Companys value proposition, we've demonstrated that we know how to execute on our M&A.
M&A activity and do so in a strategic and real value creation manner. So.
Any particular deal that's out there or conversations out there as you also know we don't comment on those.
That's our thinking.
It's fair to say you see the logic in consolidation.
Under the circumstances that I spoke up yes.
Great. Thanks, Bill I appreciate you're navigating that one thank you.
And our next question today comes from Arun <unk> with Jpmorgan. Please go ahead.
Hello, Arun as you.
Your line muted perhaps.
Yeah.
Okay. It appears we do not have a model that we will move to next question, which is from Scott Hanold with RBC. Please go ahead.
Yes. Thanks.
Clearly you had mentioned getting those longer laterals in the Haynesville and can you give us some context on a couple of things one just your acreage configuration.
What does it allow for in terms of those longer laterals and and number two.
When you look at the Haynesville is there anything that we should consider giving it the depths and pressures where there is a limit to lender the benefits of lateral lengths in terms of getting recoveries out of a total of a longer ball say versus something like the Marcellus.
Definitely so I'll start with your second question I mean in the NFC area, there are going to be limits on lateral length due to the high temperature.
Remember, that's the highest producing area in the Haynesville best returns and so that's an area where I think we will live in.
7500, 9500 foot range and that one probably can't go.
With current technology much longer than that when we look at the different areas of our haynesville acreage position, which benefits from both of the acquisitions that we did where.
G O southern was a nice puzzle pieces fit into the indigo acquisition, which allowed for configurations, where we could do some longer laterals and then our team has done a great job of doing trades that also.
Fill in acreage so that we can go to these longer laterals as I mentioned in the script, we drilled two to right around 15000 feet. Those were in the northwest part of our acreage position northwest Desoto parish those areas are conducive to <unk>.
Drill 15000 foot laterals, and so I think across the field.
That's the range.
As anywhere from 7500 to 15000 foot and as we continue to progress on our execution in the Haynesville I think youre going to continue to see those lateral links.
But it'll be a methodical approach just like we did in Appalachia, well thought out and making sure that we understand all the parameters when were going longer.
Understood.
Follow up question is.
You know kind of going back to some of the where you start to bill on the macro you talked about the haynesville declining into early 'twenty, four but see a pickup in LNG exports by the end of 'twenty 'twenty four but then call that in talking about the strip not high enough incentivize any kind of growth.
When you step back and kind of think about big picture macro do you are you generally constructive in the macro backdrop, you think just the forward prices not reflecting that potential at this point in time. So if you can give us that kind of a little bit of color around some of the depth of that conversation.
Sure I'll take that one Scott.
Thank you for asking on a day when the market's up.
Obviously I believe validating.
We remain cautiously optimistic on the first half of 'twenty for pricing.
Constructed constructive on the second half of 'twenty, four and far more convinced on the upside potential for Cal 'twenty five and beyond.
Our optimism for the first half of 'twenty four stems from slowing production growth as you alluded to plus with strong power Burns we've seen the robust LNG demand that we've seen recently in the rising exports to Mexico.
Thats tempered somewhat of course by the winter weather forecast and the possibility that we could exit March with as much as one eight tcf in storage.
As we look at the second half of 2024 are constructive views informed by LNG demand thats likely to materialize much sooner than originally expected with both Plaquemines and Golden pass currently ahead of schedule and now reports that Corpus Christi expansion.
<unk> project could start pulling gas in late 2024.
By the time, we get to 2025, we see over four Bcf a day of incremental LNG demand in the clear need for higher prices to incentivize increased activity.
With even more LNG on the horizon.
As you've seen we've had this rally now in the deferred part of the curve with the.
The prompt month up <unk> week on week, but Cal 24 up 15 cents.
Cal 25 up 16 cents in Cal 26 through 28 up 17.
And that's been driven by strong power buying and the anticipation of the early startup of the LNG facilities that I mentioned when you add that all up.
We find ourself on the precipice of a paradigm shift in the U S market as a globalizers and we think there's greater connectivity will introduce increased risk premium and volatility, especially for those who can deliver gas reliably to the Gulf coast.
The demand will be.
Okay.
Okay.
Okay. Thank you and our next question today comes from Umana Chowdhry with Goldman Sachs. Please go ahead.
Hi, good morning, and thank you for taking my questions.
My first question was a follow up to Charles' question.
I guess you talked about a first half weighted activity next year.
With the potential to add few rigs if prices and outlook looks looks a little bit better.
I was wondering if you can further efficiency gains, which you have seen this year two rig plans next year to hold production flat year over year.
Yes.
Thought on that would be that with the.
Reduction in activity.
We did this year in the back half of the year.
The go forward 2024 plan and we haven't finalized that all right now we're continuing to watch where commodity prices are at and continue to balance the priorities that bill mentioned.
I think that the timing too.
Get all the way back to flat would mean, a pretty heavy start and pretty much flat activity throughout the year to get.
Get back to that place and we're going to need to see where commodity prices move through the winter to to understand that but I think it all it all labs, where the capital plan that's within the range that we've been talking about between two and $2 3 billion for the year.
That's helpful. Thank you.
And then as a follow up you talked about your optimism around 2025.
You have laid out plans to hedge 40% to 60% of your production.
Wondering if you can provide any color in terms of how you would approach hedging for 2025.
Yeah, absolutely I think Carl touched on it earlier in the idea of increasing our downside protection at levels.
At or above our key economic thresholds.
As an important tenant in our hedging strategy and with the move we've seen in the strip those prices are now available to us.
And lead us to shift our focus away from fixed price swaps to option structures that give us that downside protection, but then allow us that asymmetrical exposure to the upside. So we will use that view to inform how we enact our next tranche of Cal 2025 and beyond.
Hedging.
Also add.
That another key tenant of our commodity risk management has really been improvement.
Improve our balance sheet, and lower debt and lower debt levels have afforded us the opportunity to have this more moderate approach to hedging.
Both trends should continue.
Helpful. Thank you.
Thank you and our next question today comes from John Ennis from Stifel. Please go ahead.
Good morning, all and thanks for taking my questions.
For my first one looking at state data your Haynesville wells continue to meaningfully outperform the basin average can you share your views on what is driving this outperformance and how.
Sustainable you think that is on a go forward basis.
Sure I think the driver of it is the <unk> fault zone in the southeast part of our acreage, it's the highest pressure area in the field and.
The well performance.
<unk>.
Shown the quality that's there both from an initial production rate and from a <unk>.
Forecasted EUR standpoint, and so the other piece, though that I think is a contributor to that sustained performance has been that thats a newer part of the core of the Haynesville and so it doesn't have the right now the parent child relationship.
Issues, the well density issues that the traditional core of the Haynesville has so a relatively new area.
Highest bottom hole pressure and it's delivering that kind of well performance and so as you've noticed.
Our percentage mix of wells in that area has grown from about 25% in 2022 to closer to 50% in 2023.
Makes sense.
For my follow up maybe looking down the road towards 2025 once the debt targets are reached when you consider other mechanisms to return capital above the repurchase program already in place.
Yeah.
Yes of course, it would I think as we said all along.
Can you Reinitiate, if you will to share buyback given.
We believe our value is relative to our intrinsic value or at least our share prices to that.
Absolutely if we can sustainably generate free cash flow and we believe we will be able to see particularly with lower debt.
The way you cut it.
Through that if you will is to put in.
Some sort of base dividends that would be something that we certainly will consider.
I appreciate it.
Thanks again for taking my questions.
Thank you and our next question comes from Paul Diamond at Citi. Please go ahead.
Hi, Good morning, all and thanks for taking my call just a quick one stepping back to the.
Well cost reduction is expected next year noted, 50% in Haynesville and five in Appalachia I just wanted to get your idea of how we should think about that trend, whether it's linear through the year or more chunky areas kind of how youre thinking about how you get from a to b.
Sure So I think with the Haynesville.
Given the cycle times, there that we should be seeing that starting in the first quarter as we think about the wells that have already been drilled and that will come on turned in line in the first quarter.
How we've been able to forecast that and so as we move through the year dependent upon.
Where commodity prices are at we're going to be continuing to drive efficiency gains there well mix can move that around and we'll see what happens with.
If there is any inflation that comes into the mix.
With higher prices or pricing stays where we think it is and we can keep moving those costs down and Appalachia.
There is a little bit of differences in well mix in our overall Appalachian now it's not just all Marcellus wells in our number because we have dry gas Utica wells in Ohio.
Part of that averaging but.
But I think that one also should show up.
At the start of the year and the only reason it would move around would be some well mix changes between the quarters.
Okay.
Understood.
And just one quick follow up actually speaking about that kind of.
Choosing different areas for wells in Appalachia, how are you guys thinking about going into 'twenty for just more generally but that mix between you know liquids versus gas through the year.
Yes, our thought there is that it won't be materially different than how we played out 2023, where we got the benefit of liquids pricing.
As gas was lower we added some completions there when we came into the year on the margin that that all moved around.
Pretty pretty.
Evenly.
Where it was.
Change I think it was nine more wells to sales that we were thinking about in 'twenty three than what we had in 'twenty two.
But that would be the could be the size of what a move there would be where we're spending roughly <unk>.
Two thirds of our capital in Appalachia is going towards liquids rich wells and the other third towards dry gas and I don't I don't think that split would change much and we apply strip against.
The development plan proposals have come in and economics drive the answer.
High level.
Understood that extra clarity in the time that any of those.
Thank you and our next question comes from Arun <unk> with Jpmorgan. Please go ahead can.
Can you hear me now.
Yes, Sir good morning.
The second Time's, a charm sorry about that earlier I'm, just I wanted to see if I could.
Maybe her split a little bit with clay on his outlook comments on 2024 play if I heard you correctly you mentioned how.
Consistent with historical patterns production would be declining a bit as you moved into the first half of the year, but the second half should be at similar levels to today and I just wanted to my hair splitting here is that the third quarter you delivered 425 Bcf of production.
In the fourth quarter guide is for 10. So I just wanted to see if you are where you're thinking about the second half being closer to the 410 or the 425.
Yes, so closer to the 425 is what we are guiding to there and kind of the way I answered that other question Youre seeing in that drop off from <unk> 425 to <unk> 410, the activity reductions that we.
<unk> to the year to navigate through the price cycle and then when you think about the cycle time on those Haynesville wells, which is a five to six months spud to turn in line, that's where as we ramped production back our activity back up that will start showing up in the second half of next year.
Okay, that's super helpful.
And.
As you think about kind of lateral footage I mean you.
You're expecting flat kind of capex any sense of how much more footage you could do.
You know next year given that.
Meaningful reductions in Haynesville costs.
We haven't finalized the well mix and the order and all of that yet, but I think in both areas. It can be in the order of 500 to 1000 feet of longer average lateral length.
Okay. That's helpful. Thanks, a lot.
Sure. Thank you and our final question today comes from Noel Parks with Tuohy Brothers. Please go ahead.
Hi, good morning.
Good morning, good morning.
I apologize if you touched on this before but.
I'm just wondering as you accumulate more data.
The Saudi East isn't there.
Eastern part of your acreage.
Some of those.
Those first wells out there.
Any sort of refinement G understanding.
Any surprises any anything that.
Are you just being able to to learn from.
A little bit longer performance data.
Well if I fully understand your question I mean, the learnings has been.
Keep in mud properties in as good a shape as we can and trying to keep bottom hole temperature.
The tools as low as we can so that we could extend run times and get to some some longer laterals in the play that's been what we've been working on operationally and we've been continuing to have success in that space.
As it relates to the well performance.
We felt like it was going to be on the high end. It was part of our original acquisition evaluation and it's performed in line with what we would we thought it would do there is varying flat periods across the <unk>.
Crudes, where some stay flat for a longer period of time, four or five months. Some stay flat two to three months before they start to decline and so maybe that's some learning there.
But overall.
Kind of the main things that we've absorbed that that we're utilizing as we go forward to keep making improvements there.
Great. Thanks.
Just thinking about just some of them, having a longer flat period than others.
Is that entirely geologically driven or is there anything as far as just the.
The rate you perform a matter.
Chokes, you use that alters that.
As far as you know so far.
I think the biggest driver is the combination of the bottom hole pressure and the effectiveness of the completion and the continuity of the prop.
Fracs that we've put on the well and maintaining that continuity.
Great makes sense, thanks, a lot.
Thank you and ladies and gentlemen. This concludes our question and answer session I'd like to turn the conference back over to the management team for any closing remarks.
Thank you all for joining the conversation on <unk> performance today, we really appreciate it and we look forward to you joining again as we continue to deliver shareholder value on.
On a sustainable way.
You all have a great weekend and well talk soon thanks.
Thank you. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.