Thank you. Good morning.

And welcome to Southwestern Energy's third quarter 2023 earnings call. Joining me today are Bill Way, Chief Executive Officer; Clay Carrell, Chief Operating Officer; Carl Giesler, Chief Financial Officer; and Dennis Price, Senior Vice President of Marketing & Transportation.

Before we get started, I'd like to point out that many of the comments we make during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual report and quarterly reports as filed with the Securities and Exchange Commission.

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance. Actual 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 to 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.

I will now turn the call over to Bill Way.

Thank you, Brittany, and good morning, everyone. We appreciate you joining us today to discuss our third quarter operating and financial results.

Before I begin, I’d like to express my thanks to our dedicated team of constantly 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 Company's productive capacity. We believe we have materially improved our capital efficiency and positioned 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 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 in the strengthening macro view.

Beyond reduced activity and the slowdown in supply growth that suggests LNG exports are up over 2 Bcf per day year-over-year, recently exceeding 14 Bcf per day, while weather adjusted power demand is up 2 Bcf a day and exports to Mexico are up almost 1 Bcf a day. These factors have helped to significantly dampen the end-of-season storage surplus with new LNG in service dates beginning next year.

By the end of '24, 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 tenets was firm access to markets of choice.

Both of our Haynesville acquisitions included strategic connectivity to advantaged markets along the Gulf Coast, including to 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 exporters.

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 of progressing towards the $3.5 billion 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 will continue to optimize investment with the optionality to add back in the back half of '24, should market fundamental support. We believe this approach to managing the business in a volatile commodity environment is prudent and will best position SWN to sustainably return capital to shareholders.

Our hedging strategy helps to ensure debt reduction while also providing upside commodity risk exposure, as we move through 2024 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 the third quarter, our basis hedging program helped to offset wider Appalachia basis differentials and we expect to continue layering on additional protection for future periods as we look to next year. While commodity prices in '23 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 non-core 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 are 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, we are well-positioned to build on the successes of '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 Bcfe during the third quarter, consisting of 4 Bcf per day of natural gas and 104,000 barrels per day of liquids, including over 14,000 barrels per day of oil production. During the quarter, we invested $454 million capital and placed 23 wells to sales.

In Appalachia, we placed 15 wells to sales with an average lateral length of more than 16,200 feet. This included a company record long lateral in Brooke County, West Virginia with a completed lateral length of over 24,000 feet.

That well is our 25th producing well in Appalachia with lateral lengths greater than 20,000 feet. Of the total wells to sales in Appalachia this quarter, 11 ran our liquids-rich acreage in West Virginia and 4 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 15,000 barrels per day. In Haynesville, we placed 8 wells to sales, with an average lateral length of approximately 9,100 feet.

6 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 in case 2 of our longest laterals to-date at approximately 15,000 feet.

Capital investment for the quarter came in below expectations, driven by some minor changes in our development program that shifted activity into 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 are 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 are 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 2024 moderating a bit, but overall, we believe cost should be down next year.

We expect to lower Haynesville well costs approximately 15% to $1,800 per foot next year and see the potential for 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 $2 billion to $2.3 billion, and increased activity offsetting deflation and efficiency gains.

Our capital program is typically front-end loaded with higher capital investment in the first half of the year, resulting in higher production in the second half. Next year, we’ll 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, Clay. Consistent with our front-end weighted development program, capital investment stepped 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 capital reversals, resulting in a small increase to our revolver borrowings 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 from the $4.4 billion 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 2024 or early 2025, after which, we plan to complement continued debt reduction with sustainable return of capital to shareholders. While leverage has ticked up modestly to 1.6 times due to the price impact on trailing EBITDA, we fully expect to return to our targeted 1.5 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 protection at or above our key economic thresholds, including enterprise free cash flow breakeven levels, while also allowing for asymmetric upside participation.

This practice also preserves for our shareholders the benefit but the higher relative operating torque of our dual basin 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.

Yes. Good morning, Bill, Clay and Carl and to the rest of the Southwestern team there.

I wanted to follow up on your prepared comments about '24 and also especially in light of what Clay offered on the cadence for '24. So, Bill, I think I heard you say that there's a possibility to add activity in the back half of '24, if prices warrant.

And Clay said, we're going to have the usual front-end-loaded capital program in '24. So, if I put those two pieces together, does that mean that the base case is the front-end-loaded capital program leading to roughly flat volumes year-over-year, and that there's a possibility to add perhaps a rig or maybe even two rigs in the back half of the year that would then bias you towards the high end of that capital guidance range.

Is that the right way to think about it?

Yes. And Clay, layer comments in on this.

Yes, 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 priorities that we would be able to both, again, reduce debt, but also look at production levels overall for the year to be -- to still -- or to be estimated right around the -- like the end of '22.

Yes. So, Charles, you're right that that shape will be kind of growing through the year in 2024 tied to, we believe, very constructive commodity price going into 2025, maybe that happens earlier in '24, and we have the optionality within the program to take advantage of that as we balance all the priorities of the company.

But we're well positioned if commodity prices play out that way.

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 comment about the 24,000 foot lateral in Appalachia.

I wonder if you could talk a little bit more about that. Obviously, it's an achievement to successfully get off a lateral that long.

But I wondered if you could talk about what you're seeing as far as productivity from that well. And if it encourages you to do more of these or even try to extend further or alternatively that maybe max out around 20, just give us the bigger context there.

Sure. We've been pretty methodical over the years, maybe earlier than others in Appalachia, where we've been extending our laterals.

Our average program is around 16,000 feet this year where we recognize the benefits of the loner lateral zone, lowering well costs and enhancing economics. And I think 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 Brooke County.

The production from the well on a 3-phase initial production was a little over 27 million cubic feet equivalent a day. Included in that was close to 1,700 barrels a day of condensate.

And so, a typical really highly economic well in our liquids-rich Appalachia that we're able to get even greater economic benefits by going longer. The well was drilled in 19.5 days spud to rig release for over 30,000 foot measured depth.

And it has obviously benefited by our vertical integration assets. We're using our company rigs.

The well was fracked with our company frack 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 20,000 foot lateral length that that program has been working for us for a while.

And given they’re SWN employees, knowledge transfer well to well and the application of knowledge and learnings is quite high.

I'm doing a little bit of acreage pinpointing here, but it looks like you guys have some Eastern Guernsey acreage and one of your peers is now touting a high liquids cut location count there. So I just wanted to address do you guys have an inventory count there?

Are you seeing similar things on your acreage? And I know it's not a large part of your portfolio, but maybe how many locations we might expect next year or a run rate?

Yes. So, we're very knowledgeable about the area.

In our minds, it's a continuation of the geology through the product windows of the liquids-rich acreage that we have in Southwest Appalachia, and it's -- some of it is indicative of the type of well performance we've been delivering in our liquids-rich assets. So, not a surprise to us.

We are drilling a pad there. Currently, we don't have a large acreage position there, but we have the largest acreage position and the highest-yielding liquids-rich acreage in West Virginia with our position there.

And so, we like it. It continues to have very resilient economics, as you move through the price cycles.

That's great. And then just the 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, does pricing change that?

Or is there an evolution of the negotiations out there that are maybe making it more attractive for you?

Sure. I'll take that.

As you know, we're 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're 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. It's 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 priced 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, we're currently the largest supplier of natural gas to LNG exporters, and we intend to retain and potentially grow our portfolio of Henry Hub based 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 we're taking a slightly different approach targeting binding transactions on post-FID facilities as opposed to nonbinding HOAs with facilities that may or may not have reached FID yet. And so, as I suggested, that does raise the bar on the complexity of the negotiation.

So, I think our disciplined approach explains why we're moving at the pace we're moving. And when we do enter into a deal, you'll know that we will have the tools to evaluate the risk and manage it.

I hope I've got a couple of questions. One of them, I'll ask in as delicate a manner as a possible.

But Clay, maybe I can go to you first. The reduction in capital in the Haynesville, 15% drop in well costs, $1,800 per foot, a big step down.

Obviously, you've signaled to us that that could be on the cards. But I'm curious if there is -- if this is a deflationary move?

Is it a well-designed change? 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, and we expect to continue to achieve on the drilling and completion side of the business, it is reduced inflation and it is longer laterals. And so, the kind of the same recipe we've always used and 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 commodity prices were to jump.

And 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.

I appreciate the answer, Clay. We’ll watch with interest.

Bill, I don't think I'm betraying any confidences by suggesting that you've made no secret of your desire for Southwestern to get bigger over time. And I watched you steer your share price to outside of the book last year, the highest level in six years and M&A is topical.

So I'm just curious if you could frame in whatever method you think is appropriate, how you see Southwestern role in M&A and especially in light of, for example, the [indiscernible] news this morning.

Thanks, Doug, for that question. I think as I've said before, well-timed, well-executed, well-integrated M&A that adds sustainable value to shareholders should be evaluated against the framework for creating shareholder value long term.

And what we've also demonstrated is the fact that our three well-timed, well-executed, well-integrated acquisitions in Haynesville and Appalachia met those objectives. Certainly, that raises the bar 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 doing that in a very-disciplined way.

So, given our assets, our capabilities, our people, we've got great confidence in the Company's value proposition. We've demonstrated that we know how to execute on M&A activity and do so in a strategic and real value-creation manner.

So, any particular deal that's out there or conversation out there, as you also know me, we don't comment on those, but that's our thinking.

Fair to say you see the logic in consolidation?

Under the circumstances that I spoke of, yes.

Clay, 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 number two, when you look at the Haynesville, is there anything that we should consider giving the depth and pressures where there is a limit to -- the benefits of lateral lengths in terms of getting recoveries out of the toe of a long -- say versus something like the Marcellus?

Definitely. So, I'll start with your second question.

I mean in the NFZ 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 the 7,500 to 9,500 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 GeoSouthern was a nice puzzle piece 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 2 to right around 15,000 feet.

Those were in the Northwest part of our average position Northwest DeSoto Parish, those areas are conducive to drill 15,000-foot laterals. And so I think across the field, that's the range is anywhere from 7,500 to 15,000 foot.

And as we continue to progress on our execution in the Haynesville, I think you're going to continue to see those lateral lengths growth. But it will be a methodical approach, just like we did in Appalachia, well thought out and making sure that we understand all the parameters when we're going longer.

Understood. And my follow-up question is, kind of going back to some of the -- where you started Bill in the macro.

You talked about the Haynesville declining into early '24, but see a pickup in LNG exports by the end of 2024. But then call that in talking about the strip, not high enough to 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 price is not reflecting that potential at this point in time. So, if you can give us a kind of a little bit of color around some of the depth of that conversation.

Sure. I'll take that one, Scott.

And thank you for asking on a day when the market is up. It's oddly validating.

We remain cautiously optimistic on the first half of '24 pricing, constructive on the second half of '24 and far more convinced on the upside potential for CAL-25 and beyond. Our optimism for the first half of '24 stems from slowing production growth, as you alluded to, plus the strong power burns we've seen the robust LNG demand that we've seen recently and the rising exports to Mexico.

That's tempered somewhat, of course, by the winter weather forecast and the possibility that we could exit March with as much as 1.8 Tcf in storage. As we look at the second half of 2024 our constructive views informed by LNG demand, it's 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 project could start pulling gas in late 2024.

By the time we get to 2025, we see over 4 Bcf a day of incremental LNG demand and 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 prompt month [ph] up $0.04 week-on-week with Cal-24, up $0.15, Cal-25, up $0.16, and in Cal-26 through -28 up $0.17, that's been driven by strong power buying and the anticipation of the early start-up of the LNG facilities that I mentioned.

When you add that all up, we find ourselves on the precipice of a paradigm shift in the U.S. market as it globalizes.

And we think this greater connectivity will introduce increased risk premium and volatility, especially for those who can deliver gas reliably to the Gulf Coast where the demand will be.

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 have your rigs if prices and outlook looks a little bit better.

I was wondering if you can compare the efficiency gains which you have seen this year to rig plans next year to hold production flat year-over-year.

Yes. My thought on that would be that with the reduction in activity that we did this year and the back half of the year, the go-forward 2024 plan -- and we haven't finalized that at 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 to get all the way back to flat would mean a pretty heavy start and pretty much flat activity throughout the year to get back to that place, and we're going to need to see where commodity prices move through the winter to understand that.

But I think it all lives with a capital plan that's within the range that we've been talking about between $2 billion and $2.3 billion for the year.

And then as a follow-up, you talked about your optimism around 2025, and you have also laid out plans to hedge 40% to 60% of your production. I was wondering if you can provide any color in terms of how you would approach hedging for 2025.

Yes, absolutely. I think Carl touched on it earlier, and the idea of increasing our downside protection at levels at or above our key economic thresholds is an important tenet 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-20 25 [ph] and beyond hedging.

I mean I'd also add that another key component of our commodity risk management has really been to improve our balance sheet and lower debt. And lower debt levels have afforded us the opportunity to have this more moderate approach to hedging and lower churn should continue.

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 Natchitoches Fault Zone in the southeast part of our acreage is the highest pressure area in the field, and the well performance has shown the quality that's there, both from an initial production rate and from a forecasted EUR standpoint.

And so, the other piece though that I think is a contributor to that sustained performance has been that that's a newer part of the core of the Haynesville. And so, it doesn't have 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, would you consider other mechanisms to return capital above the repurchase program already in place?

Of course, we would. I think as we said all along, we'd probably continue, reinitiate, if you will, share buyback, given what we believe our value is relative to our intrinsic value or at least our share prices to that.

But absolutely, if we can sustainably generate free cash flow and we believe we'll be able to, particularly with lower debt, the way you kind of prove that, if you will, to put in some sort of base dividend. So that would be something that we certainly would consider.

I’d ask a quick one, stepping back to the well cost reductions expected next year, noted 15% in Haynesville, 5% in Appalachia. Just wanted to get your idea of how we should think about that trend, whether it's linear through the year or more chunky, or just kind of how you're 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, turn in line in the first quarter.

That's how we've been able to forecast that. And so, as we move through the year, depending 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's 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. In Appalachia, there is a little bit of differences in well mix in our overall Appalachia.

Now it's not just all Marcellus wells in our number because we have dry gas Utica wells in Ohio that are part of that averaging. 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.

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 to '24, just more generally, but that mix between 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 all moved around pretty evenly to where it was a change.

I think it was 9 more wells to sales that we were thinking about in '23 than what we had in '22. But that would be the -- could be the size of what a move there would be.

We're spending -- roughly two-thirds of our capital in Appalachia is going towards liquids-rich wells and the other third toward dry gas. And I don't think that split would change much.

And we apply strip against the development plan proposals that come in and economics drive the answer at a high level.

I wanted to see if I could maybe hair split a little bit with Clay on his outlook comments on 2024. Clay, 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 Bcfe of production and the fourth quarter guide is 410. So I just wanted to see if you -- were you thinking about the second half being closer to the 410 or the 425?

Yes. So, closer to the 425 is what we're guiding to there.

And kind of the way I answered that other question, you're seeing in that drop off from 3Q's 425 to 4Q's 410 the activity reductions that we applied 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 5- to 6-month spud to turn in line, that's where as we ramp production back up, 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're expecting flat kind of CapEx. Any sense of how much more footage you could do next year, given the pretty meaningful reductions in Haynesville costs?

Yes. We haven't finalized the well mix and the order and all that yet.

But I think in both areas, it can be in the order of 500 to 1,000 feet of longer average lateral length.

I apologize if you touched on this before, but I'm just wondering, as you accumulated more data out in DeSoto Eastern part of your acreage from those first wells there. I was wondering any sort of refinements to your understanding, any surprises, anything that you’ve just been able to learn from a little bit longer performing data?

Well, if I fully understand your question, I mean, the learnings has been keeping mud properties in as good a shape as we can and trying to keep bottom hole temperature at the tools as low as we can, so that we could extend run times and get to 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's varying flat periods across the acreage where some stay flat for a longer period of time, 4, 5 months, some stay flat 2 to 3 months before they start to decline. And so, maybe that's some learning there.

But overall, that's kind of the main things that we've absorbed that we're utilizing as we go forward to keep making improvements there.

Great. That is interesting 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 rate you perform at or chokes you use that alters that as far as you know so far?

Yes. I think the biggest driver is the combination of the bottom hole pressure and the effectiveness of the completion and the continuity of the propped fracks that we put on the well and maintaining that continuity.

Thank you all for joining the conversation on SWN's performance today. We really appreciate it, and we look forward to you joining again as we continue to deliver shareholder value on a sustainable way.

You all have a great weekend. And we'll talk soon.

Thanks.