Southwestern Energy Company

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Southwestern Energy's first quarter 2023 earnings call. Management will open the call for a question and answer session following prepared remarks. In the interest of time, please limit yourself to two questions and re-queue for additional questions. This call is being recorded. I will now turn the call over to Brittany Rayford, Southwestern Energy's Director of Investor Relations. You may begin.

Thank you. Good morning, and welcome to Southwestern Energy's first quarter 2023 earnings call. Joining me today are Bill Way, Chief Executive Officer, Clay Carroll, Chief Operating Officer, and Carl Giesler, Chief Financial Officer. 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 risk 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 statement 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 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 available on our website. I will now turn the call over to Bill Way.

Thank you, Brittany, and good morning, everyone. Thank you for joining today. At Southwestern Energy, our approach to sustainable value creation is clear and consistent. Apply capital and cost discipline to a portfolio of advantaged assets in the two premier natural gas basins in the United States. We are focused on large-scale core tier one natural gas and gas liquid assets where we can leverage our operating and commercial strengths and safely and responsibly deliver lower carbon natural gas to premium markets and generate superior economic value for our shareholders. Southwestern Energy's strong first quarter performance reflects the quality of our dual-basin scale, portfolio optionality, and differentiated market access. We delivered above-target operational results with production at the high end of guidance and generated approximately $100 million of free cash flow to repay debt, consistent with the priority of debt reduction in our disciplined capital allocation strategy. Additionally, we are driving improvement in capital efficiency. In the first quarter, we continued to improve cycle times, yielding approximately 100 additional producing days during the quarter. Our strategic supply chain sourcing group has been successful in offsetting a portion of the inflationary cost pressure we expected at the beginning of this year. These efforts, in addition to our continued capital efficiency improvement drive, allows us to optimize our capital spend to align with cash flow while minimizing the impact to both production this year and the ongoing productive capacity of our business going forward. We are increasingly confident that the high service cost environment will continue to subside over the coming quarters, further strengthening our long-term free cash flow outlook. Despite the near-term commodity price weakness due to relatively high inventory levels following a record warm winter, we continue to see strong structural support for natural gas. On the supply side, U.S. production has remained essentially flat since late last year, and we have seen and expect to continue to see a decline in the gas-focused rig account and associated . We believe that near-term activity reduction will result in lower natural gas production this year, further strengthening the longer-term fundamental outlook. On the demand side, with Freeport back at full capacity, LNG exports have returned to record levels of approximately 14.6 BCF per day, supplementing persistently strong power burn. Flow assurance to markets of our choice is a critical pillar of our strategy. We have transportation agreements in place to deliver 65% of our total natural gas production to the growing Gulf Coast Demand Center, where we are currently the largest supplier of natural gas directly to LNG facilities at 1.5 BCF a day. With Port Arthur LNG reaching FID last month, we now see nearly nine BCF per day of new LNG export capacity that is in progress, and with some starting to come online as early as late this year. Our favorable access to the Gulf Coast positions Southwestern Energy to supply growing demand from both Hainesville and Appalachia. Given this positioning, we continue to receive strong interest and remain in active discussions for further LNG supply agreements. including proposals with internationally indexed pricing. As we shared in our guidance in February, we adjusted activity in response to lower long near-term natural gas prices by removing capital from our program and increasing our level of liquids-rich development this year. Guided by our discipline capital allocation strategy and our priority of funding development within cash flow, we continue to moderate our planned activity. These prudent adjustments are primarily focused on decreasing dry gas completion activity, including releasing a frack fleet in Haynesville, while maintaining our higher liquids-rich activity level in West Virginia and Ohio. This capital and operational flexibility highlights the strategic value of the optionality within both our development plan and our asset portfolio, as well as the logistical agility of our vertically integrated business model. With this flexibility, we can quickly respond to commodity price signals throughout the year while preserving the productive capacity of our business going forward. The highly successful Hainesville integration and first-year results clearly support confidence in our ability to execute on the company's multi-year strategy to create long-term shareholder value. We continue to capture the tangible benefits of our larger-scale dual-basin portfolio

are well positioned to capitalize on the strong long-term fundamental outlook for natural gas i'll now turn the call over to clay for some additional operational updates thank you bill and good morning the team started the year strong with first quarter production at the high end of guidance well performance and cycle time improvements in both appalachia and haynesville drove this out performance In total, we reported 411 BCFE of net production or 4.6 BCFE per day, including 3.9 BCF per day of natural gas and 107,000 barrels per day of liquids. We placed 36 wells to sales in the first quarter. In Appalachia, we placed 13 wells to sales with an average lateral length of just under 15,000 feet. This included 11 wells in the Super Rich Marcellus and two in the Dry Gas Marcellus. Notably, we placed to sales our first pad of Monroe County, Ohio, Super Rich Marcellus wells, which are performing in line with expectations and is confirming its competitiveness with our West Virginia Super Rich Marcellus acreage. Since we acquired Montage in 2020, We have been successfully developing our Utica dry gas inventory. This year's addition of liquids-rich activity to the development plan in Ohio further illustrates the depth, quality, and commodity optionality within our Appalachia portfolio. In Haynesville, the team placed 23 wells to sales, including 15 in the Middle Bossier and eight in the Haynesville, with an average lateral length of approximately 8,200 feet. The strong initial production rates we saw in our first year in the Haynesville have continued, with an average rate of 35 million cubic feet per day for wells placed to sales in the first quarter. On the operational efficiencies front, we are on track for our anticipated cycle time improvements. In our first year of operations in the Haynesville, we delivered 10% improvements to both drilling and completed footage per day and expect a similar 10% improvement this year. During the quarter, completion efficiencies drove accelerated turn-in lines, resulting in three more wells to sales and additional producing days, which contributed to our production performance. In the first quarter, we saw positive signs of inflation moderation. Our team is actively pursuing cost reductions while maintaining supply security. Supply and demand for OCTG has balanced with cost and availability clearly improved versus last year. On the completion side, we've also seen softening on frac horsepower costs. With these tailwinds, we are confident in our plan to drive well costs down throughout the year, especially in the Haynesville. As Bill mentioned, we are optimizing planned activity to align capital investment with expected annual cash flow at current strip prices. As a result, we expect to invest near the low end of our $2.2 to $2.5 billion annual capital guidance range, with cost inflation and capital efficiency improvements complementing activity reductions. We are delaying completion activities in our dry gas areas including the release of an additional frac fleet in Haynesville beginning in mid-May and the release of a frac fleet in Pennsylvania earlier than planned. We expect these activity adjustments to result in second quarter capital spend slightly lower than the first quarter, with most of the capital reduction occurring in the second half of the year. We have built flexibility into the program to add back this activity later in the year should prices or our expected cash flow improve. If this activity is not phased back in, we would expect to have 10 to 15 less dry gas completions and wells to sales than our current well count guidance. The completion delays are expected to result in a modest production impact in the second half of the year and a flatter quarterly production profile. Operationally, we have started 2023 strong and are focused on continuing to drive further efficiencies to optimize cash flow. Now I'll turn the call over to Carl.

Thank you, Clay. In the first quarter, we generated approximately $100 million of free cash flow. Together with seasonal working capital inflows, which typically reverse through the year, we reduced debt from $4.4 billion at year end to $4.0 billion. Leverage improved 1.2 times, though we expect leverage to increase as we move through the year. In February, we redeemed all of our outstanding 7.75% senior notes due 2027, following through on our previously communicated debt reduction plan and path to return to investment grade. Turning to hedging, We have capitalized on the high level contango in the strip by securing a base level of protection for 2025 using collars to preserve upside participation. We have also taken advantage of near record high volatility to convert collars to swaps and modestly raise our 2023 floor price. We are managing the business through the commodity price cycle to improve our financial strength and preserve our productive capacity to take advantage of the constructive, longer-term outlook for natural gas. With that, please open the poll.

We will now begin the question and answer session. To ask a question, you may press star, then 1 on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. And to withdraw a question, please press star, then 2. Again, we ask that you please limit yourself to two questions for today's call. If you have additional questions, you may rejoin the queue. At this time, we will take our first question, which will come from Charles Mead with Johnson Rice. Please go ahead with your question.

Good morning, Bill, Clay, and Carl. Thank you for taking my question. Bill, the question for you, could you give us some insight into how you are going to go about deciding when to complete the wells where you're deferring completion. I think Clay spoke a bit to it about it. Obviously, price would be a part of it, but is there a length of time that you have in mind right now, or is there a price? Maybe just elaborate on your thought process there.

Yeah, so I'll start that off. The hope would be that commodity prices and cash flow would improve, and then we could move quickly to do those completions, whether they're sometime in the third quarter or the fourth quarter of the year. But that will all be driven by where cash flow is at and what commodity prices are doing. But with our own frac fleets and with the ducks that these are creating, we will have that optionality to move very quickly and go forward with these completions. But right now, with where current prices are at, it's a 10 to 15 completion reduction that'll show up in the second half of the year.

And if that reduction stays in place, then they'll roll into 2024, obviously, and be a part of that program.

So if I understood correctly, it's not just where the price goes, but it's also Southwestern's overall free cash flow or your outspender free cash flow position is another piece of the... Yeah, let me pick one word up and move it out of the way.

We have no intention of outspending our cash flow. So we'll moderate our activity... in concert with all of the efficiency gains, the lower costs, the performance improvements, and continue to optimize that program against the cash flow that we have available. And so from an economic perspective, these wells are economic. They meet our criteria. It's really not an issue with that. It's more a focus on the discipline around capital allocation and investing within cash flow.

Got it. And then if I could just pick up the thread of service cost reduction. Clay, you already gave us some detail there with frack horsepower and OCTG. But I wonder if you could perhaps elaborate a little bit more from the perspective or the differentiated perspective you have of also running service assets. But what gives you that confidence or what are you seeing that gives you the confidence that service costs will come in a bit?

Well, to begin with, we've updated contractual arrangements that are locking those improvements in where we utilized our openers at the end of the first quarter. We proactively went back to all our service providers as we saw the price reduction in January to solicit reductions. And we've made good progress so far, which is, helping with this capital move into the low end of the guidance that not all of that capital reduction is coming from activity cuts. It's coming from some inflation moderation also. Like a lot of folks have talked about, OCTG is a big mover. We've seen reduced pressure pumping costs as part of the opener process. And then diesel is another component that those costs have come down. Our efforts are going to continue to stay strong in that space, that we need to bring these costs down and get them more in line with the commodity price environment, and we think there will be more opportunities to do so.

Thank you for that detail, Bill and Clyde. Sure.

Our next question will come from Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Yeah, thanks. Good morning. If I could just touch base on just sort of this adjusted plan to defer activity. If you step back and look at your 2023 overall budget, you know, based on where STRIP is right now, would the intent to be you're still within your CapEx guidance and your production guidance, albeit at the lower ends, would be kind of the first part of the question. Then the second one would be, you know, what happens if, you know, gas prices degrade a little bit more through the course of the year? Like, what would be the next actions?

Sure. So, I think a key point of what you said is, yes, we're currently within the guidance range on capital and production. We're at the low end of that range on capital and just below the midpoint on production right now. If we see further commodity price reductions then we will continue to be proactive in where we could take further adjustments. Like I said earlier, though, hopefully some of those capital improvements could come from further inflation moderation gains, which wouldn't impact activities, but we have identified where those next round of activity cuts would come from. There could be some more dry gas reductions on the completion uh side in uh southwest app some dry gas drilling reductions in northeast app and then in haynesville we would potentially do a mix of both drilling and completion uh slowing down if need be so we we have a plan we're we're hopeful that um we're going to be able to find some of those reductions without having to cut activity and that commodity prices will firm up.

And that whole plan is optimized fairly continuously and the output being capital required versus cash flow generated and making sure that we stay within cash flow with our investments.

Okay. It sounds like you guys have a lot of knobs and dials that you're working pretty aggressively here. So it's good to hear. My follow-up question is just on the productive capacity. And, you know, Bill, I think this has been a, you know, very strong point you've been making. You want to kind of maintain as much of that productive capacity as possible, especially looking into 24, 25, you know, potentially improving macro. So, you know, at a high level, like, can you give us a sense of like, you know, what, you know, do you think any of these actions you've done so far, um reduces your productive capacity and and just give us again a sense of like where you think that level is for southwestern's assets right now is it is it still around that 4.7 bcf per day yeah i think that what you've heard us talk about is is um is really um a a well-balanced two-year plan that talks about uh taking capital out in 23

having that capital result in a modest reduction in production, but that we are able to move into 24 and maintain a manageable ability to invest again within cash flow and drive, arrest any decline that is present. I mean, one of the reasons you know, taking a huge amount of capital and a huge production hit, the cost to kind of restart that engine is quite, it can be quite high. And so we've optimized this. Certainly the benefit of inflation coming down, the optimization of the development plan, and the knobs as you show it, we're able to kind of shape the program going forward and minimize that impact on the productive capacity feeding into a higher gas price environment.

Okay. Okay. So you feel pretty confident. You've really minimized the amount of restart costs. And so that's not an issue as we look into 24 right now.

That's right. And there's a number of proof points that can back that up, which is really the things that we've talked about on inflation, efficiencies, et cetera. And you add to that, one other item, you add to that in our dual basin position where we're able to pivot activity to liquids producing inventory, you're helping offset some of that as well.

Right. Right. Got it. Thank you. And our next question will come from Doug Leggett with Bank of America. Please go ahead with your question.

Thank you. Good morning, everyone. Thanks for having me on. Bill or Carol, I'm not sure which of you would like to take this, but I want to kind of preface the question by talking about your well costs in the Haynesville. You've talked, I think Clay talked about driving down well costs, reducing drilling days, which were all a bit, if I recollect, somewhat aspirational in the targets you laid out at the analyst day. And it sounds like you're already achieving some of those. So I guess my question is how much of the capital cost guidance that you talked about is, is permanent costs that you're taking out through efficiency. And what would that mean for your maintenance capital as you look forward into that post 2023 activity level?

So maybe I'll jump in there just at the start, Doug, when we think about the inflation moderation that we've seen that that analyst day set of annual capital had some further inflation assumed in that in the out years we don't see that now and so when you take into account inflation moderation for full years now and the ongoing efficiency gains that were not all baked in somewhere but not all of them that there's about $150 to $200 million annual capital spend reduction in those out years versus what we showed in the analyst day.

That's pretty much the answer I was looking for. Go ahead, Carol, please. That's not an immaterial number, Carol.

I mean, if you translate that to the free cash flow guidance we gave over the next, call it five years, well north of a billion dollars.

Thanks, Carl. That's what I was looking for, Clay. I appreciate the input. My second question, Bill, is really more a macro question, if you don't mind. You have relatively small non-operated working interest in the Hanesville, I guess, 2% or 4%, if I recollect. But that probably gives you some insight to ASEs for the general industry, I'm guessing, privates in particular. You talked about your own activity level. What are your expectations for the industry activity level in the Haynesville? Because it's obviously a big input to folks who are the micro at this point. I'll leave it there. Thank you.

Doug, I'll jump in there again. I think the good news on some of the rig count information in the Haynesville where we started the year with our industry with around 72 rigs and based on some Baker count updates that we got recently, that's dipped down to 64. So that's an eight rig drop right there. It's in line with what we thought would happen, that it would take a little bit of time for that to show up in the public data. It's showing up, uh, internally, we think maybe there'll be a 15 to 20 rig drop for the full year in the Hainesville. There's some other industry publications that are pointing to as high as 20 to 30 rig drop in the Haynesville. So we think it's going to continue, and it's consistent with the way we thought about it that those drops are starting to show up now.

And then you have the publics, and the publics have pulled back as well. So I think at the end of the day, a lower rig count with some requisite production leveling off or declining, depending on who you are, if the private's were in growth mode. The publics were in maintenance mode, so they'll have varying results from that point of view.

Really helpful. Guys, before I jump, I just want to clarify my first question. Carl, did you say we basically then have a billion dollars added back to the free cash flow? Did I hear you right on that?

More than. Got it.

Thanks, fellas. Appreciate it.

Price health, inflation, and this compounding effects and the reductions in capital efficiencies that Clay talked about.

Thanks a lot. Our next question will come from Arun Jayaram with J.P. Morgan. Please go ahead with your question.

Yeah, good morning, gentlemen. I want to better understand, maybe from you, Clay, the planned reductions in CapEx. The midpoint of your guidance range from last night is still $2.35 billion. I think you're indicating that you'll get down to $2.2 by deferring 10 to 15 completions. I just wanted to see if you can confirm that and maybe give us a sense of what actions you're taking today to take out $150 million of capital out of the budget. It sounds like you're moving one completion crew out of the Haynesville and is that the change and then maybe removing one additional crew from Appalachia a little bit earlier than you previously had is that I just want to go through those moving pieces yeah so you have that right I think your opening comment that we're down toward the low end of that original capital guidance range is correct

The one thing I want to make sure you understand, it's not all activity reductions that are driving the capital down there. There's a nice benefit, plus approximately 40% of that reduction is coming from the inflation moderation that we have already realized. Hopefully there will be more of that as we move through the year, but that's the basis for the 150. And then as you think about actions, We've already made the notifications to service providers around those cuts and the timing of those cuts. And when you think about the original guidance and what we're talking about today, that May-ish reduction of a frac fleet in Haynesville that would have gone to the end of the year is over a half a rig fleet when we think about our averaging. And then you mentioned that we cut one loose earlier than we had originally planned. So, you know, it's another .7 of a frack fleet that's going away versus the discussion that we had in February.

Great. That's helpful. Bill, one for you. You left us a little morsel on LNG indicating that there may be a LNG facility that comes on early. I think you mentioned later this year. I don't know if you're referring to Golden Pass, but I'd love to get more insights on that part of your prepared commentary.

Hi, this is David Talley. So later this year, we expect a small and fast LNG to go into service. And we're also expecting Golden Pass and Plaquemines to potentially start commissioning. They won't actually be in service, but they will start commissioning and taking gas. So we expect those to ramp up maybe sooner than expected.

And can you give us a sense of the magnitude of feed gas from those three projects?

That's hard to tell. I mean, it depends on the commissioning process. It usually is up and down and gradual over time. The FASP is going to be 400? $400,000 MMV to you a day.

All right.

Thanks a lot.

And our next question will come from Bertrand Dons with Truist. Please go ahead with your questions.

Hey, morning, guys. Just following up on the last comment, you know, could you talk about your approach to future LNG agreements? The commentary you just gave kind of gave the impression that you're happy to just indirectly benefit from, you know, LNG demand in the basin. But, you know, maybe because you guys are so well positioned, you're better off letting everyone else, you know, hash out the details first and test the waters, and then you can swoop in at the end with a better contract. Or are you guys waiting for something maybe specific, like a higher premium to Henry Hub or a lower deduct from, you know, JKM? Anything you're looking for there?

Yeah, I think our position in LNG on the supply side has given us a great window into the LNG markets, both domestically priced and internationally priced. We talk to and meet with utilities, both domestically and in Europe, liquefaction projects, buyers on the other end to understand that market deeper. We're going to continue to evaluate contract terms of different arrangements how far we want to go into that particular business in terms of you know do you take liquefaction capacity or do you not we we think that the benefit from both higher henry hub prices and potentially international and g prices is certainly present and and we will position ourselves to take advantage of of this in either direction. We're going to look at any of these arrangements on a risk-adjusted basis so that we have a competitive project or a competitive gas supply agreement that brings greater value than our status quo, which is Henry Hub-based projects. But even some of the current projects, we're having dialogue with them to look forward from where we are.

Okay. Yeah, that's helpful.

And then I'm looking at your hedge book. There's a, you know, a notable drop off in 2025. And I'm just wondering, is that intentional to coincide with LNG demand pickup? Or is that just your typical, you know, you don't want to hedge into the markets two years out because the market's too thin and you won't get a, you know, a great price.

There's several parts to that answer. One out in 2025, If you think about our hedging practice, we would be hedged less the further out it is from a risk perspective. Second, as a company, we've moved into a place, given our financial strength, where we're able to hedge at a lower level than we have done in the past. Third, we kind of think that it's important to get closer to the year that you're actually trying to protect revenue from to hedge so that in the case of, as we've all seen for the last few years, where you've had dramatic changes in gas price, given the structural volatility that's in that market now, the closer you can get to the particular year you're trying to protect, it appears that there's benefits. And then I think when you think about where we may hedge going forward, you know, Some sort of rateable 40% to 50%, 40% to 60% level is kind of where we're triangulating. And that is, again, given the fact that our financial strength is present and durable, and we're able to use different vehicles to hedge, callers or swaps, and we actively manage the program once it's done.

Okay, great. And then not a real third question, just kind of a – there's news about the Columbia pipeline fire. Do you guys have a number in front of you yet on, you know, what exposure? Were you able to change price points or just any color in that? And that's all I got. Thank you. Okay, thank you. David?

Yeah, so we are aware of that explosion. So it moves total about 2.2 BCF a day from Appalachia down to the Gulf Coast. They're posting as they curtailed our capacity about 400,000 total. So we have a little over 300,000 of capacity on that pipeline. So we would expect minor transportation reduction, capacity reduction, but that won't impact our production. And we can resupply our markets from our other from our other transport, from Haynesville, and move our production around. So we don't expect to see any impact.

The strength of our portfolio in this space, transportation, is very clear. We've got options well beyond just main plate on a particular pipe, and the team optimizes around that almost immediately when that happens.

And our next question will come from Umang Chaudhary with Goldman Sachs.

Please go ahead with your question. Hi, good morning, and thank you for taking my questions. I have a couple of housekeeping questions. Can you dig a little bit into your quarterly turning line cadence and production cadence for the year if we don't pick up those drop crews? Trying to understand the decline in production as you exit the year and as you start 2024.

Yeah, so I think this can help. We commented that what this will result in is a flat quarterly production profile around that 4.6-ish VCF equivalent a day of net production versus the second half increase in production that was in our original guidance.

Gotcha. That's helpful.

And then I guess on the outflow call, I think you mentioned on the working capital outflow point, which you mentioned for the remainder of the year, I just want to be sure that I caught the point correctly, that you're expecting the inflow this quarter to be reversed over the course of the next three quarters.

Imani, you got that correct. We enjoyed in the first quarter, 375 or so of working capital inflow benefit. It's very typical for the way we manage our capital, et cetera, seasonality in our business. And we do expect that to largely reverse throughout the year, given the current strip.

Thank you so much. You're welcome. And our next question here will come from Jeffrey Lemujan with TPH. Please go ahead with your question.

Good morning and thanks for taking my questions. My first one's just on differentials, which look to have come in better than expectations here in the quarter. If you could talk about what you attribute that to over Q1 and if you could share a little bit about your macro outlook on how you think this will come into the balance of the year and just key considerations around that.

Hi, yeah, this is David. So our Q1 differentials were stronger. Mostly northeast prices were higher than expected in Q1. primarily around our CityGate transport to the New York and New England markets. We also had some of our daily Northeast volumes that were sold at higher-priced locations during that winter volatility.

Great. And as you think about kind of the balance of the year, I know you have some guideposts out there, but just key considerations and moving pieces would be helpful.

Yeah, we expect it to be within guidance. And we hedge basis always have.

as well to protect them. Great. And then as my follow-up, I was hoping just to get a snapshot of DNC per foot in each of your basins throughout the quarter for Q1, just I think similar to how you spoke to Q4 on the last call. And then looking forward, you know, how you think those might trend, particularly in the Hainesville, just as we think about the ranges that you've spoken to before and how quickly we can maybe see progress towards the low ends there, just based on your commentary on service costs so far that y'all walked through.

Certainly. So we think for sure in Haynesville that Q1 will be the highest well cost per foot because that's where we had entered into the new service costs to start the year. And then now as we're pulling inflation down, that will be an added benefit with the efficiency gains as we move forward. But in Appalachia, we were around $830 a foot in Q1. And in Haynesville, we were right at $2,100 in Q1. But as I talked about, we're expecting Haynesville well costs to drive down every quarter as we move forward. And then that will approach the low end of our range when we get into the back half and in the fourth quarter of the year.

And while the basins are very different and certainly have their nuances, I think one of the proof points that is clear to me on the ability to get costs down is looking north to all of the work that has been accomplished in Appalachia and that we leverage the dual basin capability around every part of the business, but certainly cost and well cost are a big piece of that. Great. Thanks. Appreciate that disclosure.

I think just a reminder that the well performance that we have in the Haynesville is benefited by the greater depth and pressure in the Natchitoches fault zone that drives some of the higher well costs in that acreage, but it's more than offset by the performance.

Got it. Thank you. And our next question here will come from Nicholas Pope with Seaport Research. Please go ahead with your question.

Morning, everyone. Morning. I was hoping you guys could talk a little bit on the kind of balance in Appalachia between dry gas, the liquid-rich portion. I think you all have been steady at like two-thirds of activity is going to be on the liquid-rich side. So I'm kind of curious what the capacity is to process the NGL and the oil that's a part of the liquid-rich side and maybe what's governing potentially swinging the balance more towards the liquids rich side? Kind of curious how you're thinking about the balance.

So I'll start that off that, you know, as we talked about, we recognize the benefits on liquids pricing as we were coming into the year and that we were adding nine more additional wells to sales in that liquids rich area in 2023 versus 2022. The production impact of the start of that in Q1 showed up nicely with our both condensate and NGL volumes increasing. From an activity standpoint, the activities are roughly 50-50 between overall Appalachia and Haynesville. And so, you know, we're balancing maintaining the overall productive capacity as we move towards what we think will be a better commodity price environment. into 2024. So that's part of the balancing that we're utilizing as we look at that mix. We have the flexibility to further adjust that mix if we believe that's the right answer. Prices, et cetera, push us to that place. And we've got all the capacity that we need to handle greater NGLs as part of that

Got it. That's very helpful. That was all I had. And our next question comes from Paul Diamond with Citi. Please go ahead with your question.

Thank you. Good morning, all. Thanks for taking my call. Just a quick question on the 10 to 15 completion reduction we're talking about here. you know, county or geographic area you guys are focusing, or would that be more of a game time decision?

Sorry, did you say a county that we would be focused in?

Yeah, a particular geographic area.

So most of it is dry gas, like we talked about, is where the completion reductions are coming from. And then of the 10 to 15, there's more coming out of the Haynesville tied to the reduction or the getting rid of the frac fleet that we did have modeled for the full year in mid-May.

Understood. Thank you. And then just a quick question more topical on flow assurance. You guys talked about 65% of the Gulf Coast. I'm just trying to get an idea of where you guys feel the kind of the optimal level is for that in the long term.

Hey, Paul, this is David. So the 65%, so that includes both our Hainesville position and our transport from Appalachia, which so the transport from Appalachia, that's about 700,000. You know, if they were to, if there were some additional pipeline expansions that would go in place, We would look at participating in some of those from Appalachia. There really aren't any on the forefront right now. So we would see some of that growth coming from the Haynesville and where we've announced that we've participated in a few projects already.

So I think there's a lot of levers to pull and a lot of optimization in looking at both of our basins and how we want to that will go into that as well.

Understood. Thanks for your time and the clarity. And our next question will come from Subash Chandra with Benchmark. Please go ahead with your question.

Thank you. Clay, maybe this question is for you. Can you sort of describe cycle times of bringing ducts back? How instantaneous a process that might be if prices are in the right zip code?

Sure. I think in Appalachia, it'll be quicker because we have our two company-owned frac fleets in that area. And so, you know, we've moved our rigs and frac fleets in the past where we make the decision and in a week we're rigged up and drilling and or pumping. So, we would be able to move very quickly on completions of ducks in Appalachia for the reason I just talked about. In the Haynesville, it wouldn't be as quick, but with the activity reductions that we believe are going to continue both on drilling rigs and on frack fleets in that area, I think as we get into late third quarter, there will be an opportunity to pick up third-party frack fleets. to go start some of those early or then wait until 2024. But that timing will be dependent on availability, and it'll be longer than our timing in Appalachia.

Not to put words in your mouth, but would you, you know, sort of say the variance is weeks in the case of Marcellus and in the case of Hainesville?

Yeah, I would agree that in Appalachia, it'll be weeks. But on the Haynesville piece, it's all going to have to do with availability. So that'll work.

Got it. And Bill, you know, question for you. You know, if you had any thoughts about this, what do you think happens with A&D sentiment, you know, in general? And we've certainly seen a lot of headlines of, you know, Haynesville operators that were looking to tap the market. Do you think that, you know, this puts ice on it, you know, just given the macro? Or do you think some of those sort of see the writing on the wall and it, you know, puts them in play?

Yeah, as far as SWIN goes, and then I'll go from there, our focus right now is capturing the value from our scale in these two basins we're in. And today's call and all the other information we put out, I think, shows that we're having results in that area. I think you've got a number of things going on with some of the other players, whether on the private side, pricing dropped through the floor, the ability to close the bid-ask spread is too wide, or in the case of some, just specific agreements or specific objectives they were trying to achieve and the counterparties couldn't agree. The volatility of gas price and liquids, if there are any, certainly plays into that. And with this extreme volatility that's going on, it makes it more difficult for some of those to actually transact. Again, we watch all those pieces and activities. It gets down to also what's for sale or what's on the offering and how can it possibly be accreted to what you already have. especially in these two basins if it's a gas plant.

Thank you both. And our next question will come from Noel Parks with Tuohy Brothers. Please go ahead with your question.

Hi, good morning. Good morning. I wondered if you could just maybe get into a little bit more detail about Your thoughts, this should be your heading into 2024, on NGL pricing. We're kind of back to some of that divergence, you know, between different products getting fairly marked. So I just wondered if you could talk about your assumptions on those fundamentals.

When you look at NGL macros, the first one that comes to mind is ethane. A couple of things around there. Ethane gets pressured by weak PEP chem demand. or increased supply gas, also tied to natural gas, so you've got a lot of recovery going on. We think that higher exports to Asia will help improve the margins on ethylene, which could provide some support for that product. Whether or not the country goes into a recession will also play a part of that. On propane, there's a lot of domestic inventory that's present because of the mild winter. China reopening new plastic production out of Asia will help, again, exports. And when you get that channel open, that helps support prices as well. And on butanes and natural gasoline, it's really the strong global demand for crude and related products. Butane and natural gasoline are feedstocks to gasoline. You know, as demand for gasoline rises, so does the value of those products.

Great. Thanks for the detail. And just as you've talked about and taken quite a few questions around PACE and what prices look like and how that might affect your activity levels, Um, but as you said, it sounds like the cost side is, is definitely heading back from, you know, from the worst case. And, uh, but I mean, it's, it's fair to say that we're, you know, we're already almost in May. And so when it comes to changing the activity levels and, you know, pads coming on, you know, pushing out later in the year, it's, it's a fairly narrow decision window. I mean, we're, we're talking about as far as impact on 2023. as opposed to decisions that are going to have more of an effect on whether you're off to a fast start or a more modest start in 2024. 2023 is getting a little almost long on the tooth at this point as far as impact on full-year volumes.

I think, again, it's impact on full-year volume, but it's impact on the amount of cash flow we generate. We operate this business as we think about planning on a two-year rolling basis. And so, you know, short-term adjustments to our plan that is always continuously being optimized can help pivot this year and make sure that we're investing within cash flow. It also really highlights larger decisions that could have bigger impact in 24 and make sure we understand that impact. again, to maintain the productive capacity of the company feeding into the rising gas price.

Great. Thanks a lot. You bet. And our next question will come from Greg Brody with Bank of America. Please go ahead with your question.

Good morning, guys, and thanks for the time. Just with respect to your operating costs, if you do reduce your activity, do you expect to be at the higher end of the guidance or are you seeing similar disinflation on the operating cost side?

So on the LOE side of the business, we think we will see some softening, but it's lagging the capital right now because a big part of that is around saltwater disposal, water hauling, and there hasn't been deflation showing up in any material way in that space. We have benefited from lower lease use costs on gas that will help on the LOE side. but it's lagging what we've been seeing on the capital.

Yeah, and Greg, we typically, our LOE is usually a little lighter in the first half of the year, and then it usually takes up a penny or two towards the back half of the year. So we expect that to be the case this year, but still to be within that guidance range, even with the activity reduction.

Got it. And then I appreciate the capital discipline that you're implementing and practicing. Should we think about I know you mentioned the working capital should be a slight negative going forward for the rest of the year. Do you expect to pay any more debt down this year at the way you're looking at things? Or do you think we're kind of tapped out for now?

Simple answer is we do. Any free cash flow will go to debt repayment.

And as you'd expect, we always, we add what?

five billion of assets since the second half of 2020, and always look for ways to potentially core up, and any proceeds from a sale non-core might go down too.

I appreciate the cover, guys. Thank you.

And that concludes our question and answer session. I'd like to turn the conference back over to Bill Way for any closing remarks.

I want to thank you all for your interest and for your questions. A great dialogue today. We look forward to sharing more of our capturing the tangible benefits of our scale with you next quarter.

Have a great weekend. Thanks for joining. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your line.