EXE - NASDAQ

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 Raiford, 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 Carrell, 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 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 and 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 advantaged assets in the two premier natural gas basins in the United States. We are focused on large-scale core Tier 1 natural gas and gas liquid assets where we can leverage our operating and commercial strength, 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 frac fleets. 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, the Freeport -- 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 9 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 Haynesville 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 disciplined 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 frac 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 Haynesville integration and first year results clearly support confidence in our ability to execute on the company's multiyear strategy to create long-term shareholder value. We continue to capture the tangible benefits of our larger scale dual basin portfolio and 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 outperformance. 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 cost. 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 billion 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 to 1.2x, 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 of 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 call.

[Operator Instructions] At this time, we will take our first question, which will come from Charles Meade with Johnson Rice.

Bill, the question for you, could you give us some insight into how you're going to go about deciding when to complete the wells that you're -- where you're deferring completions? I think Clay spoke a bit to it about it. Obviously, price would be a part of it. But is there sort of a length of time that you have in mind right now? Or is there a price? Just maybe just elaborate on your thought process there.

Yes. 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 DUCs 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 will 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 outspend, your free cash flow position is another piece of the...

Yes. 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 cost, 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 reductions. Clay, you already gave us some detail there with the frac 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 that -- or what are you seeing that gives you the confidence that, that service cost 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.

Our next question will come from Scott Hanold with RBC Capital Markets.

Yes. 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, would -- 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 end, would be kind of the first part of the question? And the second one would be what happens if 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 side in 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 slowing down, if need be. So we have a plan. We're hopeful that 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 investment.

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 Bill, I think this has been a 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, potentially improving macro. So at a high level, can you give us a sense of like what -- do you think any of these actions you've done so far reduces your productive capacity? And just give us again a sense of like where you think that level is for Southwestern's assets right now? Is it still around that 4.7 Bcf per day?

Yes. I think that what you've heard us talk about is really a well-balanced two-year plan that talks about 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 managed -- a manageable ability to invest again within cash flow and drive -- arrest any decline that is present. I mean, one of the reasons 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 showed, 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. I mean, 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 our dual basin position where we're able to hit activity to liquids producing inventory, you're helping offset some of that as well.

And our next question will come from Doug Leggate with Bank of America.

Bill or Carl, 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 cost 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 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 levels?

So maybe I'll jump in there just at the start, Doug. When we think about the inflation moderation that we've seen, 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, there's about $150 million to $200 million annual capital spend reduction in those out-years versus what we showed in the Analyst Day.

Pretty much the answer I was looking for -- go ahead, Carl, please. A material number, Carl.

Yes. And maybe we translate that to the free cash flow guidance we gave over the next, call it, 5 years, well north of $1 billion.

Thanks, Carl, that's what I was looking for. Clear, I appreciate the input. And my second -- go on, Bill?

No, go ahead.

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 Haynesville, I guess, 3% or 4%, if I recollect. But that probably gives you some insight to AFEs for the general industry, I'm guessing, privates in particular. What are your -- 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 focus you on the macro at this point? And I'll leave it there.

Yes, 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 8-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. Internally, we think maybe there'll be a 15 to 20 rig drop for the full year in the Haynesville. There are some other industry publications that are pointing to as high as 20 to 30 in 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 public and the public have pulled back as well. So I think at the end of the day, a lower rig count with some requisite production leveling offer declining, depending on who you are. The privates 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 end up $1 billion added back to the free cash flow? Did I hear you right on that?

More than $1 billion. Price health, inflation and this compounding effects and the reductions in capital efficiencies that Clay talked about.

Our next question will come from Arun Jayaram with JPMorgan.

I want to better understand maybe from you, Clay, the planned reductions in CapEx. The midpoint of your guidance range from last night still $2.35 billion, I think you're indicating that you'll get down to $2.2 billion 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.

Yes. So you have that right. I think your opening comment that we're down towards 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 million. 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 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 it's another 0.7 of a frac 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 more so 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 love to get more insights on that part of your prepared commentary.

This is David Tally. So we -- later this year, we expect a smaller one; 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?

So that's hard to tell. I mean, it depends on the commissioning process. It usually is up and down and gradual over time.

The fast is going to be 400,000 MMBtu a day.

Our next question will come from Bertrand Domes with Truist.

Just following up on the last comment. 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 LNG demand in the basin. But maybe because you guys are so well positioned, you're better off letting everyone else 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 JKM? Anything you're looking for there?

Yes. 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 do you take liquefaction capacity or do you not. We think that the benefit from both higher Henry Hub prices and potentially international LNG prices is certainly present and we will position ourselves to take advantage of this in either direction. We're going to look at any of these arrangements as 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 domestic -- or the current projects, we're having dialogue with them to look forward from where we are.

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

There's several parts to that answer. One, out in '25, 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 in a particular year you're trying to protect, it appears that there's benefit. And then I think when you think about where we may hedge going forward, some sort of ratable 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 collars and 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 what exposure -- were you able to change price points? Or just any color on that? And that's all I got.

Okay. Thank you. Yes. So yes, 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've 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 so we -- and we can resupply our markets from our other transport from Haynesville and move our production around. So we don't expect to see any impact.

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

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

I have a couple of housekeeping questions. Can you dig a little bit into your quarterly turn-in-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.

Yes. 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 Bcf equivalent a day of net production versus the second half increase in production that was in our original guidance.

Got you. That's helpful. And then I guess on the outflow, Carl, 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.

Umang, 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 will -- we do expect that to largely reverse throughout the year given the current strip.

And our next question here will come from Jeoffrey Lambujon with TPH.

My first one is just on differentials, which looks 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.

Yes, this is David. So our Q1 differentials were stronger, mostly Northeast prices were higher than expected in Q1 and primarily around our city-gate transports 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.

Yes. We expect it to be within guidance.

And we hedge basis, always have as well to protect that.

Great. And then as my follow-up, I was hoping just to get a snapshot of D&C per foot in each of our basins throughout the quarter for Q1. Just I think similar to how you spoke to Q4 on the last call, and then looking forward, how you think those might trend particularly in the Haynesville. Just as we think about the ranges that you've spoken to before and how quickly we can maybe see progress towards the low end there just based on your commentary on service costs so far that I'll walk 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 cost 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 a foot in Q1. But as I talked about, we're expecting Haynesville well cost 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 cost 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 low costs are a big piece of that.

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.

And our next question here will come from Nicholas Pope with Seaport Research.

I was hoping you guys could talk a little bit on the kind of balance in Appalachia between dry gas and liquids-rich portion. I think you've been steady at like 2/3 of activity is going to be on the liquids-rich side. Just kind of curious what the capacity is to process the NGL and the oil that's part of the liquids-rich side? And maybe what's governing not potentially putting -- swinging in the balance more towards the liquids-rich side. Kind of curious how you're thinking about the balance between that.

So I'll start that off that as we talked about, we recognize the benefits on liquids pricing as we were coming into the year and that we were adding 9 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 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 potential shift.

And our next question comes from Paul Diamond with Citi.

Just a quick question on 10 to 15 completion reduction we're talking about here. Is there any particular 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?

Yes, particularly 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. And then just a quick question, more topical on flow assurance. You guys talked about 65% of the Gulf Coast. 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 Haynesville position and our transport from Appalachia which -- so the transport from Appalachia, that's about 700,000. 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 have 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 develop them. That will go into that as well.

And our next question will come from Subash Chandra with Benchmark.

Clay, this -- maybe this question is for you. Can you sort of describe cycle times of bringing DUCs back, how instantaneous a process that might be if prices are in the right

Sure. I think in Appalachia, it will be quicker because we have our two company-owned frac fleets in that area. And so 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 DUCs 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 frac fleets in that area, I think as we get into late third quarter, there will be an opportunity to pick up third-party frac fleets to go start some of those early or then wait until 2024. But that timing will be dependent on availability and it will be longer than our timing in Appalachia.

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

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

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

Yes. As far as swing 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. In 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 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 accretive to what you already have, especially in in these two basins, if you're -- if it's a gas one.

Our next question will come from Noel Parks with Tuohy Brothers.

So wondered if you could just maybe get into a little bit more detail about your thoughts rest of the year heading into 2024 on NGL pricing. We're kind of back to some of that divergence between different products getting fairly marked. So I just wonder if you could talk about your assumptions on those fundamentals.

When you look at NGL macro, first one that comes to mind is ethane. A couple of things around there. Ethane gets pressured by weak pet chem demand or increased supply gas or anything 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 export. 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 or feedstocks to gasoline. And so as demand for gasoline rises, so does the value of those products.

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

Yes. I think, again, it's impact on full year volume but its impact on the amount of cash flow we generate. And we operate this business as we think about planning on a two-year rolling basis. And so short-term adjustments to our plan is always continuously being optimized, can help pivot this year and make sure that we're investing within cash flow. But 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 rise in gas price.

Our next question will come from Gregg Brody with Bank of America.

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 do you -- 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.

Yes. And Gregg, we typically -- our LOE is usually a little lighter in the first half of the year and then it usually ticks 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 have been impacting. 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 you'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 had, what, $5 billion of assets since second half of 2020 and always look for ways potentially core up, and any proceeds from the sale of noncore might go to pay down too.

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. And 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.