Expand Energy Corporation (EXE) Q4 2022 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen and thank you for standing by. Welcome to the Southwestern Energy’s Fourth Quarter 2022 Earnings Call. [Operator Instructions] The 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 fourth quarter 2022 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 is 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. Earning 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. Thanks for joining us this morning. 2022 was a defining year for Southwestern Energy as we continued executing on our strategy and delivering strong results, both financially and operationally. We prioritized debt repayment, reducing debt by over $1 billion and lowering leverage to 1.3x. We complemented debt reduction with $125 million of share repurchases during the year. We successfully integrated the transformative acquisitions we completed in the second half of 2021, which expanded our asset base into Haynesville to complement our high-quality Appalachia position. We expect that our large-scale integration and development expertise will enable us to drive further operational efficiencies just as we continue to do in Appalachia. We believe that these acquisitions extend the longevity and improve the resilience of our business with deepened high-quality inventory, scale cost economics and expanded optionality. Most importantly, we now have more direct access to the growing Gulf Coast market, including the LNG corridor, where we are already the largest supplier of natural gas to LNG exporters at 1.5 Bcf per day. We are strategically positioned to supply increasing energy demand and capitalize on longer term natural gas fundamentals as well. Over the last decade, U.S. natural gas storage capacity has remained flat while U.S. natural gas supply and demand has more than doubled. The relative contraction in this balancing mechanism for the natural gas market means that smaller changes in relative supply and demand can drive quicker and more significant changes in pricing. Over the last few months, natural gas prices have fallen materially due at least in part to unseasonably warm weather, reducing demand below greater gas supply. Similar to the sharp run-up in natural gas prices during the hot summer of ‘22, we believe the recent pullback also reflects structurally increased volatility in the natural gas market. This volatility highlights why hedging remains core in our enterprise risk management practice. With our improved financial strength, we expect to hedge more moderately going forward in line with our framework. Given the current market and in the near-term, we have taken proactive steps to moderate planned activity and associated full year capital by reducing the drilling program by 2 rigs on average versus 2022. This is expected to result in a 2% to 3% production decline at the midpoint of guidance. With our planned 2023 activity levels at recent strip prices, we expect to fund our capital program through net cash flow and preserve the company’s productive scale to deliver resilient free cash flow longer term. We have additional flexibility and optionality, including through our vertical integration business to adjust activity rather quickly. Any further adjustment will incorporate a multiyear outlook for commodity prices and ultimately, rest on what we believe will best progress our longer term business and financial objectives. Consistent with our capital allocation strategy, prioritizing debt reduction, we plan to direct free cash flow generated this year to debt repayment. Returning capital to shareholders remains a core – remains core to our long-term shareholder value proposition as we approach our target debt range of $3.5 billion to $3 billion. Longer term, structurally constructive natural gas supply and demand dynamics should remain as energy security and global decarbonization drive continued strong natural gas power burn and LNG export growth. Beyond the Freeport facilities imminent returned to service, an additional 6 Bcf per day of U.S. LNG export capacity is under construction with anticipated service dates as soon as late 2024. SWN is well positioned to differentially benefit from these developments with our proximity to the U.S. Gulf Coast and direct access to the growing LNG corridor through our firm transportation portfolio, enabling delivery of natural gas from across our business. We believe the actions we have taken over the past few years have better positioned SWN to navigate the current commodity price volatility and grow the long-term value proposition for our shareholders. Let me now turn the call over to Clay for an operational update.

Thank you, Bill and good morning. In 2022, the team successfully integrated the Haynesville assets from a cultural and performance standpoint and we delivered on the combined business plan objectives of the company. This is consistent with our established track record in Appalachia. We are carrying that momentum forward into 2023 and expect to drive further execution and performance improvements. During the fourth quarter, we produced 427 Bcfe, including approximately 100,000 barrels per day of liquids. We proactively mitigated the effect of the December winter weather and unplanned midstream downtime safely and with minimal impacts to production. We placed 28 wells to sales during the quarter. This includes 15 in Appalachia with average lateral lengths of over 16,000 feet and well cost of approximately $850 per foot and 13 in Haynesville with average lateral lengths of just over 9,000 feet and well cost of approximately $1,925 per foot. During the quarter, we invested $537 million of capital, bringing our full year capital spend to $2.2 billion, consistent with the guidance. For the full year, we produced 1.7 Tcfe or 4.7 Bcfe per day comprised of 88% natural gas and 12% liquids, which was above the midpoint of our updated guidance issued in August and above the top end of our original guidance issued in February. The production outperformance was driven by strong well results and operational execution across the portfolio that resulted in more producing days during the year from accelerated turn-in lines. In our first year in the Haynesville, we hit the ground running, delivering results above expectations and achieving some early operational wins. Most importantly, we delivered basin-leading well performance as evidenced by early time production data published by third-parties, confirming the strength of our stacked Haynesville and Middle Bossier position. We also improved upon the prior operators drilling cycle times by approximately 10% while extending lateral lengths to nearly 9,000 feet. On the commercial side, we executed several key agreements that reinforced long-term flow assurance and optionality across gathering, treating and long-haul transport. These agreements bolstered our LNG access with an additional combined 800 million cubic feet per day of transportation on the LEAP and momentum in G3 pipelines that come online by the end of 2024. The value of our assets is evident with year-end proved reserves of 21.6 Tcfe and the associated pre-tax PV10 of $46.4 billion using SEC pricing. This included 2.4 Tcfe of extensions and discoveries and 1.1 Tcfe of positive performance revisions, which more than offset production and changes in the 5-year development plan. We continue to believe that the quality of our reserves and underlying inventory is a differentiator for the company. Updated for the current commodity price environment using 5-year strip prices at year end 2022, the pre-tax PV10 of our reserves was $26 billion. Turning to 2023, as Bill mentioned, our $2.2 billion to $2.5 billion capital program reflects a proactive moderation of activity that is expected to result in a 2% to 3% decline in production. For the year, we expect to average 10 to 11 rigs, which is 2 less rigs than 2022. This will include 7 to 8 rigs in Haynesville and 3 in Appalachia. We also intend to run 2 to 3 frac fleets in Haynesville and 1 to 2 in Appalachia. With our portfolio optionality and the continued strength of liquids pricing, we shifted more activity into our liquids-rich acreage with approximately 8 more wells placed to sales than last year. This is expected to grow oil volumes throughout 2023 to an average of 15,000 to 16,000 barrels per day. The team remains highly focused on offsetting the inflationary cost impacts by leveraging our strategic supply chain efforts and delivering further operating and development efficiencies. We are targeting further drilling and completion cycle time improvements as well as ongoing completion design and flow-back optimization. We are proud of the results the team delivered in 2022 and look forward to continuing to deliver in 2023. Now I will turn the call over to Carl.

Thank you, Clay. In 2022, the company generated approximately $850 million of free cash flow that supplemented with working capital inflows helped repay more than $1 billion of debt, but also returning $125 million to shareholders. We ended the year with debt of $4.4 billion and leverage 1.3x, down from 2.0x at the beginning of the year. At the end of December, we retired our Term Loan B using a revolver and cash on hand. Our credit facility remains the only unsecured component in our capital structure and recall that in April of last year, we amended that facility to transition to unsecured upon achieving investment grade. We also recently issued a redemption notice for 2027 notes, which we intend to call at the end of this month. We expect to use cash on hand to fund majority of that redemption for these higher coupon notes, which will further strengthen the balance sheet and result in increased free cash flow. Reducing debt to a $3.5 billion to $3.0 billion target range remains a priority. A strong balance sheet is foundational to our holistic approach to enterprise risk management. Additionally, lower debt makes the business more resilient through commodity price cycles. Earlier this month, S&P improved our outlook to positive and we remained one notch below investment grade at all three agencies. We believe our ratings trajectory reflects the strategic steps we have undertaken over the past few years, which have positioned us to better navigate the current commodity price volatility. We have greater scale, a lower inflation adjusted enterprise cost structure, deeper and higher quality core inventory as well as the stronger balance sheet. With that, please open the call to questions.

Thank you. [Operator Instructions] The first question comes from Charles Meade with Johnson Rice. Please go ahead.

Good morning, Bill, Clay, Carl and to the whole rest of the Southwestern team there. Bill or Clay, this is – first one for you. And I want to ask about the pace of activity and how you are going to drop those rigs over the course of the year? But maybe a better way to approach it is looking at the 1Q guide, I am a little – I can’t quite understand why the 1Q guide kind of dips from 4Q and is below the overall ‘23 guide because it implies your volume is going to grow over the course of the year. So however, you think is the right way to explain whether it’s from activity or whether some – perhaps some specific dynamics going on in 1Q. Can you help fill in that picture for us?

Certainly. So traditionally, our production profiles, as we move from the end of the year to the first quarter of the year, we typically have the lowest production quarter or a drop there and that’s tied to the little bit of front-end loading that we have and then some backed off activity as you go into Q4. And then we start the year up with the full activity for the new year and there is a little dip there and then there is some strong recovery. Additionally, when we think about Q4 2022 and 2022 in general, we outperformed on production due to the efficiency gains and we had accelerated turn-in lines and we continue to live within the updated guidance. So, there wasn’t accelerated turn-in lines at the end of the year in Q4 to bolster Q1. So that shape, not a surprise to us and kind of consistent with the typical profiles that we have. The pace then, as we move into 2023, is similar to past activity levels, a little bit higher in the first two quarters than the back two, but getting closer to some level loading there as we’re moving forward and we look at the 2023 program.

Got it. So the rig drops are going to be more, I guess, more weighted to the back half of the year, if I understand you right, Clay?

Well, it will start showing up. We have got a couple that happened in late March. And then there is one that will occur in the second quarter and then the run-rate will be lower in the second half of the year.

Got it. Thank you. And then if I could ask one more follow-up on the financial front, perhaps, for Carl. Carl, can you give us – you guys have made a lot of progress towards investment grade. And I think a lot of equity investors, not to say rating agencies aren’t important, but a lot of equity investors look at them as kind of a lagging indicator that is the leading indication. Can you give us a refresher on what achieving investment grade? How that’s going to change the opportunity set for Southwestern, particularly if there has been any shift on the posture of LNG customers?

Yes, happy to. The benefits following a few buckets, most directly is financial. You obviously lower your cost of debt and even more important, at least where I sit, we expand our access to capital. It’s just a much bigger market, investment grade compared to non-investment grade and that could be important when you most need it. Secondarily, you touched upon it is commercial. We think being investment grade will be a differentiator as people love to engage with producers in long-term LNG constructs. It just shows durability from the right hand side of the balance sheet. And then the third point which I don’t want to understate is really from a market perspective. As you well know, the market is becoming increasingly generalist and as they look where to invest the marginal dollar in the gas sector, we believe that being investment grade will help distinguish us in a positive way from our peers.

Got it. That’s helpful commentary. Thank you, Carl.

You bet.

The next question comes from Umang Choudhary with Goldman Sachs. Please go ahead.

Hi, good morning and thank you for taking my questions. You highlighted a focus on conserving your balance sheet and your growth profile sounds like its more back half weighted. I guess the question is like, at what price would you look to further cut completions if we do see a derating gas prices in the back half? And on that vein, what flexibility do you have with your non-operated rigs and crews to respond to those changes in gas prices?

Sure. So as we think about the – I’ll hit the non-op side of it first. That’s mainly in Haynesville. We expect to see a drop-off in the non-op activity as we move forward in line with our view that there will be moderated drilling program in the Haynesville across [Technical Difficulty]

I think you might have muted yourself by mistake.

Some of the value there. And like all of our capital allocation decisions, they have to compete in the rack and stack, and we will make the corresponding of the appropriate choice around whether we participate and how we would participate going forward, if we did based on the economics of those wells. I think on your first question on where we would maybe delay frac activity, it starts with – we’ve got some good optionality in that space because we own the two of our own frac fleets. Secondly, we are – we will steadily be watching where commodity prices are at, both in the current month and in the year and what we think from a fundamental perspective to be able to make those decisions, and we will have those scenarios mapped out, if needed.

And a couple of points to add to that. We don’t build DUC inventories to try to anticipate the market pricing. We only build DUC inventory for operational efficiency to drive improved performance. And on the overall plan, we intend to invest within cash flow. And in doing so, if there is adjustments that need to be made to the program, we certainly are on top of that and would make them to be able to achieve that objective.

Got it. That’s helpful. I lost you in the early part of your response, but I think I follow you that you are seeing some rig drops from the non-operated side, and you will take a call in terms of – if we do see further non-op activity, you will choose to – you have the option to participate in them or not, which can allow you to conserve capital.

You got that right.

Perfect. Okay. And then I guess on the Haynesville, specifically, I mean with the integration process successful and you highlighted that you have operated these assets for a year now, how – what are the learnings which you have gleaned from that asset year-to-date to date? And then how are you thinking about – what are the opportunities to further improve the capital efficiency of that asset?

Yes. So we’ve definitely had good learnings as we’ve gone through the full year. I think the team has done a really good job, continuing to see improved well performance and staying on track on that program throughout the year with service challenges and being a new asset. Some of the learnings are around when there are – when there is some non-productive time, the appropriate, most efficient way to get back on track and that reduces or it causes you to not have as many days worth of delay and that cuts cost. We made progress on cycle time improvement on the drilling side and on the completion side. And we think that there is further improvement opportunities there as we move forward. We – connection time, trip time, some things we’re doing on our completion designs where we are changing the proppant loading and the step-up in the proppant so that we are more effectively putting the full job away and not having any screen outs and have to go clean that out with coil, which again also adds time. And by eliminating all those, we continue to shrink the cycle times. There is broader learnings that are more around the whole development program around how we put the facilities together and enhance the facility design so that we capture the full range of the production potential that each well brings. And if we’re seeing a well outperform that we’ve got the capability to benefit from that with our facility design, and then additionally, the hydraulic modeling that we do across all the midstream providers to make sure that when we bring new wells on, we get the full benefit, and we’re not backing off other older wells when we bring those on. So those are a few examples.

Yes. And I’ll just add one other one. As you well know, we have seven high-spec drilling rigs, and more importantly, seven teams of people who run them. And they transitioned into Haynesville, the learning that happened, the ability for our teams to complete our drill wells as well as the contracted rigs that we have in the fleet gives us a lot more flexibility, gives us negotiating might. And it enables us to work to try to drive cost out and performance in. So I think it’s a broad – that’s a broader benefit that we anticipated happening that we’re delighted the team delivered.

Very helpful. Thank you.

The next question comes from Doug Leggate with Bank of America. Please go ahead.

Hi, guys. Thanks for having on. Bill, I know you don’t have a cliff there anymore, but I would love to get your thoughts on the gas market generally. It speaks, I guess, to your thoughts around it and the price risk management, you talked about earlier, but I want to frame my question like this. We have a little bit above-normal storage currently. We have a forward curve, which is 50% higher, and we lost over 400 Bcf of exports from Freeport. But I’ll say again, you’ve only just got slightly above storage. Do you think the dynamics of this gas market have shifted? And if so, why continue to do swaps rather than colors in your ERM?

I think the market dynamics have shifted. You have much greater structural volatility in the markets than we’ve had previously. And that impacts both how we hedge, how much we hedge and hedging will remain part of our enterprise risk management. And there are a number of factors when we consider hedges from a framework, whether it’s the cost we’re trying to protect, the fundamentals of the commodities, the economic thresholds we’re trying to reach or other objectives that we’re trying to meet. We use a variety of tools. It depends on what time of the year. It depends on shorter-term market dynamics. We want to lock in the protection that we believe we need in certain markets in certain circumstances, but we also want to provide the opportunity to gain the upside by putting on a measured – a number of colors. And then the whole process is dynamic, meaning that we will – we’ve converted collars to swaps where we see the need to do that. And we meet from a risk perspective on these every week to look to shape where it’s appropriate and cost-effective shape, the tools we have because we believe that some of our – part of our investor value proposition is getting some of that – are providing that access to higher pricing when should higher pricing count. We’ve recently done a number of things around our hedging. The company is in a much stronger position from a balance sheet perspective and the ability to pull back from high, high hedging numbers that at the time they were implemented had a lot more to do with our transformational growth and a concern – a particular concern in the market. But defensive hedging and perceived risk to the enterprise are major drivers for how we tend to handle this volatility.

I appreciate the full answer, Bill. Thank you for that. I guess my follow-up is, I mean, I think we’re kind of on the same page in terms of the prospective value given the forward curve, but the market doesn’t yet seem ready to believe that, which brings me to the best use of cash. And I guess my question is, since the last quarter, we have now, I guess, a 4%, 5% return on cash. You have a capital structure, which is 45% net debt, but you still have a share buyback program. So it isn’t building cash a faster way to accelerate market recognition of equity value, if the enterprise value is going to be helped started as it seems to be currently versus buybacks, I mean?

I mean, Doug, look, it’s a fair question. And at least in the near-term, as Bill noted, we intend to direct our free cash flow to repaying debt this year. With $4.4 billion of debt, we have some rows to how to get to our target range of $3.5 billion to $3 billion. And then as we approach that target range, I’m sure we will evaluate both returning capital. We do believe our stock is undervalued relative to the inherent value – net equity value of our enterprise, but I think we will also consider building cash as well. As you know, it’s not really sort of a false choice. There is an option there where you can do both. And we think lower debt, including net debt, has the benefit of lowering the volatility of our stock, which has benefits to all parts of our capital structure, including the equity of lowering the overall cost of capital. So those considerations will be very front and center as we progress our capital allocation strategy.

[indiscernible]. Carl thanks so much for that answer.

The next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yes. Thank you. Bill, I had just a broader question on how you’re approaching activity levels. I think the market was happy to see your plans to shave a couple of rigs off the program, yet you are going to be completing 25 DUCs this year. Just thinking about why not potentially save the DUCs until 2024 when the strip is like 360? And if the strip holds in 2024, would you plan to bring those rigs back?

Sure. Arun, I’ll maybe hit on the first part of that. As you know, on quite a few of those DUCs that they represent a shift into the liquids-rich portion of Appalachia, which is tied to a stronger view of liquids pricing and that’s going to show up in greater value, greater liquids volumes and the equivalent volumes of those are less. So that’s part of the decline in the gas price. When we look at the quality of our Haynesville inventory and the view that – this is a relatively short-term downturn and the cycle times with bringing those Haynesville wells online, I think with where prices are at right now, we believe that sets us up nicely going into 2024, where we think there is a more constructive market.

And if we look at overall capital program, we’re very conscious of the fact that the market dynamics structurally has changed. We’re very conscious of the fact that we would like to fund our capital program with a net cash flow. And we’re very conscious of the fact that as you think about our capital allocation strategy, investing in maintenance capital versus even growing that when prices were high was the lead off of that to generate the cash flow and free cash flow. Following investing within cash – excuse me, maintenance capital, it was paying down debt and being very deliberate about taking the $1 billion off like we did in ‘22 and more in the future. And then setting ourselves up so at one point, when we get clear line of sight on the debt, we look to do some additional return of capital to shareholders. If we go forward in time and the prices spike, we will go right back to where we expect to go right back to where we were, which is – and we will evaluate this from all different dimensions and economics and returns. But it would we go back to a maintenance capital type program, and if we did that, then some of the contracted rigs in one form or another with rejoin the fleet and to support that effort.

Great.

All of that I suppose is that the current dynamic of pricing and supply/demand balance and all of those timing owned ramping of LNG and all of those things materialize exactly like everybody wants it to, which probably often never happens. So we will watch it to phase it in, and we will continue to keep the productive capacity of the company to deliver sustainable and resilient free cash flow going forward along with paying down debt along with return of capital as we move forward.

Great. Certainly, a dynamic environment. My follow-up is, if we look at your guide, using midpoints, you guys are going to complete about 8% more footage this year versus last – the midpoint of your natural gas production is down, call it, 3.6% or so. I think 143 tolls or so. Clay, where would you peg? From an activity perspective, where you’d be at a sustaining level and CapEx to support cut sustaining a level of production at SWN?

Yes. I think a lot of that has to do with how quickly we can get the cost structure back in line with the current price environment. We had 15% to 20% inflation in 2022. That was a $2.2 billion program to deliver the 4.7 Bcf equivalent a day of net production. We’ve got modeled at the midpoint of our guidance another 10% to 15% of inflation coming in. And so I think that we are getting more efficient as evidenced by the lower average rate program that we have built in and where the midpoint of the guidance puts us on production. But I think as – in a $3 gas price environment, a lot of capital, we believe, needs to – the cost needs to come way down and on the LOE side that would lower that annual capital number. But it’s kind of a wide range of where that – how quickly that inflation goes away.

And is that a Haynesville more specific comment versus Appalachia, Clay?

So yes, in what we saw in 2022. So – and Haynesville starts with higher capital. As we see things moving into 2023, we don’t see as big of a delta through our supply chain work between Appalachia and Haynesville from an inflation standpoint.

Super helpful. Thanks a lot, guys.

Thank you.

Your next question comes from Neal Dingmann with Truist Securities. Please go ahead.

Good morning, everyone. Thanks for the time. My first question is on really what I call rig plant, your rig plant sensitivity. Specifically wondering, how do you all think about more likely there is just the pure Appalachian versus Haynesville activity adjustments when modifying your plan for gas prices. I guess what I’m asking is, saw one of your peers had recently put out a slide, suggesting historically most of the rig declines on gas goes down has been in the Haynesville. So I guess, even maybe ask another way, how do you just think about margins in your Haynesville versus Appalachia that what I’d call sort of notably high or notably low gas prices?

Yes. I think kind of the direction that we have made some adjustment with the liquids-rich program is indicative of what you’re talking about and the resilience of those assets in this price environment. But we try to make sure we’re pretty clear that the average core Haynesville versus some of our acreage in the southeast part of Haynesville, we have much lower breakeven there than the average across the whole core of the play. And I commented on that in the script where we have got higher 3-month [indiscernible], 6-month [indiscernible] performance when you look at not only our comments, but the public data and there is corresponding higher EURs on that. So that’s why our rack and stack is still a solid mix across our portfolio, but with a leaning towards picking up more liquids in the program, which is what we did.

And we have the flexibility to move quite good. So, the comments that Clay makes, they can materialize and we can begin getting results very quickly.

Yes. No, I think that’s important to understand. I think you do have that in the Haynesville. And then maybe just a second question, maybe, Clay, for you. Just on OFS in place or specifically, very recently, I am just wondering, what have you seen in cost of given the reduction in rigs and other services by you all and others, have you seen anything more recent as far as OFS cost to something you could share there? Thank you.

Yes, I can start with we are really proactive in that space. It’s early to start seeing tangible movement there. We believe that it needs to happen. And as we move further through the fourth quarter – I mean the first quarter, I am sorry, and into some of the openers that relate to some of the different services, we will get a better feel for that. We already know in other companies’ earnings calls and what we know from private conversation about rigs in the Haynesville starting to come down. I made a comment earlier, we are going to have two going down in March and then more in the second quarter. So, I think that they should go hand-in-hand, and we are going to stay really active in that space using all the tools we have from a procurement standpoint.

Sounds good. Thanks Clay.

The next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt. Please go ahead.

Good morning everyone. Appreciate taking my questions.

Good morning.

My first one is on the 2023 budget, just on the moving pieces behind that as we think about the low and high end of the range there. I know you spoke to this a little bit earlier. I don’t know, I mean you obviously got the range there on well count for the year by region. But I would be curious how you are thinking about low cost by asset there? And I appreciate your commentary earlier saying, it’s a bit early to talk about improvements in green shoots on the inflation side. But if you could speak to what the guidance contemplates as far as well cost ranges with the Haynesville and Appalachia, and how that compares what you are seeing today would be helpful.

Sure. So, it kind of starts with the fourth quarter results that I talked about in my script around well cost in both of those areas where we were in the mid-800s in Appalachia and 1,925 in Haynesville. And our thought there is that fourth quarter activity represented the bulk of the inflation that we had seen in 2022, and our – kind of our target is to do all we can do to hold closer to those costs, but that would indicate that we are seeing some inflation reduction. So, I think a range in those areas is anywhere from an 850 to 950 in Appalachia. And like we have talked about a lot in Haynesville, where you drill matters on your well costs, and it also matters for the well performance. And we have deeper wells with higher bottom hole pressure, which increases well costs, but those wells are the best performing wells in the basin. So, our range is a little bit different than some of the shallower, older part of the core Haynesville asset. But I would say that range is anywhere from that 1,925 to a little over 2,100, but we are working on efficiency improvements and inflation improvements.

Perfect. Appreciate that. That’s helpful. And then just a quick follow-up on hedge coverage, maybe referencing the added protection for 2024. Just wanted to get a reminder on where you could see that coverage moved to as a percent of production. If we should think about that conversion towards what we see on the 2023 hedge book today or if the balance sheet tempers the appetite for getting to that level as you kind of strengthen that further.

Yes. It’s a good question. And when we think about ‘24, in particular, the two factors that I would say to dominate or thinking about level, one, as regarded in the prepared remarks, it’s a priority of curing free cash flow to lower debt. That obviously would suggest that we will look for opportunities to lock in revenues that we think will lead to free cash flow and further that goal. Another factor, again, noted by Bill in the prepared remarks, is the increased structural volatility that we are seeing in the gas market. Long story short, we believe that, that higher volatility increases in risk at some point of higher hedge levels. We entered 2022 largely due to the high leverage we had during the pandemic as well as the 2021 acquisitions that we funded with about $2.4 billion of debt with reasonably high hedge levels, 80%-plus in ‘22, and then 60%-plus for ‘23. And then as you saw ‘22 and ‘23 rise last year, that created significant unrealized loss for us with our hedge counterparties and effectively created some limits and their willingness to have exposure to us. And now as we are seeing in the current gas environment, the opportunity cost of not being able to participate in locking in those higher prices last year as much as we would have liked is quite high. So, in addition to the stronger balance sheet, this increased volatility. I think we will – net-net caused us to temper our hedge levels.

Got it. Appreciate the detail. Thanks.

The next question comes from Paul Diamond with Citi. Please go ahead.

Thank you. Good morning all. Thanks for taking my call. I just wanted to quickly touch on kind of your guys’ longer term thoughts on the LNG take rate or LNG capacity, currently standing at about 1.5 billion. Just wanted to see if that was – how the conversations were going around any potential increase to capture that will be expected to be further demand pull in late ‘24, ‘25?

We have a portfolio of contracts with a number of LNG providers that range in price, in tenure, in quantity, all of that. And they build sort of a broad and concentration of risk management picture that lets us kind of add and subtract on a much broader opportunity set. Today, we are at 1.5 billion a day, again various links of contracts. We have been looking internally as a target somewhere near 2 Bcf a day. Given our total of 5 Bcf, it seems that as we analyze that economically strategically makes some sense. I think the other thing that we have talked about is access to the international market, going to be particularly careful with that to understand what that actually means and how you protect whatever you think you are going to get from enhanced margins or low-cost liquefaction, turning high cost liquefaction, shipping political dynamics, fiscal, all of the different things you would look at to want to take on that potentially higher priced commodity. And I used the word potentially, a lot of time it seems over the last 18 months, it’s been quite high. And then there has been periods of time – extended periods of time where it hasn’t. And so we will continue to study that. Our basin proximity, our already contracted firm transportation gives us all kinds of advantages, but it also mitigates some of the risk associated with entering those type of agreements. And we have talked to a number of players, we have sort of worked to screen our – the ideas of who we might want to work with, and we are having some conversation in that space as we speak. So, what we have kind of telegraphed is, you get a certain commodity price opportunity set with the Henry Hub-based agreement. You have a different set of opportunities and risks that come with a higher – a much higher price contract with a lot of additional risks that we want to understand, and we will put those together and we have more to say about that going forward. Certainly, investment grade, certainly, all the other things that we have talked about on this call and the reading materials certainly bode well for how we position the company, and we just want to go into it smartly.

Understood. Thanks for the clarity. I just had a quick follow-up. You guys have talked about you wanted to spend within cash flow. But given the structure of volatility, is that more – should we be thinking that more on like a 12-rolling-month basis, or is that – or do you guys view that more as quarter-to-quarter? I guess the question is, should we think around that?

My comments are around an annual basis. We certainly manage that much tighter, and in this particular macro environment, it’s even more – even tighter, I can assure you. So – but yes, we will manage that on an annual basis as well as the long-term as we move forward.

Understood. Thanks for the time.

Thank you for your questions.

Your next question comes from Noel Parks with Tuohy Brothers. Please go ahead.

Hi. Good morning.

Hi Noel. Good morning.

So, I wanted to touch on the topic of your in-house drilling and frac fleets. And in so many different parts of the cycle there, the advantages of those are pretty clear. And I was just wondering kind of playing devil’s advocate. Thinking about maintenance, thinking about the supply chain and just keeping rig parts and inventory and sort of the cost and challenges of that, is there anything in this sort of low cost, low price gas environment in the event it does prove persistent that could cause you to shift resources or to favor shifting a little bit more towards, say, an incremental vendor rig instead of constraint on your own fleet?

Maybe never say never, but we feel really good about what benefits our vertical integration brings to the company. And when you look at day rates, the different costs for pressure pumping and rig rates, we have got some inflation that comes from that by owning our own. The performance of those has worked well hand-in-hand with the third-party providers that we use where the learnings pass between both, and we are able to get the max benefit where both the third-party performance has improved and our own. And when you think about utilization, which I think is the biggest part of that discussion, with our increased scale from the acquisitions that we have done, we have a nice mix of seven company-owned drilling rigs and two company-owned frac fleets as part of the total program that is pretty materially bigger than that to where it gives us the optionality in a low-price environment, if we are cutting back to drop the third-parties and then continue to have the base activity done by our company-owned equipment.

And a couple of other comments on top of that. We benchmark this business, and it has to earn its own return. And so Clay and his team assure us that they go through all of that just as if it were its own little company, but it has – that it delivers on the commitments that it makes. We have consistent teams on these rigs, so we know who is coming. They happen to be employees, which is great. And so they are rewarded the way the company is rewarded. And they – their capability to learn and deliver people or better performance has been consistent in this process. They are only allowed to work for SWN. In my experience, when you have a vertical integration business like this and you allow it to go off and work for somebody else, it’s easy to lose the plot on where their home base is. So, when you take those along with Clay’s and the rigor that we put in terms of making sure this is the right thing for us to be doing, I think I am very confident that we are in a better spot.

Great. Thanks. And I am discussing with another gas producer earlier in the earnings season, the topic came up of – and it’s a bullish topic to maybe sort of help offset this near-term softness we have maybe in sentiment that with LNG coming on that there are going to be these big step functions upwards of demand from LNG coming on in ‘24, but I guess, in 2025, ‘26, especially. And I am just wondering about your thoughts about the industry’s ability sort of, hopefully, this one to be working in concert to really be able to supply the production capacity in aggregate that’s going to be needed to meet those big steps upward in demand?

Well, this productive capacity of our industry is quite powerful and robust in general. And so the ability for this industry to respond has been there, but I will mute that with pullbacks in investment, with challenges on infrastructure, with challenges on getting gas from one place to another around major cities. All of this is going to be built on the Gulf Coast, and so it goes quite far. Anyway, I think there are risks to that. And so when you – and then not everybody can grow, not everybody has the capability, the access to the markets, the access to where this – all this LNG is going to show up. And so I think Haynesville can help us, Appalachia without infrastructure is getting approved, the ability for that basin to grow. And if LNG grows to the upper end of the scale, we are going to need Haynesville, Appalachia and the Permian to supply. And I think it – there is some risk to that. At the same time, just to give you a balanced view, building all of this at one time probably means that some come on exactly at the time that they said they were coming on, 10:00 a.m. on Tuesday. The rest of it is, it becomes a challenge. You have got to have skilled workers, got to have scale capability to get it all built. And so we take a broad view of that. Fortunately, for us, 65% of our gas can get to the LNG corridor. Fortunately, our reserves are deep and broad, and we are proximal to that growth. And any firm transportation capacity that we need, we already have contracted so that when it’s built, it’s ours. And there is setup to be one of the major suppliers going forward. I will leave it there.

Great. Thanks a lot.

Thank you.

The next question comes from Gregg Brody with Bank of America. Please go ahead.

Good morning guys. I know we are at the end of the call. Just a question, on the fourth quarter, you had a nice working capital benefit there. Can you talk about whether you expect that to continue this year? And is that potential source of cash?

Yes. Good question. We typically have that benefit in the first quarter and then in the fourth quarter with the second quarter and third quarter being more of an outflow, and we would expect that same dynamic to continue through this year.

Great. And then just one more here, as you have alluded to, you are very focused on investment grade, you are going to pay down debt. How do you think about buying back stock this year, considering what’s happening with your stock price? And is it – how do you prioritize that over buybacks?

Yes. Another good question. We have been consistent not only on this call, but really over much of the last year, even since we announced it, buyback authorization back in June. The prioritization of paying debt being paramount, and this year, at least at the current commodity price outlook, we expect our free cash flow to go and reduce debt. And while we agree, stock price today is a lot less than we believe it’s inherently worth. We do believe that paying down debt has a lot of benefits for, again, all parts of the capital structure. It lowers the volatility, which has benefits for equity and lower cost of capital. And candidly, you are directly transitioning your enterprise value through debt to equity when you do that as well. So, more of the asset values to put that with the debt that should at least theoretically not practically should practically too we have seen as beneficial to your equity value. So this year, I anticipate us, again using free cash flow, as Bill said, we paid debt. And as we approach that target with greater confidence, both in terms of time and also commodity price outlook, we can do both as we have shared in the past and would expect to do so.

You are speaking the language that the rating agencies like to hear. So, thanks for the update.

This concludes our question-and-answer session. I would like to turn the conference back over to Bill Way for any closing remarks.

I want to thank you all for your questions. I think they were a terrific, great discussion. And thank you for your interest in the Southwestern Energy. And we look forward to sitting together in another quarter and sharing with some additional achievements that we have made. In the meantime, have a great weekend, and thanks again for joining us.

The conference has now concluded. Thank you for attending today’s presentation. You may all now disconnect.