Southwestern Energy Company

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Southwestern Energy's second 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 recue 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, Sarah. Good morning, and welcome to Southwestern Energy's second quarter 2023 earnings call. Joining me today are Bill Way, Chief Executive Officer, Clay Carroll, Chief Operating Officer, Carl Giesler, Chief Financial Officer, and Dennis Price, Senior Vice President of Marketing and Transportation. Before we get started, I'd like to point out that many of the comments we make during this call are forward-looking statements that involve 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. We appreciate you joining us today to discuss our second quarter operating and financial results. Southwestern Energy's strong quarterly performance reflects the disciplined execution of our strategy of responsibly and efficiently developing our Tier 1 dual-basin inventory. We are generating long-term economic value for our shareholders by capitalizing on SWIN's advantaged assets, scale, expertise, and assured access to deliver our natural gas to premium markets of choice, including LNG across the Gulf Coast. We believe the execution of our strategy translates our strong E&P business into greater economic returns and equity value for our shareholders. As we continue to progress our actionable corporate priorities, we expect to narrow the gap between the intrinsic value of our business and the company's current market valuation. Our top priorities remain strengthening the balance sheet through debt reduction, improved capital efficiency, and maintaining the company's productive capacity while generally investing at maintenance capital levels. Progress we're making on these objectives continues to improve the resilience and strategic positioning of the business through the commodity price cycle. This quarter clearly demonstrates the positive trajectory of our capital efficiency. Our strong production performance was primarily due to improved completion efficiencies that resulted in reduced cycle times and additional producing days during the quarter. And as Clay will detail shortly, we also continue to see encouraging results from our inflation mitigation efforts. Additionally, the company continues to demonstrate the inherent flexibility in our business by adjusting our development program in response to overall and relative commodity price levels. Our updated guidance reflects both our production outperformance year-to-date and the ongoing activity optimization and inflation reduction efforts that have allowed us to invest less capital to generate that production. Consistent with our capital allocation strategy, free cash flow generated from our capital savings will be applied towards debt, further strengthening the balance sheet. We expect to reduce debt year over year from annual free cash flow and proceeds from a non-core asset sale in the second quarter. We ultimately plan to reduce debt to our target range of $3.5 to $3 billion, and as we approach this range, return capital to shareholders. Our constructive outlook for natural gas is supported by both supply and demand fundamentals. Regarding supply, we believe the capital discipline that we've seen through the industry-wide activity reductions will result in moderating if not declining sector production heading into next year. Regarding demand, both strong power burn and increased LNG imports should provide additional price support. With another facility reaching FID last month, nearly 12 BCF per day of incremental LNG liquefaction projects are now under construction along the Gulf Coast. These projects have been service dates as early as next year, with nearly 8 BCF per day expected to become operational by the end of 2025. We believe natural gas pricing would need to strengthen materially to incentivize the production growth necessary to meet this next wave of LNG demand. While Permian-associated gas growth is expected to provide some of the needed supply, particularly to the facilities on the south Texas coast, we believe that the Haynesville, given its advantage proximity, will be critical to supply the majority of this increased LNG demand. Southwestern Energy is already both the largest Haynesville producer and gas supplier to existing U.S. LNG facilities. The company is well positioned to supply the next wave of LNG from Haynesville. And additionally, we have further optionality in our business to leverage our direct access from Appalachia to the Gulf Coast through our firm transportation portfolio. And we have the required scale and inventory depth to remain a key natural gas supplier to the LNG sector for years to come. As we transition into what we believe will be a more constructive natural gas macro, our improving capital efficiency and strengthening balance sheet will position us well to drive increased economic returns and shareholder value. Let me turn the call over to Clay now for some operational updates.

Thank you, Bill, and good morning. The team delivered another strong operating quarter with production of 423 BCFE. Our production consisted of four BCF per day of natural gas, and 106,000 barrels per day of liquids, including nearly 16,000 barrels per day of oil. We saw outperformance across our portfolio driven by accelerated turning lines, improved well performance, less downtime, and increased ethane recovery. During the quarter, we invested $595 million of capital and placed 50 wells to sales. In Appalachia, we placed 28 wells to sales with an average lateral length of more than 17,300 feet. Nineteen of those were in our liquid-rich acreage in West Virginia, and nine wells were across our dry gas areas in Ohio and Pennsylvania. In Haynesville, we placed 22 wells to sales with an average lateral length of 8,500 feet. Sixteen of the wells were in the Haynesville interval, and six were in the Middle Bossier. From an industry perspective, we have seen a nearly 20% reduction in gas-directed drilling activity year-to-date, with continued moderation expected as we move through the second half of the year. Lower sector activity, combined with an improved global supply chain, has provided the opportunity for our strategic sourcing team to mitigate and, in some cases, reverse the inflationary cost pressures we had expected at the beginning of the year. We have captured savings across the board, particularly in casing, track horsepower, and chemicals. We are continuing to work with our service providers to further align costs with the current commodity price environment. Our original guidance assumed 10 to 15 percent inflation this year, but our successes to date have decreased our outlook to low single-digit inflation for the year with the potential for deflationary impacts next year. We're particularly encouraged by the deflationary cost reductions and capital efficiency gains we've been able to achieve in the Hainesville. And in 2024, we expect well costs to be 10% to 15% lower than this year. Those savings are already helping to improve the company's capital efficiency metrics and free cash flow generation in 2023. As we shift into the back half of the year, we are formally updating our full year guidance. Consistent with the previously communicated activity adjustments and the reflected team's outperformance year to date, we are lowering our 2023 capital guidance by approximately 10% or $200 million to a range of $2 billion to $2.3 billion with only a modest impact to production. From an activity perspective, we expect approximately 10 less drilled wells and 15 less wells completed and turned to sales than originally planned. Given this moderating activity, we expect capital investment will decrease roughly $100 million in the third quarter from the second quarter. The team has done an excellent job delivering on our plan in the first half of the year, and we have strong operational momentum heading into the second half. Now I'll turn the call over to Carl.

Thank you, Clay. Consistent with our front-loaded capital program and the seasonality of natural gas prices, our investment outpaced our operating cash flow during the quarter by approximately $140 million. We nonetheless ended the quarter with net debt in line with last quarter at $4.0 billion. Approximately $120 million in proceeds from a non-core Pennsylvania Utica asset sale largely offset our quarterly cash outspend and seasonal working capital outflow. Our leverage increased modestly to 1.4 times, still within our target leverage range of 1.5 to 1.0 times. We remain on track to deliver our annual program within cash flow and anticipate year-end 2023 debt to be lower than that at year-end 2022. We expect a direct free cash flow and proceeds from our non-core asset sales debt reduction. Bill noted our target debt range remains $3.5 to $3.0 billion. We believe debt reduction directly translates to increased shareholder value. Lowering debt transfers enterprise value from lenders to shareholders. growing our market capitalization. Reducing debt also lessens both the financial risk to our future cash flows, as well as the volatility in our stock, both of which we believe lower our cost of capital. Aggressing towards our target debt range will further position SWIM to be able to sustainably return capital to shareholders and return to investment grade. On the hedging front, We added to our base layer 2025 natural gas hedge position during the quarter and currently stand at approximately 40 percent and 10 percent hedged respectively for 2024 and 2025. We continue to target a more moderate hedge production range of 40 to 60 percent. We believe this range balances protecting our financial strength with appropriate risk-adjusted upside exposure. This approach should improve price realizations given our constructive natural gas outlook. We are actively executing across multiple facets across the business to translate the significant value of the company into greater value for shareholders. Operator, please open the line for questions.

Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. In the interest of time, please limit yourself to two questions and re-queue for additional questions. At this time, we will pause momentarily to assemble our rosters.

Our first question comes from Charles Mead with Johnson Rice.

Please go ahead.

Good morning, Bill, Clay, and Carl. I have a question. I appreciate, Clay, you've already gone through some of the deltas on the wells drilled and turned sails and that sort of thing, and I appreciate the detail you guys offer in your updated guide and your press release, but I wonder if I could Rather than look at each individual piece, just maybe take a stab at cutting through to the, I guess, the meaning. And it looks like with 50 wells turned sales into Q, it looks like that you guys are pulling or have pulled some completions forward in time because of your efficiencies. And the question is, if that's the case, that you pulled some completions out of 3Q into 2Q or out of 4Q into 3Q. Are you going to reload the 4Q completion schedule? That's the best part of the curve right now, and I guess maybe it's a long way of asking, are you biased towards the high end of that wells-to-sales guide? Sure.

Sure. So given where commodity prices are right now, our guide is reflecting that we won't go add incremental completions back in the fourth quarter. But that optionality still exists if we see a price surge that allows us to go forward with that. All that consistent with the way we guided in the first quarter call. And you are right. completion efficiency gains caused us to have more wells turned to sales in 2Q than the original budget and guidance at the start of the year. All that consistent with the operational improvements that we've been continuing to focus on and we're seeing them show up.

Okay, thank you for that Clay. And then on your presentation, You've given us some new detail on slide 15, and I just wanted to ask a question, because there's one thing on this slide that surprised me, and specifically, it was that in the DeSoto East area, your Bossier wells are actually more productive than the Haynesville wells, and I think this is also what you've identified as your most productive area. I wonder if you can perhaps address whether that was a surprise to you as well, and perhaps is this an artifact or some kind of downstream result of all the faulting in the area?

Sure. So we had a good feel for the DeSoto East Natchitoches fault zone area from the beginning. It was part of why we targeted the assets that we acquired and the fact that there were stacked Tier 1, Middle Bossier, and Haynesville in that area was another big part of why we focused on that area. When you look at DeSoto East, as you mentioned, there are some different fault blocks included in that broader area. Both the Haynesville and Middle Bossier perform essentially the best in Haynesville in that area. There is a certain fault block where Middle Bossier does outperform the Haynesville, but on average across DeSoto East, they almost look identical and they're some of the highest IP and EUR parts of the Haynesville field.

Thank you for that detail, Clyde.

My next question comes from Doug Legate with Bank of America. Please go ahead.

Thanks. Good morning. Good morning, everyone. Thanks for having me on and love the messaging on the improving equity volatility. So thank you for reinforcing that message. I have two quick ones, if I may. I want to hit the 800-pound gorilla in the room, Bill, which is your step down in spending. It seems to me that you're not done yet. I'm talking specifically, our understanding is that you're testing different fluid loadings, different completions in the Hainesville in particular, which seems to me that's a big potential low-hanging fruit to drop capital and improve efficiency even further. So I wonder if you could just address that. Maybe it's a question for Clay, but it seems to us that's another area that's still got some running room. Can you elaborate on that, please?

Certainly. We've been active around all of the completion optimization efforts for some time now across both Appalachia and Haynesville. Fluid loading has been an area that has benefited the production performance across both areas. We continue to optimize completions across different parts of our field to come up with the best combination to deliver the best well performance. And so that will continue. I think some of our other peers have talked about making some movements in that place. I think those are things we've been doing over time and will continue to do.

Claire, do you think you can get the capital back under $2 billion?

You keep asking us that. I think that depending upon commodity price, depending upon activity levels, depending upon the continued deflation reduction success, I think there's a range of outcomes that maybe is similar to what we guided to for 2023 that has a midpoint of the $2.15 billion, but a range of $2 billion to $2.3 billion.

All right, consistent with the messaging. Thank you for that. My follow-up is a macro question, and it's just a real quick one. I asked this to one of your peers the other day, but there's a perception that the Haynesville has a big overhang of uncompleted wells. But when we look at the disclosure you guys put out last night relative to some of the third-party services, there seems to be a massive gap between the perception and the reality of what you think is your duck backlog. So I wonder if you could just address that. What do you think the duck situation looks like relative to the perception that there's a big load of supply that could come on stream into a higher gas price?

Yeah, we agree with your comment that the public data has it way overstated. Maybe by more than half, depending upon the different services. The public count on one of the ones we look at for Haynesville right now says we have 30, and we actually have a little more than half of that right now. So we think it's overstated. Agree with your thoughts on that.

Great stuff. Thanks so much, guys.

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

Hi, good morning, and thank you for taking my questions. For my first question, would love your thoughts on the gas macro, your thoughts on the setup in the back half of the year, and then how are you thinking about risk management through hedging? I noticed you added some hedges in the back half of 23 and then some in 25.

I think Bill addressed very well our outlook on natural gas over the next couple years, but when you narrow into the balance of 2023, a lot of our view is derived around a very constructive fundamental picture that we've seen emerge this summer with increased gas burns and a rebound in exports of LNG offset perhaps a little bit by the overhang in storage. And so when we think about the balance of 2023, it's really a question of where inventory levels end up in October and how does that position us going into the winter. So you're correct that we did add some downside protection to that part of the curve in the event that we see a warmer than normal start to winter. And so we wanted to increase our downside protection in case that was to materialize. But Generally speaking, we're very opportunistic about how we add hedges to our book, guided by our view of the market. And so when you think broader about our risk management strategy, it's focused on exactly that, opportunistic adding to our portfolio to increase our downside protection but still allow us some upside participation.

That's very helpful. And then a little bit on the operation and how you're thinking about it. Efficiency gains was obviously a very strong update from you guys in 2Q. You have increased your duck inventory for the end of the year, so that gives you some optionality towards increasing activity to the extent the macro does improve. especially for the winter. So I'm trying to understand the balancing act here in terms of obviously keeping a balance sheet strong and maintaining the strength of the balance sheet, but also maintaining a productive capacity. Like you mentioned, production is declining in the back half of the year.

Yeah, with the adjustments we made to the completions and the drilling count, the duck inventory moved up like we would have expected. And you're right, it does provide us optionality as we move into 2024. Again, it's going to be driven by where commodity prices are at and where we see deflation. And it'll all be clearer as we get closer to the end of the year and we're able to fully put together the 2024 plan, but optionality is what we want to have.

Gotcha. That's really helpful. Thank you.

Our next question comes from John and it's with . Please go ahead.

Hey, good morning all and thanks for taking my questions. For my first one, with the understanding that 2024 planning is still ongoing, could you offer some high-level comments on what the revised 2023 plan means for production and capital cadence in 2024?

Sure. As we think about 2024, we always have a slightly front-loaded program, and that will continue again as we plan out 2024. And in some ways, could be a little accentuated with the reduction in activity that we just guided into for 2023. That profile for 2024, I think, will look similar to our past profiles with the front-end loading, where you'll see the greater production volumes showing up in 3Q and 4Q in a normal year where we're not pulling back the activities because of the front-end loading in the front half. As we talked about, we want to be positioned to benefit from the constructive commodity price environment. If that shows up in early 24, late 24, more in 25, we're going to keep reading those tea leaves and what we think about the fundamentals to then lay out our capital plan for 2024 in line with all of that. More to come there, and as I've said, we're seeing cost deflation showing up, and hopefully as we move into 2024, we're going to be able to get service costs more in line with the current commodity price environment.

Terrific. And for my follow-up, if I'm not mistaken, you achieved a company record in terms of average lateral length in Appalachia this quarter. With the notable uptick in industry commentary this earnings season regarding EMPs achieving positive results on wells with laterals in that 15 to 20,000 foot range, could you provide color on your inventory depth that would support extended laterals? And are there any technical limitations or concerns with drilling laterals closer to that 20,000 foot level?

So I'll start with I think we've got close to 10 wells now that have exceeded 20,000 feet. In the quarter, we completed a well in Ohio that was almost 24,000 feet. I think our vertical integration, the experience of our drilling and completion teams are all leading to us being able to really have a competitive advantage in that place. We have done the majority of that in Appalachia and the 17,000 foot average lateral length in 2Q is an example of that. That knowledge and experience, we're moving into the Haynesville. The Haynesville is a little bit different with some of the fault blocks and with the higher bottom hole pressure and temperatures, but we think we're going to make progress in the Haynesville also to capture those benefits of longer laterals. In late 2Q, early 3Q, we TD'd wells in the Haynesville that had a close to 13,000 foot lateral length and one that was over 14,000 feet. So progress is being made there. Our inventory continues to be improved by our land groups. doing acreage trades, picking up leases so that we can continue to add to the contiguous nature of the lease position so that we have the optionality to go longer.

I appreciate all the color and congrats on a positive update. Thank you.

Our next question comes from Bertrand Dennis with Truist. Please go ahead.

Hey, good morning, guys. On the first question, and just on the LNG front, maybe last quarter I would have put you in the category of conservative towards locking in a contract, but maybe your recent commentary and maybe even the personnel that you brought with you on your recent marketing trips have maybe suggested that you're getting a little more interested or maybe the deals coming available are more attractive to you. So I guess the first part is, is that fair? And then the second part is, you know, are there any of the new kind of dynamics of the LNG contracts standing out to you above just, you know, a Henry Hub premium kind of deal?

Sure. No, I think that's fair. You know, as Bill alluded to in his opening remarks, you know, we're the largest supplier of natural gas to the U.S. LNG exporters right now with over a BCF and a half a day currently sold to a wide variety of buyers We feel like we understand this market very well, and we believe that there are and will continue to be plenty of internationally priced supply opportunities for us. And since we have, you know, two BCF a day of production that currently reaches the LNG corridor, we think we'll remain a major supplier to the sector going forward. More pointedly to your question, we're evaluating all of these opportunities to potentially leverage our position into an attractive risk adjusted globally priced supply agreement. But I think regardless of how we price our transactions, we believe our scale and direct connectivity to the corridor will allow us to benefit differentially from the growing demand from the next wave of LNG. You know, you're right, the structure of contracts is shifting a bit. The market is maturing. And we're taking a very disciplined, risk-aware approach to how we contract the next tranche that we sell.

That sounds great. And then the second one, your 3Q differential guidance for gas, you know, it shows the realities of a bit more challenged quarter. your full year outlook seems to remain pretty strong so i was just wondering if you're are you already seeing something maybe intra quarter or maybe could you just talk about the relative difference between your differential and the hanesville and marcellus maybe you know one is outperforming the other you know considering you know maybe the ducks coming on or mvp impacts thanks yeah i think you know the

Obviously, the basis market in the northeast has weakened as we've moved from the second quarter into the early third quarter, you know, driven primarily by, you know, a mild winter and the resulting buildup in east region storage levels, plus throw in a little bit of pipeline maintenance as well on top of that. You know, I think when we think about how that affects us company-wide, You know, we have a large portion of our production in the basin hedged, plus we have access to the Gulf Coast via our firm transportation arrangements. So we're very comfortable, despite this volatility in near-term basis in the Northeast, comfortable with our full-year guidance range on differentials.

Just a real quick correction to my comment on lateral links. We've got 23 that are over 20,000 feet, so I misstated it earlier. Sorry.

No problem. I appreciate it.

Our next question comes from Paul Diamond with Sooty. Please go ahead.

Good morning, all. Thanks for taking my call. I just wanted to touch base a little bit on We talked about ducts a little bit. Just wanted to get your idea on what you guys see as kind of a run rate, proper level of inventory for ducts in a normalized market for you guys.

Yeah, our core philosophy is we don't build ducts. We're about having the right amount of ducts in front of us for the efficient drilling and completion process. in both areas and so that we can continue to make progress on those and not have a lot of success on the drilling efficiency gain and then be waiting on the completion, that we can line them straight up. And so that's in line with the duck inventory that we guided to originally between the two areas. I mean, somewhere in the 25-30 range with the program that we had in 2023, uh, given the, the way we're, uh, optimizing around gas price right now, and we've got a few more ducks, like we talked about earlier, that will give us some optionality, but, but we're more about the right amount of ducks to keep driving efficiencies.

Understood. Thanks. And, um, just one quick follow up talking to kind of, uh, you know, looking forward to our activity. Um, What are you guys kind of viewing as the bellwethers for, you know, rig cadence? What would you guys want to see to start bringing rigs back online? And in your mind, what does that really look like into, you know, H2 and 24?

Yeah, I mean, I think we're going to continue to balance that we are at a minimum living within our cash flow with our capital spend and see a more sustained view of commodity prices going higher in the future. And remember, our portfolio gives us a lot of exposure to liquids, so oil and NGL prices are part of that discussion, but we're mainly a natural gas, so natural gas prices will drive that. And that will be the guide as we move into the year and the maintaining the productive capacity of the company and staying in that maintenance capital environment that we've been in now for a while, and those will be the drivers as we move into 2024.

Okay, understood. So we just think about it as a kind of cash flow driven balance then?

Yes. Understood. Thanks for your time and clarity.

Our next question comes from Arun Jaram with JP Morgan.

Please go ahead.

Yeah, good morning. Arun Jaram, JP Morgan. I had a quick question on how we should think about the sustaining CapEx kind of requirements of the business next year. Tim, you guided to third quarter production of 429 BCFE and 4Q at 414. And so as we think about you guys trying to sustain production, should we think about the fourth quarter run rate as being what we saw for or the second half average? But just getting thoughts on how we should start thinking about 2024 production that you'd like to hold.

Well, I think all that range could apply, depending upon where commodity prices are at. I mean, with 2022, we were a little bit above 4.7. We're going to be 4.6, BCF equivalent a day of net production. This year, the fourth quarter will be a little lower than that, as we've talked about. So I think that range lives within our view of maintaining the productive capacity of the company. And then we're going to move within that range given where commodity prices and where costs potentially come down to.

Got it, got it. And just my follow-up, I know it's been asked a couple of times, but in the second half of the year, Clay, you're spending around $900 million, if we did our math correct. So you're basically spending, you're saying, below sustaining at this level. And maybe a quick follow-up on that is we know that you've maybe changed some teams on your OFS vendors, particularly in the Haynesville. So I was wondering if you could give us maybe a snapshot on where leading edge well costs are trending relative to what you quoted as analyst day.

So you're right about the second half capital spin being below the sustaining capital. I think about 72% of our full year guided turn in lines have happened through 2Q, kind of what we're seeing on the wells we're drilling now that have more of the benefit of all the cost reductions that we've seen and the operational efficiencies that we've had are more in line with what I'm guiding in particular in the Haynesville well cost to for 2024 in that $1,800 a foot range. So we've got drill wells that are seeing that reduction, and then we're ahead of the game on the completion efficiencies right now. And to your point, I mean, where we've made change-outs on the pumping providers, those are providers that have worked with us in the past. They're vetted, and the performance has been very good.

Great. Thanks a lot.

Our next question comes from Noel Parks with Twitty Brothers. Please go ahead.

Pardon me. Is your line on mute perhaps?

This concludes our question and answer session.

I would like to turn the conference back over to Bill Way for any closing remarks.

I just want to express from the leadership team and all the employees of Southwestern our appreciation for you all joining the call today. And we look forward to updating with you in a quarter, in the third quarter coming up.

That's it. Thank you.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.