Good morning, ladies and gentlemen, thank you for standing by. Welcome to Southwestern Energy's second quarter 2023 earnings call. Management will open the call, call for a question and answer session following prepared remarks. In the interest of time, please limit yourself to two questions and 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, Sarah. Good morning, and welcome to Southwestern Energy's second quarter of 2023 earnings call. Joining me today are Bill Way, Chief Executive Officer, Clay Carrell, Chief Operating Officer, Carl Giesler, Chief Financial Officer, and Dennis Price, Senior Vice President of Marketing 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 risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the Risk Factors and the Forward-Looking Statements sections of our annual report and quarterly reports as filed with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance. Actual results or developments may differ materially, and we are under no obligation to update them. We may also refer to some non-GAAP financial measures, which help 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. 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 SWN'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. 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 billion 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 in-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 advantaged 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. Additionally, we have further optionality in our business to leverage our direct access from Appalachia to the Gulf Coast through our firm transportation portfolio. 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 4 bcf per day of natural gas and 106,000 bbl per day of liquids, including nearly 16,000 bbl per day of oil. We saw outperformance across our portfolio, driven by accelerated turn-in-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 ft. 19 of those were in our liquids-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 ft. 16 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, frac 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%-15% 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 Haynesville. In 2024, we expect well costs to be 10%-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 to reflect the 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-$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 1.4x, still within our target leverage range of 1.5x-1.0x. 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 to direct free cash flow and proceeds from our non-core asset sale to debt reduction. Bill noted our target debt range remains $2.5 billion-$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. Progressing towards a target debt range will further position SWN 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% and 10% hedged, respectively, for 2024 and 2025. We continue to target a more moderate hedge production range of 40%-60%. 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. 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 roster. Our first question comes from Charles Meade with Johnson Rice. Please go ahead. Good morning, Bill, Clay, and Carl. Morning. I, I have a question. I appreciate... Clay, you've already gone through some of the deltas on the wells drilled and turned sales and that sort of thing, and I, and I appreciate the detail you guys offer in your updated guide and your press release. I wonder if I could, rather than look at each individual piece, just, you know, maybe take a, take a stab at cutting through to the, I guess, the meaning. It looks like, you know, with 50 wells turned sales in 2Q, it looks like that you guys are pulling or, or have pulled some completions forward in time because of your efficiencies. 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, that's the, the best part of the curve right now. I guess, maybe it's a long way of asking, are you biased towards the high end of that wells to sales guide? Sure. Given where commodity prices are right now, our, 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, a price surge that allows us to, to go forward with that. All that's consistent with, with the way we guided in the first quarter call, and you are right, our 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, we're seeing them show up. Okay. Thank you for that, Clay. On your presentation, you've given us some new detail on slide 15, I just wanted to ask a question, because there's one thing on this, 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, which... I think this is also what you've identified as your, your, your most productive area. I wonder if you can, if you could perhaps, address whether that, that was a surprise to you as well. Perhaps, is this, is this an artifact or some kind of a, a downstream result of, of, all the faulting in the area? Sure. 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, 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, Clay. Sure. My next question comes from Doug Leggate with Bank of America. Please go ahead. Morning, Doug. Thanks. Good morning. Good morning, everyone. Thanks for having me on, and love the messaging on the on on the improving equity volatility. Thank you for, thank you for reinforcing that message. I, I have two quick ones, if I may. I, I wanna hit the 800 lb gorilla in the room, Bill, which is your step down in spending. It seems to me that you're not done yet, and I wanna... I, I, I'm talking specifically, our understanding is that you're testing different fluid loadings, different completions in the Haynesville in particular, which seems to me that's a, a big potential, you know, low-hanging fruit to drop capital and improve efficiency even further. I wonder if you could just address that. Maybe it's a question for Clay, but it seems to us that's a, another area that's still got some running room. Can you elaborate on that, please? Certainly. We've, we've been active around all of the completion optimization efforts for some time now across both Appalachia and Haynesville. Fluid loading has, 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. So that will continue. I, I think some of our other peers have talked about making some movements in that place. I, I think those are things we've been doing over time and will continue to do. Clay, 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, that maybe is similar to what we guided to for 2023, that, that has a midpoint of the $2.15 billion, but a range of $2 billion-$2.3 billion. All right. Consistent with the messaging. Thank you for that. My, my follow-up's a macro question, and it's just a, a real quick one. I, 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. When we look at the, 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 DUC backlog. I wonder if you could just address that. What do you think the DUC, you know, situation looks like relative to the perception that it's, you know, there are 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, you know, but maybe by more than half, depending upon the different services. The public DUC count on one of the ones we look at for Haynesville right now says we have 30, and we actually have little, little more than half of that right now. We think it's overstated. Agree with, 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. Then how, how are you thinking about risk management through hedging? Notice you added some hedges in, in the back half of 2023 and then, some in 2025. I think Bill addressed very well our, our outlook on natural gas over the next couple of years. 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. When we think about the balance of 2023, it's, it's really a question of where inventory levels end up in October and how does that position us going into the winter. You know, 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. We wanted to increase our downside protection in, in case that was to materialize. You know, generally speaking, we're very opportunistic about how we add hedges to our book, guided by our view of the market. 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. A little bit on the operation and how you're thinking about it. Efficiency gains was obviously very strong, strong update from you guys in 2Q. You have increased your DUC inventory for the end of the year, that gives you some optionality towards increasing activity to the extent the macro does improve, especially for the winter. I'm trying to understand the balancing act here in terms of, obviously, keeping your balance sheet strong and maintaining the strength of the balance sheet, but also, you know, maintaining a productive capacity. Like you mentioned, your production is declining in the back half of the year. Yeah. With the adjustments we made to the completions and the, the drilling count, the DUC inventory moved up like we would have expected. You're right, it, it, it does provide us optionality as, as we move into, 2024. 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, and we're able to fully put together the 2024 plan. Optionality is, is what we want to have. Gotcha. That's very helpful. Thank you. Our next question comes from John Annis with Stifel. Please go ahead. Hey, good morning, all. 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, we always have a slightly front-loaded program, and that will continue again as we plan out 2024. In some ways, that 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, in a normal year where we're not pulling back the activities because of the front-end loading in the, in the front half. As we talked about, we, we want to be positioned to benefit from the constructive commodity price environment. If that shows up in early 2024, late 2024, more in 2025, 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, we're seeing cost deflation showing up, and hopefully, as we move into 2024, we're, we're going to be able to get service costs more in line with the current commodity price environment. Terrific. 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 E&Ps achieving positive results on wells with laterals in that 15,000-20,000 ft range, could you provide color on your inventory depth that would support extended laterals? Are there any technical limitations or concerns with drilling laterals closer to that 20,000 ft level? I'll start with, I think we've got close to 10 wells now that, that have exceeded 20,000 ft. In the quarter, we completed a well in Ohio that was almost 24,000 ft. I, 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, we, we have done the majority of that in Appalachia and, and, and the 17,000 ft 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, 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, in late 2Q, early 3Q, we, we TD'd wells in the Haynesville that had a close to 13,000 ft lateral length and one that, that was over 14,000 ft. 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 Donnes 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, you know, conservative, you know, towards locking in a contract. Maybe your recent commentary and maybe even the personnel that you've 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. I guess the first part is: Is that fair? 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 a, 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, we're the largest supplier of natural gas to the U.S. LNG exporters right now, with over 1.5 bcf 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. Since we have, you know, 2 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. 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, that sounds great. The, the second one, your 3Q differential guidance for gas, it, you know, it, it shows the, the realities of a bit more challenged quarter, but your full year outlook seems to remain pretty strong. I was just wondering, are you already seeing something maybe intra-quarter? Maybe could you just talk about the relative difference between your differential in the Haynesville and Marcellus? Maybe, you know, one is outperforming the other, you know, considering, you know, maybe the DUCs coming on or MBP impacts. Thanks. Yeah. I think, you know, the-- obviously, the, the, the basis market in, in the Northeast has, 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 you- we think about how that affects us company-wide, you know, we have a, a, a large portion of our production in the basin hedged, plus we have access to the Gulf Coast via our firm transportation arrangements. We're very comfortable, despite this volatility in near-term basis in, in the Northeast, comfortable with our full-year guidance, range on differentials. Just, just a real quick correction to my comment on lateral links. It's, we've got 23 that are over 20,000 ft, so I've, I misstated it earlier. Sorry. No problem. I appreciate it, guys. Our next question comes from Paul Diamond with Citi. Please go ahead. Good morning, all. Thanks for taking my call. I just wanted to touch base a little bit on, you know, kind of with the... You talked about DUCs a little bit. Just want to get your idea on what, you know, you guys see as kind of a run rate, you know, proper level of inventory for DUCs in a normalized market for you guys? Yeah. Our, our core philosophy is we don't build DUCs. We're, we're about having the right amount of DUCs in front of us for the efficient drilling and completion of, in both areas, and so that we can continue to make progress on those and, and not have a lot of success on the drilling efficiency gain and then be waiting on the, the completion, that we can line them straight up. That, that's in line with the DUC inventory that we guided to originally. Between the two areas, I mean, I mean, somewhere in the 25-30 range with the program that we had in 2023. Given the, the way we're optimizing around gas price right now, and we've got a few more DUCs like we talked about earlier, that will give us some optionality. We're more about the right amount of DUCs to keep driving efficiencies. Understood. Thanks. Just one quick follow-up. Talking to kind of, you know, looking forward towards activity, what are you guys kind of viewing as the bellwethers for, you know, rig cadence? What would, what would you guys want to see to start bringing rigs back online? In your mind, what does that really look like into, you know, H2 in 2024? Yeah, I mean, I, I, I think we're going to continue to balance that, 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, in the future. Remember, our portfolio gives us a lot of exposure to liquids, so oil and, and NGL prices are part of that discussion, but, but we're mainly a natural gas, so natural gas prices will drive that, and that, that, that will be the, the guide as we move into the year. The, the maintaining the productive capacity of the company and staying in that maintenance capital environment that, that we've been in now for a while, and those will be the drivers as we, as we move into 2024. Okay, understood. 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 Jayaram with JP Morgan. Please go ahead. Yeah, good morning, Arun Jayaram, JP Morgan. I had a quick question on how we should think about the sustaining CapEx kind of requirements of the business next year. Bill, you guided to third quarter production of 429 bcfe and 4Q at 414. As we think about you guys trying to sustain production, should we think about the fourth quarter run rate as being what we solve for or the second-half average? Just getting thoughts on how we should start thinking about 2024 production that you'd, 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 bcfe a day of net production. This year, the, the fourth quarter will be a little lower than that, as we've talked about. I, I think that range lives within our view of maintaining the productive capacity of the company, and then we're, we're going to move within that range, given where commodity prices and where costs potentially come down to. Got it. Got it. 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. You're basically spending, you're saying, below sustaining at this level? 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. I was wondering if you could give us maybe a snapshot on where leading-edge well costs are trending relative to what you quoted at Analyst Day per foot? I'll so, so you're right about the second half capital spend being the below the sustaining capital. I think about 72% of our full-year guided turn-in-lines have happened through 2Q. The kind of the what we're seeing on the, the wells we're drilling now that, that have more of the benefit of all the cost reductions that we've seen and the, 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. We've, we've got drill wells that are, that are seeing that reduction, and then we we're ahead of the game on the completion efficiencies right now. To your point, I mean, where, where we've made changeouts 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 Tuohy Brothers. Please go ahead. Pardon me, use your line, I mean, 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 of the employees of Southwestern, our appreciation for you all joining the call today. We look forward to updating with you in a quarter, in the, in the third quarter, coming up. That's, that's it. Thank you. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.