Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwestern Energy's Q2 2022 earnings call. Management will open the call for a question and answer session following prepared remarks. In the interest of time, please limit yourself to two questions and re-queue for additional questions. This call is being recorded. I would now like to turn the conference over to Brittany Raiford, Southwestern Energy's Director of Investor Relations. You may begin. Thank you, Cole. Good morning, and welcome to Southwestern Energy's Q2 2022 earnings call. Joining me today are Bill Way, President and Chief Executive Officer, Clay Carrell, Chief Operating Officer, Carl Giesler, Chief Financial Officer, and Jason Kurtz, Head 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 report 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, and 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'll now turn the call over to Bill Way. Thank you, Brittany, and good morning, everyone. Southwestern Energy is well-positioned as a leading natural gas producer in the two premier US natural gas basins. We are executing on our deliberate strategy to grow resilient free cash flow, as evidenced by our Q2 and year-to-date results. I'm particularly pleased with the successful integration of our Haynesville business and its contribution to the company's results. In June, we progressed our capital allocation strategy, complementing continued debt repayment with a share repurchase authorization of up to $1 billion through the end of 2023, which is nearly 15% of our current market capitalization. This share repurchase program underscores management's confidence in the long-term free cash flow generation capability of our business. Additionally, due to its flexibility, we expect to execute the program consistent with our strategic financial objectives of reducing debt and returning to investment grade. This program also directly allows the company to capitalize on the significant disconnect we see between the current enterprise value and the intrinsic value of our business, as reflected in our Q2 PV-10 reserve value of $31 billion at recent strip prices. Regarding the current macro environment, we believe natural gas supply and demand dynamics have strengthened near- and long-term, supporting our growing free cash flow generation. On the supply side, capital discipline, producer consolidation, service market tightness, and infrastructure capacity constraints continue to moderate production growth. On the demand side, global decarbonization and energy security priorities have accelerated the demand for clean-burning, reliable US natural gas. Domestically, strong industrial and residential power generation demand have become less sensitive to natural gas pricing, given continued coal power capacity retirements. The net effect, we believe, is that the US natural gas market continues to move from structural oversupply to a more balanced market with the potential for further excess demand, especially in the Gulf Coast region. As a key differentiator for SWN is our proximity and firm transportation to the long-term demand growth along the Gulf Coast. As the largest producer in Haynesville with complementary firm transportation from Appalachia, 65% of our total production reaches this market. Approximately 12 BCF per day of liquefaction is currently in service, which could more than double with FERC-approved projects, including approximately seven BCF per day that is already under construction. Today, Southwestern Energy is one of the largest suppliers of natural gas to existing LNG exporters at 1.5 billion cubic feet per day. As natural gas transitions from a regional to a global price-linked commodity, we believe we will differentially benefit as the Haynesville and Gulf Coast garner premium pricing relative to other basins. We are evaluating on a risk adjusted basis potential opportunities to benefit from global pricing by leveraging our proximate, reliable, long-term supply capability to help enable liquefaction projects to achieve FID. Hedging remains core to SWN's enterprise risk management practice, ensuring recovery of the company's costs and capital expenditures. With our improved financial position, however, and the supportive fundamental outlook for natural gas prices, expect our future hedging levels to migrate lower within our approved ranges and with preference for using collars. As our hedges settle, our reinvestment rate will more clearly reflect the inherent cash generation capability of our asset base. The resulting prospective rate of change in our free cash flow profile differentiates SWN as an investment opportunity. We're highly encouraged by the high level of performance across our portfolio and are increasing our full year production guidance and updating other key metrics. Included in that update is an increase of our 2022 capital investment by approximately 10% to offset inflationary impacts and further strengthen the continuity of our operational activity as we head into our 2023 maintenance capital investment program. This approach increases cumulative free cash flow generation, accelerating debt reduction, and the return of capital to shareholders. As a core aspect of how we operate at SWN, by the end of this year, Haynesville production will join Appalachia as fully certified, responsibly sourced gas. Additionally, our ninth annual corporate responsibility report will be released this fall and highlights ESG achievements for the company. This report will also include a longer-term GHG emissions reduction goal and the specific path for the company to achieve it. With that, I'll turn the call over to Clay for an operational update. Thanks, Bill, and good morning. Strategic execution is a key pillar of our strategy, and I will highlight a few proof points that support the company's sustained performance in this aspect of our business. Halfway through the year, our development program is on track and performance continues to exceed expectations. For the quarter, we delivered net production of 438 BCFE or 4.8 BCFE per day, including 4.2 BCF per day of natural gas and 100,000 barrels per day of liquids. Production surpassed the high end of guidance, primarily due to well performance and cycle time improvements. Overall, we placed 42 wells to sales during the quarter. In Appalachia, we placed 23 wells to sales with an average lateral length of approximately 14,000 feet. Our rich and super rich areas accounted for 13 of those wells, increasing liquids volumes quarter-over-quarter and enhancing margins. Marcellus and Utica dry gas acreage in Ohio and Pennsylvania accounted for the remaining Appalachia turning lines. In Haynesville, the team placed 19 wells to sales with an average lateral length of approximately 9,500 ft. Among them is an over 13,000 ft lateral, which is currently producing in line with expectations at greater than 40 million cubic feet per day from the Middle Bossier interval, which highlights the strength of our stack pay position in Haynesville. Operational execution and cycle times in Haynesville continue to improve. In DeSoto East, we have realized drilling time improvements of over 15% year-to-date, including a recent well with a spud to rig release of less than 30 days. On average, across the field, we are delivering a 10% drilling time improvement compared to plan, driven by the application of new technologies and learnings from wells earlier this year. Overall, we are continuing to see strong initial production rates and improving well performance. Our integrated development approach ensures necessary gathering and firm transportation capacity is in place, providing flow assurance and market optionality. As Bill mentioned, we are updating select 2022 guidance, including increasing our full year production guidance to reflect both the strong performance in the first half of the year and our updated expectations for the second half. From an activity standpoint, we expect to average nine to 10 rigs and four to five frack crews during the second half of the year, consistent with our plan development program. Q3 capital is expected to be in line with our first and Q2 investment levels, and full year capital investment is expected to be in the range of $2.1 billion to $2.2 billion. We continue to realize cost and operational execution benefits from our vertical integration that are partially offsetting industry cost pressures. We are adding a second SWN-operated frack fleet in Appalachia in the Q3, displacing a third-party stim provider and delivering surety of service, cost reductions, and operational efficiencies. We are also repositioning a third SWN-owned rig to Haynesville late in the Q4, which we expect to further improve performance, compress cycle times, and reduce costs. In addition to our vertical integration, our proactive planning, purchasing, direct sourcing, and key service provider relationships are ensuring availability of the goods and services required to deliver our plan both this year and next. Now I'll turn the call over to Carl to provide a financial update. Thank you, Clay, and good morning. This quarter, we generated approximately $170 million of free cash flow and further improved our leverage ratio to 1.6x. We expect to achieve the top end of a 1.5x to 1.0x target leverage range in the Q3. Our debt balance temporarily grew quarter-over-quarter by about $150 million. This increase reflects a hedge-related working capital draw caused by the sharp rise in natural gas prices between April and June. Recall that like most producers, we pay hedge settlements early in the production month before receiving the more than offsetting corresponding physical sales proceeds later the following month. Accordingly, our quarter-end debt balance included credit facility borrowings of $406 million. By the end of July, we had repaid the revolver in full, demonstrating the short duration of that hedge-related working capital draw. Looking forward, due to strong operational performance and given the current commodity price outlook, free cash flow should approximate $1 billion in 2022, and as our hedges settle, $2.2 Billion per year starting in 2023. We will prioritize allocation of this free cash flow to debt retirement in the near term before shifting more heavily towards share repurchases. At current strip, we expect to be able to reach the $3.5 billion top end of our target debt range by the end of next year while also completing the share repurchase authorization. This capital allocation strategy is consistent with our strategic objective of returning to investment grade. In May, Moody's upgraded SWN to Ba1, now placing us one notch below investment grade at both Moody's and S&P. We believe our materially improved business and financial risk profile already is or is close to investment grade. We plan to continue to manage the enterprise consistent with returning to investment grade. The ultimate timing of that return, however, rests with the credit agencies. This concludes our prepared remarks. Please open the line for questions. We will now begin the question and answer session. To ask a question, you may press star then one on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. 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. Our first question today will come from Scott Hanold with RBC. Please go ahead. Thanks. Good morning. Could you all, you know, talk about obviously having good exposure on the Gulf Coast where the demand center is. Could you give us your most recent thoughts on, you know, capital allocation between Appalachia and the Haynesville and, you know, how you think about that going to 2023, considering what you see as the gas market dynamics at this point? Yeah. This is Bill, and Clay and Carl may have a couple of comments. When we take a look at an annual plan, that annual plan is racked and stacked for the development locations that we have. Economics are run, prioritized, and we prioritize development based on that, obviously taking into account all the other midstream and other factors in that. Today we're at 55,45, 55% Haynesville, 45% in Appalachia. We haven't done the granular work on 2023 yet. It shouldn't materially differ from that, and we'll update you if it does. Okay. Understood. [crosstalk] Go ahead. Just a quick add. The competitive economics, the portfolio's got liquids rich West Virginia that are benefiting from both high natural gas and liquids pricing. Obviously, the Haynesville performance, high rates, sustained profile. We really like the portfolio across the position. The complementary nature. You know, when we got into Haynesville and looked back at Appalachia, the complementary nature of all of these means, and has resulted in the fact we have activity across the board in every major development area. That's part of the analysis as well. Understood. A little bit about the strategy with the free cash flow, you know, with regards to buybacks and debt reduction and your goal to get to investment grade. If I'm hearing you right, like, debt reduction is still the priority, but I guess early on, are you still looking? You know, you did some buybacks. You know, how aggressive could you get with buybacks, you know, in the more near term, you know, versus, you know, debt, you know, just, you know, leaning into debt reduction a little bit harder. I just want to get a sense of your appetite at these price levels to get more aggressive, you know, with the buybacks right now. Scott, thank you for the question. It's a good one. We all maintain pretty consistently, debt reduction remains our priority. That will guard primary allocation to free cash flow. That said, we fully expect to continue to steadily repurchase shares with an increasing as our hedges roll off and our free cash flow picks up. That all being said, if commodity prices get to a situation where we feel comfortable that we'll be able to achieve our debt objectives in a reasonable time frame consistent with returning to investment grade, it's absolutely possible that we could pick up our share repurchase pace. Thanks for that. Our next question will come from Austin Alcorn with Johnson Rice. Please go ahead. Good morning, Bill, and to the rest of the team. Morning. This quarter's volume beat, did it come from the Haynesville production or Appalachia production, or a combination of both? Yeah. Mainly Appalachia this quarter. Q1 was Haynesville. Haynesville delivered on its forecast in Q2, but Appalachia is the bigger driver of it, and a lot of it had to do with the improved liquids performance in that area, and that was driven by the mix of wells that came online in the Q2 and the cycle time improvements that we had where those wells came online earlier than what we had originally forecasted. Appreciate it. This is maybe a question for Carl, but once you achieve your debt target and complete your buyback authorization around next year year-end, what do you expect to do with the free cash flow after that? It's a good question. We've been consistent in our capital allocation strategy. Number one is ensuring maintenance production. Number two is reducing our debt to a balance sheet objectives, both leverage and obviously quantum of debt. Three is returning capital. As long as we're doing the first and have done the second, I would imagine our board will continue to authorize us to return capital. Gotcha. I appreciate the color. That's all from me. Our next question will come from Neal Dingmann with Truist Securities. Please go ahead. Morning, all. A A little bit different take on shareholder return specific. I'm just wondering, would y'all consider reinvesting more back in the business if some reasonably priced capacity were to open up? Or do you all consider a better value creation, given the current share price, just the shareholder return that you've talked about? Yeah. I think in the near term, certainly our priorities are really clear around debt reduction, around return of capital to shareholders, and around maintenance capital investment. I think if when those objectives are met, I think we have to take a look at the opportunities in front of us, what makes sense, given both the changing commodity environment and objectives of the company and make some decisions at that point. Yeah, I agree with that, Bill. I think that makes sense. Maybe just to follow up on LNG specifically. I know there's a number of potential opportunities given your unique position that you have down there in the basin. I'm just wondering. Are there opportunities you see near term and wonder how you would think about structuring any deal you might see in order to capture likely future upside? Thank you. Yeah. This is Jason. I'll make a couple of comments, and Bill may have something that he wants to add. I think, you know, as Bill said earlier, we are a major supplier to, you know, all the LNG facilities in the Gulf Coast right now, approximately 1.5 BCF per day going to those facilities. You know, you are correct. There's. You know, we're in multiple conversations with, multiple different opportunities or suppliers and, you know, we definitely have the structural advantage to supply the LNG with the Haynesville, and then we also have the ability to back that up with transport we have that comes out of the Appalachia to the Gulf Coast as well. You know, we're really evaluating all of these transactions on a risk-adjusted approach. You know, that takes time because these are large transactions. I think a big piece of that answer is really looking at these on a risk-adjusted basis. Some of the agreements that have been in place have had resulted in negative margins for a number of years, and they've switched recently with the big swing in gas prices. We've looked at opportunities where the off-takers are in areas of conflict, so you'd have additional risk there. As Jason said, we're in conversation with most of the players. I think our plans are to triangulate around a couple of ideas that, you know, our vast resource and transportation network could support, helping them over the FID decision point, and then do a bit of a risk-based approach on how much better is the margin with all the risks versus a margin or a premium price margin against Henry Hub, and make a decision based off that. No, great details. Definitely some great opportunities, guys. Thank you. Yeah. Great. Our next question will come from Doug Leggate with Bank of America. Please go ahead. Hey, Doug. Thanks. Good morning, Bill. Bill, I wonder if I could start with your hedging philosophy. I mean, obviously risk management, you've told me many, many times is part of your DNA, but you know, for obvious reasons, we'd love to see you with less hedging today, but that's sadly not the case. How do we think about how you know, how hedging factors into your go-forward philosophy as you right-size the balance sheet? Yeah, when I look at hedging today, one comment I'll make is that that very hedging practice supported and enabled the company to transform itself from a single basin company in Appalachia to a dual basin gas leader with connections to all of the growing demand centers. I don't want to lose sight of that piece. There are benefits to this. Having said that, with that transformation and with the strength of the company and the supported fundamental outlooks, expect, as I said in my opening remarks, future hedging levels to migrate lower within our approved ranges. The company is now in the place where it can confidently do that, and you should expect that to become more and more visible going forward. In the near term, any hedges that are done, we'd probably prefer collars, which gives you continued access to some of the upside that you speak of. That's where we sit today. Okay. We wouldn't expect to see you buy out hedges like some of your peers have done, do we? Doug, it's a good question. Something that we'll evaluate. We obviously have competing capital priorities with progressing with debt repayment and trying to return to investment grade, the share repurchase. You know, there's a unique opportunity to take advantage of that at what we think is a. You know, really attractive and kind of opportunistic level, we'll clearly consider that. We're pretty steadfast in you know, moving forward. We think we have good cash flow profile as is, particularly as our incumbent hedges roll off and we move into 2023. While we'll look at that, I don't know if we're spending too much time waiting for that to happen. I appreciate the answers on that, guys. Thanks. I know it's not an easy one. Bill, my follow-up is really just to ask you to spell something out for folks that maybe have missed the change that have taken place in the portfolio. Because it seems to me that the back end of the gas curve has moved up quite substantially. We think of value in a sustainable discounted cash flow basis. In order to have sustainability, you need inventory depth once those hedges roll off. When you sit here today, what do you think your sustainable economic inventory is across the two basins? I'll leave it there. Yeah. I wanna have Clay spend a couple of minutes and put some detail on the table for this. We've got more than 6,000 development locations with the portfolio that we now hold, and the strength of those and the economics generated by those are quite impressive. Clay, why don't you kind of put that breakdown together for Appalachia, Haynesville, and the company? Sure. Doug, I know there's a IR deck that went out and a lot of the information or the high-level summary is on page 12 of that deck for Appalachia inventory and on 13 for Haynesville. But as Bill mentioned, starting point, 6,600 future drilling locations at a pace right now of about 135 wells being drilled per year. In Appalachia, we've got 14 years of below $250 breakeven inventory that's a combination of high rate, low cost natural gas wells and significant liquids-rich opportunities in West Virginia. Very solid long-life inventory in Appalachia that gets some exposure to multiple commodities. In the Haynesville, we have 20 years of $2.50 or below break even inventory and that inventory it's all dry gas, a mix between our Haynesville and our Middle Bossier. The profile of those Haynesville wells, as we've talked about before, really high initial rates. We're getting close to 45% of the EUR recovered in the first year. The production profile has a flatter profile than other areas, and the economics associated with that inventory is outstanding. Between the two areas, it's pushing on 19 or 20 years of $2.50 and below break even inventory in the current commodity price and cost structure, environment that we're in right now. You can see a really robust inventory complementary to the two areas. We're pretty excited about it. Thanks. That's very helpful. Sure. Our next question will come from Arun Jayaram with JP Morgan. Please go ahead. Yeah. Good morning. Bill, I wanted to get your perspective on how tightness in the oil services market may influence your activity levels, you know, next year. Obviously, you're vertically integrated to some extent, but historically, Southwestern has done a little bit more activity in the first half. You had a little bit of a shaping in terms of spending and thoughts about potentially shifting to more of a level loaded program, cause you know like to keep experienced crews and things like that. So I wanted to get your thoughts on that. Clay, could you just talk about cycle times you mentioned in your prepared remarks? I'd love to get a sense of, you know, for every rig line in the Marcellus or Appalachia, you know, how many wells to sales do you expect on typically, and the same thing in the Haynesville? Appreciate the questions. So far, as far as tightness in the oilfield services side, yeah, we've seen it. I think the great outcome for us is the planning that was put into both the acquisition of services, the clear plans that we had on how we would implement those, and really making the company as efficient as it could be, which is a benefit to anybody that comes to work for us 'cause we're not having any company-induced downtime or non-productive time, which makes it more efficient for service providers that work for us. We do front load the business. I think we've moderated that a little bit because we wanna make sure continuity of goods and services continues as if you were to ramp down then ramp back up. In fact, some of the capital that we're gonna deploy in the latter part of this year is specifically related to making sure that we retain the strength of the continuity of that activity level 2022 to 2023 and get a great running start on 2023. Our vertical integration teams continue to excel at what they do and give our contracting partners a clear understanding of what we know it takes to drill a well. From the very detailed part of the drilling all the way through completions, et cetera. There's a constant learning that goes on between our teams and the contracting teams. We only drill and complete for ourselves, so we're not a competitive threat. We actually are we think can be a competitive enabler for improved cycle times, improved quality of drilling, and attracting talent to come to us. We have seven rigs, seven teams of people that are dedicated to those rigs. There's a consistency that brings, and it turns into quality of wells, quality of timing, quality of efficiency, which is helping us with lower costs than what the industry might be seeing because of that consistency of the teams. Arun. On the cycle times, yeah. Thanks. Go ahead. Yeah. At a high level, the cycle times are shorter in Appalachia than they are in the Haynesville. The Haynesville has the longer drilling times and completion times due to the higher pressures and the greater depths of those wells. We've made improvements in both of those. You mentioned my answer a little while ago around turning lines being faster on some Southwest Appalachia wells. We've commented on spud to rig release improvements in the Haynesville that are moving some of those wells from as high as 55 days back in the acquisition model to down around 30 days spud to rig release now. In general, when we think about the number of wells per rig line in Haynesville, we're drilling eight... To get all the wells drilled, we get about eight to nine wells drilled per rig line in the Haynesville. Then in Appalachia, it's somewhere in the 15 to 17 wells drilled per rig line in those areas. The focus all the time is to continue to look for ways to compress those cycle times and bring those wells online quicker, and that's the go-forward approach that we're working off of. Just to clarify, when you say eight to nine wells, is that to sales, or is that just for the drilling aspect of it? That's the drilling piece of it to sales, a lot has to do with the number of DUCs that you come into a year with. Again, we don't build DUCs. We try to maintain the right amount of DUCs for us to be as efficient as we can be. That's why I gave you the drilling metric because the to sales can be a little bit lumpy, dependent upon what you're coming into the year with. Okay, great. My follow-up, Carl, I was wondering if you could help us think about how Southwestern's cash tax rate could evolve. Maybe you could do us a little bit of a teach-in on what the AMT could mean for you guys as well as your ability to use NOLs, given some of the M&A activity that you've done, you know, in the Haynesville. Arun, thank you very much. I think, I'll deal with the cash taxes up front. This year, we're anticipating cash taxes roughly 25 to 30, all the way up to $75 million to $80 million, depending on how prices behave. And then going forward, beginning in 2023, this is already accounted for in the cash flow numbers that I had in our prepared remarks. We're expecting $200 million to $300 million in cash taxes beginning in 2023, obviously dependent on commodity prices. I'll tell you that as we talked about before on these calls, when we did Indigo, it created a roughly $50 million limit on our ability to use NOLs. That has increased our cash taxes. So that's why we're at these ranges. I think that should provide some reasonable guidance to what our cash tax payments are going forward. Just how does the AMT potentially impact that? I don't think. We're still evaluating it. We're not sure it's gonna have a material impact from what we've already described. Great. Thanks a lot. Our next question will come from Subash Chandra with Benchmark. Please go ahead. Oh, thanks. Bill, it seems that other than Southwestern, every Haynesville public or private or nearly every is potentially for sale. This might be a strange question to ask, but do you feel at this point you have optimal scale to deliver on that LNG vision, near term and long term? You know, capturing the benefits of increased scale is part of our core strategy, and accessing LNG opportunities, like you talk about, would be one of those benefits. I think that we're gonna keep looking at M&A activity or opportunities, study them, within our two basins. I think given the recent transactions, the greater than 6,000 development locations, the quality of our assets and all the other corporate objectives around debt and investment grade and returning capital, we've raised the bar, which makes M&A more challenging. When you look at the capability of the company and the 1.5 BCF per day of gas we already move into the LNG space and the overall company gas production rate at just under five BCF per day, assuming that we can work terms and do those on a risk-adjusted basis, we have the capacity to enter into additional ideas around LNG. That's the part that we're exploring now, whether they're domestically priced or internationally priced is a part of that. You know, the presence of our vast inventory along with a transportation network and a gathering network already in place so that we can assure flow, and assure that we can meet contractual obligations today and going forward, I think we're well positioned to look at additional activities. Thanks. Good answer. My follow-up I guess is, you know, some pipelines have recently implemented RSG pricing pools. Have you seen that play out in, you know, in any materiality, and are you seeing price premiums for RSG? Yeah, we've been doing RSG and entering into contracts since 2017. Let me get Jason to get you a bit of an update on what we're seeing. Yeah. I would say I think you're probably referring to Tennessee and the new filing that they recently came out with. I think that is very new right now, and so, you know, there's a lot of people that are just now beginning to look at that potential opportunity and getting the different pools set up that are required to be able to transact there. So no transactions have happened on the new pooling agreements yet, to my knowledge. You know, we have other opportunities, as Bill said, since 2017 that we've been working direct with different suppliers that are interested in buying, you know, RSG. Got it. Thanks everybody. Our next question will come from Umang Choudhary with Goldman Sachs. Please go ahead. Hi. Good morning, and thank you for taking my questions. I guess the first question was really on the Haynesville. Can you walk us through some of the latest productivity or cost trends in the Haynesville Basin as you get some more time to operate those assets? Sure. As you know, the benefit of the deeper depths is higher bottom hole pressure, and then it also has higher bottom hole temperatures. Those bottom hole temperatures are where you have potentially shorter tool life, and it can cause you to have shorter laterals. A big thing we've been focused on is reducing the bottom hole temperatures and maintaining the drilling mud properties and keeping those bottom hole temperatures as low as we can, and then also maintaining the whole stability with managed pressure drilling techniques. Early in the year, we had drilled some wells in that area right after closing. As we've been talking about, our expectation was to really learn and optimize as we started drilling wells. We moved into other areas of the field as planned, and then now we've come back to the deepest, hottest areas. The things I mentioned are causing us now to get longer tool run times. We're able to drill longer laterals, and we're able to reduce the time to get the wells drilled, which is providing some well cost savings. That's kind of the driver of the benefits we're seeing on the drilling side in the Haynesville area. Great. Anything on the productivity front, in the Haynesville? Are you seeing some uptick there as you get your thumbprints on the program? Yes. We've been commenting on the IPs, the initial production rates from the wells that we're turning to sales. For the Q2 in a row, our wells to sales in the Haynesville have averaged about $34 million a day of gross production rate, and that's elevated from the prior operators and the public data. Part of that is us gaining a better understanding of the subsurface, continuing to optimize the flow back and how much pressure differential we're willing to see when we're flowing back those wells, and then also the profile over time and continuing to shallow that decline on the profile over time. We've been extremely pleased with the production performance in the Haynesville. The IPs have ranged from 25 million a day to as high as 50 million a day in different areas of the field. We think that's part of the tier one high quality inventory that we have, and it's showing up in the production performance, and it's occurring in both our Haynesville wells and the Middle Bossier wells. That's great to hear. Maybe on the follow-up, if you can tie it to your plans for growth for the remainder of this year from that asset and heading into next year. Also maybe if you can touch on any midstream issues which you're seeing which could limit that growth rate till Gulf Run comes online. Yeah. I'll hit on the first part of that, and then Jason can cover the second. We're in a maintenance capital program. As we came into the year, we talked about a small amount of growth in the Haynesville. At the enterprise level, we were gonna stay in that maintenance capital program, flat production. As you can see from the production rates, we're realizing the growth in the Haynesville that we had planned for 2022. We've talked about some additional, like, capacity that we agreed on earlier in the year that is going to cause a similar amount of growth potential in 2023 in the Haynesville. We haven't finalized all the 2023 plans yet, but we expect to stay at that enterprise level maintenance capital program with some incremental growth in the Haynesville, similar to what we did in 2022. Yeah. I think Clay covered it real well. I mean, I'll just add, you know, part of our M&A framework and just the integrated planning process at Southwestern just ensures that any asset that we buy or operate, that it has adequate midstream and pipeline capacity. We have a continuous, planning period, very integrated with marketing, midstream, and the division to continually, you know, ensure that we have the capacity to move, you know, our product from the wellhead all the way through to the marketplace. That's really helpful. Thank you so much. Our next question will come from Nicholas Pope with Seaport Research. Please go ahead. Morning. Hello, everyone. Morning. How you doing? I was hoping we could dig a little bit more into the comments Clay just made on the Haynesville. I mean, looking at lateral lengths, it looks like y'all are up 50% kind of on lengths from when you first took over Haynesville last year. And as you look at cost, I mean, where should we think about it as a, you know, dollar per kind of lateral foot right now? Because it looks like just kind of tracking that metric, and we haven't seen significant inflation outside of just the longer wells. Trying to pinpoint a little bit on just what well costs in Haynesville have tracked as you've kind of gone over the last four quarters of this operation and kind of where they are right now. Like, total drilling and completion costs right now on these kind of 10,000 ft lateral length wells. Sure. To start with, our lateral progression is methodical just like we did in the Appalachia. We're gonna average for the year somewhere around 9,000 ft. The previous operator had anywhere from 5,500 ft to 9,000 ft, but a lower average than that in the upper 7,000 ft to maybe 8,000 ft. We are progressing lateral lengths. There's a big economic benefit tied to that, but we're doing it in a methodical, constructive way to make sure that the execution is there. When you talk about well cost per foot, we're staying steady in the $1,600 to $1,700 per foot range throughout the year. Now inflation has been coming at us in that area. As we've had these execution improvements, they're partially offsetting that increase in the well cost there. Remember, part of why our wells have the strongest EURs and some of the strongest returns is because we're in the deepest, hottest, highest pressure part of the Haynesville that has incremental costs versus other parts of the Haynesville. Those are more than offset from an economic standpoint by the well performance. Got it. I mean, that's exactly what it looked like to me. That number there, that $1,600 to $1,700 a foot is, I think it's impressive. That's all I had. I just wanted to clarify. I really appreciate it, Tim, the time. Thanks. Thank you. Thank you. Our next question will come from Noel Parks with Tuohy Brothers. Please go ahead. Hi. Good morning. Morning. I just wanted to check. Just from a comment that there was in the release about the CapEx budget, it seemed like there was an implication that some of the increase was mostly going to benefit the 2023 maintenance CapEx program. I just wanted to check on that and you know get a sense of what that might involve. Sure, Noel. What our intention was is that this incremental capital, since we're seeing higher than expected inflation, was to allow us to maintain the planned activity levels through the Q4 so that the 2023 program stays strengthened on track for us to come into the year with the high-quality service providers, with the third-party equipment that we need so that 2023, we hit the ground running as we enter the year. We're maintaining all of those goods and services like you mentioned in this environment, and the quality that we've seen as we've moved through the year so far. Gotcha. The benefit from that capital, why we're focused on 2023 is the cycle times that we talked about earlier. The Q4 activity isn't going to add well counts and production to 2022. It's going to come online early at the start of 2023, which helps us maintain that flat production profile in 2023. Okay. Gotcha. Okay. Thanks. Thanks a lot. Thanks for the clarification. One thing I was wondering, you know, since you do own and control your own rigs and, soon another frac spread, I just was wondering about maintenance and whether, just as far as, parts and, you know, any other upgrades you need to make over time. Are supply chain issues affecting any of the component parts that you need? If so, I'm just wondering if that's something you see on an improving path or whether there's still pressure or, you know, maybe even getting a little tighter. Sure. The maintenance of our vertical integration is an important part of why they execute like they do, and we have been able to stay ahead of any supply chain issues that we need there to replace any parts and if we're doing any upgrades. The upgrades that we do, when we do them, they involve third parties who we don't have to maintain all that equipment ahead of time. They have it. Our process of making sure that the rigs and the frac fleets are performing at the level we need safely and dependably, that process is working well for us, and we haven't had any delays or any problems in the current environment type of that. Okay, great. Thanks a lot. This will conclude our question and answer session. I'd like to turn the conference back over to Bill Way for any closing remarks. I appreciate you orchestrating our conference. On behalf of all of us at Southwestern Energy, thanks a lot for your interest in the company. We enjoyed sharing some of our achievements on this call today. Have a great weekend, and we look forward to speaking to you again soon. Bye now. This concludes the Southwestern Energy Q2 2022 earnings call. You may now disconnect your lines at this time.