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spk08: Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Southwestern Energy's second quarter 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 requeue for additional questions. This call is being recorded. I would now like to turn the conference over to Brittany Rayford, Southwestern Energy's Director of Investor Relations. You may begin.
spk00: Thank you, Cole. Good morning and welcome to Southwestern Energy's second quarter 2022 earnings call. Joining me today are Bill Way, President and Chief Executive Officer, Clay Carroll, 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 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, and actual results on 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.
spk12: Thank you, Brittany, and good morning, everyone. Southwestern Energy is well positioned as a leading natural gas producer in the two premier U.S. natural gas basins. We are executing on our deliberate strategy to grow resilient free cash flow, as evidenced by our second quarter and year-to-date results. I'm particularly pleased with the successful integration of our Hainesville 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 second quarter PB10 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 U.S. natural gas. Domestically, strong industrial and residential power generation demand have become less sensitive to natural gas pricing given continued cold power capacity retirements. The net effect, we believe, is that the U.S. 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 SWIN 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 liquid faction is currently in service, which could more than double with FERC-approved projects, including approximately 7 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 Hainesville 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 SWIN's enterprise risk management practice, ensuring recovery of the company's cost 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 callers. 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 SWIN 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 22 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 SWIN, 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.
spk07: 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 cells during the quarter. In Appalachia, we placed 23 wells to cells 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 turn-in lines. In Haynesville, the team placed 19 wells to sales with an average lateral length of approximately 9,500 feet. Among them is an over 13,000-foot 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 the Haynesville. Operational execution and cycle times in the 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 planned, 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 9 to 10 rigs and 4 to 5 frac crews during the second half of the year, consistent with our planned development program. Third quarter capital is expected to be in line with our first and second quarter 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 SWAN-operated frac fleet in Appalachia in the third quarter, displacing a third-party STEM provider and delivering surety of service cost reductions, and operational efficiencies. We are also repositioning a third SWIN-owned rig to Haynesville late in the fourth quarter, 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.
spk01: Thank you, Clay, and good morning. This quarter, we generated approximately $170 million of free cash flow and further improved our leverage ratio to 1.6 times. We expect to achieve the top end of our 1.5 to 1.0 times target leverage range in the third quarter. 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. We call 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 a 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 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 strength, 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 SWIN to BA.1, 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.
spk08: And 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 speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. And 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.
spk04: Please go ahead. Thanks. Good morning. Could you all, you know, you all talk about obviously having good exposure on the Gulf Coast where the man 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?
spk12: Yeah, this bill, and Clay and Carl may have a couple 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% Hainesville, 45% Appalachia. We haven't done the granular work on 23 yet. It shouldn't materially differ from that. And we'll update you if it does.
spk04: Okay, understood. And go ahead.
spk07: 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.
spk12: And 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. So that's part of the analysis as well.
spk04: Understood. And then 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. And if I'm hearing you right, like debt reduction is still the priority, but you'll, 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. So I just want to get a sense of your appetite at these price levels to get more aggressive with the buybacks right now?
spk01: Scott, thank you for the question. It's a good one. As bills, we all maintain pretty consistently debt reduction remains our priority. And so that will guard primary allocation to free cash flow. That said, we fully expect to continue to steadily repurchase shares. with it 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.
spk04: Thanks for that.
spk08: And our next question will come from Austin Alcoyne with Johnson Rice. Please go ahead.
spk05: Good morning, Bill, and to the rest of the team.
spk08: Good morning.
spk05: This quarter's volume beat, did it come from the Hainesville production or Appalachia production, or a combination of both?
spk07: Yeah, so mainly Appalachia this quarter. Q1 was Hainesville. Hainesville 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 second quarter and the cycle time improvements that we had where those wells came online earlier than what we had originally forecasted.
spk05: Appreciate it. And then 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?
spk01: That'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. And then three is return of capital. And 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.
spk05: Gotcha. I appreciate the color. That's all from me.
spk08: And our next question will come from Neil Dingman with Truth Securities. Please go ahead.
spk03: Mornel, a little bit different take on the return specific. I'm just wondering... would you 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, uh, given the current share price, uh, just the shareholder return that you've talked about?
spk12: Yeah, I think in the near term, certainly our priorities are, are really clear around debt reduction around return of capital shareholders and around, um, maintenance capital investment. I think if, uh, 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.
spk03: Yeah, I agree with that, Bill. I think that makes sense. And then maybe just to follow up on L&G specifically, could you all speak? 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 how do you think about, 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.
spk02: Yeah, so this is Jason. I'll make a couple of comments and Bill may have something that he wants to add. But 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 a day going to those facilities. And You are correct. We're in multiple conversations with multiple different opportunities or suppliers, and 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. So we're really evaluating all of these transactions on a risk-adjusted approach, and that takes time because these are large, large transactions.
spk12: 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 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 now 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 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.
spk03: Great details. Definitely some great opportunities, guys. Thank you.
spk08: Our next question will come from Doug Legate with Bank of America. Please go ahead.
spk09: Thanks. Good morning, Bill. Bill, I wonder if I could start with your hedging philosophy. Obviously, risk management, you've told me many, many times, is part of your DNA, but 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 hedging factors into your go-forward philosophy as you right-size the balance sheet?
spk12: 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 the 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, expect future hedging levels to migrate lower within our approved ranges. and 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. And in the near term, any hedges that are done would probably preference collars, which gives you continued access to some of the upside that you speak of. So that's where we sit today.
spk09: Okay. We wouldn't expect to see you buy out hedges like some of your peers have done, should we?
spk01: Doug, it's a good question, something that we'll evaluate. We obviously have competing capital priorities with progressing our 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 really attractive and kind of opportunistic level. We'll clearly consider that, but we're pretty steadfast in that. 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. And so while we'll look at that, I don't know if we're spending too much time waiting for that to happen.
spk09: 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's taken place in the portfolio. 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. But in order to have sustainability, you need inventory depth once those hedges roll off. So when you sit here today, what do you think your sustainable economic inventory is across the two basins? And I'll leave it there.
spk12: Yeah, I want to have Clay spend a couple of minutes in detail. 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. So, Clay, why don't you kind of put that breakdown together for Appalachia, Hainesville, and the company?
spk07: Sure. So, Doug, I know there's an IR deck that went out and 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 6600 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 break-even inventory that's a combination of high-rate, low-cost natural gas wells and significant liquids-rich opportunities in West Virginia. So very solid, long-life inventory in Appalachia that gets some exposure to multiple commodities. In the Haynesville, we have 20 years of 250 or below break-even inventory. And that inventory has, 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. So between the two areas, it's pushing on 19, 20 years of 250 and below break-even inventory, and the current commodity price and cost structure is environment that we're in right now.
spk12: So you can see a really robust inventory complementary to the two areas. We're pretty excited about it.
spk09: Thanks, Ellis. That's what I wanted to say.
spk12: Sure.
spk08: And our next question will come from Arun Jayaram with JP Morgan. Please go ahead.
spk14: Yeah, good morning. Bill, I wanted to get your perspective on how tightness in the oil services market may influence your activity levels. 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've had a little bit of a a shaping in terms of spending and thoughts about potentially shifting to more of a level-loaded program because you like to keep experienced crews and things like that. So I wanted to get your thoughts on that. And then, Clay, could you just talk about cycle times you mentioned in your prepared remarks? I'd love to get a sense of for every rig line in the Marcellus or Appalachia, how many well as to sales you expect, typically in the same thing in the Hainesville.
spk12: Appreciate the questions. So 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 because 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 want to make sure continuity of goods and services continues as if you were to ramp down and ramp back up. In fact, some of the capital that we're going to 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 22 to 23 and get a great running start on 23. Our vertical integration teams continue to excel at what they do and 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. And so 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 drillings, and attracting talent to come to us. So we have seven rigs, seven teams of people that are dedicated to those rigs. There's a consistency that 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.
spk07: Arun, on the cycle times, yeah.
spk14: Thanks. Go ahead.
spk07: Yeah. So 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. But 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. And then in Appalachia, it's somewhere in the 15 to 17 wells drilled per rig line in those areas. And 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 also.
spk14: And just to clarify, when you say eight to nine wells, is that to sales or is that just for the drilling aspect?
spk07: That's the drilling piece of it. To sales, a lot has to do with The number of ducks that you come into a year with, again, we don't build ducks. We try to maintain the right amount of ducks for us to be as efficient as we can be. But that's why I gave you the drilling metric, because the sales can be a little bit lumpy, depending upon what you're coming into the year with.
spk14: Okay, great. My follow-up, Carl, I was wondering if you could help us think about how Southwestern's cash tax rate could evolve. And 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 NOLC, given some of the M&A activity that you've done in Haynesville.
spk01: Thank you very much. And 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 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 preparative marks. We're expecting 200 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, and so that's why we're at these ranges. And I think that should provide some reasonable guidance to what our cash tax payments are going forward.
spk14: And just how does the AMT potentially impact that?
spk01: We're still evaluating it. We're not sure it's going to have a material impact from what we've already described.
spk08: Great. Thanks a lot. Our next question will come from Suvesh Chandra with Benchmark. Please go ahead.
spk10: Thanks. So, Bill, you know, it seems that other than Southwestern, every Haynesville public or private or nearly every is, you know, is potentially for sale. You know, this might be a strange question to ask, but do you feel at this point you have optimal scale to, you know, deliver on that LNG vision near-term and long-term?
spk12: 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 going to 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 a day of gas we already move into the LNG space, and the overall company gas production rate at just under 5 BCF a day, assuming that we can work terms and do those on a risk-adjusted basis, we have the capacity to enter into additional production. ideas around LNG, and that's the part that we're exploring now, whether they're domestically priced or internationally priced is a part of that. So, 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 opportunities.
spk10: Thanks, Gideon. And then my follow-up, I guess, is some pipelines have recently implemented RSG pricing pools. Have you seen that play out in any materiality, and are you seeing price premiums for RSG?
spk12: We've been doing RSG and entering into contracts since 2017, so let me get Jason to get you a bit of an update on what we're seeing.
spk02: 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 there's a lot of people that are just now beginning to look at that potential opportunity and getting involved. 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. But, you know, we have other opportunities, as Bill said, since 2017 that we've been working, you know, direct with different suppliers that are interested in buying, you know, RSG.
spk10: Got it. Thanks, everybody.
spk08: And our next question will come from Umang Chaltri with Goldman Sachs. Please go ahead.
spk06: Hi, good morning, and thank you for taking my questions. I guess the first question was really on the Hainesville. Can you walk us through some of the latest productivity or cost trends in the Hainesville Basin as you get some more time to operate those assets?
spk07: Sure. So, as you know, the benefit of the deeper depths is higher bottom hole pressure. And then it also has higher bottom hole temperatures. And those bottom hole temperatures are where you have potentially shorter tool life. And it can cause you to have shorter laterals. So a big thing we've been focused on is reducing the bottom hole temperatures and maintaining the drill and mud properties and keeping those bottom hole temperatures as low we can and then also maintaining the the whole stability with managed pressure drilling techniques and so early in the year we had drilled some wells in that area right after closing and as we've been talking about our expectation was to really learn and optimize as we started drilling wells. And so then we moved into other areas of the field as planned. And then now we've come back to the deepest, hottest areas. And the things I mentioned are causing us now to get longer tool runtimes. 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. So that's kind of the driver of the benefits we're seeing on the drilling side in the Haynesville area.
spk06: Great. And anything on the productivity front in the Haynesville? Are you seeing some uptick there as you get your thumbprints on the program?
spk07: Yes. So we've been commenting on the IPs, the initial production rates from the wells that we're turning to sales. And for the second quarter 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. And 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. So 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. And so we think that's part of the Tier 1 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.
spk06: That's great to hear. And maybe if you can, on the follow-up, maybe if you can tie it to your plans for growth for the remainder of this year from that asset and heading into next year. And also maybe if you can touch on any midstream issues which you're seeing which could limit that growth rate until Gullifront comes online.
spk07: Yeah, so 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. But at the enterprise level, we were going to 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 talked about some additional leak 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. And 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.
spk02: Yeah, I think Clay covered it real well, but 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. And, you know, 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 marketplaces.
spk06: That's really helpful. Thank you so much.
spk08: And our next question will come from Nicholas Pope with Seaport Research. Please go ahead.
spk11: Morning. Hello, everyone. Morning.
spk13: 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 links, it looks like y'all are up 50% kind of on links from when you first took over Haynesville in last year. And as you look at costs, I mean, should we think about it as a dollar per kind of lateral foot right now? And because it looks like it's just kind of tracking that metric and haven't seen significant inflation outside of just the longer wells. So trying to pinpoint a little bit on just what well costs in Haynesville are have tracked as you've kind of gone over the last four quarters of this, of this operation and kind of where they are right now, like total drilling and complete costs right now in these kind of 10,000 foot lateral.
spk07: Sure. Sure. So to start with our, our lateral progression is, is methodical just like we did in the Appalachia and we're going to average for the year somewhere around 9,000 feet. And the previous operator, uh, had anywhere from 5,500 to 9,000 feet, but a lower average than that in the upper 7,000s to maybe 8,000. So we are progressing lateral links. 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, but then as we've had these execution improvements, they're partially offsetting that increase in the well cost there. And 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. But those are more than offset from an economic standpoint by the well performance.
spk13: Got it. So, I mean, that's, That's exactly what it looked like to me. But that number there, that 1,600 to 1,700 foot, I think it's impressive. So that's all I had. I just wanted to clarify. I really appreciate the time. Thanks.
spk08: Thank you. Thank you. And our next question will come from Noel Parks with Tuohy Brothers. Please go ahead. Hi. Good morning.
spk11: Good morning. I just wanted to... 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 largely going to benefit the 2023 maintenance CapEx program. So I just wanted to check on that and get a sense of what that might involve.
spk07: 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 fourth quarter 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 and that 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.
spk11: Gotcha.
spk07: And... The benefit from that capital, why we're focused on 2023 is the cycle times that we talked about earlier, the fourth quarter 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
spk11: maintain that flat production profile in 2023 okay gotcha okay thanks thanks a lot uh thanks for the clarification and um and one thing i i was wondering you know since you do own and control your own rigs and uh soon another frac spread um i just was wondering about maintenance and whether um just as far as as parts and any other upgrades you need to make over time. Are supply chain issues affecting any of the component parts that you need? And if so, I'm just wondering if that's something you see on an improving path or whether there's still pressure or maybe even getting a little tighter.
spk07: Sure. So 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 are we don't have to maintain all that equipment ahead of time. They have it. And so 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 tied to that.
spk11: Okay, great.
spk07: Thanks a lot.
spk08: And this will conclude our question and answer session. I'd like to turn the conference back over to Bill Way for any closing remarks.
spk12: 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.
spk08: And this concludes the Southwestern Energy second quarter 2022 earnings call. You may now disconnect your lines at this time.
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