西南能源 (SWN) 2022 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Southwestern Energy's Third Quarter 2022 Earnings Call. (Operator Instructions) 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, Chad. Good morning, and welcome to Southwestern Energy's Third Quarter 2022 Earnings Call. Joining me today are Bill Way, President and Chief Executive Officer; Clay Carrell, Chief Operating Officer; and Carl Giesler, Chief Financial Officer.

Before we get started, I'd like to point out that many of the comments we make during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual report and quarterly reports 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 and developments may differ materially, and we are under no obligation to update them. We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.

I will now turn the call over to Bill Way.

Thank you, Brittany, and good morning, everyone. Southwestern Energy's strategic intent is to generate resilient free cash flow from responsible natural gas development of our leading positions in the 2 premier U.S. natural gas basins. In the third quarter, the company continued to generate free cash flow, which was used to reduce debt and achieve our target leverage range. We also complemented debt reduction with $80 million of share repurchases, bringing our year-to-date total to approximately 10% of the authorized amount.

Prioritizing debt reduction, as we progress toward are $3.5 billion to $3 billion, a target debt range benefits shareholders by expanding our opportunity set, including LNG, reducing the volatility of our stock, enhancing the resilience of our free cash flow through the cycle and supporting our expected return to investment grade.

With the current commodity price outlook and our improved balance sheet that allows us to moderate our hedging levels to provide shareholders greater commodity price exposure, while maintaining disciplined enterprise risk management. We expect our lower hedge profile will generate increasing free cash flow even in this backward-dated commodity price environment. As our hedge position moderates, we anticipate our financial results, key financial metrics and enterprise value will more clearly reflect the underlying value of our business as evidenced by our pretax PV10 reserve value of more than $30 billion at recent strip.

We believe our integrated upstream marketing and transportation approach to developing our more than 15 years of core inventory is yet another example of capturing the tangible benefits of scale and in this case, our increased scale. We are well positioned to benefit from the structurally supported long-term Gulf Coast natural gas demand growth. Our well-timed Haynesville acquisition positioned us as the largest Haynesville producer, giving us scaled production and reserves near the LNG corridor and other growing gas demand centers along the Gulf Coast.

Today, SWN markets up to 5 Bcf per day of gross gas production from Appalachia and Haynesville of which 65% is transported to the LNG corridor and Gulf Coast. This large-scale dual basin supply to the Gulf Coast has enabled us to become one of the largest suppliers of natural gas to the LNG sector.

Today, with 1.5 billion cubic feet of sales under Henry Hub based agreements, we are assessing further LNG gas supply opportunities to capture advantaged pricing on a risk-adjusted approach is to consistent -- is to be consistent with the inherently greater price volatility from global gas exposure. Based on this, we plan to target international pricing exposure for up to 500 million cubic feet per day or up to 10% of our overall daily gross gas production.

Given the importance of flow assurance and marketing gas optionality, we secured additional capacity on future takeaway projects to the Gulf Coast. This quarter, we added capacity on Momentum's upcoming NG3 project and further expanded our LEAD capacity. Both projects are expected to be fully serviced by 2024. We believe that with our focus on natural gas, growing access to the global LNG markets and long-term track record of both low-cost and low-emissions operations, the company is well positioned to help reliably meet domestic and global energy needs and support the foundational role of natural gas in the lower carbon future.

To help realize that future, we are proud to announce the company's long-term GHG emission reduction goal of a 50% decrease by 2035, which is consistent with the path to net 0 by 2050. We expect 70% of our forecasted reductions to be achieved through direct operational abatements. This goal aligns with our ESG approach of creating sustainable value through meaningful impactful actions in the communities where we work and live. This longer-term GHG emission reduction goal supplements our existing programs including being the first and only E&P company to return more freshwater back to the environment than we consume in our business. Shortly, we will release our ninth annual corporate responsibility report, which will detail how we are building on our legacy of responsible development and commitment to ESG as a core value.

With an increasingly -- with an increasing and resilient free cash flow generation profile, a strong balance sheet near investment-grade credit ratings and advantaged access to the LNG corridor and other growing demand centers, we believe Southwestern Energy offers a compelling value and differentiated rate of change investment opportunity in a structurally constructive long-term natural gas outlook.

I'd like to turn the Clay over -- call over to Clay for some operational updates.

Thanks, Bill, and good morning. We delivered another solid quarter with production near the high-end of guidance and the development program on track across both Appalachia and Haynesville. For the quarter, we had net production of 443 Bcfe or 4.8 Bcfe per day, including 4.2 Bcf per day of natural gas and 97,000 barrels per day of liquids. Our integrated upstream, marketing and transportation approach has ensured we have ample firm capacity from wellhead to sales point to move our production to markets of choice and mitigate the impacts of periodic midstream downtime events.

Overall, we placed 31 wells to sales during the quarter. In Appalachia, we placed 14 wells to sales with an average lateral length of approximately 15,600 feet. Our super-rich area in West Virginia accounted for 8 of those wells and our Marcellus and Utica dry gas agents in Pennsylvania and Ohio accounted for the remaining Appalachia turn-in lines.

In the fourth quarter, based on our super-rich activity and the timing of completions, we anticipate holding oil volumes flat. In Haynesville, the team placed 17 wells to sales with 15 in the Haynesville and 2 in the middle Bossier with an average lateral length of approximately 9,300 feet. We continue to see strong initial production rates from our wells, averaging 35 million cubic feet per day.

This quarter marks 1 year since we entered the Haynesville and we've been encouraged by the results and learnings to date. We've successfully extended lateral lengths on average to approximately 9,000 feet from less than 7,000 feet in 2021, reduced cycle times and implemented more efficient completion designs. Despite inflationary pressure on well costs, production performance and well economics continue to exceed expectations. The team has done a good job of hitting the ground running on this new asset and delivering in a challenging industry operating environment. In the quarter, all the wells that went to sales were fully planned, drilled and completed by SWN. We now have clearer line of sight for go-forward operational efficiencies and technical improvement opportunities as we incorporate learnings from the past year.

We expect to further compress cycle times and over time, decrease well costs as the inflationary environment abates. This year has demonstrated SWN's capability of large-scale asset integration and delivery and we have strong momentum heading into 2023. Additionally, all our Haynesville wells are now certified as RSG, making us fully certified across the enterprise.

Looking to the fourth quarter, our activity will moderate consistent with our planned development program and we expect our full year 2022 capital investment will be near the top end of our guidance range. Sector inflationary pressures and a tight services market will continue into next year. We are well on our way to securing the necessary goods and services to deliver our 2023 program and based on our contracting work to date, we anticipate 2023 inflation in the 15% to 20% range, consistent with industry estimates. We are actively working through ways to partially offset this inflationary pressure, including operational efficiencies, strategic sourcing and capturing further benefits from our vertical integration assets.

Now, I'll turn the call over to Carl to provide a financial update.

Thank you, Clay, and good morning. In the third quarter, we generated approximately $220 million of free cash flow. Together with working capital reversals, this has allowed us to both reduce debt by more than $225 million and execute another $80 million in share buybacks. We are now within our 1.5 to 1.0x long-term target leverage range with quarter end leverage at 1.4x. We will continue to progress towards our target debt range of $3.5 billion to $3.0 billion.

With recent pricing volatility, we expect to achieve the top end of our target debt range in late 2023 or early 2024. Future prices will dictate the pace and progress on our authorized repurchase program. Fitch upgraded SWN to BB+ this quarter and we are now consensus-rated 1 notch below investment grade by all 3 agencies. As we achieve our target capital structure, we expect our future free cash flow allocation options will expand, enabling the consideration of additional shareholder capital returns. For these and other reasons, we believe SWN is well positioned to drive economic returns and shareholder value and the structurally supportive long-term natural gas environment.

Please open the line for questions.

(Operator Instructions) And the first question will be from Doug Leggate with Bank of America.

Guys, I wonder if I could start off with a question on the takeaway -- the new takeaway agreements that you have. Bill, as I recollect, the acquisitions were predicated on ensuring that you had adequate takeaway. So can you walk us through the nuance of what the incremental takeaway means? Is this a different allocation of where you expect your weighted basis to move or higher destination realizations? I'm just trying to understand what the implications of that are. And then I've got a follow-up, please.

Sure. As you well know, we take a very integrated approach to E&P and marketing and transportation and do so, whether we're in acquisition mode or whether we're drilling wells in a particular part of the basin. And so as you look at the -- when we did the acquisition and completed it, we had all of the transportation and capacity that we required to be able to move the gas that we were attempting to move. And that was a condition precedent of doing all of those deals.

But as you move forward in time, we continuously optimize our marketing and our transportation if we can -- if we find an opportunity to add a bit of transportation and lay off some somewhere else, we'll do that. If we look to find a new marketplace that we've become very interested in and we wanted to pursue that, we can add transportation.

So net, we're in a maintenance capital mode. We are -- this capacity reinforces our long-term flow assurance and our access to the markets that it serves. We're not signaling a growth in production or growth in drilling beyond maintenance capital through our plan. And we found the opportunity to optimize further. And one other comment I'll make about optimization, when we build transport capacity, it's not a one-and-done. If we're going to take on $300 million a day, it doesn't necessarily come in one $300 million a day done. We like to layer it in, we like to build optionality so that we can really optimize the economics of the program.

Bill, forgive me for the follow-up on this, but does this put you in a position where you can market excess capacity? Because obviously, a number of your peers don't have the same luxury that you do or having to take away in place.

Yes. Obviously, that opportunity is present, but we don't acquire transportation to then turn around and resell it. We acquired transportation to optimize our plan, maximize its value. We have sold transportation capacity or laid it off temporarily to others in the past and it's more of an outcome when you're finished doing your planning than a core objective. If we can make a little bit of that on the side, we do that. We also buy gas and move guests through our -- through any part of our transport where there's available capacity and make a little margin there as well.

My follow-up, hopefully, a quick one for Carl is Carl, obviously, there's upward pressure on CapEx. I think we're all aware of what's happening there. But last quarter, you talked about the free cash flow capacity as strip has come down pretty meaningfully. Since then, I'm wondering if you could share any update on how you see at strip today with CapEx pressures and any changes in cash taxes, for example, what you see your free cash flow outlook in '23 at this point?

Doug, thank you for the question. Obviously, with continued inflation and at least the near-term softening in commodity prices, we expect our cash flow to come in lower than levels that we had discussed in August. That said, we believe we still have a line of sight, actually a pretty clear line of sight to achieving our debt targets while continuing to progress our repurchase program next year.

And the next question will come from Charles Meade from Johnson Rice.

Bill, I wanted to ask about your trajectory going into '23. And more specifically, you guys had a nice beat in 3Q, but it makes the -- it makes spread a little bit steeper decline in -- going into 4Q, even though you guys are still on track in a larger sense, but that decline we're seeing in 4Q, it is -- what are the implications that are going to carry over into '23 from that?

Yes, Charles, I'll start. It's all consistent with what we talked about in the second quarter where when we elevated the capital guidance due to inflation, it was so that we could keep activity levels on track with our originally planned activity levels and that fourth quarter activity sets us up for 2023 to start the year off in the right way. And as we all know, the timing of completions has clearly a quarterly impact on production levels. And so what we're doing in the fourth quarter is going to be the production that comes online in 2023 in the beginning. And then we will have a similar, somewhat front-end loaded program as we come into 2023. So we should have a similar profile to that production as we move into 2023.

Got it. That's helpful detail, Clay. And then perhaps the follow-up, you referenced the efficiency gains you expect to see in the Haynesville now that you guys have put a couple of quarters under your belt there. Can you give us a sense of the -- I guess, the kind of the qualitative and the quantitative. What is the scale of these -- of the efficiencies you think you can -- you have line of sight on? And where are they coming?

Yes. It's a continuation of the conversations that we've been touching on as we started operating in the Haynesville. We clearly got a year of learnings that is helping us as we forecast 2023. We've had completion design improvements that have helped with the well performance of these wells when we brought them online. We've seen cycle time improvements as the program has moved through the year that we feel like as we get into 2023 will be more consistent across the program.

We've done facility modifications to help us optimize production levels and reduce the impact of downtime as we move through the year. So we think all of the key categories around efficiency improvement that we focus on are setup for us to continue to make progress as we move into 2023 and especially with the 1 year of learnings behind us.

And the next question will come from Scott Hanold with RBC.

Can I ask on, as you look into 2023 and beyond? And I would say, first and foremost, you all did a really good job of generating a lot of free cash flow in 3Q and you not only reduce debt fast, but also did -- you had a pretty strong share buyback quarter as well. As you kind of look into next year and sort of the point Doug made about having the lower strip prices out there, how do you think about stock buybacks balance between that and that debt reduction target because it looks like you bought back at about 740 in the third quarter? Obviously, your stock is now below $7. So it seems like it's a good opportunity to really lean into buybacks here.

Scott, it's a great question. And the reality is our approach really has not changed. Our priority remains to reduce debt. We believe that has various benefits, not only for debt, but for equity, reduced volatility and other benefits. That said, as we progress towards our debt objectives, we'll continue to repurchase shares. And we believe that with what we think is a significant disconnect between our share price and net asset value, the opportunity for those buybacks should be accretive for a while. It certainly were in Q3 and future commodity prices and our corresponding cash flow will dictate the pace of our progress on that front.

Got it. And as my follow-up, kind of going back to the contract you did adding 500 today on the LNG corridor. Can you give us a sense of what are some of the pricing dynamics you all will get out of that? How does that differ from just selling it in market? And how are those discussions going with also those counterparties on negotiating what kind of price uplift or exposure to international markets right now? How is that -- how are those conversations going?

So the added capacity gives us better netbacks versus Perryville, for example. And so we took the opportunity to get the capacity. Now there's nothing wrong with Perryville either. It's quite strong, but this gives us a bit of an added advantage. On LNG, let me comment that today, we moved 1.5 billion of gas to the LNG sector in multiple agreements. Our strategy has moved forward to have us pursue take 1.5 Bcf per day and make it 2 Bcf a day. And of that, 0.5 Bcf a day would be focused on the LNG market and specifically international pricing, where we believe that there is an opportunity for us to understand that better and potentially access higher margins. We will do so with a risk-based approach to that. We're in conversations with all of the appropriate LNG projects that we can reach and that dialogue will continue.

I would expect that we're quite a ways away from having an agreement in place or even deciding to go pursue that given the risk nature of the global gas markets and the volatility that's there. But the -- maybe real clear that 0.5 Bcf a day I mentioned is our target is up to that. We're not at a point right now where we want to go any further than 0.5 Bcf a day, which is still a robust pursuit, but again, global gas volatility and all of the learning and discussions that need to go on, we're going to take a measured approach to that.

Okay. Are the counterparties a little bit more open to providing you access to those markets and say they might have been 2 to 3 months ago when international prices were a lot more robust? Or is it kind of -- are they kind of looking at more of a balanced approach to it as well?

Yes. I think you need to think about them in terms of 2 sets existing LNG exporters, less likely to probably let anyone into new agreements that relate to existing marketing opportunities. There's always exceptions and there's always opportunities. But in the main, I would go there. The new entrance to the game are more interested in looking for ways to create some kind of an enabling event, whether it's a very healthy in-basin producer that's got the financial strength and the reserves to back up an agreement and negotiate something going forward that has increased pricing or as you've seen in some of the press where somebody comes in and builds a pipeline to the facility to enable it to happen or something like that.

And there's all kinds of options in that space. But in the main, we're having some good discussions with those different next -- the next wave to come on and even with that, it takes time to work through all of the nuances that are about international marketing of gas.

And our next question is from Paul Diamond with Citi.

I was just hoping to kind of circle back a bit on the Haynesville productivity and efficiency gains. You noted that you're moving from 7,000 to call it, 9,000-foot laterals. Has there been any surprises as far as location? I know you guys are at a point where you kind of poke holes in the entire basin. Is there any areas that you're more enthused about than others? Or is everything kind of coming up rose?

Well, I would say that it is performing across the position as we had expected when we did our original evaluation and in a lot of ways, even better performance than what we had expected. The Southeast part of the play in DeSoto and Red River Parish and the Natchitoches Fault zone is where we've had the best performance. We figured that, that would be the case based on the greater reservoir pressure and the deliverability and EURs that those wells have, and we've continued to see that throughout the development but across the play and our acreage position, the performance has been where we thought. I think that the proof points of that are how we've delivered the program over the year, all the drill wells, turn in lines. All the activities are on track with our program and then we're getting the performance that we expected, if not a little bit more. And in this service environment, I think that's a big positive and it points to the quality of the integration of the asset that occurred and then the execution that the team has delivered.

Okay. Understood. And just one quick follow-up on that. How do those well results play into your approach of splitting your capital expenditures between Appalachia and Haynesville? I know you've talked more about like 55, 45 previously. Does that still hold? Or is there any leakage one way or the other?

This is Bill. When we prepare our budget for a given year, we take all of the opportunities that we have across the enterprise and effectively rack and stack them by economic return. You have these large Haynesville wells. We have wells in Appalachia with high volumes of gas as well. We have wells with natural gas liquids and condensate. So we put them all down economically, we then pick a slate of wells to be drilled and then optimize around that. So we're not over-capitalizing midstream in place or we're not under-utilizing capacity somewhere. And so it's a kind of a choreographed approach to laying out an inventory of wells.

Certainly, right now, we're at 55, 45. It will probably be somewhere in the same neighborhood given the strength of the economics across the enterprise. And the fact that we really are advantaged in that we have complementary investment opportunities in every part of our business, it could change. Probably it could, but it will be in the decimal points versus some wholesale change at this point.

The next question will be from Nick Pope from Seaport.

I was hoping you guys could provide a little more clarity on operating costs. Kind of looking at full year guidance, you guys are trending well below kind of where that full year unit guidance is on operating cost. So trying to make sure I kind of understand if that's you guys just operating ahead of schedule. Or if fourth quarter, we should expect some kind of uptick in operating costs? Or is there anything unusual going on there?

Yes. I would say that from an inflationary standpoint, we have seen the impact on the expense side as well as the capital side in the main categories of water disposal, water hauling, compression. But our team is very focused on how we can offset some of those costs. And provide some efficiencies that don't take us -- have us take the full brunt of those. But we have seen increases. And as we move into the fourth quarter, I don't see a big change to what we've seen year-to-date.

Yes, I agree with that. And I'll tell you why I don't have Brittany reach out to you and look at that and give you some further color.

Got it. I appreciate that. On the kind of back to that efficiency question, I know we're all -- there's been several questions on it so far. If you look at the Haynesville kind of it seems like the lateral lengths last 2 quarters have kind of been in a similar ballpark 9,300, 9,400-foot. Do you feel like you are reaching kind of like the optimal link there? Is there limitations on geometry? Or do you think you might you might push that further? I guess where do you think you are on kind of being able to push the limits on kind of how big wells you're putting down there?

Sure. So like we talked about this first year, a lot of learning has occurred. As it relates to lateral lengths, we're going to be very methodical about it just like we did in Appalachia. And each area of the field has some specifics that maybe limit how long we can go. We want to make sure that we stay efficient in the program. And so that's a potential lever. It's not the same opportunity like we had in Appalachia to go 15,000 feet laterals there given the geometry, there's some fault in there in that Natchitoches Fault zone. So I think around the 9,000 foot right now is where we're finding some optimized efficiency, and we'll continue to take a very methodical approach to that going forward.

And by way of a further example, we can do 24,000 foot laterals in Pennsylvania. All of our wells aren't 24,000. They're optimized. So that's one data point. The other data point is in Louisiana, you're restricted to 15,000-foot laterals in most part. And so -- but we're not going to put all of our wells bumping up against that limit. All at once, as Clay said, we'll take our time to learn and then advance that average forward.

The next question is from Neal Dingmann with Truist Securities.

Carl, an easy one first. Just could you just talk obviously balance sheet suggest today quickly improving? Can you talk about you and the teams not for engine going forward?

Neal, thanks for the question. Look, with the strengthening balance sheet, as Bill described, what we believe is a structurally strong long-term outlook, particularly for natural gas, we anticipate being able to lower our hedge levels, certainly below where they've been for '22 and '23 going forward. That said, hedging does remain a core part of our enterprise risk management. So while we'll moderate, we'll continue to protect our financial strength.

Glad to hear that. And then just a follow-up on Bill, maybe for you and team, on M&A. Again, I'm just more curious is there -- you guys did obviously 2 outstanding deals a bit ago. One, are there still a number of deals floating around in the Haynesville; and 2 would you entertain any of these as long as they sort of satisfy your criteria that you've had in the past?

And I'll make a comment -- I want to make one more comment on the hedging before I get to that. We've actually -- where we have these 3 rolling periods, and we used to be in the first year, 58%. We've lowered the low end by 10 percentage points on the first rolling period and the second rolling period. So -- and we had already done the third. So again, stronger financial strength, capability of the company of keeping enterprise risk management in line.

On the strategy around M&A, I'm certainly capturing the tangible benefits of scale is what we're all about, not just growing to be bigger. And so you heard on this call, you hear it, see in our book, you understand us well. Those benefits are coming in optionality, greater capability to expand our marketing into areas where we haven't been before.

But we're going to continue to look at M&A opportunities that show up and let me define what that means. We believe it's important for us to understand what's going on in our basins where we choose to be. That doesn't mean we're going to buy everything. It's just we need to understand that. And occasionally, opportunities come up for us to look at.

But if you look at our recent deals, you look at the importance of the corporate objectives that we continue to talk about around repaying debt, returning capital to shareholders and meeting the criteria of our framework work for acquisitions, which has become more challenging given the assets that we purchased and given the improvement that we've made in our asset base. I think our priority right now is paying down debt, returning capital to shareholders. Again, we look at some things and evaluate them, but we're sticking to that focus of continuously improving the strength of the company.

And the next question will come from Umang Choudhary with Goldman Sachs.

Umang Choudhary from Goldman Sachs. Hope you can hear me okay. My first question is on inflation. You talked about 15% to 20% inflation next year. Are you seeing any signs of any regional bifurcation in terms of how much inflation you're seeing between Appalachia and Haynesville?

Yes. So as we went through 2022, we realized higher inflation in the Haynesville than in Appalachia. And as we've started our contracting process for 2023 that trend is considering -- is continuing, maybe moderating a little bit, but Haynesville a little higher than Appalachia. We've used the same approach that we used in 2022 around contracting the major spend categories early well in advance of the coming year and that served us well in 2022, especially from a quality of the goods and services where in Haynesville and in Appalachia, we did not have any of the execution issues that some of the operators have seen around supply chain and around timely getting all their goods and services done. So that's the approach we're using as we move into '23.

That's helpful. And for my next question, I wanted to talk about your credit rating. How are the discussions going with credit agencies on the path to investment grade is a $3.5 billion debt number, is that the boggy which they're looking for or are they comfortable given the macro environment, are they comfortable with probably a higher number?

Great question. I'm going to make a couple of comments. To answer your question directly, our target debt range of $3.5 billion to $3 billion is exactly that. Our target debt range while the agencies expect us to progress and openly meet that, that is not a requirement that they said that we need to meet to achieve investment grade. Referring from that, that we could potentially become investment grade before achieving that level of debt. So I wanted to make that clear.

I guess our second point is we believe that from both a financial risk profile and a business risk profile, we are already either at or at least very close to investment grade. And that leads to my third point, it's really just a matter of time, a, for us to continue delivering on what we've said we'd do with the agencies in the market more broadly. And 2 for -- rather be, I guess, for the agencies to make the decisions when they do because it's ultimately their decision to make.

We go into quite a bit of detail, and I've had the opportunity to meet them as well. And I think the -- Carl is right, it's not an absolute number, but the credibility of our path to get there is what they are banking on. And we talk a lot about that. We share a lot of detail on that path. We have built a credible path, a wholesale change in that changes the game and they're very clear about that. But right now, the confidence that they have shared with us around the pathway that we're pursuing gives us the confidence of our dialogue and belief.

The next question will be from Subhasish Chandra from the Benchmark.

Bill, a question for you on maybe not now, perhaps longer term. Any interest in sort of getting involved in some of these other sustainable type things that whether it's carbon sequestration or hydrogen, you guys have been certainly when it comes to sustainable development, have been, I think, pretty early. So curious what you think there?

Yes. I think that we continue to evaluate some of those options and carbon sequestration is one of them that we are thinking about. We've been in a leading position for a long time doing whether it's water or air. And as you think about water and air and you think about opportunities to make a difference that are backed up by real changes to the business or backed up by reductions that are actual in nature versus more indirect. We take that approach, and we'll study those and if they make sense to us, we'll dig into them a bit more. But sequestration is one that we are looking at, along with, obviously, continuous improvement in the achievements and metrics that we have.

The Momentum NG3 deal that we talked about in the press release has a CCUS component tied to it that is in the early stages, but was part of our attraction to that deal.

Exactly.

Okay. Interesting. And Clay, I guess, when you say a traction of that deal, that is where Southwestern plays an active role in the sequestration aspect of NG3?

So we're partnering with them, and we're improving the emissions from a reduction of CO2 that happens in that Haynesville basin area.

Okay. Got it. And just a follow-up. I think you mentioned that you're well on your way, something like that towards securing your 2023 services. Can you give a context of like how much of that has sort of price visibility, how much of that is still going to be floating through the course of next year?

Sure. It has all the traditional service company contracting components to it with some have quarterly openers, some have twice a year openers in them. Drilling rigs, for example, are typically fixed for either a 6-month contract or a 12-month contract. We're dealing with a lot of the same service providers we've worked with in the past. So we're not breaking new ground as we continue to work together to position the company to get the best cost we can in this environment, but also the quality of services and continuing to update the way we structure those agreements to provide the best opportunity for the company as we go forward, and that's well underway.

And I think one other aspect of it that I put on the table is continuity of talent and being able to count on very capable people to execute the plans we have. Seven of the rigs that we use -- we will use and '23 and 2 of the frac fleets we use in '23 are staffed by Southwestern Energy employees as we own that equipment and that business and their capabilities are incredible and they stand very strongly with the contractor counterparts, but they are also a high degree of continuity in the fact that they're part of our team and direct employees, and we're thrilled to have them and that risk then moves off the table and we can focus on other aspects of the risk profile.

And the next question is from Noel Parks from Tuohy Brothers.

Talking about your company-owned rigs, and I'm thinking of some of the things I've seen from the rig companies as far as their own risk/reward and caution. And I was wondering if we're in a long-term, say, $5 or better gas world and maybe we've hit the peak of the growth in inflation. Would you consider another company-owned rig and I'm thinking in terms of the long time frame for lead time for a new build. So is that something that would be on the table for you, you think?

I think you've got to look at that kind of an opportunity in a couple of different ways. One, capital allocation priorities, paying down debt, returning cash flow to shareholders is our 2 priorities in the use of cash. Second thing is being able to operate and maintenance capital to keep the business in a place where it doesn't roll backwards, you got to keep the investment opportunities consistent on the plan.

And then the other part is just studying the environment and understanding the utilization rates and just how certain are we that, that base load needs to increase. As you'll note, we don't have 7 frac fleets and 7 rigs. We have fewer frac fleets partly for utilization, partly for availability from third parties and having that mix so we can learn. So I would say that, that has to go into that discussion. And right now, we're focused on the great teams we have and the capital allocation strategy that we put out in the market.

Great. Fair enough. And sorry if you touched on this already, but thinking about your hedging strategy and Obviously, with less debt, there's less pressure to lock in cash flows. As you look ahead to next year 2023 and into 2024, is there a point where you think it's likely you might need to turn back more towards thinking in terms of downside protection? It certainly seems that the nat gas fundamentals globally are kind of on a one-way ride up. But I think we just get beyond the next year, is it time to start thinking about some caution there? Or do you think erring on the side of leaving the upside exposure just still outweighs the need for downside protection?

Thank you for the question. So let me start by saying we've not left managing the downside risk. We're able to moderate hedges in the current environment, but do understand that on balance, as part of our enterprise risk management practice, hedging is a major piece of that, and we will -- we remain in that place where we're going to be watching from the defensive perspective and defensive protection perspective, what's happening.

When you strengthen, the company's strengthened the balance sheet is stronger, all of that, the market is stronger, you get to have a bit more optionality. But hedge minimums remain. I think the key point is that we've got a lot of capital and a lot of costs, just like everybody else does. And one of the priorities for us is to protect that and get your money back at least. And so the hedging ranges that we are hedging targets that we set, take that into account and take into account the forward gas strip or liquid strip, depending on what you're doing and making sure that at the given strip pricing, we are managing that risk.

We have the opportunity to use swaps and colors and other things such that you can give yourself a bit more upside exposure. And as we've already said, our hedges, we're hedged. Our upper limit in the current year is 80%. We don't need to be at that place, but at a given strip, but as it moves around, we move around with it and monitor those and link them together. So I think -- I know we have a lot of investors who want to be certain that we're not walking away from that defensive risk management side, and it's integral to our enterprise risk management, so we are not.

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

Well, thank you all for joining us on the call. Thank you very much for the questions. Any further clarification on our plans, please reach out to us, especially our IR team, they're very happy to talk. And with that, have a great weekend, go Astros, and we'll talk to you soon.

Thank you, sir. This concludes Southwestern Energy's Third Quarter 2022 Earnings Call. You may now disconnect.