EXPAND ENERGY Corp (EXE) Q3 2022 Earnings Call Transcript

Good morning, and welcome to the Chesapeake Energy Third Quarter 2022 Earnings Teleconference. Please note, this event is being recorded. I would now like to turn the conference over to Chris Ayres, Vice President, Investor Relations and Treasurer at Chesapeake Energy. Please go ahead.

Thank you, Andrew. Good morning, everyone, and thank you for joining our call today to discuss Chesapeake Energy's third quarter 2022 financial and operating results. Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website yesterday. During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our press release yesterday and in other SEC filings. Please recognize that, except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements. We may also refer to some non-GAAP financial measures which help facilitate comparisons across periods and with peers. For any non-GAAP measure we use a reconciliation to the nearest corresponding GAAP measure and it can be found on our website. With me on the call today are Nick Dell'Osso, Mohit Singh and Josh Viets. Nick will give a brief overview of our results, and then we will open up the teleconference to Q&A. So with that, thank you again. I'll now turn it over to Nick.

Good morning, and thank you all for joining our call. Before we get to Q&A this morning, I want to cover three topics that we believe are most important to our shareholders. The first is our strong third quarter execution, second is our industry-leading cash returns and the third is our strategy to continue our momentum into 2023 and be LNG ready. So to start off, we had another strong quarter operationally. We delivered on our production in the Haynesville and Marcellus and had some great well results in the Eagle Ford. We did experience a few delays in Eagle Ford production due to facility delays that pushed some volumes into Q4, but believe those will be temporary. We're reaffirming our annual production and CapEx guidance ranges for 2022, reflecting our confidence in our delivery as we finish out the year. In the Haynesville, we've made significant strides with midstream capacity. We've increased our gathering and treating capacity by 25% for this year and up to 60% in out years. We've also committed 700 million cubic feet a day to a new pipeline to be built by Momentum from the heart of the Haynesville play down to Gilles. This project also has an associated carbon capture and sequestration program with it. We're really excited to be a part of this unique and transformational project. We have an opportunity to participate in up to 35% of the equity of the project, and we expect to take that option. This gives us greater than 1 Bcf/d, or more than 50% of 2024 and beyond Haynesville volumes that are contracted for Gulf Coast delivery and pricing with both the Momentum pipe and our Golden Pass transaction. In the Marcellus, our synergies from the Chief acquisition continue to come to fruition. As we've discussed before, we're maximizing the capacity of the combined gathering systems. We're looking forward to 2023, where our well design improvements of longer lateral length and enhanced completions should show up with improved productivity per well. We've also been able to add a little bit of leasehold in the Lower Marcellus core of the play, which we're really pleased to do. Looking forward in the Marcellus, we're moving to a co-development of the Upper Marcellus in the core of the basin to optimize development of all zones of inventory. We expect the 2023 program to be about 50% Upper Marcellus and 50% Lower Marcellus. This will bring the average well performance down marginally, but does maximize overall inventory returns. Combined, the Lower and Upper Marcellus remain the top natural gas return opportunity in the U.S. On the Eagle Ford, I'm sure you all have questions about the process. We have no new news to report this morning other than the process is moving along very well, and it's too early for any results. We've been very pleased in the breadth of the interest in the assets and we'll report results when available. Turning to our cash returns. Our model continues to lead the industry in delivering returns to shareholders. We generated $773 million of adjusted free cash flow in the third quarter. This yielded $3.16 per share of total dividends to be paid this quarter. Additionally, we recently purchased $400 million of shares from former creditors. This brings buybacks on the year to $1.1 billion, 80% of which have come directly from former creditors. Our total returns to date, including buybacks and dividends, totaled $1.9 billion this year. We're really proud that Chesapeake stands alone at directing its free cash flow to meaningful actual cash returns. During the quarter, we also were able to simplify our capital structure with the warrant exchange. That resulted in eliminating two-thirds of the outstanding warrants, and it also resulted in a reduction of our short interest by 55%. We're pleased that when you combine this with our repurchase efforts, we're still able to lower our fully diluted share count. Separately, we continue to work with the rating agencies in recognition of our investment-grade quality balance sheet, and we're pleased that S&P upgraded us to BB this month. So to wrap up, I want to talk about how we're positioned for 2023. Our Marcellus program will remain steady and continue to highlight leading capital efficiency and the very best returns of all gas opportunities in North America. In the new slides we posted today, we added some slides that lay out our Haynesville market strategy. We expect to leverage our capital efficiency leadership, our growth flexibility and our midstream partnerships to position Chesapeake to be LNG-ready as the macro tailwinds from the significant increase in demand due to export capacity expansions arrive in the second half of the decade. We've been consistent in our message to grow and capacity additions are available to meet incremental demand. As export capacity doesn't begin to increase until at least 2024, we're setting up our near-term volumes to be relatively flat and begin to ramp slowly as we approach 2024. We're truly excited about what this setup means for our shareholders as we're uniquely positioned to deliver differential shareholder value over the next several years due to our superior capital returns, deep attractive inventory in the best places and a premier balance sheet, all while doing things with a focus on sustainability. Andrew, we'll open it up for questions now.

The first question comes from Scott Hanold with RBC Capital Markets.

Obviously, the Haynesville, you all are preparing to do more there. But I guess, the last couple of quarters, there had been some constraints and there are a couple of different constraints. Can you just provide a little bit of color on that? And then to Slide 23, it looks like you've got some solutions, but just give us a sense of timing and level of confidence that you have in this plan and strategy? Because it does seem like the Haynesville from an LNG perspective and just from a volume perspective, it's going to be important to you all going forward.

Yes. Great question, Scott. It's important. I'll talk a bit about this and others may have something to add. We have seen constraints. We've been talking about that for a number of quarters, and we've been active in contracting for incremental capacity, both on the gathering side as well as the treating side. We've also now contracted for incremental takeaway with the Momentum pipe. We are positioning for what we do think is an opportunity to grow over the next few years. But in the near term, we really don't see any need for growth. So 2023 is probably setting up to be about flat on a year-over-year basis but we'll have an exit-to-exit growth rate. When you think about what we've done in the Haynesville, at the beginning of last year, as we were integrating the acquired assets and recognizing some of the constraints that existed, we dropped to five rigs. There's a lag effect on the reduction in rig count like that, and we're seeing lower turn-in lines as a result of that reduction in rig count show up now in the fourth quarter as well as into the first quarter of 2023. That's all exactly as expected and the capacity additions that we've contracted for, and you can see on that map on Slide 23 that you referenced, they do begin to show up as we move through 2023 and get into 2024. So we're right in line with aligning our volumes to capacity additions as we've been talking about. So volumes ticked down a little bit in the first quarter of '23 and then as we build our activity moving through the year, we'll see an exit-to-exit growth. We think this is all very well timed with where we think the longer-term supply-demand dynamics will head, and we're pleased with the setup.

Got it. And just to clarify that, so you've got your guide post for 4Q, which is a downtick and then '23 is another downtick before it goes up. Just wanted to clarify that.

First quarter of '23 should be a little bit of a downtick from there, yes.

Okay. Got it. Okay. And then my follow-up is on that Momentum pipeline. Can you just discuss a couple of things. One, the pricing dynamics around that for you all in the gas. And then number two, the CCS options, you talk about, it sounds like you're going to commit to the 35% participation. What kind of capital and timing around that capital would that result in?

Sure. So the pipe itself will deliver gas to Gilles, and we will pay a rate which we cannot disclose for the terms of the contract. But if you look at the market out there for FT in the basin, we think this is right in line with what other pipes are charging. We ran a pretty competitive RFP to determine which pipe we would participate in and ultimately selected this one. So we felt it was a really attractive overall rate on the pipe as well as a market delivery solution and then the carbon capture piece was quite helpful as well. Momentum is also going to build a bit of gathering for us in the field. There were a couple of sections on the Haynesville acreage that had yet to be contracted for wellhead gathering. We've been able to tie that into this entire contract and get that done at an attractive rate as well. The carbon capture element of it is going to take longer to be built out than just the delivery to Gilles. But the way this will work is that we will deliver the gas to Gilles inclusive of CO2, so it won't be CO2 treated in the field. The CO2 will all be removed at the delivery point, so you'll have scale in the removal of the CO2 before it goes further downstream to market. Then with that scale, you can afford to sequester the carbon. We think it's a really innovative project. We're excited to be a part of it. It's not done yet. We still have to finish the contracts and the documentation around the equity participation. We do intend to do that. The cost to participate in the equity, of course, is a projection, not completely known, but we would estimate probably around $350 million over a couple of year period. The return on that investment to us should be quite attractive.

The next question comes from Umang Choudhary with Goldman Sachs.

I would love your thoughts on the macro environment here, given gas prices have been so volatile and weak recently, and there are concerns around supply outpacing demand next year. Also, would love to get your thoughts around what price levels will you look to reduce activity in the Haynesville if, say, winter weather is warmer than expected.

Great question, Umang. We have spent a lot of time talking about the macro lately. It has certainly been volatile, as you suggest, and it has been headed a bit lower. The great thing about the gas market today is that even with volatility it's still at levels at which our company makes a really attractive profit and we generate great cash flows for shareholders. So we think we're well prepared for either a weaker gas price environment or if it turns cold and gas prices become more robust, we're prepared for that as well. Based on the setup of growing supply that we see across the market today and demand that is really going to rely on weather in the short term, we are very well prepared for a weaker gas market as we move into 2023. We can't predict it, don't know if that will actually happen, but if it does, we'll be ready for that. At what price would we reduce activity in the Haynesville is a great question. There is no hard and fast answer to that; it depends on a handful of things. One, it depends on how the curve reacts relative to just the nearest term months on the curve. And it depends on how we see the dynamics that affect that — what the drivers really look like. We remain bullish on the longer-term supply-demand fundamentals, particularly for the Haynesville and for the U.S. as a whole. We will pay very close attention to the 2023 and 2024 setup as to how supply and demand will play out and the timing that growth in demand should show up. There's plenty of uncertainty around the precise timing of when export capacity will come online. Even the best efforts at estimations could be off by several months in an environment where supply chains are still challenged and labor markets are tight. We are prepared to be responsive to this kind of market. If you saw prices fall in a sustained way or the curve fall down into the mid- to low-$3s, we'd probably pull back a bit. We still make a good bit of money at that level, but it would indicate to us that the supply-demand fundamentals are weaker than we expect today and would give us a reason to step back and think about whether activity should come down. It's hard to predict exactly what that looks like because it depends on the facts at the time, but that is certainly a point at which we would evaluate whether our capital allocation is where we want it.

That's great. Clear. And my next question was on your capital spending outlook for next year. As you go through your budgeting process, any early read across in terms of how you're thinking about cost inflation and the impact on your spending next year? And then any — you talked about enhanced completions and shifting to longer laterals. Any benefits from that as you add more of those into your program next year?

Yes, this is Josh. As far as inflation goes for next year, year-over-year, I think we're thinking it's going to be in the 10% to 15% range. If you think about the activity we've been talking about — carrying forward five rigs in Marcellus, adding a seventh rig in the Haynesville, which we'll continue to monitor the markets and be flexible with that program, and then a relatively steady 2- to 3-rig program in the Eagle Ford — that's how we see the year shaping up from a capital standpoint. On the enhanced completions, where we're looking is really in the Marcellus specifically. We're not only increasing lateral lengths, but we're also looking at adding additional wells per pad, and that's one of the advantages we find with co-development. The completion optimization there is really about fluid loading and we think there are areas that benefit from less fluid. Those are the things we'll look at, which not only drive potential cost reductions and enhance capital efficiency, but we also think there are opportunities to increase productivity as well. That comment was specific to the Marcellus.

The next question comes from Doug Leggate with Bank of America.

So Nick, I'm clearly losing the value erosion debate on the variable dividend. But I do have a question on use of proceeds if and when you eventually sell the Eagle Ford. What should we think in terms of how you deploy those proceeds — whether it be to incremental acquisitions, to the balance sheet or indeed to share buybacks, given that you continue to see your share price undervalued?

Great question, Doug. So we've said with the proceeds from the Eagle Ford that we have a return model, and we would think about applying these proceeds through that return model. We've said that the dividends really are about operating cash flow. This is not operating cash flow. So we would lean more heavily to buybacks when we think about the proceeds here. Importantly, especially as we recognize that we could have a softer gas market here, at least for a year or a little bit more, we will pay down some debt with the proceeds. We will make sure that as we sell off an asset that has a lot of EBITDA, we ensure our balance sheet stays in great shape. We expect to look at the proceeds, think about the right balance sheet impact to reduce leverage, and then think about the best way to pursue a return of some of that capital to shareholders through a buyback. We'll have to wait and see when the proceeds come in, the magnitude of the proceeds and exactly how it all plays out to have specific answers for you, Doug.

Great. Thank you. It's a good enough answer. I guess my follow-up on inflation: one of your peers reported last night pointing to perhaps higher-than-consensus expectations for capital. You guys haven't really given a '23 look yet, but your fourth quarter run rate doesn't seem to be seeing a lot of cost pressure. So could you give us a steer as to what you think your core inflationary capital impacts could look like for the 2023 budget in that flat production profile you talked about? I'll leave it there.

Yes, this is Josh. On the Q4 burn rate, we do see some activity pull back in the fourth quarter because we dropped some rigs in the Eagle Ford, and that's pulling back our Eagle Ford spend. We also see a little bit lighter completion quarter in the Haynesville. So that's why our burn rate in Q4 will look a little different than the preceding quarter. As we think about 2023 and reference year-over-year inflation, we would expect to see the most inflationary pressures in the Haynesville. You could be looking at 15% plus there potentially, assuming rig counts stay relatively flat. In the Marcellus, we expect inflation to be more moderated — that basin tends to be more stable in nature — so the inflation we're anticipating there is really going to be in the mid-single digits.

The next question comes from Zach Parham with JP Morgan.

I guess just another follow-up on Doug's question there. You talked about this 10% to 15% inflation in '23. If we think about that in the context of the '22 budget, should we just add 10% to 15% on top of that and if so, does that include the impact of the seventh rig in the Haynesville and also any spending associated with the Momentum project?

Well, anything that we've done in '22 that's incremental will be an additional capital expenditure to layer in. But generally, we've guided you on activity. So the five rigs in the Marcellus, you need to account for the seventh rig in the Haynesville. We've given you guidance on cost per foot. The 2 to 3 rig range in the Eagle Ford remains. We'll continue to look at other opportunities, such as the acreage we picked up in the Marcellus, and if there are more opportunities like that, that could push up capital heading into next year.

Got it. And then one just on the operational side. I think Nick mentioned that the average well performance would come down marginally in the Marcellus as you do more co-development. Can you compare the Upper and Lower Marcellus well productivity? While both still clearly have very strong returns, what's the step down in EUR you expect on the Upper versus Lower?

Maybe I'll stick to what we've disclosed in our presentation. What we provided in the deck is an estimate on a 12-month EUR per foot. What you see there is just over a 20% reduction on a per-foot basis. But we do have the ability to drill longer laterals in the Upper, and on an absolute well basis that starts to offset some of that productivity loss and we can drill longer laterals simply because there are fewer wells to be navigating around. That's why we see an opportunity here with competitive returns. In addition, with co-development of Upper and Lower, we can put more wells on a pad, creating additional capital efficiencies, which we think can further enhance the returns specified in the deck.

The next question comes from Charles Meade with Johnson Rice.

Good morning, Nick, you and your team. You hear me?

Yes, Charles. How are you?

I'm fine. I wanted to pick up on the upper versus lower. I think this is the first time, at least I can recall, you guys comparing the productivity, and that's really helpful what you put on that slide. But I'm curious, my baseline, the only other operator that has talked about the upper versus lower in Northeast PA had a number more like the upper being 70% as productive. My understanding was that was primarily a function of less thickness in the upper. Can you talk about your number — I think it works out to about 77% — has that number changed over time or does it change across your geography? Just give us a little history and outlook on that upper versus lower.

One thing to consider is the productivity decline from the Lower to the Upper will be dependent upon the spacing at which the Lower was developed. You do expect to encounter some depletion, and that depletion will vary based on several factors: overall thickness, the thickness of the Cherry Valley limestone which is the barrier between the two, and how the Lower was developed. Some operators to the east developed the Upper with tighter spacing. We've been a bit wider throughout our history developing the Lower, so we may have a slightly advantaged expectation with Upper performance going forward.

Got it. That is helpful, Josh. Then shifting to the Haynesville, maybe more for Nick. If I think back to our last call, you were talking about the possibility of an eighth rig in '23. If I'm understanding your commentary right, that remains a possibility, but it seems like it's more of a distant possibility or maybe a second half '23 possibility at this point? Do we have the right sense?

I think you do, Charles. I would call it an option. One of the things we wanted to communicate is that we wanted to make sure we had midstream capacity, takeaway capacity in the gathering and treating space should we get to a place where we want the eighth rig. Over time, as LNG export capacity grows and there's incremental demand out of the Haynesville, we'd love to accelerate. We certainly have the inventory and the assets to justify acceleration when there is demand that's not being met. But as we sit looking at the market today, we don't anticipate that an eighth rig would be needed during 2023. If it turns out that it is needed, we'll be ready, but right now, we're not expecting to go to eight rigs in 2023.

The next question comes from Subhasish Chandra with Benchmark.

Nick, I appreciate the Eagle Ford sale proceeds is a bit hypothetical, but I still want to ask on the debt reduction to keep calibrate the debt ratio there. You have a very healthy working capital surplus if you include that in that debt calculation, and can you sort of give maybe a rough number of what the debt reduction piece might be? Maybe you can't because it's too hypothetical. Secondly, on the return of capital related to the Eagle Ford sale, have you considered a special dividend that might accompany the sale or is that hypothetical as well?

Well, Subhasish, thanks for those questions. On the first one, as Nick said earlier, the intent is to let the sales process play out and see what kind of proceeds we get. At a very high level, the intent is to pay down some debt. At this point, we would not get into the specifics of how much that would be. Overall, we are very happy with the shape of the balance sheet. As you can see from the materials, we are saying net debt-to-EBITDA is 0.4 turns. We are very comfortable with that. When selling a producing property and the loss of EBITDA has to mirror the overall pro forma debt level, we will pay down some of it, but the specifics will come at a different point in time. On your second part about a special dividend, the same logic applies. Once the bids are in and we recognize which path we are taking, we'll be happy to share more details.

Fair enough.

One obvious connection is that if we don't see structural supply growth until at the earliest 2024, that could mean soft gas prices, and soft gas prices can lead to weaker equity prices. Should that happen, we think our stock would be even more undervalued than it is today. We don't mind the dynamics of receiving a bunch of cash from this transaction and being poised to acquire our stock if it's falling due to macro conditions, which we would believe is short term with growth in demand coming. So we like the setup of thinking about volatility in near-term natural gas prices; that volatility can lead to volatility in equities, and we have a lot of cash.

That will be a good place to be. A follow-up: could you remind us about your bid week versus spot. For fourth quarter, we've already seen October and November weaken. How much of your 4Q is locked in at this point?

October and November are pretty well locked in. When we give our basin expectations, the biggest floating piece is December. We did lean a little bit heavier on first-of-month pricing for November than we typically do. We see the forecast for warmer weather in the East Coast through at least the first half of the month. This week there are early reports of potential cold fronts showing up — it's pretty early and supply remains robust — so we leaned a little bit harder on first-of-month pricing for November.

The next question comes from Nicholas Pope with Seaport Research.

I had a question on the post-quarter share repurchases. I think you commented you repurchased $400 million of shares in October. Just looking at the math, it seems like with the dividend and current cash flows you probably used some debt to repurchase those shares. I was curious if that was a choice because it was a creditor that had some availability, a block trade, or if that was just timing related to when the dividend is going to be paid out in December versus where everything is? Just curious about that big share repurchase.

Yes. The trade was done after the quarter closed. We've been clear that the intent of having a $2 billion share and warrant buyback plan is to have availability in case one of our creditors at emergence wants to sell down; we are ready to provide a bid. More than 80% of the buybacks we have done are former creditors, and it helps remove the perceived overhang from those former creditors. We've been pleased to do about $1.1 billion of buybacks and are well ahead of schedule, and we still have about $900 million remaining until the end of 2023 to prosecute the rest of the program.

Got it. I appreciate that. And then as you look at that credit facility, if you're going to add on to that, it looked like you commented that there was an average interest rate of about 6% to 6.6% on the credit facility in the third quarter. What's the timing of transitioning to a more traditional facility? It's obviously coming out of bankruptcy and is a little higher than where your peers or your debt metrics might suggest. What's the timing and ability to move around the credit facility in the near term?

The interest rate you referenced goes off a pricing grid depending on utilization of the credit facility. We carefully monitor conditions and the intent would be to try and refinance the credit facility before it becomes current. It matures next year, so we are looking into ways to refinance prior to it becoming current. Depending on macro conditions and what happens with the Fed, given the shape of the company and our engagement with different lenders, we feel optimistic about being able to do it in a timely manner.

The next question comes from Phillips Johnston with Capital One.

Just one more on the cost inflation front. Nick, you referenced Slide 12 which is helpful. It looks like you're anticipating Haynesville well costs can move up to a little over $1,600 per foot on a blended basis next year. What are the factors that could move that number either higher or lower? And can you give us a sense of what percentage of that is essentially locked in from a pricing perspective?

Philip, some of the risks to inflation include diesel — we're seeing shortages across the country right now. Diesel affects our drilling cost and has implications on transportation costs for things like proppant. Demand for rigs and pumping services remains high with most high-spec rigs utilized today, so if demand remains high that could enable providers to push pricing. We've been active in the second half of the year and specifically in the third and early fourth quarter working with existing suppliers. It may look like us taking on a bit higher cost today but providing pricing certainty and protection from additional inflation in 2023. That approach can preserve cost. As far as an absolute percentage, I'm not in a position to provide that today. But the bulk of our primary services on the frac and drilling side have been locked in for next year.

Okay. I appreciate the color. I also wanted to ask about potential timing of ultimately achieving investment grade and how important that is to the company. Based on your conversations with the agencies, is the limiting factor mainly a function of scale? What's the overall path they want to see, and how important is investment-grade rating to management and the Board?

Philip, investment grade is important to us. As you think about the LNG strategy, being investment grade would be extremely valuable. We are actively engaged with all three rating agencies. The credit metrics are investment-grade quality already, and there's an element of seasoning and showing a track record of performance, which we are demonstrating. The tone of conversations is positive. S&P upgraded us to BB last month, so we are seeing progress. We're a couple of notches away from investment grade, and we feel confident we're on the right trajectory — it's a matter of time.

And the last question today will come from Matt Portillo with TPH.

Just a question in the Haynesville. I appreciate the color on Slide 12 around the cost difference between the Haynesville and the Bossier. I assume a little of that might be apples and oranges with some shallower targets in the Haynesville further north in the basin. Could you talk about the cost difference between the two horizons and if we head into a lower commodity price environment in '23 or '24, is there some potential to cut back on the Bossier development? Or should we consider that necessary from a co-development perspective moving forward?

The Bossier is a more challenging formation for us. It is shallower, but the lithology and rock type make it a bit more difficult from a drilling and completion standpoint, which drives some of the cost differences. At this point, I don't think we would pivot away from it. It's an important interval to continue to develop. It represents a modest part of the program, but it's important to continue to work down the learning curve, extend the limits of the zone, and we think there's a lot of efficiency still to be gained. That's a story we'll continue to develop next year.

Perfect. Then as my second question on gas marketing, the Momentum pipeline brings a unique opportunity here with CCS. We've seen industry participants talk about net-zero or carbon neutral oil marketing going forward and potentially achieving a premium. On the gas side, I know you've talked about RSG getting a small premium at the moment. If you tie your gas marketing opportunities with CCS and work toward LNG contracts, do you think we could see a more meaningful uplift to gas pricing as these projects evolve?

Matt, that's a great question. I believe we should see that, though it will take time to evolve. In early discussions with LNG off-takers in Europe and Asia, they are extremely interested in the carbon footprint of the gas they're buying. They're asking many questions about it and want to understand what responsibly sourced gas means and the overall footprint. When we highlight statistics like our 0.02 methane intensity from gas production, it gets the attention of international gas buyers. We think it will increasingly get the attention of domestic buyers as well. Today, there's no tax or structural incentive for buyers to pay more for a lower emissions footprint gas molecule, but that could change. There's talk about a methane tax and how that might show up in production decisions; we'll be keenly interested. With our footprint, we are well positioned relative to potential policy changes. We think this area will evolve significantly as the world recognizes the need for growing natural gas production and the demand that exists for affordable, reliable and lower-carbon energy. We believe demand for what we do grows from here and the best operators will benefit the most. All right. I think that's the last question we had this morning. I want to thank everybody for the time. To reiterate, we are extremely excited about the setup we see. We have worked hard to position this company, our portfolio and our execution for the market conditions that we see today. We know there will be plenty of volatility in these market conditions, and we think we are uniquely positioned to take advantage regardless of where that volatility heads in the near term. With the structural tailwinds we see to supply-demand for natural gas in the second half of this decade, we think the production we're delivering to market goes a long way to solving the challenges facing the economy today. Every employee at this company is proud to produce energy that delivers reliable, affordable and lower-carbon solutions for energy generation around the world. We think the demand for what we do only grows from here and the best operators will benefit the most. Look forward to continuing the conversation as we move to the end of the year. Thanks very much.

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