Cameron Horwitz:

Good morning and thank you for joining our second quarter 2024 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer; and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website and we will reference certain slides during today’s discussion. A replay of today’s call will be available on our website beginning this evening. I’d like to remind you that today’s call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday’s earnings release, in our investor presentation, the Risk Factors section of our most recent Form 10-K and Form 10-Q and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today’s call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Toby.

Jeremy Knop :

Thanks, Toby. Before I summarize Q2 results, I want to take a moment to thank our shareholders for the tremendous show of support in last week's vote on the Equitrans acquisition, of EQT shares cast more than 99% voted in favor of the deal despite this being an unconventional acquisition relative to what investors have become accustomed to in upstream M&A over the past decade. We see this vote underscoring the strong support from investors. They share a philosophical view that being at the absolute low end of the cost curve will create differentiated and sustainable long-term value amid a volatile commodity price landscape. Since taking over EQT in 2019, we as a management team have never been more [inaudible] that this company is on the right strategic path, and we look forward to continuing our track record of execution on behalf of our shareholders. Shifting to second quarter results, as planned, we curtailed one Bcf per day of growth production throughout most of the quarter, which along with non-operated curtailments impacted net production by approximately 60 Bcfe during Q2. Despite curtailments, strong operational efficiency and well performance drove production of 508 Bcfe above the high end of our guidance range. Per unit operating costs came in at $1.40 per Mcfe below the low end of guidance due to LOE and G&A expenses coming in below expectations. CapEx also came in below the midpoint of guidance despite an accelerated development pace, as efficiency gains drove lower than expected well costs. Turning to the balance sheet, we're off to a fast start on our deleveraging plan as we repaid $600 million of 2025 senior notes last month with cash on hand and proceeds from the Equitrans transaction. We exited the quarter with net debt of roughly $4.9 billion down from $5.7 billion at the end of 2023. Concurrent with the closing of Equitrans, we also upsized our revolver from $2.5 billion to 3.5 billion, which speaks to the depth of support for our bank group. This revolver is on par with the largest companies in the energy industry and gives us ample liquidity to handle any foreseeable natural gas price scenario moving forward. With the close of Equitrans this week, pro forma gross debt is expected to be approximately $13.5 billion, inclusive over the redemption of Equitrans is 14% preferred equity at closing. With the deal closing sooner than we originally anticipated, we expect our deleveraging timetable to be pulled forward by approximately six months. On the midstream side, we plan to pursue a minority equity sale of Equitrans as regulated assets, which are projected to generate approximately $700 million of adjusted EBITDA. This strategy will allow EQT to retain full operational control and upside value associated with synergy capture and future pipeline expansions. We're also marketing the remaining 60% of our non-operated assets in Northeast Pennsylvania and are in active discussions with both domestic and international buyers. We continue to target reducing our long-term debt to $5 billion to $7 billion and are highly confident in achieving our goal. Alongside planned after sales, we have further de-risked our deleveraging plan by increasing our near-term hedge position. We're approximately 60% hedged in the second half of 2024 with an average floor price of roughly $3.30 per MMBtu and approximately 60% hedged in the first half of 2025 at an average floor price of roughly $3.20 per MMBtu. We are actively building our hedge position in the second half of 2025 in order to bulletproof our deleveraging plan in any reasonable natural gas price scenario. Turning briefly to the Appalachia macro landscape, while the pace of eastern storage builds is moderated, absolute storage levels remain high on the back of warm winter weather last year, thus pressuring Appalachia pricing this year. In response to market fundamentals, we continue to tactically curtail production, including over the past weeks, and expect to continue this tactical curtailment program during the upcoming fall shoulder season. To this end, our second half 2024 production guidance assumes 90 Bcfe of anticipated curtailments, which should have a meaningful impact on both eastern and total U.S. storage levels as the market wraps up injection season. I want to highlight that normalized for the roughly 180 Bcfe of total curtailments that we expect this year, our production would have been above the high end of our original 2024 guidance range, which speaks to the productivity and operational efficiency gains that Toby spoke to a few minutes ago. While Appalachian storage is elevated today, the startup of MVP last month should provide support to Appalachian differentials moving forward. To put MVP's impact in context, assuming MVP flows at just half of its capacity on average for a year implies 300 to 400 Bcf of gas that otherwise would end up in Eastern storage that now will be directed to the Southeast demand centers. Given total maximum Eastern storage is roughly 975 Bcf, MVP flows represent a material and structural shift and local supply and demand fundamentals, which in turn should help tighten local basis over the coming years. In fact, between MVP coal retirements and organic load growth, we see implied Appalachian demand approaching 41 Bcf per day by 2030 compared with 35 to 36 Bcf per day of current basin supply, which should translate to better local pricing and present a sustainable growth opportunity for EQT at some point in the coming years, given we have the deepest, highest quality inventory of any operator in the basin. Turning to guidance, we have issued pro forma Q3 and Q4 metrics on slide 29 of our investor presentation. Our cash operating expenses are expected to range from approximately $1.10 to $1.25 per Mcfe in the second half of the year, which at the midpoint is roughly $0.25 per Mcfe below our standalone operating expenses in Q2. This reflects the benefit of eliminating expenses associated with the Equitrans acquisition or the most notable movement being our gathering rates, which are forecasted to decline from $0.59 per Mcfe in Q2 to just $0.05 to $0.09 per Mcfe in the second half of the year. Inclusive of the benefits from third-party revenue and the full run rate distributions from our MVP ownership, our net operating expense should equate to roughly $0.75 to $0.85 per Mcfe by the fourth quarter, which is approximately $0.60 per Mcfe lower than standalone EQT and drive home the relative advantage of our vertically integrated cost structure. It's also worth highlighting that we do not embed any of the $250 million of base synergies into our Q3 or Q4 numbers as we have conservatively modeled base synergy capture beginning in mid-2025. As I mentioned previously, our second half 2024 production outlook embeds approximately 90 Bcfe of strategic curtailments this fall, which we will opportunistically execute should gas prices remain depressed. I'd note that curtailments are driving approximately $0.05 per Mcfe of upward pressure on our second half 2024 cost structure. So our 2025 expenses should be even lower than the range as I cited previously. While we still need to go through our full budgeting process for 2025, we preliminarily expect an all in pro forma capital budget in the range of $2.3 billion to $2.6 billion. Beyond 2025, we forecast long term pro forma capital spending ranging from $2.1 billion to $2.4 billion per annum prior to capturing the $175 million of upside annual synergies we laid out with the Equitrans acquisition announcement. Said another way, our long term capital spending inclusive of Equitrans should essentially be in line with standalone EQT capital spend in 2024. And this is before capturing upside synergies, which speaks to the structural capital efficiency improvements accruing in our upstream business. At recent strip pricing, we forecast pro forma cumulative free cash flow of approximately $16.5 billion from 2025 to 2029 in an average annual gas price of roughly $3.60 per MMBtu over this period. Even assuming a $2.75 natural gas price over this period, EQT will still generate north of $9 billion of five year cumulative free cash flow. While the bulk of our peers would be cash flow neutral or negative, underscoring the power of our low cost structure and highlighting how EQT is uniquely positioned to create differentiated shareholder value in all parts of the commodity cycle. And with that, I'll turn the call back over to Toby for some concluding remarks.

Operator:

[Operator Instructions] Your first question comes from a line of Arun Jayaram from J.P. Morgan.

Jeremy Knop :

Hey, Jeremy. Good morning. Yes, we're seeing really good interest. I think I would characterize it as really a renewed set of interest, a lot of new names, actually, in the process from the international space that we didn't see the first time around. So that's been really encouraging, a lot of great engagement. So I think our feeling towards that process remains really positive. And I hope to get that wrapped up by your end.

Jeremy Knop :

Yes, taking the route that we outlined in the prepared remarks actually bypasses most of the sort of considerations you might typically get hung up in with like drag rides, tag rides, and a deal like that. So it really simplifies it and I think it really provides a better, higher quality, more diverse set of assets to back an investment which drives the cost of capital down. So look, we've spent a lot of time, we've had a lot of discussions with a lot of parties on this already, even pre-closing. And so with closing happening a couple days ago, we're really in the thick of getting that data organized so we can kick that process off. And I hope to be able to get that wrapped up as soon as yearend. It might bleed into early Q1 but I think there's a real chance that all gets wrapped up this year as well.

Doug Leggate:

Hey guys, thanks for having me on and congratulations. I didn't quite realize it'd been five years Toby. It has indeed flown by. I've got two quick questions, I hope. The first one is on the capital budget for the next two or three years alongside the compression results that you've had. What we're trying to figure out is how much of the spending is related to that de-bottle making, if you like, and when does it roll over so that you basically get back to a steady state level of spending associated with your growing program?

Jeremy Knop :

Yes Doug, welcome back by the way. If you look at what we've put in our new slide deck that we put out last time, we put a couple case studies in from some recent pad level compression projects that we've installed. These are not a perfect proxy to centralized compression, which is a lot, it's going to have a much broader impact superior to what these examples show. But even those examples at $3 gas, I mean these are, you're generating 2.5x to 3x your money on that compression on just the pad level. So again, on a centralized basis, it's going to be higher than that. And then beyond just uplifting that base PDP for the existing production, you're going to see an impact on all of our future development as well. So the rate of return on this compression is superior to probably any well we could pick to drill. And as Toby said, the spend amount is really not that much. When you space it out across a couple of years on an annual basis, it's mitigated even more. But if you look at slide 8 of our investor presentation, the delta between that 2025 guidance number and then what we call long term right below that, you can kind of think about that as the annual difference in sort of uplift and spending we might see in a given year while we're doing that before reverting to a much lower range long term. And as a reminder that lower range that we show from $2.1 billion to $2.4 billion long term that excludes the $175 million of synergies that we called upside synergies. So I would say that upside synergy assumption assumed a level of uplift from compression less than what we're already seeing on even a pad level basis. So I think that number is probably even biased higher as we see the benefits of these projects come to fruition.

Toby Rice:

That's correct. That's a simple way to put it up.

Jeremy Knop :

Yes, that's a great question, actually. It's something we've kind of debated internally as we've thought about the right structure here. So for the regulated assets specifically, if you start with the transmission storage segment of Equitrans, that is really an extension of the gathering system. There are a lot of big header pipes that cross state lines, and so they are regulated. Maintaining the right pressures on those systems, being able to control things like expansions, is really integral to managing the gathering systems appropriately. And then when you think about those pipes then flowing into a longer distance regulated pipeline like MVP, maintaining that interconnection, that pressure at an appropriate level, it all kind of works together as a single system. And then as we think about MVP, as we talked about last quarter, the expansion on that project, we think is a highly economic expansion. That's something that we want to get done to evacuate more gas out of Appalachia and get it to a premium end market in the southeast. We want to make sure that project happens. Whether 5 or 10 years from now, it makes sense to still own something like MVP. Once all that expansion is completed, I think that's something we'll always evaluate. But I think at this juncture, we do want to maintain the operatorship and ownership of it.

Doug Leggate:

I guess that's pretty clear. Thanks for taking my questions in place and thanks for your comments, Jeremey.

Neil Mehta:

Yes, congratulations on closing the transaction, team. Two questions on the macro here. First is just can you talk through your hedging strategy, both near and long term, and how does the E-Train acquisition play into your hedging decisions going forward as you want to take advantage of the volatile market that you talk about.

Neil Mehta:

That's helpful. And then can you just talk through, you've done a great job walking us through your long-term views around data centers and power demand growth, which we agree is a very compelling story. 2025 is a little trickier just because you've got some pushout of some major projects like Golden Pass, and we're trying to digest the spare capacity that might be in the system too. So how do you think about the supply demand outlook for gas as we think about 2025, and what are you guys watching as markers?

Operator:

Your next question comes from a line of Scott Hanold from RBC.

Jeremy Knop :

Yes, so this is actually something really exciting that we've been really pleasantly surprised by. So I guess on the production side, we have not seen any reaction. So we have, production continues to be flat consistent with our expectations. What has surprised us though is that in that end market, we model the way we sort of mark that station 165 pricing where we're selling gas, we've sort of modeled it around a $0.20 premium dip to M2 pricing. We have seen pricing recently kind of average $0.50 to $0.70 above, so significantly higher than what we have assumed. And there have been periods of time where it's well worth $1 above M2. And so I think we've been really encouraged by how much gas that market has been taking. Part of it has been impacted by some maintenance on Transco, but I think for being a midsummer period, seeing that demand and that premium price already show up, I think is an awesome really early side marker. And so I think that the benefit we might see in winter periods could be even better as well, and certainly better than maybe what we have forecasted, but it's still early. There's a new price marker that flat put out for that station 165 market. So we're watching like everybody else to see how that develops, but I think all signs are pointing to a really positive direction on that.

Scott Hanold:

I appreciate that. Sounds good. Here's my follow-up, Toby. Look, you've been never shy to discuss politics from time to time. And as it relates to being a gas producer, what do you think the biggest issues are for the upcoming election? Like, what are the things that are you really focused on?

Operator:

Your next question comes from a line of Josh Silverstein from UBS.

Jeremy Knop :

Yes, Josh, I think in our view it's just maintenance mode. I mean I think in our prepared remarks we commented that if we had not retailed this year, we would have been above the high end of the range originally that was 2,300 Bcfe on the high end, We're running our business in maintenance mode so I would expect looking at the next year that's the volume level you look at. I think the only difference there is that the divestment of our non-op interest in some of the transaction impacts from that but aside from that we're running enough in a steady maintenance of cadence.

Jeremy Knop :

Yes, call it 550 to 600 hangs on a quarter.

Jeremy Knop :

Yes, it really comes down to kind of what value and multiple we would sell that at. But yes, I mean, all else equal, if you sell down some of that, it should drop a little bit. But that's factored into how we look at pro forma leverage already. So I don't think it really impacts how we think about our plans. And the only other thing that's going to impact that next year, too, is obviously gas prices. So if prices decline or go up a lot, that percent of midstream is going to oscillate with that as well.

Roger Read:

Yes, thanks. Good morning, everybody. I'd like to take a look slide 11, you have the organic deleveraging and the free cash flow expectations, ‘25 through ‘29. I'm just curious. Clearly, you're not going to be aggressive on the hedging side in the future. So what's sort of the underlying assumption on gas prices, gas volumes that gets us the numbers you lay out there?

Operator:

Your next question comes from the line of David Deckelbaum from TD Cowen.

Toby Rice:

Yes, we have a small amount of those completion efficiencies baked into our ‘25 plan right now given the newness of this step change in completion efficiencies, we want to see a little bit more time, but we'll continue to add that back in there. And in the second part of the question?

Toby Rice:

Yes, I would say, we think the upstream spending profile is going to be pretty similar to what we had pre-E -Train. I'd say that the impacts of the reduced CapEx are going to really start once those compression projects start hitting the front lines, which I'd say ballpark 12 to 18 months before that slope down. So everything that you're seeing in the upstream spending now is really just driven by base operating efficiencies and balancing the service pricing we see.

David Deckelbaum:

Yes, thanks, Jeremy. Just continuing on that I guess that long-term guidance of $2.1 billion to $2.4 billion at the midpoint is it fair to say that that's just reflecting the benefits from the installed compression bringing down that upstream budget relative to sort of the $2.3 billion the $2.6 billion in ’25?

Operator:

Your next question comes from a line of Kevin MacCurdy from Pickering Energy Partners.

Jeremy Knop :

That number that EBITDA number actually does not include the MVP distributions because that's going to be more of an equity method investment. So we'll provide clarity on that as we go forward. And the second part of your question was what again?

Jeremy Knop :

Yes, I think it is for MVP specifically. I think on a whole company basis, the main impact was what we noted in our remarks earlier that curtailments are skewing the per unit cost metrics higher. So I think as you look into 2025, if you were to look at per unit metrics, those should skew lower, assuming no curtailments. But otherwise I think it should be a pretty decent proxy, which is why we broke it out separately.

Jeremy Knop :

Yes, we don't proactively, on like a year ahead basis, bake in things like shut-ins, that's more of in response to the market. So if we did say the whole thesis in ’25 -‘26 analogy just got derailed for some reason, and there was a need to curtail, that would take production below that this sort of quarterly annualized number that I think you were getting at. But that's something that I think we would address more real-time as the market evolve.

Jake Roberts:

Good morning. Maybe staying on that topic, is there any difference in how we should be thinking about the curtailments being baked into the guide of the back half of this year relative to what we saw in the first half? And what we're trying to think about is if there's a change in ECT's elasticity of supply between the two periods, perhaps with MVP online.

Jake Roberts:

Got it. Thank you. Quick second one. On slide 7, the three sites you've highlighted, I think you mentioned that you see kind of thousands of opportunities across the field to implement this. Can you give a sense of which how many wells each site touches, so to speak?

Operator:

Your next question comes from the line of Michael Scialla from Stephens.

Jeremy Knop :

Yes. I'm not sure where the five years came from. I think we're excited to pursue that expansion as soon as possible actually. I think the only the only thing that we would that would cause us any delay is just making sure that it was time to come online with that expansion project on Transco to take all the gas but beyond that I think we were incentivized to get that built as soon as possible. And again that net to EQT that's a cost of probably $200 million to $250 million net to get that built and I would say that the guidance that we have given out in our slide deck that longer-term guidance today. I just say there's ample cushion built in. So I wouldn't expect that CapEx number longer term to really change it all despite the timing that we decide to pursue that expansion project. So that remains something that high on our priority list to get knocked out.

Jeremy Knop :

No. I mean we just closed two days ago, so it's a little quick to do that. But I think it's something that we're going to start exploring quickly.

Jeremy Knop :

Look, it's in response to the market if we can make money selling gas who wouldn't curtail anything obviously. But our assumption right now is that the majority of those curtailments probably take place in September and October We have curtailed even over the past week some volumes on given days depending on weather depending on maybe it's over a weekend not up quite to a 1 Bcf a day level, but we do on a very dynamic basis optimized realized pricing to make sure that we're optimizing value creation and not just giving our product away for price where we can't make money. And that's what we'll continue to do,

Noel Parks:

Hi, good morning. Just had a couple. I was wondering you talked a bit about the impact of MVP on regional gas storage especially in the east and where do you say we are in really offsetting the effect of seasonality as a big driver of gas pricing LNG eventually as a feed then is going to offset that, but just some thoughts on where you think we are at this point.

Noel Parks:

Got it, and I wondered just if you had thoughts on the outlook for industrial demand, both sort of in-region and out-of-region in terms of gas from more of an energy security resiliency level, just taking a greater role and sort of on a microgrid level as power demand overall keeps increasing.

Toby Rice:

Yes, I'd say at a very high level, energy insecurity is going to continue to be a big theme around the world and even in parts of this country, and the volatility that we see is only going to drive consumers of natural gas closer to the source of where that energy is produced to reduce the number of things in between their manufacturing facility and the source of energy. That's one way they can protect their supply and protect their business. And that just is going to mean that we think this volatility is going to drive more in base and demand for natural gas products.

Toby Rice:

Thanks everybody for being here today. With this being our five year anniversary, I just want to reiterate to everybody that all of the progress that we've made at EQT would not have been possible without the shareholders. It was you that voted 80% to put in a new management team here and give us this opportunity to realize the full potential of EQT. It was you all that voted, brought in a board of directors that has really been amazing at guiding us through this amazing transformation. And with this 99% shareholder vote supporting transformative transaction with the E-Train assets, you've given us a platform to continue this momentum. And we're really excited about working hard for you going forward.

Jeremy Knop:

Thanks, Toby, and good morning, everyone. I'll start by summarizing our first quarter results beginning with sales volumes, which totaled 534 Bcfe. As previously announced, we curtailed 1 Bcf per day of gross production beginning in late February and through all of March in response to the low natural gas price environment resulting from warm winter weather.

Operator:

[Operator Instructions] Your first question comes from the line of Neil Mehta with Goldman Sachs.

Toby Rice:

Yes. So we're continuing to have some really constructive conversations there and have a lot of great momentum. And I think what we're seeing is the announcement of the deal with Equinor a couple of weeks ago is actually really catalyzing those to move forward even more swiftly. So we have a ton of confidence in getting that done and a lot of great dialogue that's ongoing.

Ati Modak:

Got it. Appreciate that. And then as you think about the supply/demand macro for natural gas in the U.S. right now, you did mention that you will extend the cuts. How are you seeing the response -- the production response that you're seeing from the latest numbers? Is that -- is there an element of sufficiency there? Do you think there's additional cuts required? And how should we think about your philosophy as you think of bringing the cadence back online?

Jeremy Knop:

Yes. At a high level, when you think about the macro outlook, you added about 400 Bcf a day into storage in excess from the winter weather, then another 200 on top of that from production being higher than we all forecasted. So you have an overhang of about 600 Bcf that has to get worked out by, call it, October. And that will happen -- the market mechanism forces that to happen both through curtailments to limitations in supply but also increases in demand from coal to gas switching. And as Toby said, certainly constructive summer weather can give that a boost as well. But look, I think to maintain that market rebalance through the summer, you probably maintain low prices. It probably can't rise all that much. But once you get through that October period, you see the inflection of LNG demand really start to pick up. We think that market starts to change pretty swiftly.

Arun Jayaram:

Gentlemen, I wanted to get your thoughts on, obviously, the data center demand, you highlighted in your deck how you think that this could create kind of a premium opportunity for gas that's sold on the Transco Zones 4 and 5 South lines. I was wondering if you could give us just your general thoughts on how differentials may play out in the Appalachia Basin over time and specifically highlight your leverage to these 2 zones?

Toby Rice:

Yes, we were certainly encouraged to hear Governor Shapiro's comments about natural gas, both on increasing potential for power demand, but also in his comments about the LNG pause and advising President Biden that this LNG pause is a bad idea. I think Governor Shapiro understands that the people of Pennsylvania understand that natural gas is the economic engine that's powering the economy here in Pennsylvania and understands that natural gas is the key to decarbonizing, not only our own grids in the U.S., which Pennsylvania is the poster child for how impactful you can be lowering emissions when you replace coal with gas, but also understanding how we can do that on the world stage.

Operator:

Your next question comes from Jacob Roberts with TPH & Company.

Toby Rice:

Are you talking about from the sale or which you're talking about specifically?

Toby Rice:

Yes. So net to the non-op interest, what's baked in there is about 10 to 15 Bs and the rest of it is operated deferrals that we -- are direct impact of our decisions.

Jeremy Knop:

Yes. So I think what's unique about MVP is that it is a -- it's a pipe where EQT owns 60% of the capacity today. And we are the only producer shipper on that pipe. So there's no other producers who actually can access that market through MVP. The other 40% are held by utilities on the other end. And so I think we are very uniquely positioned in that sense. The expansion will be part of a FERC open season. So who ends up with that capacity just under that regulated process. But it's certainly something that we think we are positioned to benefit from either way. I mean there's value to be created through the expansion. There's value to be added for the utilities by supplying them new gas in that end market. I mean we're all aligned and wanting to have that happen. Even if we are not the ones to take the capacity out, not win that auction, I think we benefit either way, we get to sell more gas where producers collectively in Appalachia get to sell more gas to the utilities on the other end of that pipe. So it's -- no matter how you look at it, I think, a big net benefit to EQT.

Michael Scialla:

I want to see a little bit more detail on your curtailments in terms of price level you would need to see before you change your decision there on the Bcf per day of curtailments.

Michael Scialla:

Okay. And Jeremy, so say you -- it sounds like you expect a pretty good step up in price when you get to sort of the October time frame. If you were to see that $1.50 price persists through the summer before you see that step up, would that suggest you're going to likely extend those curtailments through the summer?

Michael Scialla:

Got you. And then just want to follow up on MVP. You talked about the demand growth you see in the Southeast U.S. and your plans to expand the pipeline, so a lot of focus on the integrated upstream, midstream model for you in your lower cost structure. How do you think about that with your divestiture plan and your potential to lay off, so I'm interested in that pipeline. Is it important to maintain control there? Or could you sell off all your interest there? I guess, just how you're thinking about marrying those 2 things?

Bertrand Donnes:

Just had a question on the potential divestitures. As you reduce debt, how price sensitive are you? Is this kind of a highest bidder wins? Or is this, say, hey, if the bids aren't up to your expectations, you just kind of walk away?

Jeremy Knop:

Yes. If you step back and think about the time line, the rating agency guided us towards, it's, call it, 12 to 18 months post-closing. We have guided closing to be probably a Q4 event. So we think about it as like we need to get through the deleveraging plan by the end of 2025, right? I think most of us expect the market for gas in 2025 to be a lot more robust than it is today, so because we're taking an opportunistic approach. We have good momentum right now. I feel very good that we get things done near term at very attractive values. But if we -- if something happens, and we decide, hey, let's be a little more patient, wait 6 months, wait 9 months, there's no issue doing that to make sure we maximize value.

Toby Rice:

Yes. I think stepping back at a very high level, just from a market diversification perspective, we sort of soft circled around 10% of our volumes being exposed to international pricing, feels about right. And depending on the discussions with end buyers, we could toggle that number up or down. Where we're at right now, we've got about 10% of our numbers here. But keep in mind, these agreements are nonbinding, and there's some work to do to get the terms that allow us to achieve our objectives. So we have that level here, but maybe not all of those agreements will make it to the finish line, but we've got a lot of optionality, give us the ability to make sure we get the terms that we need.

Toby Rice:

Yes, it's certainly another dynamic that we're putting into consideration. And when we step back and we look at the opportunity, servicing the emerging market of LNG, we have capacity to do that with our existing pipes. But one of the great things about data center demand is Appalachia has proximity to that. And so when we talk about advocating for LNG, this is more of a tide is going to raise all ships and be constructive for long-term demand of natural gas demand in the U.S. But when it comes to data centers, our view is really how can we get more direct exposure to that rising demand. And so we positioned the company extremely favorably to be able to make sure that we can get differentiated access to this new opportunity set. Things like positioning with MVP is great, showing the willingness to be first mover on doing large transformative gas supply deals that deliver reliable clean energy to customers. We're fielding calls on that front. And so we're really taking a much more targeted approach and leveraging our operation and commercial footprint to capture these opportunities in front of us.

Operator:

Your next question comes from Roger Read with Wells Fargo.

Toby Rice:

Yes. Part for the course, we pulled and refiled with the FTC and the sustained operating procedure. So we've continued to work alongside the FTC and provide updates along the way. We're really encouraged about the opportunity to talk to the FCC about how this transaction makes Americas natural gas Champion EQT, a lower-cost energy provider, delivering more reliable energy and also helping customers acquire cleaner energy sources. So a lot of great things for us to talk about with the FTC, and we're excited about the process.

Toby Rice:

Yes. I think there's a new dynamic that's really taking center stage here. Everybody understands the energy that they acquired. They want it affordable. They want it reliable. They want it clean. And certainly, with data centers liability is at the top of the list. But the other dynamic at play is going to be speed. And there's only one energy source that has shown the proof of track record of being able to meet any sort of demand from America and that is natural gas. Speed matters. And at a very high level, there's a couple of things that's going to allow natural gas to service this new demand quickly. Number one is leveraging existing power infrastructure, understanding that natural gas power plants are only running on average around a 60% utilization factor. There's an opportunity to leverage that underutilized capacity, and that could increase natural gas demand in the near short term.

Jeremy Knop:

I think it's super important to remember here, too, in terms of like in consumers reaching out wanting to buy gas, like if there is a first-mover advantage in this, like we already have it, right? We already sold 1.2 Bcf a day on a 10-year basis to the 2 biggest utilities in this region, right? And so when you think about where all the demand for data centers is right now in the country, today, you have about 20 gigawatts of demand. 13 of that is in the Southeast market, right? So a tremendous amount. So when these utilities reach out and they say, we need long-term reliable gas from a stable producer like EQT is the first name on the list. That is why we are the only ones who have already done a deal like this and done it at a scale that I think dwarfs what most people could do because we're the preferred supplier of gas. And you have to have a lot of characteristics in your business to be able to be that preferred supplier, part of it is scale, part of it is depth of inventory, it's credit ratings. It's having a really creative team that can work with utilities in buyers of gas to structure deals like this.

Operator:

Your next question comes from Noel Parks with Tuohy Brothers.

Toby Rice:

Yes. I think the Freeport outage is just an example of the uncertainties that exist in any market, natural gas not excluded. And the Ukraine war, who saw that happening and the positive catalyst that created on our market. I think how do we deal with these types of uncertainties. One is understand that these uncertainties will exist. And part of the way we handle that and position the business is to take a steady measured approach when we're thinking about accessing new markets. I think we certainly are the first ones to get excited. But when it comes to translating that to action, we are very strategic and very methodical on the steps that we're taking to do that.

Jeremy Knop:

Noel, think about how much LNG export capacity is being built just in Calcasieu Pass as an example, right? I mean that dwarfs just Freeport alone. So say there's a hurricane or a barge sinks, I mean, come up with any scenario, say that is shut in even for a month, the amount of volume that backs up in U.S. storage from just one event like that can be pretty tremendous.

Noel Parks:

Great. And I totally understand your framing of the factors of data center demand growth, coal retirement. And sort of on the issue of grid fragility, I think, in particular, about the microgrid market. I was thinking back to your deal with Bloom Energy a couple of years ago for RSG certificate sales. And I just wondered if you saw similar opportunities, whether deals like that are kind of a good investment in company time, in terms of just what you can capture, in terms of sort of economics of those. So any thoughts on that would be great.

Operator:

Your next question comes from Josh Silverstein with UBS.

Jeremy Knop:

Yes. So I guess, first of all, on the cost walk, I don't anticipate much of a change from the non-op sales. They are high-quality assets, but it's not going to move the needle all that much. I think there's other variables in the mix that will have a more outsized impact of that in terms of like you capturing synergies, other projects we're investing in around the asset footprint. So I wouldn't -- I think that's still a pretty good directional walk as to where we expect that to end up.

Joshua Silverstein:

Got it. That's helpful. And then just before just on the hedges, just going back to the prior call, I thought the view was that E-Train would now be the new hedge, but you guys have added hedges into the first half of next year, pretty similar to it looks like to what the second half of '24 is. Was it just a view of maybe some potential weakness or uncertainty this winter before you have a rising demand outlook going forward? Or is this a change in strategy over the past few months?

Operator:

There are no other questions in the queue. This will conclude today's conference. Thank you for your participation. You may now disconnect.

Cameron Horwitz:

Good morning and thank you for joining our fourth quarter and year end 2023 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website and we will reference certain slides during today’s discussion. A replay of today’s call will be available on our website beginning this evening. I’d like to remind you that today’s call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday’s earnings release, in our investor presentation, the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today’s call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Toby.

Jeremy Knop:

Thanks, Toby and good morning, everyone. I’ll start by summarizing our fourth quarter results, which highlight our operational momentum as we closed out the year. Sales volumes of 564 Bcfe was toward the high end of our guidance range, reflecting continued best-in-class execution from our drilling and completion teams, along with strong well performance. Our per unit adjusted operating revenues were $2.75 per Mcfe, and our total per unit operating costs were $1.27 per Mcfe, which were at the low end of our guidance range driven by lower-than-expected LOE and G&A expenses. It’s worth noting that we outperformed LOE expectations every quarter in 2023 with total absolute LOE coming in $40 million below our internal forecast, driven largely by more efficient water handling facilitated by the investments we’ve made in water infrastructure. Capital expenditures were $539 million, which were in the lower half of our guidance range, reflecting the operational efficiency gains Toby mentioned previously. Turning to the balance sheet. Last month, we completed several transactions that eliminated debt, reduced interest expense, simplified our balance sheet and established an important 10-year pricing reference point, which is the longest dated bond outstanding of our natural gas peers and underscores the market’s confidence in our inventory duration. First, we retired all outstanding convertible senior notes due in 2026, which eliminated more than $400 million of absolute debt. Recall, our fully diluted share count already included the shares associated with our convertible notes. We simultaneously liquidated the capped call that we had purchased in conjunction with the issuance of the convertible notes for cash proceeds of $93 million. Pro forma the convertible note retirement, our total debt outstanding is currently $5.5 billion, which equates to a 1.6x leverage when annualizing fourth quarter adjusted EBITDA. Following the convertible note settlement, we executed a highly successful $750 million 10-year bond offering last month, the proceeds of which we used to pay off 60% of the term loan that we borrowed in conjunction with the closing of the Tug Hill and XcL Midstream acquisitions. We saw extremely strong demand from the credit market with a peak order book of almost $6 billion and the bonds pricing at a tight 1.65% spread to comparable U.S. treasury rates, which is similar to credit spreads of many of the highest quality large-cap companies in the broader energy sector. In conjunction with the bond offering, we also extended the maturity of our remaining term loan from mid-2025 to mid-2026, providing ample flexibility for maturity management moving forward. In terms of capital allocation, we will continue to prioritize debt pay-down until we achieve our $3.5 billion gross debt target. Our capital allocation philosophy is underpinned by an unwavering focus on establishing a fortress balance sheet, countercyclical and opportunistic share repurchases and a steadily growing base dividend. This long-term focused value investing framework has received resounding support from our increasingly high-quality shareholder base, and we will continue to allocate capital in accordance with this first principles framework. Looking ahead to 2024, we are setting an annual production guidance range of 2,200 to 2,300 Bcfe, which is underpinned by a fully loaded maintenance capital program of $1.95 million to $2.05 billion. Additionally, we are investing $200 million to $300 million into several strategic growth projects in the form of midstream and water infrastructure and infill land capture this year. These opportunistic investments are significantly value enhancing, and I want to take a moment to highlight the merits of each of these. The acquisition of XcL Midstream last year created a full-service midstream platform within EQT. And through this platform, we are already sourcing proprietary opportunities that generate strong risk-adjusted returns and robust free cash flow yields, even superior to those of our core Marcellus wells, while at the same time derisking our upstream operations. As shown on Slide 10, we are investing in three Midstream growth projects this year, comprised of the Clarington Connector, the OakGate Pipeline and the Pacific Coast Compression project. The combined capital associated with these projects is approximately $115 million. And once fully operational, these projects should generate aggregate annual free cash flow of nearly $50 million in the form of superior price realizations. This implies these investments will generate an aggregate free cash flow yield of nearly 40%, which is extremely attractive given the absence of price risk and the annuity-like cash flow profile over a 20-year asset life. We forecast a total return on investment of roughly 8x and the aggregate net present value of these projects is estimated at $250 million, implying value creation for shareholders equivalent to roughly $0.60 per share. Despite only having this Midstream business for just 6 months, these initial projects provide a glimpse into the long-term opportunity we see for this new business line. Reinvestment opportunities of this quality only come about because of the symbiotic relationship between our midstream and upstream teams working in alignment together. We believe this approach to growing shareholder value is differentiated among peers, especially in a $2 gas world, and intend to cultivate this platform so that it becomes an even more impactful driver of shareholder value creation over time. Within our reserve development CapEx, we’ve also allocated $80 million to expand our existing water infrastructure assets in West Virginia. As shown on Slide 12 of our investor deck, we expect 2024 investments into our water infrastructure to drive annual savings of $20 million, implying a 25% free cash flow yield on our invested capital. Our EQT-owned water system has materially increased the amount of water produced that we can recycle, which is having a tangible impact on our cost structure as demonstrated by our LOE coming in below forecast every quarter last year, translating to $40 million more free cash flow than originally forecasted. Turning to land. We have roughly $100 million allocated to opportunistic infill leasehold growth in mineral acquisitions this year. As shown on Slide 13 of our investor presentation, opportunistic leasehold additions organically replenished 65% of the acreage that we developed over just the past year, which is a pace of replenishment that can materially expand our years of inventory when aggregated over time. We believe this ability to organically backfill developed inventory is a unique feature among U.S. shale plays that largely exists only within Southwest Appalachia due to the land configuration and historic development activity. We are seeing notable opportunities to add to our acreage position at extremely attractive prices this year given the low commodity price environment, which we were able to capture due to our strong financial position. To put into context, the value creation potential of deploying leasehold capital, we highlight a very tangible example on Slide 13 of our investor presentation. In 2022, we infilled leased acreage and increased our working interest by 18% in our Polecat North development located in Greene County, which we brought online last year. The incremental interest we added in this project through organic leasing is projected to generate a 90%-plus free cash flow yield in year 1 alone and nearly 55% of annual free cash flow yield over the first 5 years and a return on invested capital of roughly 7x the strip pricing. This example highlights why we see these tactical land expenditures as an extremely attractive reinvestment of capital while simultaneously extending inventory duration, which can, in turn, help facilitate additional strategic initiatives such as signing long-term supply agreements. A key point I want to leave you with on these growth projects is whether it’s land capital, infrastructure investments, our acquisition strategy, long-term agreements with utilities or our base upstream business, we are incredibly intentional about aligning these decisions to ensure they symbiotically work together to enhance each other and collectively result in optimal risk-adjusted compounding of shareholder capital in the decades ahead. In essence, this is the definition of terminal value. And through building a successful track record of these decisions, we expect this to be reflected in our stock price. Lastly, I want to quickly touch on our cost structure guidance given the moving pieces with the imminent startup of MVP. We are guiding full year transmission expense to $0.42 to $0.44 per Mcfe, which is up approximately $0.10 year-over-year driven by the costs associated with MVP. This is partly offset by an accompanying contractual step-down in our gathering rates, which we forecast to be in the $0.52 to $0.54 range for 2024, down from roughly $0.65 in 2023. Within our 2024 corporate differential guidance of $0.50 to $0.70, we conservatively assume EQT flows only a portion of our MVP capacity due to downstream limitations at Station 165. In the winter months, we should be able to flow at higher rates on MVP and realize a greater premium on downstream pricing. Thus, the cash flow uplift associated with MVP will be seasonal in nature until downstream expansion projects come online. It’s also worth highlighting that we have roughly 500 MMcf per day of our Station 165 pricing exposure hedged through financial instruments and firm physical sales through 2025, which provides downside protection should there be any further price pressure downstream of MVP over the next few years. With nearly 2.5 Bcf per day of upcoming project expansions at Station 165 and significant demand pull from the Southeast region, our ability to flow volumes on MVP and associated realized pricing should progressively improve over the coming years culminating in the commencement of our firm sales contracts in 2027 that are projected to improve our corporate-wide differential by $0.15 to $0.20, driving a $300 million-plus uplift in annual free cash flow generation. Turning to Slide 11 of our investor presentation. We announced the proposed acquisition of an additional 34% ownership in the EQT operated Seely and Warrensville gathering system in Northeast Pennsylvania for $205 million in cash, and we currently expect the transaction to close in late Q1 or early Q2. EQT currently owns 50% of this gathering system. So our pro forma ownership will increase to 84% based on terms agreed to in the purchase agreement, subject to the potential exercise of certain preferential purchase rights. Recall, this gathering system was part of the Alta acquisition we completed in 2021, which has been a significant source of value creation for EQT. The purchase price implies we are acquiring these assets for a double-digit free cash flow yield, underscoring how this deal allows us to reinvest capital into durable, long-lived infrastructure at an attractive rate of return with near zero execution risk, given we operate both the system and the upstream development underpinning the assets. Consistent with our broader strategy to reinvest capital into assets that improve our corporate cost structure, our greater ownership in the system will immediately lower our overall free cash flow breakeven price by more than $0.01 per Mcfe upon close. We are currently looking at ways we can shift even more development activity onto this system over the coming years, which could drive additional upside to the transaction. Moving to hedging. We tactically added to the front end of our 2024 hedge position earlier this year, leaning into the price spike that occurred ahead of the winter storm in January. We have now greater than 50% of our first quarter 2024 production volumes hedged with a weighted average floor price of $3.87 per MMBtu, which has derisked a significant portion of our free cash flow outlook for the year. We have nearly 50% of our second quarter production hedged with a weighted average floor of $3.39 per MMBtu. And roughly 40% of our Q3 production covered at a weighted average floor price of $3.42 per MMBtu. Additionally, we’ve recently added some 2024 winter hedges, taking our fourth quarter hedge coverage up to more than 20% with a weighted average floor price of $3.47 per MMBtu. Turning to Appalachian. Basis differentials were relatively wide during the fourth quarter, driven by an elevated Eastern storage level and rising production associated with multiple operators completing wells that were deferred from earlier in the year. Our strong basis hedge position again paid dividends this quarter, boosting our corporate-wide realized natural gas price by $0.08 per MMBtu. As it relates to the increase in Appalachian supply, after peaking at just under 37 Bcf per day in December, production in the basin has fallen by roughly 1.5 Bcf per day, and we anticipate further declines in the Appalachian supply through the second quarter. On the local demand side, it’s noteworthy that PJM recently doubled its 15-year annualized load growth forecast from 0.8% to 1.6%. This equates to nearly 7 gigawatts of additional power demand by 2027, in more than 10 gigawatts by 2030, which, if satisfied by natural gas, would translate to nearly 2 Bcf per day of additional local demand by the end of the decade. This trend of increasing local demand juxtaposed against a relatively flat basin supply and the commencement of MVP should provide a structural tailwind for local pricing over the coming years, which we do not believe is currently priced into the basis futures market. As it relates to Lower 48 supply, it’s worth highlighting that a prominent data vendor revised its year-to-date supply estimates downward by 1 to 2 Bcf per day this week. We had suspected certain data sources were overstating production, and this downward revision validated the market is not as oversupplied as many previously thought. Assuming production simply stays flat at the current revised level and weather is normal through the injection season, end of summer gas storage will be roughly in-line with the 5-year average level. I’ll close by sharing a few philosophical thoughts on what we believe it takes to not only survive but to thrive as a natural gas producer and a macro backdrop that we expect will be characterized by unpredictable volatility for the foreseeable future. The real long-term winners in this business will not be the biggest companies that gain scale simply for the sake of scale, but will instead be the companies that have a corporate cost structure that is currently and in the future at the low end of the cost curve. A low cost structure is the only competitive advantage one can have in a commodity-driven business, which is why it is our North Star and drives nearly all of our strategic decision-making. While we are believers that future natural gas prices will be higher on average, we do not believe that prices will be stable at the $4 to $5 level, like the prevailing consensus view. And building a business around this assumption of average prices is likely to end poorly. Until we return to a world where we can build necessary domestic infrastructure, we believe we are more likely to see prices either around the $2 level they are today to force high-cost producers to curtail production and activity were materially higher to curtail demand, as pricing becomes the only variable left to balance natural gas inventories. Said another way, we believe an increasingly fat-tailed distribution of outcomes. That is a critical distinction, and we’re already seeing the manifestation of this dynamic with prompt month pricing at this moment. However, EQT is at the low end of the cost curve and will be moving even further down the cost curve over the next 5 years due to our contractual gathering rate reductions in long-term MVP firm sales agreements. This outcome is by design as our philosophy toward creating value in a cyclical, volatile commodity business has underpinned every one of our strategic decisions over the past several years. The culmination of these decisions has created a unique opportunity for investors, deploy capital into the preeminent natural gas platform that is positioned to generate peer-leading shareholder value through all parts of the commodity cycle over the long-term. And with that, we will open the call to questions.

Arun Jayaram:

Yes. Good morning, team. I wanted to see on Slide 9, you highlight your views on maintenance CapEx and strategic growth CapEx and you compared it from 2024 relative to a 2025 to ‘28 outlook. Jeremy, I was wondering if you can maybe help us think about the trajectory of that spend? How does 2025 look versus ‘28? And maybe just some thoughts on midstream CapEx under this outlook because that was a clear focus of today some of the strategic midstream investments that EQT is making.

Arun Jayaram:

That’s absolute helpful. Second question. Give us some thoughts on the glide path on the $2 billion deleveraging target. There have been some recent press reports on EQT, potentially looking at selling your non-op piece in Northeast PA. I don’t know if this is a great environment to be selling assets. I was wondering if you could comment on maybe some inorganic opportunities to de-lever, call it, in a big bang type of approach.

Arun Jayaram:

Great. I will turn it back. Thanks.

Sam Margolin:

Hey, good morning, everybody. Thanks for taking the question.

Sam Margolin:

Thanks for the detail on the – on your activity plans for ‘24. As always, that’s a recurring slide. My question is the ranges of the number of wells that you drill and complete and turn to sales are the same range, but they are not necessarily aligned on either end. And so when you think about how you execute within those ranges, do they move together on a one-to-one basis? Or is there a scenario where you drill 120 wells, you complete 120 wells and you turn 120 wells in-line. And you have no change in sort of like your DUC backlog or your deferred TILs?

Sam Margolin:

Okay. That makes sense. And then, I mean, this is sort of a follow-up to those ranges. They are designed, I guess, to correspond to a number of different market outcomes. I mean what’s the market condition where you might materially change those ranges and bring down activity levels below where you’ve been running? Obviously, as you can imagine, that’s an inbound question I think all of us get from investors. Thanks.

Sam Margolin:

Understood. Thank you so much.

John Abbott:

Hey, good morning. And thank you for taking our questions. Our first question is really on your 5-year cumulative free cash flow outlook. You mentioned $9 billion. And that’s lower than you gave in the third quarter. Obviously, that’s part of lower commodity prices. But when you think about those two outlooks, has there anything really changed on the cost side in terms of assumptions? And anything particularly moved when you look at those two projections?

John Abbott:

Alright. And then the other question here is really all related to your long-term gas differential. Where do you think your differential sort of – if you sort of look at strip pricing, where do you think it is from 2027? And then Jeremy, you sort of went out there and you suggested that in-basin demand should improve over time, and that’s not reflected in current differentials. Where do you think that could potentially move?

John Abbott:

Very, very helpful. Thanks for taking our questions.

David Deckelbaum:

Good morning, guys. Thanks for taking my questions. I was hoping just to dig in a little bit more on just Arun’s question. I think you will highlight the lower implied maintenance CapEx going into ‘25 and beyond. I guess if we think about that delta of – I guess, $100 million, $200 million next year, is most of that just coming from continued synergies on the Tug Hill assets? Is it lower base decline? Is it implied cost savings? Is it less infrastructure spend? Or is it sort of all of the above? Or what’s driving the bulk of that?

David Deckelbaum:

And then maybe just to talk a little bit about just the LOE side or production cost side. I think you’ve highlighted in the deck, especially on Slide 12, the benefits of the water system. The guidance, obviously, this year, I guess, now inclusive of the Tug Hill deal and some other moving parts, your LOE is moving higher. Are you including the expected benefits from the water system investments in your ‘24 guidance around LOE? Or is that something that would be additional upside?

David Deckelbaum:

Yes, the $40 million, and I guess like the completion of the systems in ‘24?

David Deckelbaum:

Appreciate the color.

Kevin MacCurdy:

Hey, good morning. I had a couple of questions on the liquids production and pricing. The first question is, it looked like ethane production was lower than guidance for 4Q, while pricing for the other NGLs was higher than what we expected. Can you give some more detail on those two items and maybe remind us how your heavier NGLs are priced?

Kevin MacCurdy:

And how are your NGLs price?

Kevin MacCurdy:

Great. And looking at the forward guidance, it looks like liquids, excluding ethane, declines from 4Q volumes and then again from the 1Q volumes. What’s driving the decrease for the heavier liquids?

Kevin MacCurdy:

Okay. I appreciate the detail. Thank you.

Ati Modak:

Hi, good morning, team. Thank you for taking the questions. You talked about the capital allocation priorities this year highlighted debt pay-down as the focus, maybe help us understand the thought process around how your view of the macro environment factors into that decision matrix between the different pieces and how we could expect that to evolve?

Ati Modak:

Got it. Thank you for that. And then you mentioned the low cost structure as an advantage. You mentioned a couple of drivers there as well, but I was wondering if you could provide some more color on those pieces and what drives it down further over the next few years?

Ati Modak:

Thank you. I appreciate that. I will turn it over.

Scott Hanold:

Yes. Hey. You all kind of indicated that your breakeven point this year is around 220. And how do you think about that with the gas cracker, if gas prices do, say, continue to trend on the direction they are related to weather, whatnot, I mean would you guys be willing to make changes to make sure that you guys generate positive free cash flow, like so. The bottom line question is like when you start getting around that 220 threshold, would you be willing to cut a little bit more to kind of preserve free cash flow rather than burn some cash?

Jeremy Knop:

Yes. Scott, I would just underpin too. I mean you have to remember, I mean certainly for a business like EQT, where we are drilling 15 wells, 20 wells a pad, the CapEx we spend this year has no real impact on our production this year. It really has an impact on production next year. And so when we are thinking about that sort of rate of return and you save yourself $100 million this year, what’s the impact on free cash flow next year. Certainly, with where pricing even is today after pulling back and I think our expectation is probably significantly higher than the strip today. It’s really hard for us to justify that, especially just given the financial position we are in, the amount of liquidity we have in our credit ratings. We are just not under the same pressure that most of our peers are. So, that allows us to be a little stickier and plan for the long-term and not be as reactive. But look, we – as we have said before, our production guidance gives us flexibility to reduce as needed. But reducing CapEx activity this year is not – I mean it would be window addressing this year at the expense of next year, and it’s just not how we run the business.

Toby Rice:

Yes. It’s a great question. Listen, I think on the political front, I mean I think political force can override market forces for so long. And our job is to align with the market is to make sure the energy we produce is the cheapest, most reliable, cleanest form of energy that’s out there. And I think eventually, the demand for this product is going to overweigh, I think the political short-term gains that people are thinking that they are helping by doing this. So, I mean long-term, we feel even more optimistic about the large role natural gas will play in the commodity mix going forward. But yes, I mean in the short-term, we need to be sensitive to the market that we are in. Activity reduction is going to be a big thing. I mean a key part of our thinking is we positioned our business to be a low-cost operator in the U.S. I mean our breakevens are significantly lower than what we think is the marginal cost of production. And we are going to see if those marginal producers reduce activities. We have already seen that start to happen. But that’s something we are going to be monitoring and then it’s – eventually, we will have a normal winter. But even without that, with just normal weather, we should be balanced coming into 2025.

Jeremy Knop:

And Scott, with all the bearish narratives out there, I think it’s really important to remember that with these data revisions that came out of Genscape a week or so ago, I mean production levels were not at 107, pushing this bearish narrative, production levels today are like 104.5. And so if you look at where we are at today with normal weather, the market is actually balanced. And so the extra, call it, 275 Bcf that’s in storage right now is really just a result of, again, a really warm El Nino winter. If we had just had normal weather, the market would be balanced right now. So, I think this sort of overarching view of the market is just so out of balance, production is way too high. LNG is delayed. I think when you step back and kind of cut through the noise, it’s really not the case, which is I think why we are being a little more patient and disciplined here. And as it relates to a lot of the LNG headlines and some of the politics playing into that, I mean there is really no impact through – at least the end of 2026. So, as we look at the market today, we don’t really see any change in the LNG build-out timeline. I mean we expect in Q3, Q4, those facilities start to come online. And again, I think that the work the market needs to do is just to clean up that excess overhang in storage coming out of winter. But the market is really not that far out of balance. I mean it’s a difference of 1% to 2% kind of change in your fundamental model. And it can flip back pretty quick too. So, I think if you are running a long-term business, you just have to – you have to keep that in focus. We are really not that far out of whack on the fundamentals.

Toby Rice:

Yes. I mean it’s really just asking people to step back and see. It seems like we are in violent disagreement – violent agreement here on what we want from our energy system in the future, like Republican and Democrat, everybody wants more affordable energy. Everybody wants more reliable energy. Everybody wants cleaner energy. And I think the work that we are doing is highlighting, I mean I would say the biggest difference that we are doing, the hump that we need to get people over is to understand that natural gas is a cleaner form of energy. And the good news is we don’t have to play with theories. We don’t have to rely on literature. We have case studies at big scale that show that natural gas is a decarbonizing force, whether that’s simply putting the spotlight in America and showcasing why we are the number one leader in lowering emissions in the world, it’s because of natural gas. And also, I would say the other narrative we need to address is the fact that some people think that America is the largest producer of oil and gas, the regulations or pipeline blockages can’t be that bad. But I think the simple response to that position is yes, we might be the largest producer of oil and gas in the country. We are the largest exporter of LNG in the world. But the question that needs to be asked is, is that enough, we have got ramp of inflation, wars in Ukraine, global emissions still skyrocketing, energy poverty is growing, energy security is crippled. Clearly, the United States needs to do a whole heck of a lot more because the world can only contain so much chaos before it starts spilling over and impacting Americans. So, the world security is our security. And these are simple points that we can make. It is a little bit of a different perspective that people haven’t thought too much about. You lay that common sense approach underneath the framework from climate leaders around the world that recently gathered at COP and came out with a very simple punch list of what needs to happen. Transition fuels are going to be necessary to meet the climate ambitions that we have. That’s a fancy word for natural gas is going to play a role. Carbon capture is going to be a part of those solutions. And then I think also the recognition that solar and wind as great as they can be, they are not the complete solution, and you need a heavyweight solution, and that is natural gas to meet the goal. So, we have got cover from the environmental front, but it’s really just getting this common sense message out, and that’s where we spend a lot of time working the megaphone.

Operator:

Your next question comes from the line of Josh Silverstein with UBS. Please go ahead.

Toby Rice:

Yes. I would say at a very high level, I mean keys to success is to have a low-cost structure so that we can weather the storm. And that also is going to position us to be opportunistic to play some of the volatility. Operate – and I will let Jeremy expand on that a little bit. But operationally, one of the things that we have looked to build into our business is the ability to bring some surge capacity. So, understand whether that’s choke management and pension volumes back so we can respond to higher price environments or in some cases, just holding back some TILs and building some DUCs. I think having a flexible program is going to be something that’s needed. But that’s going to be more around the edges. Having a low cost structure is going to allow us to run consistent programs and be responsive, but not be completely whipsawed by the commodity price.

Josh Silverstein:

Thanks. My last question was just on hedges. You mentioned a lot in there, but it looks like you didn’t add anything for 2025. I definitely get the constructive outlook that you guys have. But clearly there is the factor of weather, which you have mentioned as well that we just don’t know how that will play out. Why not at least look to add in something for 2025 at this point, just to have a base level in there? It looks like you added something for second half or fourth quarter for this year below where the strip is next year. So, I thought that would be great. Thanks.

Josh Silverstein:

Thanks.

Paul Diamond:

Hi. Good morning. Thanks for taking my call. I just wanted to touch base real quickly on – you talked about LOE and some of the savings have been driven by water handling. I guess my question is how much more, I guess meat on the bone you think there is there? How much further do you think you can drive it lower?

Paul Diamond:

Understood. And then I have just kind of one final quick one. As the prop market sits right now on the curve, how should we think about kind of the operational cadence through the year with that 140 – or 110 to 140 TILs, should we think about that as pretty steady throughout the year, and more back half loaded, or how should we think about it as the market sits down?

Paul Diamond:

Understood. Thanks for your time.

Toby Rice:

Thank you everybody for your time. We are looking forward to executing for you in 2024. Thanks a lot.

Cameron Horwitz:

Good morning, and thank you, for joining our third quarter 2023 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer; and Jeremy Knop, Chief Financial Officer. In a moment, Toby and Jeremy will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. A replay of today's call will be available on our website beginning this evening. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of factors described in yesterday's earnings release and our investor presentation, the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today's call also contains certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

Jeremy Knop:

Thanks Toby, and good morning, everyone. I'll start by briefly summarizing our third quarter results, which as a reminder include 39 days of contribution from the Tug Hill and XcL assets. Sales volumes in the third quarter were 523 Bcfe comprised of 491 Bcf of natural gas and 5.2 million barrels of liquids. We note third quarter production volumes included roughly 5 Bcfe of curtailment principally in response to weak local demand and approximately 8 Bcfe associated with lower-than-expected non-operated turn-in lines and curtailments. On a per unit basis, adjusted operating revenues were $2.28 per Mcfe, and our total per unit operating costs were $1.29, down from $1.37 in the second quarter, reflecting the accretion benefit from a partial quarter contribution of Tug Hill's low-cost assets and lower-than-expected LOE due to increased produced water recycling. Capital expenditures excluding non-controlling interests were $445 million, including stand-alone EQT CapEx of approximately $400 million, which was at the low end of our guidance range, reflecting the continued operational efficiency gains Toby mentioned previously. Adjusted operating cash flow and free cash flow were $443 million and negative $2 million, respectively. It's worth noting, however, free cash flow was negatively impacted by $28 million of non-recurring expenses from the Tug Hill transaction without which we would have generated positive free cash flow during the quarter. Looking ahead to the fourth quarter, we provided guidance on Slide 33, which reflects a full quarter of contribution from Tug Hill and XcL Midstream acquisitions. It's worth highlighting that the midpoint of our GP&T guidance range of $1 per Mcfe is roughly $0.10 lower than our stand-alone GP&T in the second quarter, which underscores the cost structure accretion from the low breakeven Tug Hill and XcL assets. I'd also note our fourth quarter production outlook embeds expectations of curtailments in the first half of the quarter, given elevated Eastern storage and seasonal demand weakness. While we are still early in the budgeting process and working through the optimization of our development schedule for 2024, we preliminarily expect to run three rigs and three to four frac crews next year, which should allow us to maintain pro forma production at approximately 2.3 Tcfe. We anticipate free cash flow of roughly $1.7 billion next year at recent strip pricing of approximately $3.40 per MMBtu, which equates to a 2024 free cash flow yield of 10%. On a cumulative basis, we project nearly $14 billion of free cash flow from 2024 to 2028, which is roughly 60% of our enterprise value and 80% of equity market capitalization. This means at our current valuation, investors have the opportunity to buy the premier natural gas company in North America with the most scale, the deepest and highest quality inventory and among the lowest cost structures and the best credit rating at a material discount to peers. Turning to the balance sheet. Recall, we funded the cash consideration of the Tug Hill and XcL acquisition upon close in August with $1 billion of cash on hand and $1.25 billion of term loan borrowings. We exited the third quarter with $5.9 billion of total debt, including $400 million related to equity-light convertible notes, which equates to an LTM leverage of 2.1x, though we note this figure includes the full impact of financing the Tug Hill and XcL acquisitions with just 39 days of EBITDA contribution. For reference, excluding Tug Hill and XcL impacts, we estimate LTM net debt-to-EBITDA would have been approximately 1.25x at the end of the third quarter. Despite rising treasury yields, EQT's credit spreads have tightened, highlighting our strong credit profile. Recall, we were upgraded to Baa3 by Moody's shortly after we closed the Tug Hill acquisition, so we are now investment-grade across all three credit rating agencies. I will also note that EQT has the lowest five-year bond yields among natural gas-weighted peers, 100 basis points below the average, which also reflects the strength of our credit quality, an unwavering commitment to low leverage and our differentiated scale, inventory quality and low cost structure. As it relates to capital allocation, we remain pleased with the execution of our shareholder return framework to date, and we will continue with our opportunistic all-the-above strategy with our North Star being the countercyclical long-term compounding of cash flow. Consistent with our track record, we will maintain a strong bias towards debt repayment over the coming quarters, at least until we achieve our 1x leverage target at $2.75 per MMBtu natural gas pricing, which will provide a fortress balance sheet through all parts of the commodity cycle. This will, in turn, minimize downside risk to our enterprise while allowing us to limit the need to defensively hedge and cap what we anticipate being unpredictable asymmetric price movements to the upside in the years ahead. We also continue to rigorously assess new investment opportunities with strong risk-adjusted returns that improve the quality of our business, similar to our West Virginia water system we highlighted last quarter. With the XcL Midstream team now part of EQT, we are actively exploring opportunities to deploy capital into differentiated infrastructure investments that can debottleneck our upstream production, allow us to durably compound cash flow at very attractive rates of return with minimal risk while simultaneously improving our operational efficiency. Our share buyback program also remains a key tool for opportunistic execution at points in the cycle where we see favorable risk-reward potential for generating returns well in excess of our weighted average cost of capital. Recall, at our current share price, we have generated an approximate 40% return for shareholders on the roughly $600 million of share repurchases we have executed to date, which is the highest amongst our peer group, and we still have approximately $1.4 billion remaining under our existing authorization. And finally, sustainable long-term base dividend growth is a key pillar of our shareholder return strategy, and to this end, we recently raised our dividend by 5% to $0.63 per share on an annualized basis. Since initiating our dividend in late 2021, we have now increased it by more than 25% cumulatively over that period, which underscores our confidence in the sustainability of our business and a corporate free cash flow breakeven price that is amongst the lowest in North America. As we eliminate structural costs from the business through actions such as debt repayment, share repurchases and synergy capture, we expect to continue growing our base dividend over time without putting upward pressure on our corporate cost structure. Turning to the macro environment. We see several factors lending support to the natural gas market in 2024 and beyond. First, strong gas-fired power generation, resilient LNG export demand and lower-than-expected production this summer reduced expected storage overhang than many were forecasting back in the spring by over 300 Bcf. Second, while we do expect some incremental supply from associated gas in connection with new Permian pipeline capacity commencing in the fourth quarter, we see Lower 48 volumes exiting this year flat to slightly down compared to Q3 of 2023. And we see further declines in the first half of 2024 as the impact from a 25%-plus drop in gas rigs since March begins to set in, especially in the high decline Haynesville play where the rig count remains well below maintenance levels. Third, the progress demonstrated commissioning the Golden Pass and Plaquemines LNG facilities has been encouraging and will create structural tailwinds, allowing LNG demand to reach a record 15 Bcf per day even before the facilities are fully operational. Fourth, we expect natural gas power generation to continue taking away share from coal as the investment case for coal weakens further, with the market increasingly turning to cleaner burning natural gas. We expect coal production to drop by over 20% year-over-year in 2024 as the effect of the recent wave of coal retirement takes hold, and a tightening coal market will further support the natural gas fundamentals in the power sector moving forward, where total gas equivalent demand for coal still stands at 14 Bcf per day in the United States alone. Moving to hedging. We tactically added to our hedge position during the quarter to further derisk a portion of our expected free cash flow and debt repayment goals. We now have greater than 40% of our Q1 through Q3 2024 production hedged, inclusive of Tug Hill's volumes with a weighted average core price of approximately $3.60 per MMBtu and a weighted average ceiling of $4.10 per MMBtu. Note, our hedge position remains strategically tilted towards the first half of 2024, where we see the most potential downside risk should normal weather again not materialize. While protecting near-term cash flow and prioritizing our debt repayment goals, we are intentionally creating the flexibility to maintain maximum upside price exposure in late 2024, 2025 and beyond when the natural gas market looks increasingly tight and we see the potential for pricing to move asymmetrically higher. As it relates to basis, Appalachian differentials have been relatively wide of late, driven by elevated Eastern storage levels, a byproduct of the warm prior winter. Our strong basis hedge position paid dividends this quarter, boosting our corporate-wide realized natural gas price by $0.12 per MMBtu. We have roughly 80% of expected fourth quarter local volumes covered with basis hedges that are in the money relative to the current strip so we remain in an advantaged position near-term. Over the medium to long-term, we see several factors that could lend structural support to Appalachian bases, including the commencement of MVP and additional coal-fired power retirements in the PJM market, creating incremental demand upward of 4 Bcf per day. As it relates to MVP timing, we're encouraged by the recent Equitrans and PHMSA consent order and continue to model the first quarter of 2024 in-service date. The outlook for MVP increasingly derisks expansion projects to move production further into the Southeast U.S. are progressing. As Toby highlighted, EQT's scale, quality and depth of inventory, low cost structure and investment-grade balance sheet uniquely position us to help facilitate these expansion projects. This dynamic is underscored by the 1.2 Bcf per day of long-term firm sales agreements that we recently signed with investment-grade utilities in the Southeast region. These deals create a win-win outcome as they underpin the debottlenecking of downstream markets and directly link EQT's volumes to a market price at a meaningful premium to Henry Hub while simultaneously providing utility customers with surety of low-cost natural gas supply for decades to come. Upon commencement, we see these agreements and the associated debottlenecking projects improving our 2028 corporate-wide differentials by $0.18 per Mcf, which in turn should drive more than $300 million of annualized free cash flow uplift in 2028 and beyond. These deals provide EQT long-term supply growth optionality that is paired with sustainable utility demand, dynamics which could drive an even greater uplift to long-term free cash flow over time. Importantly, these contracts and debottleneckings occur around the same time our gathering rates with Equitrans complete the contractual step down from $0.80 today to $0.30 per Mcf in 2028, further accelerating the decline in our free cash flow breakeven price and supercharging the free cash flow growth at a time when we expect other gas plays like the Haynesville to be approaching inventory depletion, thus driving up the marginal cost of natural gas. Quite simply, the difference between a higher marginal cost of natural gas experienced by peers compared to EQT's declining cost structure should uniquely accrue to EQT's shareholders in the form of free cash flow growth and value creation. These firm sales agreements represent examples of the various differentiated opportunities we are seeing arise from EQT's gravity and momentum as the clear operator of choice for the highest-quality long-duration inventory in the North American natural gas market. And we believe these opportunities will ultimately allow us to continue to create differentiated shareholder value relative to peers in the years ahead. Importantly, these types of opportunities are not simply due to scale but underpinned by EQT's world-class assets, coupled with a culture and teams that are relentless in their pursuit of excellence as the operator of choice and driven to maximize value for shareholders. I'll close by highlighting Slide 12 of our investor presentation, which illustrates an internal analysis of the natural gas price required to generate sufficient free cash flow such that a gas producer generates a simple 10% return on current respective enterprise value, what we view to be the most basic tenet of shareholder value creation. We believe the days of wellhead IRRs driving activity levels amongst U.S. gas producers are in the rearview mirror as this behavior related to the destruction of hundreds of billions of dollars of capital in the last decade. Put very simply, wellhead IRRs on D&C CapEx are unrelated to corporate returns and cost of capital. Instead, we see the marginal cost of U.S. natural gas supply beholden to a fully burdened corporate cost curve that requires a sufficient return on corporate capital or enterprise value, not just a return on field level CapEx. I want to highlight a few observations from this slide. First, the marginal molecule of U.S. gas supply is coming from the Haynesville, requiring a natural gas price of approximately $3.50 per MMBtu to even begin generating cash flow in maintenance mode, meaning below this price, no shareholder value is being created and inventory optionality is being depleted. On the other hand, EQT is at the low end of the cost of supply curve, which translates to structurally more durable through-the-cycle free cash flow generation and returns for our shareholders and also less need to defensively hedge away gas price upside. Further, we see the price required to generate corporate return for Haynesville producers already at north of $4 per MMBtu based on current market valuations. On the other hand, EQT shares are pricing in a level embedding a mid-$3 gap price, providing a superior entry point to gain exposure to natural gas prices and in a superior risk-adjusted manner due to EQT's lower cost of supply. As previously noted, our contractual gathering rate improvement, unrivaled depth of repeatable low-cost inventory and new firm sales agreements will drive EQT's cost of supply even lower over the next five years in contrast to the rest of the industry, which will likely see upward pressure over this period as peer producers move toward lower-quality inventory. As a result, we believe EQT is uniquely positioned to capture a disproportionate amount of natural gas price upside relative to peers in the years ahead. I'll now turn the call back over to Toby for some concluding remarks.

Operator:

Thank you. [Operator Instructions] Your first question comes from the line of Umang Choudhary with Goldman Sachs. Please go ahead.

Toby Rice:

Hi, Umang. This is Toby. Let me just put some broader color on what's happening in the United States, and then I'll kick it over to Jeremy for more of the details. Over the last 10 years, we've seen natural gas demand grow about 50% in this country. During that period of time, the pipeline capacity that's been built has only grown about 25%. And so it shows the drive from a need for more pipeline infrastructure that would lead to opportunities like this going forward. Jeremy, do you want to cover some of the more detailed points about this transaction, how it came together?

Umang Choudhary:

Great. And is there any further opportunities of such nature which you foresee in the future? And also, if you can help us quantify the risk around that free cash flow uplift of $300 million. Do you see any scenarios where that $300 million will not come through for EQT?

Umang Choudhary:

That’s very helpful. Thank you.

John Abbott:

Good morning, and thank you for taking our questions. Toby, there's been a lot of press speculation recently about further industry consolidation even between gas companies. How do you think about industry consolidation from here and how do you see EQT's potential role in that?

John Abbott:

Appreciate that. And then for our follow-up question, appreciate the free cash flow guidance that you sort of provided right there. But when you think about spending, I mean, you haven't put out your budget, but when you think about long-term, true long-term maintenance CapEx without taking into account potential debottlenecking opportunities, how do you think of that at this point in time from a spend perspective to hold maybe 2.3 Tcfe flat?

John Abbott:

Very, very helpful. Thank you for taking our questions.

Arun Jayaram:

Yes. Good morning. Toby, the crown jewel of the Tug Hill deal was the XcL Midstream system. I wanted to get your thoughts on value creation opportunities from integrating the midstream further in terms of internal and third-party opportunities. Obviously, it is going to help your cost structure as you highlighted as well.

Arun Jayaram:

Great. And just maybe a follow-up on the 2024 outlook where you've highlighted $1.7 billion of free cash flow potential. It sounds like CapEx will be in the low $2 billion range. Can you give us a sense on your thoughts on differentials for next year?

Arun Jayaram:

Great. Thanks a lot.

Nitin Kumar:

Hi. Good morning guys, and thanks for taking my questions. I kind of want to start on this new firm sales contract. I think, Jeremy, you mentioned that there's an impact of about $100 million to $200 million near-term. Could you help us bridge the gap of what is driving that? I understand that the longer-term benefit comes from better pricing. What's the restructuring of the AMA costing you?

Nitin Kumar:

Got it. That makes sense. And then just maybe a quick question around service costs. You mentioned the low $2 billion type of CapEx number for next year. If you could maybe help us peel the onion a little bit around assumptions around deflation. You talked about pretty material capital savings from operating efficiencies on Tug Hill, $150 per foot. How much of that is baked in or what are your thoughts on the service cost environment right now?

Nitin Kumar:

Okay. Thanks guys.

David Deckelbaum:

Hey guys. Thanks for the questions. I wanted to ask just that you provided the 2024 outlook. I assume that at this point, it sounds like that's the original budget of the $1.7 billion base for EQT and then $300 million-plus or so for Tug Hill. So it doesn't seem like you're incorporating any of the benefits that you're seeing so far of improvements, especially on the Tug Hill side?

David Deckelbaum:

Well, maybe like if you could expand on that a bit because I think that's helpful. As we think about improvements into the business from an efficiency standpoint into 2025, could you sort of quantify some of like the maybe front-loaded opportunistic investments around infrastructure and lands that would be in 2024? Does that extend through 2025, 2026? Is this a multi-year integration and investment process? Or is this more of an upfront 2024 situation?

David Deckelbaum:

Appreciate it. If I could sneak in the housekeeping one. Is there a meaningful shift in your deferred tax assumptions for next year, cash tax as a percentage of overall burden?

David Deckelbaum:

Appreciate a little help. Thank you guys.

Michael Scialla:

Good morning, everybody. Wanted to see, you talked about the potential for the $150 per foot of savings with the operational efficiencies that you're applying to the Tug Hill assets, what needs to happen for that to become a reality? And I guess where are those relative costs based on the wells completed there so far?

Michael Scialla:

That's helpful. Thank you. And I wanted to ask about the – your agreements with the LNG. In terms of – any comments there on the discussions you're having with potential end users of LNG? And would any agreement there be contingent on converting your HOAs to binding agreements? Sort of what's the process that needs to play out there?

Michael Scialla:

Thank you, guys.

Kevin MacCurdy:

Hey, good morning. The firm sales contracts you locked in starting in 2027 are very impressive. With those margins derisked, do you have any plans to grow into the volumes? And is that baked into your 2024 to 2028 free cash flow outlook?

Kevin MacCurdy:

Got it. So it's not baked into that outlook at this time, the 60% free cash flow of BV?

Kevin MacCurdy:

Great. And then you mentioned the $0.55 of NYMEX for 2024. I just wanted to get a little bit more clarity on whether that included basis hedges and any Btu uplift?

Kevin MacCurdy:

Great. Thank you.

Jean Ann Salisbury:

Hi. Good morning. I just – on the 2 MPA of HOAs, do you have an ideal share of portfolio linked to global gas prices? And what's kind of your thinking that underpins that ideal share if you do?

Jean Ann Salisbury:

Great. That's all for me. Thanks.

Paul Diamond:

Good morning and thanks for taking my call. Just a quick one. You guys talked about the kind of that theoretical max is 500 days versus the average of about 400 currently. I just wanted to see if you guys could put a little bit of clarity around, I guess, how you see bridging that gap. Like how close can you get to the 600 and over what timeframe?

Paul Diamond:

Understood. Thank you. And just one quick follow-up. You guys talked about the incorporation of MVP and coal retirements producing about 4 Bcf of incremental demand out of Appalachia. Just want to see if you could give a bit of clarity around the timing of that. Is that over the next one year, five years? Just how do you see that kind of developing?

Paul Diamond:

Understood. That's all for me. Thanks for your time.

Noel Parks:

Hi. Good morning.

Noel Parks:

One question I had was as you have put together some of these longer-term forecasts and projections, and when you make the infrastructure piece, some of the trends look really compelling. As you look at different pricing scenarios, do you picture, and this, of course, would be a high class problem. Do you picture a gas price high enough where a plausible feeder kind of gets reintroduced of the industry overdrilling again? I mean, I know is that sustained $6, $7 or something like that?

Jeremy Knop:

I'd say another interesting caveat to that, that's really important to remember. I think a lot of people like to talk in terms of averages when talking about future gas prices or commodity prices. In our view, I think what's going to change a bit in the character of the gas market going forward is in a world where there's less coal to switch to, you have renewable intermittency, you have your days of demand covered dwindling for gas. You're going to see a lot more volatility. And so instead of a clear price signal, so to speak, of $5 or $6, as you suggested, which would give you confidence to drill and grow, I think you might see a year where gas is really high and another year where gas is really low. That will average out to an attractive price to the middle, but it does create a lot of volatility. And I think from a planning perspective for companies that are just pure upstream producers, it creates a lot more pause before saying we want to go invest an extra $1 billion in drilling in a given year. And I think that if you want to look at a case study of that, you can see what happened in the past 12 months where that really seemed to be all the rage in 2022 of prices were high single digits. And all it took were a couple of events and prices fell as low as $2. Now you're seeing the Haynesville start to really decline. So I think when you look ahead, I think that's an important differentiation. But I think the net effect is you're going to see some air gaps emerge of oversupply and undersupply. And that really underpins our focus on cost structure because we don't want to be one of those producers that has to decline and has to ramp back up. We'd love to be able to really produce durable cash flow and return for investors through the cycle. And again, if you're worried about prices one year falling to $2 like we just saw this year and you have to hedge that but then you missed prices going back up materially higher, over the long run, you're not going to generate nearly as much value. So again, that outlook is really informing how we scope the business, whether it's through just organic cost cutting, it's our hedging strategy, our balance sheet, how we think about future M&A. But that characteristic, I think, is an important caveat and it will be a lot different in the next five years compared to the prior five years.

Toby Rice:

Well, I think what you are seeing is energy security coming back into the headlines in the American grid. And when you look at a lot of the power generation capacity that's been added, over the last five years, a lot of it has come from intermittent, albeit lower carbon energy solutions like wind and solar. And people are now stepping back and saying, do we have the reliability that we need? And you see this across all ISOs across the country where your peak demand number is coming very close to your reliable electricity generation. While you may have coverage from intermittent sources above that, you realize that when that peak demand hits and you're pushing them, your red lining, your reliable electricity power generation, you're on your knees praying for the wind to blow and the sun to shine. And I think people are looking at this now and looking for more energy security and realizing that low carbon energy solutions like natural gas are going to be the solution that the world needs.

Operator:

Thank you. Your final question comes from the line of Bert Donnes with Truist. Please go ahead.

Toby Rice:

Well, I think it's just prudent as an investor to think about protecting against the downside while also providing exposure to what we think is going to be a really exciting natural gas market. So I think one thing that's going to be the alternative is, and we can play that with – by hedging and caring about the floors and also caring about the ceilings we're putting in our business, we can do that with some of the supply deals, we structure delivering floors that cover our cost of capital, allow us to generate the returns that our investors are demanding while also providing ceilings that prevent customers from experiencing price blowouts. And at the end of the day, the integrated energy producer like EQT that has control over the cost to pull the gas out of the ground, the contracts to move it through the pipeline and get it through the tailpipe of LNG facility, we can offer pricing that ensures us to be able to generate returns but also gives the world what it really needs, which is guardrails on pricing. And that is – that will give them the energy security that ultimately is so desperately needed right now. So again, we think customers that are looking to play the spot market with this volatility, it's going to get pretty exciting. And I think we can take away some of the volatility and still generates pretty great returns and create some really great win-win scenarios for customers.

Bertrand Donnes:

Those are a lot of great points. Thanks, guys. And then maybe shifting gears a little bit. It looks like you're drilling slightly shorter laterals in 4Q versus 3Q, but you're still completing or turning in line maybe some longer laterals. So could you talk if there's a strategy shift there or if that's just a quarterly blip and you're still targeting longer laterals?

Bertrand Donnes:

That's perfect. Thanks, guys.

Toby Rice:

Thanks, Eric. This quarter marks another quarter where we've demonstrated some pretty meaningful steps to make the energy we produce at EQT cheaper, more reliable and cleaner for the world and also create value for shareholders. What was really great to see this quarter is really talking about how the differentiating aspects of our business, our low-cost structure, our scale, our deep inventory and environmental attributes are actually creating value and creating opportunities for our business that we are optimistic will present some really attractive investment opportunities for us in the future, and we look forward to keeping you guys updated along the way.

Cameron Horwitz:

Good morning, and thank you for joining our second quarter 2023 results conference call. With me today are Toby Rice, President and Chief Executive Officer; Jeremy Knop, newly appointed Chief Financial Officer; and David Khani, outgoing Chief Financial Officer. In a moment, the team will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. A replay for today's call will be available on our website beginning this evening. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of factors described in yesterday's earnings release and our investor presentation, the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

David Khani:

Thanks, Toby. It's bittersweet to be on my final conference call after three and half amazing years at EQT and over 30 years on Wall Street and in the corporate world. I'm honored to have left my mark on this company, and I feel a deep sense of pride in all that we have accomplished in a relatively short period of time. Since I joined in January of 2020, the stock is essentially quadrupled. We regained investment-grade credit status and EQT was added to the S&P 500 Index. Even with this, EQT is truly a unique organization on a trajectory that I believe will create tremendous value for years to come, which is why I'm excited to remain a long-term shareholder in this company. I'm also thrilled to see Jeremy appointed as EQT's next CFO. I've seen his exceptional execution capabilities first hand, and I'm extremely confident he is the right person for the job. Jeremy and I have worked closely together on many aspects of the business, including financial policy, capital allocation and hedging, which will ensure strategic continuity and a smooth transition of the role. With that, I'd like to say one final thank you to all our stakeholders for your support. And I'll now turn the call over to Jeremy.

Toby Rice:

Thanks, Jeremy. To conclude today's prepared remarks, I want to reiterate a few key points. Number one, EQT's operational execution has been on point in 2023 with our drilling and completion teams, setting multiple internal and world records during the quarter. Number two, we continue to successfully implement our value-oriented capital returns framework with an incremental $800 million of debt retired in Q2, taking our cumulative debt retirement to more than $1.9 billion since late 2021. Number three, our recent HOA for tolling capacity at Lake Charles represents an initial step in progressing our LNG strategy, which seeks to diversify a portion of our production into international markets and achieve the best combination of upside exposure with downside risk mitigation. And four, we strategically added to our 2024 hedge position which ensures the accelerated achievement of our debt retirement goals while simultaneously providing shareholders maximum upside exposure to gas prices in late 2024, 2025 and beyond. And lastly, number five, our 2022 ESG report underscores our peer-leading environmental performance with a 20% year-over-year decline in EQT's production segment Scope 1 and 2 greenhouse gas emissions, moving us yet another step closer toward the realization of our ambitious 2025 net zero emissions goal. I'd now like to open the call to questions.

Umang Choudhary:

Thank you. And best of luck, Dave, and hope to stay in touch. My first question was around your plans of around improving your free cash flow breakeven. I wanted to get your thoughts on capital efficiency improvement heading into 2024, given you recently – given you highlighted drilling completion efficiency gains and a 5% reduction from deflation. Also if there's any update on the next-gen well design, which you talked about early in the year?

Umang Choudhary:

Got you. That's very helpful. And my next question was on LNG strategy. You've obviously taken the first step towards executing your strategy by signing the HOA agreement with Lake Charles, any update on what the end customers are looking for? Any color on the price exposure, which they're willing to take and their willingness to sign collar contracts?

Umang Choudhary:

Thank you.

Devin McDermott:

Hey. Good morning. Thanks for taking my question. And Dave, congrats again on the retirement. So my first one is just on Tug Hill and Toby, I'm not sure how much more you can say, but I was wondering if you could talk a little bit about just the high-level dialogue with the FTC, the reason for the slight delay here and what gives you confidence in the ability to close this deal here in 3Q?

Devin McDermott:

Okay. Great. And then separately, on MVP, that disclosure on it being roughly cash flow neutral is helpful. But I was wondering if you could elaborate a bit just on some of the moving pieces there. I know you've taken some cash payments upfront for the scheduled rate relief that comes along with that pipe entering service. What's the net remaining rate relief? And how should we think about the impact of that piece over the next few years?

Devin McDermott:

Great. Thank you.

Bertrand Donnes:

Hey. Good morning guys. Just one of your peers have taken the approach that LNG exports will be about 15% to 20% of U.S. volumes, so they want to keep their contribution in that range. I just want to see if that matched kind of your internal strategy or does the tolling agreement if you have maybe let you pivot more easily and so you maybe could go above that percentage.

Bertrand Donnes:

Got you. And then my follow-up on the same topic is just kind of two smaller points. Does your ability to increase your capacity to the Gulf Coast have any impact on maybe the pace of additional LNG deals? And then the second part of that is just with a 15-year term on your side, did you want to match the end users agreements to that duration? Or do you maybe want to do five years here and there and add up to that 15 years? Thanks, guys.

Bertrand Donnes:

Sounds good. I appreciate it.

Arun Jayaram:

Yes. Good morning. Toby, I wanted to get a follow-up on your comments on your expectation that you could close the deal with Tug Hill in the next 30 days I mean, do you contemplate any changes to the original agreement. And so I just wanted a sense is if you close in 30 days, do you expect it to be consistent with the original terms signed with Tug Hill.

Arun Jayaram:

Great. My follow-up, Toby, you started the call talking about a lot of efficiency gains on the drilling and completion side. And then obviously, you have the MACH3 program, which is underway, excluding any kind of impacts from service cost tailwinds next year, how should we be thinking about capital efficiency of next year's program, just given some of the benefits, efficiency gains that you highlighted this morning.

Arun Jayaram:

Great. And I also want to pass on my regards to Dave, good luck in retirement. Great working with you over these years.

Operator:

Your next question is from John Abbott of Bank of America. Please go ahead, your line is open.

Toby Rice:

Well, I think what's special about West Virginia is the terrain and logistics become very important. And so to solve logistics constraints, investing in infrastructure is the solution. And so you've seen the benefit from the water infrastructure investment that we've done in West Virginia, that will continue, and we've identified a synergy with the Tug Hill acquisition to combine the Tug Hill water system with our system that not only is going to expand our produced water network, but also freshwater delivery. So we're excited about continuing with the progress on the water side.

Jeremy Knop:

John, I think just to add to that from more of a financial perspective too, if you look at that water system we built out, we spent about $80 million doing that. And today, that's generating savings of about $20 million a year. So think about that as like a 25% free cash flow yield. And that's something that – it's not like a well that declines, it's durable. It's got longevity to it for the next 10 to 15 years. Some of the other projects we've looked at recently, one of which we highlighted when we announced that Tug Hill acquisition, was additional pipeline connectivity throughout the basin. We're seeing similar sorts of returns on those projects at kind of a mid-20% free cash flow yield. The more projects like that we can find to reinvest capital into the more value we think we can create both through reinvesting and compounding but also just improving the base quality of the business. So it's something we're focused on. We've got the operational teams looking around trying to find more opportunities to reinvest cash flow like that. But I mean, those are two examples just to make it a little more tangible.

Toby Rice:

Yes, certainly, out of the gate until some of the downstream expansion projects are completed that really create more of that demand pull at that delivered market. We just plan to reallocate volumes that are currently being sold in basin to that MVP capacity. Where the basin sits today, and I think 2023 is a good example where in-basin storage is about 100 Bcf a day above – not per day, 100 Bcf above normal. There's not a lot of headroom, we think MVP coming online. We'll take some of that froth out of storage and balance the market a little bit more. If additional infrastructure is built, we would love the opportunity to grow into it. But where we sit today, it's hard to see that being in the next one to two years.

Operator:

Your next question is from Scott Hanold of RBC Capital Markets. Please go ahead, your line is open.

Toby Rice:

Scott, at this time, I think we'd just like to stay focused on getting the deal done with the FTC, and we'll look forward to updating you guys on path forward after we get through this.

Jeremy Knop:

Yes. So let me answer it this way. Getting these deals in place is a multi-step process. Signing the HOA is the first step in that. As we look forward to the next steps it comes down to getting a binding agreement in place based on those HOA terms. And then following up on that with that sales and purchase agreement, a collar structure is what comes into play as part of that sales and purchase agreement. So it's a little premature to give too much clarity around that at the time. But you're right that, that is still our intention.

Operator:

Your next question is from Michael Scialla of Stephens. Please go ahead. Your line is open.

Jeremy Knop:

Yes. So there's a couple of dynamics at play. And when we look at the market going forward, we try to get a sense for – well, it's hard to predict price exactly. We try to get a sense for where the SKU is. And so when you look at where storage is today heading into this winter in the first half of 2024, we feel like there's pretty equal upside, downside SKU. And so that's why you've seen us lean a little bit more into swaps, even though it's something we're generally trying to deemphasize in the past. Unless we see strong cost SKU in the options market, it's hard to feel good about leaning into those. But really near-term because that we would like to derisk our debt repayment goals and so as we get towards the back half of 2024 and into 2025, where that upside is just so much more asymmetrically skewed, but is not yet reflected in the options market or in the future strip. We want to remain patient there and hedging more near-term allows us to do that. So look, it doesn't mean we're not going to hedge 2025 at some point, but we think where the market sits today, it's far off from where really it should be. And as you think about how the market might trade as you get into 2024, I think most market participants and analysts see that how 2025, 2026 market is getting especially tight as you see that demand ramp for at least – ramp in nameplate capacity of LNG, but the market obviously trades the season ahead. And so I think as you get towards next summer, and the market starts looking at winter 2024, 2025 and a lot of that demand ramp, unless you have a step change really increase in production at the same time. I think the market will look increasingly tight, and that will probably start getting reflected next summer and probably a much more asymmetric way. And so I think we're trying to be patient at this point in time and not be in a position where we need to really defensively hedge and take away that upside, which is what I think a lot of our investors are looking for in the market today.

Toby Rice:

Yes. Operational cadence for EQT assets will remain the same. Our plan with Tug assets to continue to maintain activity levels. I think the high-grade opportunities would probably start seeing those, hit the schedule maybe 12 months just take some time for us to set those wheels in motion. But pretty much in summary, similar plans for the first 12 months and then you could start seeing us optimize the asset base.

Operator:

Your next question is from Josh Silverstein of UBS. Please go ahead. Your line is open.

Toby Rice:

Yes, Josh, we've always looked at investing in LNG facilities does the world need it to do that right now? It seems like these projects are getting going, what the world needs is EQT supply, so we're participating in that front. So our price here is really getting exposure to international markets. If we can do anything on the East Coast, that would give us exposure to sustainable growth opportunities. That's the real value for us. So we're not looking to make investments in LNG, but there could be opportunities where from a risk mitigation perspective, it could make sense for us to make a small investment in LNG facility, but that's sort of how we're viewing it right now.

Toby Rice:

No. I think just when we looked at several facilities early on, we weren't sure if we needed to make an equity investment to get international pricing and after a lot of discussions, we found that we really don't need to do that.

Jeremy Knop:

Yes. So you're right that really while this deal has been pending, our focus has been to be opportunistic tactically, but really accumulate cash ahead of closing. So until closing happens, I think you can expect us to continue doing the same thing. After the acquisition closes, I think you should really expect, until we meet our debt targets, to really pursue the same strategy, which is weighted towards debt repayment. And then tactically, when we see dislocations in the market lean into that buyback. But I think the concept of a formulaic programmatic buyback. It's just a long-term strategy. It's something you'll see us probably shy away from at least near-term. I think we like to be more tactical in how we approach that, especially in an industry that is inherently always cyclical, both from a macro standpoint and even a weather-driven standpoint. We think there'll be continued opportunities to create outsized value for patients just like we've done to date.

Operator:

Your next question is from Paul Diamond of Citi. Please go ahead. Your line is open.

Toby Rice:

Yes. The goal for us is to raise the bar. These records show what could happen and the potential we have and the goal for the operating teams is to move that average performance up to peak performance. So that's the game that we're playing and we're removing any bottlenecks to achieving that peak performance along the way. Our attitude is that peers have the ability to keep up with us. And this is the fire that keeps us continuing to evolve and look for ways to continue raising the bar. So we're proud of where we're at, but we're always looking to get better. And that's really – I'd say one of the defining characteristics of our culture is just our ability and the drive to continually evolve our business.

Operator:

Your next question is from Jeoffrey Lambujon of TPH. Please go ahead. Your line is open.

Jeremy Knop:

Yes. So that $0.15 that we talked about associated with the deal. That's all pre-synergies. This kind of as a rule of thumb. We don't like to include synergies and just our base guidance. So think when we announced Tug Hill, we were talking about $80 million a year of total synergies. We haven't been able to refine that just due to some gun jumping laws around just this FTC process. But that's all incremental upside to the guidance we've given, that $0.15 and even that rate of return that we talked about on that existing West Virginia water system we already built.

Jeremy Knop:

Yes. We see most of those projects as more demand pull back rather than supply push. So we don't anticipate needing to take out contracted capacity, but those are important for just the long-term development of that station 165 market.

Operator:

Your next question is from Noel Parks of Tuohy Brothers. Please go ahead. Your line is open.

Toby Rice:

It is about $28 million. And when you think about it, normalize on a dollar per ton, it's less than $10 per ton to achieve the emissions reductions.

Toby Rice:

I don't think there's any elements that are unique here that stand out. I think this is just part of the process to review the deal and concept. I mean, I'd just remind everybody when the FTC issued their second request to us who was back in November. And I think if you just remember what the gas market was like, there was a lot of concerns over a natural gas, what was happening with Europe and peak fear on gas shortages. So I think we took the opportunity to take a closer look, and that's the process that we're going through and are happy that we're in a place where we're confident in getting this in close within the next 30 days.

Operator:

Your next question is from John Daniel of Daniel Energy Partners. Please go ahead. Your line is open.

Toby Rice:

Well, I think on the internal side, I mean look at the setup we're delivering to the operations teams, I mean, large-scale, long lateral combo development certainly sets the teams up to knock it out of the park. And that definitely would be considered an internal improved thing that we do that is going to be hard to replicate with other asset bases. But you got to go out there and you got to execute and the teams are doing that. We have very close relationships with our service providers. I think on this run here, there's been a lot of improvements on bit design that the teams have worked with our service providers. So really close relationship and our success is really going to be based on the success of our partnerships, and we've got some great partners on the drilling front and across the operational spectrum. So I'd say probably half of it is internal, and the other half is the great working relationship we have with our service providers.

Toby Rice:

Yes. I mean when I step back and you look at the – I mean we've sort of gotten past the step change in operational efficiencies. It's more of a slow grind and the factors that are ultimately going to be defining the success of the operation, we sort of pushed past just what specifically we're doing on site at that operation, and it's really external factors that are really influencing things like do we have long laterals ready to drill. What's the land situation look like? And on the completion side, what's the logistics on water and sand. So it's as much as the system that we're creating as it is the actual individual performance. And I think industry has already made the move to recognize that long laterals are the key and how much of that they have and the quality of inventory, I think, is going to be defining characteristics on their efficiency going forward.

Operator:

There are no further questions at this time. I will now turn the call over to Toby Rice for closing remarks.

Operator:

This concludes today's conference call. Thank you for your participation. You may now disconnect.

Cameron Horwitz:

Good morning, and thank you for joining our first quarter 2023 results conference call. With me today are Toby Rice, President and Chief Executive Officer; and David Khani, Chief Financial Officer. The replay for today's call will be available on our website beginning this evening. In a moment, Toby and Dave will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday's earnings release and our investor presentation, in the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

David Khani:

Thanks, Toby, and good morning, everyone. I'll briefly summarize our first quarter results before discussing our balance sheet, the macro landscape, hedging, 2023 guidance and use of our free cash flow. Sales volumes for the first quarter were 459 Bcfe or 2% above the midpoint of our guidance range. Our per unit adjusted operating revenues were $4.11 per Mcfe and our total per unit operating costs were $1.34, resulting in an operating margin of $2.70 per Mcfe. Capital expenditures, excluding noncontrolling interests were $464 million or 7% below the midpoint of our guidance range as operational efficiencies exceeded expectations. Adjusted operating cash flow and free cash flow were $1.24 billion and $774 million, respectively. We also had a $426 million working capital tailwind during the quarter, largely driven by declining accounts receivable from decreasing prices with a further tailwind expected in Q2 and Q3. Our capital efficiency for the quarter came in at $1.01 per Mcfe, which was approximately 10% better than what was implied by the midpoint of our guidance ranges, driven by outperformance on both production and capital spending. Note that as we complete the excess pills that were shifted from last year, our second half capital efficiency should improve by double digits relative to the first half. Turning to the balance sheet. Our strong credit profile and ample liquidity remain a core tenet, underpinning our operating philosophy and will provide differentiated value for opportunities for EQT moving forward. Our balance sheet position continued improving with trailing 12-month net leverage exiting the quarter at 0.9x, down from 1.2x last quarter and 1.9x a year ago. We exited the first quarter with $3.3 billion of net debt and $2.1 billion of cash on hand, inclusive of the $1 billion in proceeds from our notes offering. This week, we extended our $1.25 billion term loan to the end of 2023, which aligns with the timing of the amended purchase agreement and provides timing flexibility. The bank term loan, along with our cash balance, gives us the flexibility and confidence to fund the cash portion of the Tug Hill deal independent of any bond proceeds that we raised last fall. As Toby mentioned, we continue to actively progress our debt retirement initiatives. We retired 210 million of senior notes principal in the first quarter primarily via open market purchases at an average price of 96% of par. Since unveiling our capital returns framework, we have retired more than $1.1 billion of debt principal, which has eliminated nearly $40 million of annual interest expense. Our commitment to a bullet-proof balance sheet is being recognized by the credit rating agencies. S&P and Fitch reaffirmed our investment-grade credit ratings over the past several weeks with stable outlooks at both agencies, even as natural gas prices have temporarily receded as we further execute our objective of achieving $3.5 billion of gross debt pro forma for the pending Tug Hill acquisition, we believe additional credit rating upgrades are possible. I'd like to also briefly highlight Slide 10 of our investor presentation, which shows our track record of materially growing our asset base while lowering our net debt. At year-end '19, our net debt was $5.3 billion. Our proved reserves were 17.5 Tcfe our production -- net production was 4.1 Bcfe per day. Fast forward to 2022, -- we increased our proved reserves to 25 Tcfe and our production to 5.3 Bcfe per day through the Chevron and Alta acquisitions and organic reserve growth. All while decreasing our net debt to $3.3 billion through the end of the first quarter. Said another way, we have grown our asset base by 30% to 40%, while simultaneously lowering our net debt by a comparable percentage over the 3 years and our plan for additional debt reduction post closing the Tug Hill acquisition should more acutely highlight this track record. Turning to a few brief thoughts on the gas macro landscape. The combination of warm winter weather and the Freeport outage left roughly 400 Bcf of excess natural gas in storage this winter. The market is in process of rationing this excess gas with the balancing items likely to be split between low production and increased gas-fired power demand. On the former, declines in gas directed activity has accelerated as of late with pricing falling well below many producer breakevens across the U.S., and we believe additional gas-directed activity declines in the coming months to moderate the pace of storage injections by roughly 200 Bcf. As it relates to power generation, over 7,000 megawatts of U.S. coal generation is set to be retired in 2023 and we are seeing gas take further share from coal in the power stack to the tune of roughly 2 Bcf per day this year. With the average cost of coal rising materially in 2022, the coal to natural gas switching floor has increased by 50% or more and we believe this is a structural shift given the massive underinvestment in coal capacity. There are several avenues of upside potential that could drive additional market timing above our current base case expectation, including higher sustained LNG exports, greater industrial demand, and reduce imports from Canada, given a tight Canadian storage market. We expect continued volatility in natural gas prices as gas and coal activity moderates and storage overall is an inadequate buffer relative to peak demand. Moving to hedging. Our 2023 hedge book underscores our evolved hedging philosophy that seeks to provide investors with the best risk-adjusted exposure to natural gas prices. We have 62% of our 2023 production covered with floors at an average weighted price of $3.38 per MMBtu, which provides significant cash flow protection and downside pricing scenarios while maintaining upside exposure. We also have 10% of our 24 volumes hedged at a weighted average floor price of $4.20 per MMBtu and a weighted average ceiling of $5.40 per MMB2. Given our expectation of improving natural gas macro fundamentals as the year progresses, we will opportunistically look to add to our 2024 hedge position at the appropriate time. As it relates to basis, we are seeing a material benefit from our expanded firm transportation portfolio. which was reflected in our first quarter differential coming in at a $0.16 premium to NYMEX as we captured favorable pricing spreads during the quarter. We continue to expect additional opportunities to expand our FT position as other Appalachian operators release existing firm transportation capacity. As it relates to MVP, Slide 8 of our investor presentation illustrates the project's impact on EQT's cumulative free cash flow. While the benefit of MVP is interlated with the spread between NYMEX and local Appalachian prices, the current future strips suggest MVP has an immaterial impact on our cumulative free cash flow as higher price realizations are largely offset by higher transportation expense. That said, we continue to be staunch supporters of the MVP as the project is necessary to ensure energy security for the Southeastern region of the United States while achieving its carbon reduction goals via the phaseout of coal-fired generation. We were encouraged to see Energy Secretary Grand Home show of support for MVP and broader energy infrastructure this week with notable comments on how these projects will deliver dependable energy to Americans while supporting the reliability of the electric grid. For reference, our model assumes MVP starts up in the second half of 2024 and and we will adjust assumptions if needed. Importantly, gathering rates contractually begin declining in 2025 independent of MVP success, providing a further tailwind to to free cash flow as margins widened by $0.15 from current levels, adding approximately $300 million of annual pretax free cash flow by 2028. Turning to guidance. We are reading our 2023 production outlook of 1.9 to 2 Tcfe. This range provides significant flexibility to respond to evolving macro conditions with the low end of our production guidance of product's potential outcome of moderating activity should natural gas prices continue to decline. We are currently running 2 operating horizontal rigs and thus not contemplating reducing rig activity. but we have flexibility around our completion cadence as well as our choke management program. We are also reiterating our 2023 capital budget of $1.7 billion to $1.9 billion, excluding the pending Tug Hill acquisition, which embeds 10% to 15% year-over-year oil field service inflation. As it relates to leading edge inflation trends, we are experiencing a flattening out of steel costs and starting to see long-haul logistics prices softening. We believe this is a signaling of some degree of price relief on local logistics such as sand and water hauling and could enable further completion efficiencies. While still too early to predict with precision, we believe this backdrop could set up for some degree of net price relief for EQT by the fall and upside potential to our free cash flow outlook later in 2023 and into 2024. As a reminder, $100-plus million of our budget is associated with turning in line wells that slipped from 2022 into 2023 due to third-party constraints and thus is not anticipated to carry forward into future periods. This dynamic, along with the shallowing of our base PDP decline is anticipated to drive 5% to 10% improvement in our capital efficiency in 2024 and beyond, independent of any oil field service cost relief. Our per unit operating expense range is 2% per Mcfe lower at the midpoint driven by lower production taxes and G&A. We're also lowering the range of our average differential forecast for the year to negative $0.35 to negative $0.60 per Mcfe, driven by narrowing local basis and the benefits from our firm transportation portfolio. On Slide 32 of our investor deck, we provide adjusted EBITDA, operating cash flow and free cash flow outlooks at various natural gas prices for the remainder of 2023. At recent strip pricing, 2023 adjusted EBITDA is expected to be approximately $2.9 billion and 2023 free cash flow is anticipated to be roughly $1 billion implying a free cash flow yield of 9% at the bottom part of the cycle. As it relates to cash taxes, we continue to expect our remaining federal NOLs to offset the bulk of our 2023 taxes. Our 2024 cash tax rate would be approximately 5% to 7% of operating income or $120 million to $170 million at current strip pricing, increasing to the low 20% range in 2025 and beyond which is fully captured in our cumulative free cash flow outlook. Turning to capital allocation. We repurchased almost 6 million shares during the first quarter and have retired a total of more than 20 million shares under our buyback authorization at an average price of roughly $30 per share. Our buyback strategy is opportunistic in nature as we seek to maximize the return generated for investors, and we are pleased with our execution to date as we have generated the best buyback return among the gas peer group. We've also retired $210 million of debt principal during the quarter at an average price of 96% of par taking our total debt principal retired to $1.1 billion since initiating our capital return framework. This focus on debt retirement has driven our net leverage down a full turn over the past year highlighting our commitment to a bulletproof balance sheet. Looking ahead, our cash position affords us tremendous flexibility as it relates to financing the cash portion of the pending Tug Hill acquisition. As we work constructively with the FTC and approach deal closing, we plan to maintain cash on hand to effectively prefund a portion of our expected debt paydown post deal close. We will also look for opportunities to buy back additional stock post deal close, especially in light of the value accretion and the cost structure improvements that Tug Hill and XL assets will bring to EQT. As Toby mentioned, we see greater than $12 billion of cumulative free cash flow from 2023 through 2027 at today's lower strip even before factoring the benefits of the pending Tug Hill acquisition, leaving us with plenty of firepower to fully achieve and exceed our debt retirement goal and our equity buyback authorization. I'll now turn the call back over to Toby for some concluding remarks.

Operator:

[Operator Instructions]. Our first question comes from Arun Jayaram from JPMorgan.

David Khani:

Yes. So it's a great question, Arun. So we've added about 500 Bcf -- I'm sorry, $500 million a day of FT capacity over the last 18 months, mostly to the Midwest and some to the Gulf Coast. These are definitely higher value regions that give us exposure to improve realization. So -- and we continue to expect to add more this year and make that better. So that was definitely a piece of it. The other piece of it was our hedging strategy and how we had certain areas and leave certain areas open. M3 was a very strong region for us this quarter. As a nuclear facility in New York went offline, we're seeing higher and higher values up in that M3 area as winter shows up. So winter is a very positive M3 area. And then like the third piece is, as natural gas NYMEX prices come down, our local basis narrows as the correlation is about 80% to 85%. So NYMEX goes up. Our basis widens NIM has come down or basis narrows. So those are the 3 impacts of which I'd say the first 2 will probably long-lasting, and we'll improve -- keep doing it. And the last one is going to be obviously subject to what NYMEX prices do.

Toby Rice:

Yes, Arun, let's look at where people's heads are at around the world when they're thinking about energy. I think there's a couple of classes where people sets are at. We've got some people that still have their heads in the sand, thinking that just focusing on the United States and fixing emissions here is going to somehow solve the global emissions issue that they're concerned about. They need to pick their head up. We've got other people that have their heads in the clouds and thinking that some of these solutions that are being proposed, the 5 physics and are only addressing 1 part of the energy ecosystem, and they may be a little bit too optimistic. What we need is people to have a level head talking about deploying proven, scalable, truly sustainable solutions like unleash U.S. LNG that will have the biggest impact on lowering global emissions that will have the biggest impact on providing more energy security to the world. Now I'm excited about where the world has moved. We've moved away from a world that is a sum of the above approach towards energy, only solar only wind. We've seen that strategy play out in Europe and the world has taken notice that, that may not be the best solution, and it may not be capable solution. So the world has moved back towards a more realistic and more practical approach in all of the above approach towards energy. That's where unleash U.S. LNG sits. But if we want to meet the environmental ambitions and the time line needed to get there. If we want to accelerate pulling the 3 billion people around the world that live in energy poverty, if we want to protect the 60% of Americans who live paycheck to paycheck, we need to move from an all-of-the-above approach to energy to a best of the above approach towards energy. And while the world certainly, I think isn't capable right now on determining what is the best source of energy, one of the things that we're excited about over the last year is we've been successful in defining the criteria at which energy will be graded upon. And those criteria are cheap, reliable and clean. And one of the -- that seems to be universally accepted as the 3 main criteria. And we're seeing actions with the administration Secretary Grand Home supporting pipelines, supporting MVP and in the closing paragraph of her letter says that energy needs to be affordable, reliable and clean. So we are very excited about the progress we've made. There's still a lot of work left to do. I think permit reform is inevitable. Our energy ecosystem is maxed out. Pipelines are full. Refineries are running at maximum capacity. And without that extra flexibility, we are at risk of a major event to throw us back into another energy crisis. That event can be weather. We see utilities in New England writing letters to the President saying that they're concerned if they experience a mild -- a cold winter. How they will deal with that. It could be a cyber event. We saw what happened with Colonial Pipeline. It could be another geopolitical event. It's not -- in my opinion, it's not if one of these events happen, it's when. And we need to build up our industrial energy capacity so that we can deal with these events when they take place. And that's 1 of the reasons why we believe Perma Reform is inevitable. I think people understand where we're at and what we need to do, and we're excited about helping lead the conversation going forward.

Umang Choudhary:

My first question was on the -- on your plans. On the outlook, I mean, you appreciate your thoughts around the natural gas macro outlook. I was wondering if you can give any color in terms of like what levels would you look to adjust your completion activity? And any color you can provide on your choke management plans.

David Khani:

Yes. And I'd just add, due to the water line issue last year, our production has not -- is below maintenance levels normally by, we'll call it 2% to 3% already. So we've actually contributed, I would say, our share a little bit of the reduction in gas to help balance the market as well.

David Khani:

Yes, it's a great question because you're right, with lack of coal-fired generation as baseload with some nuclear coming offline and then replacing it with gas and renewables, you're going to have more and more volatility going forward. And so as a producer, how do you handle that One, you have to have a very, very strong balance sheet. So having investment grade, having onetime leverage. Maybe over time, we'll build up cash as well. So our net leverage might even below that 1x. The second is you have to have the low-cost structure, right? So if you notice, we've taken our cost structure down from from we'll call it, $2.85 to $2.90 down into the 220s, right, over time. So very important to be a low-cost producer in a commodity business. And then third is we're using our hedging strategy with collars. If we do something on the LNG front, we'll do stuff with collar. So we'll try to manage that volatility. And so I think that's the 3 ways we'll do it. And I'd say the fourth way is probably also to have very low to no emissions because that means the end market demand will stay very strong for your product on a relative basis.

John Abbott:

Apologies for the sirens in the background here. It sounds like something is going on. Our first question is related again to the Tug Hill and Excel Midstream acquisition. It looks like you're still suggesting those are going to close around midyear. It sounds at that time, we'll have potentially some sort of update to guidance. Just sort of thinking about that, could you remind us what is included in the $80-plus million of synergies that you had initially suggested? And at this point in time, where do you see potential upside versus that?

John Abbott:

So just to be clear, does combo development factor into those synergies?

John Abbott:

Appreciate it. And then I want to go back to Arun's earlier question on differentials. So Dave, it sounds -- as you said, you've had about $500 million of FT over the last 18 months. How do you describe the opportunity set sort of going forward to improve on realizations going forward at this point? What is -- how do you think about available FT coming up? What is the opportunity set there for you to improve realizations at this point?

Operator:

The next question comes from David Deckelbaum from Cowen.

Toby Rice:

Sure. Just to level set what we've seen, we've seen a 10% reduction in rigs that were focused on gas. It's about 17 rigs have come off. We expect that trend to continue down -- and we're also looking at some of the commentary. The big focus really needs to be on the completion activity -- and from the earnings with Halliburton next year Liberty, they are signaling that they're seeing a mobilization of frac crews moving away from gas towards oil. So that will be something else that we're looking at throughout the course of the year in addition to the rig reductions. .

David Deckelbaum:

You brought up, I think, if there are some ongoing headwinds here before we get to a lot of the LNG egress that comes on in -- and obviously, the coal retirements looking for some displaced gas there. How do you think about managing a like short-term curtailment profile? And you highlight at a corporate level now your free cash breakeven this year are $1.65 with the benefit of the hedge book. Do you think about curtailing things at a corporate level? Or is this still calculated at a field level of sort of an individual area or a bad basis? .

David Deckelbaum:

I appreciate that, David. And if I could just ask a little bit more on just Umang's question earlier around the hedge book. The curve for '24 is kind of sitting in and around the area where you guys had hedged out for '23. You don't have much hedge volumes in '24 now. I guess how do you think about that dynamic just given the fact that your realizations could look pretty attractive if you hedged out 24 at this point? Is that more a sort of a commentary or reflection on your confidence in hitting deleveraging goals this year and requiring less of a hedge profile next year? Or is that more of taking this wait and see into what ultimately might be a volatile spike for the '24 curve?

Operator:

The next question comes from [indiscernible]. Your line is open. Please go ahead.

David Khani:

Yes. So the volumes down to the Gulf, that's all physical. That's not financial. And so -- and we are looking to add more over time, and there is more pieces that will come up over time. It's very episodic, as you can imagine. So we will look to continue to grow the FT position to all the higher-valued areas, including the Gulf. And I think it's important to note that as you see a lot of volume growth down in that area. It's important to have hedging will play more of a role in the Gulf Coast as Haynesville tries to grow and Permian tries to growth. So you need to have Gulf Coast and hedging as a strategy now. Once you get tied up into the LNG market, then that will actually alleviate some of the need to hedge basis down there, too. So there's a lot of things that you need to do to manage the complexity down there.

David Khani:

Well, right now, until we have all LNG off the East Coast, we're going to be running in a maintenance of capital perspective. So right now, the buybacks are competing probably more with our debt retirement and maybe a little bit on the margin with dividend. If we were to get access to East Coast LNG and be able to grow, which we're talking -- we'll call it several years into the future, then it will be a rate of return exercise, and we'll have a view of what we think our NAV at a, we'll call it mid-cycle price, and then we'll compare it against the value we can get to lock in that growth with LNG pricing.

Unidentified Analyst:

Circling back to Tug Hill, the bonds you issued last year had some SMR conditions in them linked to a deal closing by June 30. And I appreciate you still think you're on track to close by midyear, but clearly, it's going to be a little bit closer to that date than you originally envisioned. Dave, maybe you can talk a bit about how you're thinking through those mechanics and what your contingency is of closing so last June.

Unidentified Analyst:

Got it. Okay. And then my follow-up there is just, I mean, given the strong start to free cash flow this year, would your preference actually be to have even more short-term prepayable bank debt and the financing mix. you originally envisioned just to provide even more short-term debt reduction runway?

Operator:

The next question is from Paul Diamond from Citi.

David Khani:

Are you talking about the demand growth? Or you're talking about us growing production?

David Khani:

Yes. So you'll have coal retirements as part of that. As you know, the Shell cracker has come on as well. And -- and I would say probably in the neighborhood of 1 to maybe 2 Bcf per day over the next several years is probably a good sort of ballpark number.

Toby Rice:

On an M&A basis, our strategy will stay the same. Obviously, a commitment to making sure the financial accretion is there. But the differentiating aspect is looking for opportunities that will lower our cost structure. And the new dynamic is really the competition is competing with the value from buying back our own stock. So I mean, that ultimately is going to be the thing that changes given where our stock trades, but we're going to stay committed with this strategy that we've laid out. We think it's created a lot of value and we'll stay disciplined.

Noel Parks:

I just wanted to talk a bit about when we're thinking about expansion of nat gas into industrial uses, microgrid reduces and so forth. I sort of have in mind your your project with Bloom Energy that is been underway for a while now. In a lot of these type of installations, what becomes evident pretty quickly is the whole sort of grid integration type of issues that can come up, especially when you're looking to sort of resiliency type issues. And I was just wondering, in the sort of EMS management -- energy management system software technology market, I'm hearing more and more about that being a focus as people look at projects. I just wondered, is that something that you could protect potentially see yourself making an investment in sort of the software, energy integration software. Is that something you could picture yourself doing under the EQT umbrella?

Noel Parks:

Great. Not something I've heard of before. So it's interesting. And just taking another stab at sort of the macro picture. If we look at sort of this incredibly volatile year we've had sort of spurred off by Russia, Ukraine and then sort of the downward move you saw on weather. Do you think that we are I mean the software a long time was that LNG and that export demand, if anything, might sort of contain volatility a bit. But I'm wondering if it may be -- the reality is that we're going to see from geopolitical pressures and seasonal variances. Is it conceivable you think that we're headed towards maybe a permanent level of this sort of volatility I mean, I looked back over the past year, there's maybe only 1 or 2 months that haven't seemed to then like a $2 swing intra month on pricing. So yes, I guess I just interested in your thoughts on is -- is this the new norm we're going to get used to? Or do you look at the past year as being more an aberration that will indeed get smoothed out by.

David Khani:

Yes. And I'd just say we need more storage capacity and we need more pipelines to be able to do it because if you keep taking coal-fired generation, which is baseload offline and don't replace it with the ability to add more baseload kind of fuel. You're going to increase volatility.

Josh Silverstein:

Great. SP249079218's You guys mentioned some flexibility in the program for this year, obviously, depending on price. Can you just elaborate a little bit more what that might mean? Would you reduce rigs? Would you just build up DUCs for next year or thoughts and any shut-ins. Just curious what you guys would think about as far as flexing activity. . Josh, the simple way to think about it is EQT is.

David Khani:

Yes. I mean we're not running 15 rigs we're running 2 put in perspective -- so we don't have a lot of cutting 50% of our rigs would be more damaging to us. We can manage the production in other ways if we have to. .

David Khani:

Yes. So we are -- we're actually further along on the debt buyback is the amount of free cash flow that we generate. And so I think we could see ourselves getting to a target somewhere around midyear next year. That gives us flexibility to buy back stock as well in that. So I'd say Q1 is probably still a good ratio. And then once we hit our debt targets, we could then effectively change that ratio be much more equity if you want to, assuming we're going to be opportunistic, right? But we have -- we'll have a lot of flexibility. And then just beyond that, you think about it, we really only allocated about 1/3 of our free cash flow. So you think about that as a longer term -- how do we deploy that capital. And again, that will be and the next guy sitting in my seat role to figure out how to allocate capital properly.

Operator:

So I'll hand back to the management team for concluding remarks.

Operator:

This concludes today's call. Thank you very much for your attendance. You may now disconnect your lines.

Cameron Horwitz:

Good morning, and thank you for joining our fourth quarter and year-end 2022 results conference call. With me today are Toby Rice, President and Chief Executive Officer; and David Khani, Chief Financial Officer. The replay for today's call will be available on our website beginning this evening. In a moment, Toby and Dave will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday's earnings release, in our investor presentation, in the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

David Khani:

Thanks, Toby. It has been an honor having spent the last three years working with you and the EQT team. I've been amazed at how much this organization has accomplished in such a short period of time, and I am grateful to have been part of that evolution. EQT is truly a unique company with a world-class asset base and exceptional culture, a proven development model and a strong balance sheet. I am proud to have left my mark on this company and will be leaving we can see on the trajectory that will create shareholder value for years to come. As mentioned in the announcement this week, I will stay fully engaged with APP for the next several months as I help facilitate a smooth transition, and I look forward to seeing many of you at upcoming investor events. Now turning to results. I'll briefly summarize our fourth quarter and full year numbers before discussing our balance sheet hedging and 2023 guidance. Sales volumes for the fourth quarter were 459 Bcfe, roughly in line with the midpoint of our guidance range despite weather-related impact of approximately 10 Bcfe. Our adjusted operating revenues for the quarter were $1.32 billion or $2.87 per Mcfe, and our total per unit operating costs were $1.39 and resulting in an operating margin of $1.48 per Mcfe. Capital expenditures, excluding noncontrolling interests were $396 million in the fourth quarter, slightly below the midpoint of our guidance range. Full 2022 capital expenditures came in at $1.43 billion, excluding acquisitions, in line with the midpoint of our $1.4 billion to $1.475 billion guidance range. Fourth quarter adjusted operating cash flow was $622 million, and free cash flow was $226 million, which takes our total 2022 free cash flow generation to approximately $1.94 billion. We also saw a $442 million working capital tailwind during the quarter, which was driven by a receipt of our cash election option from E-Train, declining accounts receivables from decreasing prices and lower margin requirements. Our capital efficiency for the quarter came in at $0.86 per Mcfe, up from $0.72 per Mcfe in the third quarter driven by lower production. This was expected due to third-party infrastructure limitations earlier in the year that negatively impacted our 2022 TIL count. For the full year 2022 our capital efficiency averaged approximately $0.74 per Mcfe, which is roughly 30% below the gas peer group average despite the just noted third-party issues impacting production last year. Turning over to the balance sheet. A core tenet to our company's operating philosophy is to have a strong credit profile and ample liquidity. We believe this will create differentiated value opportunities for GT moving forward. Recall, we saw several positive balance sheet milestones last year, including achieving investment-grade credit ratings. Our balance sheet improvements to continue in the fourth quarter with trailing 12-month net leverage exiting the year at 1.2 times and down from 2.3 times a year ago. We exited 2022 with $4.2 billion of net debt and $1.46 billion of cash on hand inclusive of the $1 billion in proceeds from the notes offering in the fourth quarter that will be used to help fund the cash portion of our pending Tug Hill acquisition. As Toby mentioned, we continue actively progress towards our debt retirement initiatives. We've retired an incremental $283 million of senior note principal since our last update via open market purchases at an average price of $0.95 at par. Since unveiling our capital returns framework, we have now retired more than $1.1 billion of debt principal, which has eliminated nearly $40 million of annual interest expense. Moving to hedging. Our 2023 hedge book underscores our evolving hedge philosophy that seeks to provide investors with the best risk-adjusted exposure to natural gas prices. We currently have 62% of our 2023 gas production covered with 4s, an average weighted price of $3.37 per MMBtu, which provides significant cash flow protection and downside pricing scenarios while maintaining our private exposure. Since our last update, we have also added to our 2024 hedge position with 10% of our 24 volumes now hedged at a weighted average floor price of $4.20 per MMBtu and a weighted average ceiling of $5.40 per MMBtu. As it relates to basis, we have nearly 90% of our 2023 Appalachian production covered via basis hedges, providing significant protection against any potential material widening of differentials. Over the medium to long term, we see reasons for structural optimism as it relates to local basis, most notably driven by incremental power demand growth in PJM and coal-fired power retirements. We have also benefited from expanding firm transportation portfolio as we've been able to ship gas further west and capture associated favorite pricing dynamics. Recall, we have added an incremental $300 million a day to our FT portfolio last year, including $200 million to the Gulf Coast and $100 million to the Midwest. Looking ahead, we expect additional opportunities to expand our FT position as our peer-leading inventory depth allows us to capitalize on the trend we've seen of other Appalachian operators releasing existing firm transportation capacity. For 2023, our market mix is expected to be roughly 37% local 28% Gulf Coast, 20% Midwest and 15% eased. Note we now model an MDP start-up in the second half of 2024, which at the midpoint will take our local basin exposure to approximately 30%. As a reminder, our gathering rates contractually begin declining in 2025 independent of MPC's success, providing a further tailwind to free cash flow as our margins wide. Turning to guidance. We expect 2023 production volumes to range from 1.9 Ts to 2.0 Ts with the midpoint roughly flat compared with 2022. As we bring online the incremental pills that were delayed last year, we expect sequential growth in the second quarter and production achieving our 500 Bcfe quarterly maintenance run rate by midyear. Note that we contemplate a variety of scenarios in our 2023 planning with the low end of our production lines tied to the potential of moderating activity should natural gas prices continue to decline. We are setting the 2023 capital budget of $1.7 billion to $1.9 billion, excluding the pending Tug Hill acquisition. Our budget in beds, 10% to 15% year-over-year oil service inflation, with our supply chain contracting strategy, providing strong access and cost position. With the likely decline of gas-directed drilling activity this year, we see the opportunity for some price relief in the second half of 2023. This has not been factored into our outlook. As Toby mentioned, $100-plus million of our budget is associated with turning in line wells that slipped from 2022 into 2023 to third-party constraints and thus we not anticipate to carry forward into periods. This dynamic, along with the shallowing of our base PDP decline is anticipated to drive 5% to 10% improvement in our capital efficiency in 2024 and beyond. On Slide 31 of our investor deck, we provided adjusted EBITDA, operating cash flow and free cash flow outlook for 2023 at various NYMEX natural gas prices. Aided by insulation from our hedge book and material cost improvements we have achieved over the past several years, our projected 2023 free cash flow ranges from approximately $900 million at $3 gas to $2 billion at $4 gas implying a free cash flow yield of 8% to 17%. As it relates to cash taxes, we had roughly $1 billion of federal NOLs as of the end of 2022 and at current strip pricing, we expect these NOLs to offset the bulk of our 2023 cash taxes. Our 2024 cash tax rate would be approximately 7% to 9% of operating income or $150 million to $200 million at current strip pricing increasing to the low 20% range in 2025 and beyond, which is fully captured in our cumulative free cash flow outlook. Turning to capital allocation. We have now retired over 20 million shares of our buyback authorization at an average price of $30 per share. Recall that we have eliminated additional 5.7 million shares via convertible note repurchases last year. So in total, we've lowered our fully diluted share count by more than 6% since beginning of 2022. We still have significant firepower to retire shares with $1.4 billion remaining under our current $2 billion authorization. As mentioned previously, we've also made significant progress to our debt retirement with $1.1 billion of debt principal retired since initiating our capital return framework. We continue to target absolute debt of $3.5 billion pro forma for the tug acquisition, which will further bulletproof our balance sheet by taking our debt-to-EBITDA to 1 times to 1.5 times, assuming a $2.75 NYMEX gas price. Looking ahead, our low-cost structure and hedge book provide differentiated downside protection for 2023 free cash flow, which we will allocate towards our base dividend further debt retirement and opportunistic equity buybacks with an anticipated greater than $12 million of cumulative free cash flow from 2022 through 2027 and we have plenty of firepower to achieve and exceed our debt retirement goal and equity buyback authorizations. I'll conclude by highlighting Slide 11 of our investor deck, which underscores the economic impact of the cost structure improvements of EQT has achieved over the past several years from 2019 to 2021, we generated an average ROCE of negative 8% at an average realized natural gas price of approximately $2.50 per MMBtu, inclusive of hedging. Over this period, we've reduced annual costs by roughly $700 million, with spring loads our corporate return profile into an improving natural gas price environment. This was exemplified in 2022 as our ROCE jumped to roughly 17% with just a $0.50 improvement in realized natural gas prices at $3 per MMBtu. At current strip pricing, our ROCE should improve over the coming years, highlighting the sustainability of our operating model and the value creation potential of our business. I'll now turn the call back to Toby for some concluding remarks.

Operator:

[Operator Instructions] Our first question is from Umang Choudhary with Goldman Sachs. Your line is now open.

Toby Rice:

Yes. Great question. So I think you'll see us continue our approach towards our capital allocation plans. What you've seen in the past has been a prioritization of debt paydown. That's going to shift asset value into the hands of our equity holders. And then you'll see us continue to be opportunistic with the buybacks. And obviously, the fixed dividend that we put in place is durable and will be a story that will continue to look to grow that over time.

Umang Choudhary :

And then would love your latest thoughts on the natural gas outlook. On the -- what are you expecting from a supply response, how are you thinking the market is shaping up and then how does that change the way you approach your strategy around hedging? And then any update on the -- any thoughts around M&A to the extent you can you can prosecute it given the -- given what's going on with age.

Toby Rice:

Yes. And specifically, in regards to our strategy, I think Dave's comments on our hedging strategy is designed to give us the downside protection while also giving us great exposure to commodity prices. So you'll see us continue to execute that approach. As it relates to our activity levels, what you're seeing with us this year is putting a plan in place that will get our production capacity back to 500 Bcf per quarter run rate. We feel like that's prudent to get that capacity back. But that will give us the ability to respond in more real time if we continue to see gas prices decline or we'll be happy to have that production capacity if gas prices move back to our view of where we think prices will be in the future. So on an M&A basis, we're going to continue. You'll see no change on the approach there. One of the key characteristics of our M&A approach hasn't just been on making sure we see the financial accretion on deals with cash flow per share NAV per share. But the other factor, which is really showing up is our commitment to buying low-cost, high-quality assets and in a low cost low price environment today, you're seeing the benefits of that. And so we'll continue to reinforce that element of our M&A strategy.

Sam Margolin:

I wanted to ask about the remark on Slide 12 about looking at new well designs. And maybe just talk a little bit about like some specific outcomes you're going for with this approach, whether it's like a PDP extension type of outcome or if it's to manage declines? Or what exactly is going on with that comment?

Sam Margolin:

And then just as a follow-up that you just mentioned with respect to inflation. And you mentioned you thought that the current market would drive some activity levels lower. And I wonder if you could just characterize a little more of your outlook here, if it's just -- do you think that sort of unit cost on the service side are nearing a plateau or if maybe the activity levels were so overheated, that we could actually see services kind of give back some price right now just because of the severity of the market conditions?

Operator:

Our next question is from David Deckelbaum with Cowen. Your line is now open.

Toby Rice:

Yes. As it relates to our hitting our production capacity targets by Q3, the thing we're really looking at is completion efficiencies and really stages per day footage completed per day. And one of the slides we showed how we've gotten back to sort of historical performance levels there. So we'll be watching that, and that will really be the guiding factor on the pace of reaching that target. As it relates to the activity levels relative to toil acquisitions, we were always planning on running this activity level, and we weren't planning on changing our activities with the Tug Hill transaction that was probably going to be something that would be incorporated in '24. So we're executing sort of as we planned, and we'll adjust when that deal gets closed.

David Khani:

Well, yes. So the purchase price was set at midyear last year. And so any change in free cash flow effectively will lower the price each month that will -- that this takes to close. So if they change -- if they decide to change activity and the response to this marketplace, then whatever impacts to free cash flow that will benefit to us. But we don't know that they're changing activity. We do know that they did add hedges at $5 on half of their gas production to lock in that a good portion of the free cash flow. So -- and our expectation right now is that this will close midyear.

David Khani:

Correct, yes, we're just trying to show that we and a much lower gas price before we don't generate free cash flow.

Neal Dingmann:

First, Dave, thanks for all the time, definitely been a great help. And probably my first question is on cost, specifically. What's your comfort level with -- when you see inflation and other potential incremental pressures this year -- and just really wondering how sensitive is that to your D&C plan? You mentioned how you potentially would change D&C based on what gas prices. But I'm just wondering how does that relate to what you're thinking on costs as well.

Neal Dingmann:

Yes, definitely, it seems like the applicant guys are in better price or better area there. And just maybe lastly, just on housekeeping. I'm just wondering -- you mentioned about the $50 million adjustment per month color on the purchase price for the adjusted to included in Tug Hill. I'm just wondering, is that included in the Tug Hill hedges? Or is that incremental?

Neal Dingmann:

Yes. You mentioned about isn't there -- with that, you mentioned that $50 million per month regarding the purchase price adjustment, I'm just wondering, is that included in the Tug Hill hedges? Or is that incremental?

Operator:

The next question comes from Roger Read of Wells Fargo. Your line is now open.

Toby Rice:

Yes. I think there's a couple of things that are happening from an activity level, as these mature basins -- or the shale plays continue to mature, the amount of activity levels will lower over time that should have an impact on lowering service costs. But also the other thing that's taking place is the breakevens in the United States is rising as operators are moving to Tier 2 geology and both in geography and also in the zones that they're completing. That will have the impact of increasing the marginal breakeven price of gas. That will help solidify price. The other thing I'd say is, as far as duration is concerned, I mean the one thing that we're seeing is the call for cheap reliable clean energy. And if we learned one thing in 2022, looking what happened in Ukraine and Russia, the lesson learned there is energy security matters. And without energy security, you cannot transition. Europe has gone backwards on their emissions targets because of the lack of energy security. And the most important takeaway from all of this is where did Europe turn for energy security. They turn to natural gas. And so we think that the call for this product is only going to strengthen over time because natural gas is the key to providing energy security to Americans in the world.

John Abbott:

Dave, thanks for all of the entire Bank of America team who wants to echo best your best wishes in your next chapter. Our first question is going to be on the Tug Hill and XcL Midstream acquisitions. So when you look at -- so the guidance that you provided back in September of last year and when you sort of think about these acquisitions potentially closing in the middle of this year. First, is the midstream spend that you laid out in September still on track at XcL? And then second, how does your current thoughts on the potential impact of the breakeven include updated thoughts on inflation heading into this year.

Toby Rice:

So as far as -- what was the second part of the question there?

Toby Rice:

Yes. So I mean, the key thing with Tug Hill and the reason why those assets had such a low breakeven cost, was really due to the fact that they own their midstream and also the liquids percentage of their program that they're running there. So yes, they're going to be pay with inflation like every other operator and we'll recast what that looks like from a CapEx perspective. The one thing I'd say is these are pretty high-quality assets. So the activity levels needed to maintain production will mitigate some of the service cost inflation effects. But hopefully, by the time we take over, we've seen a little bit more balance come from service costs.

John Abbott:

And then our second question is sort of on the natural gas macro. Despite spot weakness, the forward curve is about 50% above year-ago levels with former storage, albeit after losing Freeport exports. What do you think is going on?

Operator:

Our next question comes from Noel Parks with Tuohy. Your line is now open.

Toby Rice:

Yes. So the type curve revisions resulted in an increase of about 350 Bcf and that's sort of what we're referring to when we said performance revisions. So we have seen an increase to performance didn't bake in anything on the science work that we're doing. It's just too early to factor that in.

Toby Rice:

Yes. And I hope that investors look at this with a theme that you're starting to see around this industry where well performance is sort of degrading across industry to be assured to see that high-quality assets are translating to dependable performance, and you're seeing positive improvements in the well results that we're putting out, I think, is -- should be very reassuring for investors.

Toby Rice:

Yes. So rigs were good through the end of the year with the frac crews, 2 out of the 3 frac crews or -- sorry, we have 2 out of 3 factories locked up. We've got a frac crew that will be joining sort of middle part of this year that we're currently under negotiations for right now. So I'd say probably that's the biggest big resource we have that we're working on. And as I mentioned, steel is the other big factor, which we'll cover through the first half of this year, and we'll continue to work through that. pressure for the second half.

David Khani:

Sure. So right now, we're dealing with extra G&A tied to the FTC and it will pull an unclosed process. So if we were to effectively close by midyear, I would say probably the last of what we would deal with is most likely all hitting at the end of the second quarter. It could some hit in the third quarter. But I would say that's probably your best bet from what we know right now.

Paul Diamond:

Perfect just a quick question for you on 2023 guidance. The numbers give you some optionality around some growth versus some reductions just wanted to kind of get you guys sensed on the strategy. And should we be thinking about that in yearly with pricing? Or is it more -- or is there kind of [indiscernible] on the high side and then it will step change if pricing drops below a certain level?

Paul Diamond:

And just one quick follow-up. As we kind of move to a more long-term supportive fundamentals of $24 million and $25 million has there been any shift in kind of your priorities from Southwest PA versus the Northeast versus West Virginia? Or is that still kind of Southwest PA still pretty much the kind of the front runner as far as priorities go.

Operator:

There are no further questions. I'll pass the call back over to the management team for closing remarks.

Operator:

That concludes the conference call. Thank you for your participation. You may now disconnect your lines.

Cameron Horwitz:

Good morning, and thank you for joining our third quarter 2022 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer; and David Khani, Chief Financial Officer. The replay for today's call will be available on our website beginning this evening. In a moment, Toby and Dave will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements, because of the factors described in yesterday's earnings release, in our investor presentation and the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that I'll turn the call over to Toby.

David Khani:

Thanks, Toby. And good morning, everyone. I'll briefly summarize our third quarter results before discussing our balance sheet, hedging and guidance updates. Sales volumes for the third quarter were 488 Bcfe, which was modestly below the midpoint of our guidance range. As Toby mentioned, third party and logistical constraints put a governor on our activity during the quarter, limiting our TILs to just 16 verse our guidance range of 22 to 32. Our adjusted revenues for the quarter were $1.7 billion or $3.41 per Mcfe, and our total per unit operating costs were $1.42. As a result, our operating margin was $1.99, about $0.90 cents or 85% higher than last year. Capital expenditures were $349 million below the low end of our guidance range, largely due to lower-than-expected completion activity. Adjusted operating cash flow was $940 million, and free cash flow was $591 million, bring our total year-to-date free cash flow to approximately $1.7 billion. Our free cash flow also reflected a basis differential of $1.2 per Mcfe wider than our guidance of $0.80 to $0.90per Mcfe due to wider local differentials and unplanned outage on the NEXUS system. Our capital efficiency for the quarter came in at $0.72 per Mcfe which was a 4% sequential quarterly improvement resulting from lower capital spending. On slide 26, we highlight our capital efficiency has averaged $0.70 per Mcfe on a year-to-date basis, which is 35% below the gas peer group average despite the third-party issues impacting the timing of our production this year. Turning to the balance sheet, at the end of the third quarter, our trailing 12-month net leverage stood at 1.3x, down 0.3 turns from the prior quarter. To fund the Tug Hill and XcL acquisition we raised $2.25 billion of debt which is leveraged mutual to our existing profile. This comprised of raising $1 billion of senior notes and $1.25 billion of term loans with strong support from both the banks and our institutional investors. Despite a challenging credit environment, we priced our two tranches of senior notes at 175 to 200 basis point spreads to respect to treasuries with further tightening in the secondary market. This enabled us to lower funding costs and implement efficient repayment terms. We see the successful debt financing is another testament to the underlying credit quality of our business and value the support we received from our banks and bondholders. As highlighted with the deal announcement, we raised our year end '23 debt reduction target from $2.5 billion to $4 billion, which will take our gross pro forma debt down to approximately $3.5 billion. With our debt trading below par due to the Fed raising rates, we have even more principal purchasing power. Once we achieve our absolute debt target, we will have a bulletproof balance sheet with leverage of 1x to 1.5x using a conservative $2.75 per MMBtu to NYMEX gas price. We have already executed $830 million of debt reduction goal this year and expect to make material additional progress over the coming quarters, giving the robust projected free cash flow generation. Looking at liquidity, we ended the quarter with approximately $2.6 billion comprised of an essentially undrawn credit facility and $88 million of cash. Two positive equity items to point out. First, we replaced approximately $180 million of letters of credit with surety bonds during the quarter. And second, we received $196 million from ETRN Midstream, subsequent to quarter end as we exercise our option to receive cash in lieu of a portion of near-term fee relief. Now moving over to hedging, as mentioned on Tug Hill acquisition call, we added to our legacy hedge book in the third quarter, taking our hedge funds from 50% to 60% next year through the purchase of deferred premium puts with an average strike price of $4.65 per MMBtu. We've also executed on the majority of our plan to hedge 60% of Tug Hill's production next year through the combination of deferred premium puts and collars with an average floor price of $5.53 per MMBtu to an average ceiling of $10.80 per MMBtu. On a pro forma basis, we have approximately 60% of our 2023 production hedge with floors have an average strike price of $3.30 and approximately 45% covered with ceilings at an average strike price of $5.65 per MMBtu. We remain unhedged for 2024, and we'll be looking for opportunities to begin building our -- out our hedge position. Turning to guidance, as Toby mentioned, a third party and logistical constraints have reduced our plan 2022 TILs by approximately 30% verse our original outlook. Strong underlying well performance and field optimization have mitigated the impact to 2022 sales volumes, which are now expect it to be 1,925 to 1,975 Bcfe or roughly in line with the lower end of our prior guidance range. We're also lowering our full year capital expenditure guidance to $1.4 billion to 1.475 billion excluding acquisitions to reflect the lower TIL count. While we're in the midst of the budgeting process for 2023, our supply chain contracting strategy puts us in a strong access and cost position given our multiyear sand and frac crew contracts. We plan to give more fulsome details once we provide 2023 guidance, but we expect EQT to experience inflationary impacts at the lower end of broader industry ranges for next year. Given our structurally superior hedged position next year, we expect our 2023 free cash flow to expand by approximately 90% year-over-year at recent strip pricing prior to the effect of Tug Hill, and after factoring in cash taxes, providing differentiated free cash flow per share growth to our shareholders. I'll now turn the call back over to Toby for some concluding remarks.

Operator:

[Operator Instructions] And our first question of the day is from the line of Arun Jayaram of JPMorgan Chase.

Toby Rice:

Yes. Good morning, Arun. So one thing I think that's worth noting is the waterline issues have been resolved, the pipelines have been fixed. And so those issues are behind us. Some of the supply chain issues that we face with some other third-party vendors; I think those issues will nagging at us. But we're doing everything we can to build an amorphous ability to program. I'd say all of these impacts together, largely are behind us. And I think we should be back on pace by mid-23 with that 2 Tcf run rate production base.

Toby Rice:

Yes, Arun, I think the answer there will be dependent on how much we can beat the baseline operational efficiencies that we have baked into our program. And then also looking for other optimization efforts within the system that's in front of us, that would be additive to what our base plan is. So I think, I mean, the punch line is the team is shown the ability to claw back and we're still fighting for every -- and every Mcf. And we think there could be an opportunity for us to get there, but it'll be dependent on those actions.

Umang Choudhary:

Hi, thank you. Good morning. I just wanted to follow up on the question from Arun, I understand that you're working through a budget and that you have fewer TILs this year. How does that how, like given that TILs are probably going to have an impact to your first half '23 production. Would love your preliminary thoughts on 2023 activities? Should we expect your activity levels to go back for the legacy asset to keep it flat to around 90 to 100 wells per year? Or would it be higher next year? As you try to grow production sequentially exit to exit this next year?

Umang Choudhary:

Got it, that's really helpful. And then my second question was really on the LNG strategy, any update and any update on the discussions which you are having with the LNG customers? As it comes to diversifying, you have exposure to international markets.

Operator:

Our next question is from the line of Neal Dingmann of Truist.

Toby Rice:

Yes, so outside of the waterline issues that have been repaired getting access to some equipment, there's been some longer lead times that sort of the supply chain should we talk about then with all of this, we've got backup plans, and our flexibility to execute on those backup plans has been challenged because of some weather and we experienced some drought conditions that wouldn't allow us to get fracs at the operational efficiency that we needed. And so that's one of the x factors that is driving sort of the weather impacts that we laid out on that chart.

Toby Rice:

Yes, Neal, I'd say with the best returns coming from Southwest Pennsylvania, the work that we've done to reduce costs in West Virginia have made those more competitive from a return's perspective. And then I'd also say over in the Utica, some of the science work that we've done, primarily widening spacing no surprises shown increased recoveries per foot makes those returns more attractive. So our ultimate goal is to sort of get to a place where we can improve the economics across all inventory, we're seeing that right now. And so I think, as we drive our schedule, it's really going to be dependent on these surface factors, number of wells, lateral lengths, combo development. And so that's sort of what drives the schedule on the makeup. I would say one of the things we look at is a board that shows the returns across every single project. And we are driving to drill our best acreage in our best wells first. And over 80% of our schedule is factoring on the projects that are in the top quartile of our inventory base.

Operator:

And our next question is from the line of David Deckelbaum.

Toby Rice:

So the benefit of moving wells back in '23, I guess, to argue maybe, Frank, some of the service costs environment we do hope that service costs will abate a little bit, so that could be one of these benefits but right now we'd like have these volumes today, with current price backwards, we're pushing -- the other thing is, if you notice then slide 11 -- ability to pull things back with -- so that was I hope that we were able to beat out that -- cycle time improvement will carry forward with our wells bore. So we'll get them in and then -- benefit.

Toby Rice:

Yes, I think our mix that we do is a good baseline -- I would say one of the other things that will help with Tug Hill coming on board is this was increased our flexibility to be able to make up for or operate with --

Toby Rice:

Yes, we were hoping to get better insight and clarity on task forward with our science, these delays and some of the tils has happened on some of our science projects. So yes, inside, it's probably been pushed back, I'd say four to six months on the science as well.

Scott Hanold:

Yes, thanks. I'm going to have a couple of questions. And I think you might have answered part of it in that last set of answers, but it sounds like there's some choppiness in his line that was hard to hear, but just to clarify, it sounds like Tug Hill, you don't anticipate any of these midstream issues to impact Tug Hill once you get that is part of EQT and also as part of that can you give us a sense of how much of the relative well outperformance underlying well outperformance, benefited EQT over the last say quarter or so.

Scott Hanold:

Got it. And then my follow up is on the shareholder return plan, obviously, you guys have had previously talked about doubling that the buyback pace and you've got a pretty good authorization out there $1.6 billion and I think that goes through 2023 along with the debt reduction. Is the goal here to really kind of eat through that authorization given your free cash flow profile, over the next year so should we expect you trying to utilize that as aggressively as possible. And with the buybacks if you can clarify exactly how much was done in the third quarter too.

Cameron Horwitz :

I think the number was close to probably $75 million I think or two.

Cameron Horwitz :

So -- but I think he's asking just for 3Q versus 4Q. So I think it's about -- roughly half was done in the third quarter, maybe a little bit more, and then a touch was done in the fourth quarter. And obviously, we'll probably do -- we'll obviously do more in the fourth quarter.

John Abbott:

Hey, good morning, and thank you for taking my questions. Toby, I want to go back to a question that Neal had asked a little bit earlier about XcL Midstream optimization. And what I'm trying to understand is yes, I understand this is going to allow you to optimize your program on the water side. But what is the ability to on that extend on your existing asset base? You do have dedication? So is it really on the Tug Hill assets? Are there other assets that you already have that you couldn't optimize on? How does that kind of work?

John Abbott:

Thank you. That's very, very helpful. And then for the second question, it's going to be on the new ventures. I mean, you discussed hydrogen here, and you are exploring other opportunities. What is the willingness to spend? What is your appetite to spend more on the new venture fund at this point in time?

Operator:

Our next question comes from the line of Noel Parks with Tuohy Brothers.

Toby Rice:

Yes, I think that the Tug Hill team has done a really good job with that asset base. So I think it's going to be, really confident, we're going to be able to at least replicate the success that they put out there. I also am optimistic and thinking that our drilling and completions teams will be able to showcase operational efficiency gains, like what we've done in the Alta assets. And that's simply a function of having access to the best technology, the best cruise that certainly is going to give us some tailwinds in doing that. What was the second part of that question about?

Toby Rice:

Yes, it's hard, as far as the development approach with the Tug Hill, and this is one of the things we look at when we're looking at acquisitions is are we -- is this asset going to be suitable for, large scale combo development and Tug Hill assets are because the Tug Hill team was intelligent, and adopting, full pad development. So there's not a lot of child wells that we have to move around, they fully developed their pads, which is a great development program that sets us up for combo development.

Toby Rice:

Yes, I think the most exciting technologies is technology that produces hydrogen and a solid form of carbon. And so we'll be testing some of that technology. But just standard technology that we know to make hydrogen today compare that with carbon capture, we can generate hydrogen, sub dollar 50 per kilogram. Right now, we look at hydrogen that the issues are really two issues before getting, big adoption of hydrogen. The first one is the cost for hydrogen. While we can make this stuff pretty cheaply, when you throw in the costs for transportation and the actual infrastructure takes to move hydrogen, you're looking at around $20 per million Btu. Why would the world choose that energy when they can buy natural gas for a price that's significant less than that. But what's really amazing is to think about when we Unleash US LNG, we will be creating an opportunity to rebuild, 50 Bcfe a day of new infrastructure in this country and when we build that infrastructure, we can build it hydrogen ready. And that means on lease US LNG, can underwrite a significant portion that is necessary to achieve the hydrogen economy is the future in this country. And if we can do that, then the feasibility of hydrogen becomes that much more attainable. And something that where is a really nice benefit of unleashing US LNG lowering emissions around the world is going to help us lower emissions within our borders. The second aspect of hydrogen that needs work is creating demand for this stuff. And so this is really the chicken and the egg. People haven't used hydrogen because it's not -- people aren't making and people aren't making because people aren't using it. This hub with having these this group of hydrogen producers and hydrogen consumers working together is going to allow us to get past that chicken and the egg issue and I think it's going to be a really great example of the collaboration necessary to make these exciting zero carbon solutions a reality. More to come.

Unidentified Analyst :

Hey, guys, thanks for taking my question. I just want to make sure that I have the debt reduction well understood. So you guys have done $830 million to date. Next year between the term loan, the convertibles and [Inaudible] that gets you up to about $3 billion of debt reduction. Is the plan for the other $1 billion to just come from buybacks in the secondary market or tender offer? Or is there some debt repayment that I'm missing in that calculation?

Unidentified Analyst :

Yes. And in terms of, if natural gas prices that we have a warm winter, and they're a lot lower than what strip is, would you dial back on the share buybacks to protect the debt repayment? Or would it be a mix of the two and you just wouldn't get to $4 billion reduction by the end of '23? How are you thinking of which is more important for cash flow? Which is the first use for --

David Khani:

That's right. We're going to -- we'll take a balanced approach to that and look at the value of our stock and look the debt and where it's trading and make the best decision.

Unidentified Analyst :

Oh, yes, it's not a question of you get in there. It's just if you get there by year end '23. But got you, sounds good. Thank you.

Kevin MacCurdy:

Hey, good morning, guys. I think all the questions in the delayed turn lines have been answered. So shifting gears a little bit. We noticed in the financials, there was a more positive impact from lower midstream than we anticipated. Can you talk about the financial impact of that heading forward and maybe strategic plans for that asset?

Kevin MacCurdy:

Great. And so the impact of Laurel Midstream, I think it was around $25 million this quarter. Is that a good run rate heading forward? Or was that driven just by the higher commodity prices that we saw in 3Q?

Operator:

Our next question comes from the line of Paul Diamond of Citi.

Toby Rice:

Yes. I think the industry range is sub between 10% and 20% inflation, so we should probably be at the lower end. And it is a moving target a little bit because, obviously, we don't have everything 100% locked up. And so we do have spot exposure to some commodities and things. So -- but if you look at steel pricing has come down, you look at some of the commodities have come down, you -- I think inflation in some of the equipment looks like it's slowing down. So I think we feel good about what we have contracted and kind of what the outlook for the open stuff is that should put us in a position. As you know, we invested in our sand infrastructure that reduce the last mile to last-mile delivery. You see we invested in the water system, which you can see how critical that is and when we took that into the Tug system. So we'll continue to reduce the inflationary impacts. And then obviously, we'll see what the new well design looks like for, we'll call it, the second half of '23 into '24?

David Khani:

Yes. It's a big focus for us has been the areas that we've seen the most dramatic increase in cost to date, which has been on the steel side of things. So we'll continue to focus on that.

Toby Rice:

Thanks, everybody, for joining us on this quarterly call. The world is certainly more volatile, but one thing that's consistent is our asset performance continues to show improvements. Our cost structure continues to decline. We have a free cash flow profile that's going to allow us to essentially retire our market cap and achieve our long-term leverage targets in the near term. And we've got a good track record doing some really smart consolidated deals on the consolidation front that's driven accretion and value creation for shareholders. And with our Unleash U.S. LNG campaign and the strengthening desire for cheap, reliable, clean energy that is going to be American-made natural gas, I think is going to present a pretty exciting and compelling opportunity for sustainable growth for our shareholders, and we're really excited about the future. And we'll talk to you guys' next quarter. Thank you.

Cameron Horwitz:

Good morning, and thank you for joining our second quarter 2022 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer; and David Khani, Chief Financial Officer. The replay for today's call will be available on our website beginning this evening. In a moment, Toby and Dave will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements, because of the factors described in yesterday's earnings release, in our investor presentation and the Risk Factors section of our Form 10-K and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

David Khani:

Thanks, Toby, and good morning, everyone. I'll briefly summarize our second quarter results before discussing our balance sheet, hedging, basis and guidance updates. Sales volumes for the second quarter were 502 Bcfe, in line with the midpoint of our guidance. As Toby mentioned, we implemented new technologies during the quarter to address the tight trucking market we experienced in the first quarter. This is paying off as we saw a material improvement in completion efficiency on a sequential basis. Our adjusted operating revenues for the quarter were $1.6 billion or $3.21 per Mcfe, and our total per unit operating costs were $1.37. As a result, our operating margin was $1.84 per Mcfe, about $0.80 or 75% higher than last year on higher volumes and price realizations. Capital expenditures were $376 million, in line with the high end of our guidance range. Adjusted operating cash flow was $915 million and free cash flow was $543 million, bringing our total year-to-date free cash flow to more than $1.1 billion. Our capital efficiency for the quarter came in at $0.75 per Mcfe, which was up sequentially due to greater spending on science associated with our new completion design and continued inflationary pressure. Turning to the balance sheet. Recall, we achieved investment-grade credit ratings from Fitch and S&P earlier this year, underscoring the material progress we made in creating a more sustainable company for our stakeholders. As Toby mentioned, we are taking even more action to bull-proof our balance sheet through all parts of the commodity cycle by raising our year-end 2023 debt reduction target by $1 billion to $2.5 billion. This will reduce our gross debt to approximately $3 billion and accelerate achieving our long-term leverage target of one to 1.5x using a $2.75 gas price. We are not wasting any time executing our goals as we deployed approximately $390 million over the past several weeks, including repurchasing approximately $175 million of senior notes and $213 million of convertible note principal and premiums. We note that the retirement of convertible notes executed to date has lowered our fully diluted share count by approximately six million shares while also simplifying our balance sheet. At the end of the second quarter, our trailing 12-month net leverage stood at 1.6 times, down 0.3 turns from the prior quarter. Note, our net debt at quarter end reflects the impact of approximately $690 million of working capital usage during the quarter, the bulk of which should reverse in the second half of the year. At recent strip pricing, we forecast our year-end 2022 and 2023 net leverage to be approximately one time and 0.1 negative times, respectively, which contemplates executing the remainder of our buyback authorization and accounts for a 20% dividend increase. We ended the quarter with approximately $2.2 billion of liquidity, and we recently renewed our $2.5 billion unsecured revolving credit facility with a five-year maturity. Two key points to note here. First, we added two new banks to our bank syndicate. Second, we were easily able to maintain our credit size while most revolvers have shrunk by approximately 15%, both of which showcase the underlying credit of our business and the strength in our bank relationships. As noted in the SEC filing earlier this month, we exercised our option to receive a cash payment of $196 million from Equitrans Midstream in lieu of a portion of near-term fee relief. We expect to receive proceeds by late 3Q or early 4Q. As shown in slide 18 of our investor deck, this cash election does not impact the $0.15 per Mcfe long-term gathering rate reduction from today's levels. Also, we still model an MVP start-up in fourth quarter 2023. Moving over to hedging. During the quarter, we opportunistically restructured our hedge book for 2023. Specifically, we converted the bulk of our remaining 2Q through 4Q 2024 swap positions into costless collars. For the summer, we placed approximately $4 floors and $6.25 ceilings; and in the winter, $7.30 floors with $11 ceilings. The positive market skew at the time enabled us to set $3 of upside with only $1 downside, tying to our plan to provide stakeholders with strong risk-adjusted upside. Separately, as we've seen signposts of global economic slowdown, we thought it would be prudent to add floors to our 2023 hedge book, buying approximately $4.55 puts with premiums that we were able to defer into 2023. With these actions, we are now approximately 50% hedged on our 2023 volumes, predominantly with wide collars and puts. As an illustration of the resiliency of our forward outlook, if NYMEX retraced to approximately $3 per MMBtu in 2023, we would still expect to generate approximately $1.6 billion of free cash flow next year or a 10% free cash flow yield. Conversely, if natural gas averaged $7 per MMBtu level, we would expect to generate almost $6 billion of free cash flow in 2023 or nearly a 40% free cash flow yield. Now turning to LNG. As Toby mentioned, we are making progress on our strategy and see an increasingly bullish setup for global natural gas fundamentals on a multi-decade basis. We expect global natural gas demand outside of North America to grow from approximately 285 Bcf per day today to 375 Bcf per day by 2050. This means supply growth equivalent to doubling the entire US natural gas production base is necessary to balance the global market in less than 30 years. There is a growing recognition both domestically and abroad that we are unlikely to meet this demand without significant incremental production from Appalachia, which is home to the longest runway of low breakeven, low carbon intensive natural gas inventory in the world. As noted in our unleash US LNG deck, resource quality and longevity dictate that 70% of incremental US LNG export growth will ultimately need to come from Appalachia. Equity is currently in various stages of discussion for supply agreements covering approximately one Bcf per day of FT capacity to the Gulf Coast. We are looking at ways to catalyze East Coast LNG, which could have meaningful ramifications to our Appalachian production long-term. Turning over to guidance. As we noted last quarter, we saw pricing pressures broaden across all service lines. We experienced some further inflationary impact since our first quarter call, and as such, we are raising our 2022 CapEx guidance range to $1.4 billion to $1.5 billion, the midpoint of which is in line with the high end of our prior guidance. As highlighted in slide 13 of our slide deck, our contracting strategy provides significant risk mitigation on a go-forward basis. The most notable is our long-term sand supply agreement and frac crew contracts we extended to 2024 and 2025. We are reiterating our 2022 EBITDA and free cash flow guidance ranges, but see bias towards the upper end. Note that our guidance reflects strip pricing as of July 2022. Given a structurally superior hedge position next year, our 2023 free cash flow should expand by approximately 100% year-over-year, providing differentiated free cash flow per share growth even with flat production volumes. Again, using strip pricing, we see approximately $22 billion of cumulative free cash flow through 2027, which is net of all expected cash taxes and hedge premiums. I'll now turn it back over to Toby for some concluding remarks.

Operator:

We will now begin the question-and-answer session. [Operator Instructions] The first question is from the line of Arun Jayaram with JPMorgan. You may proceed.

Toby Rice:

Sure, Arun good morning. So as it relates to our capital allocation framework, I think what we've done is set out authorizations that we know we can execute, but as you mentioned, we do have flexibility to go above there. I think the flexibility is important because we want to make sure that we are matching the allocation decisions with the environment that we're in. I think there's a lot of clarity on the debt retirement goals that we've stated. But to put a little bit more color on our buyback approach, our buyback approach is opportunistic, and we believe that's appropriate given the current volatility that we see in this world. But understand that that's tough to model, the buyback pace that we have. So I'd ask you to look at what we've done in the past. In Q1, we've taken advantage of our buyback authorization and bought back over $240 million worth of stock, retiring about 9.9 million shares. In Q2, we repurchased about $213 million of convertible notes, and that has the impact of retiring around 5.7 million shares. So over the past two quarters, we've retired over $400 million of shares, retiring about 15 million shares at an average price of around $31 per share. I think the approach is providing some pretty good results. But look at what we can do in the future, and we have the opportunity to continue that pace. We're, obviously, stepping into a more robust free cash flow generation phase of this business, and I think the opportunity for us to do more is appropriate.

David Khani:

Yeah. So I'll answer that question. Yeah, no cost. Everything was done at market, and so no cost to us. So if you step back and just give you high levels, right now, with our hedges in place, we basically have a $2.92 floor and we have approximately $4.95 ceiling. And so that's the bounds of -- and we're about 45% -- I'm sorry, about 50% floors, and we're about 45% ceiling. So that provides the risk adjusted benefit. If the floors were reached, we'd be about $1.5 billion. If the ceiling would be reached or breached, it would be about almost $4 billion. So that just gives you a sense of range of outcome there. With the repositioning, okay, we basically converted our swaps, which we'll call it about 10% of our hedge position was converted into costless collars. And as I said earlier on the prepared comments, the SKU was about $3 up and $1 down. And if you look at the value today, that position that we did is about $110 million into the money. And if we hit the ceilings of that -- of what we just did, we would create about $450 million of upside on free cash flow. So that gives you a sense of magnitude of what we did and it allows investors to understand how we have -- we think about the risk-adjusted upside.

David Khani:

Welcome.

Umang Choudhary:

Hi, good morning, and thank you for taking my question. My first question was on the well performance. Any -- from the next-generation completions, any early read through there? And then if it is successful, how would that change slide number 12? How much of that inventory would you be able to add with the sub-250 breakeven?

Umang Choudhary:

That's helpful. And maybe next question is on the LNG strategy. You mentioned that you are in discussion with a lot of LNG customers. How are the discussions progressing? And what are the key points which the customers are looking for more clarity on?

Umang Choudhary:

All right. That’s helpful. Thank you.

Operator:

Thank you. The next question is from the line of Neal Dingmann with Truist. You may proceed.

Toby Rice:

Production capacity, yes, Neil. Pipeline capacity in Appalachia, we've finally reached the limit of the midstream takeaway capacity in Appalachia. And as long as that's the case, we are going to remain disciplined in maintenance production mode. We put a slide in our deck that sort of shows the dynamics of what's taking place on slide 29. One of the questions we get a lot is people have said, we say, well, why aren't we able to add more supply. We've got the biggest natural gas field in the world, and we cannot use that to help lower energy prices for Americans. Why is that? And we say, well, because we don't have pipelines. They've been blocked, canceled and opposed over the last 10 years. And people say, well, we've been blocking pipelines for the last 10 years and we've been able to experience low energy prices. Well, the reality is we've always had excess pipeline takeaway capacity out of this basin during those times when those pipelines were canceled. Those would have added to that capacity. We've hit the wall now. And that's why EQT is going to continue to remain disciplined. And it's an opportunity for this country to recognize this and say that -- and get more pipeline LNG infrastructure built in this country so we can address the growing demand for natural gas.

Toby Rice:

Yeah, Neal. So I think, anything -- any asset you look at, I think you want to make sure you're getting quality. So we definitely compare asset quality versus ours. I think you look at Alta the cost structure that that asset base did, it lowered our cost structure of this company, lowered our breakevens by over $0.05. So that's one consideration. But I mean, at the end of the day, everything we do on M&A is going to be. It's got to be more accretive than buying back our stock, and that's the ultimate decision.

Toby Rice:

Thanks, Neal.

Operator:

Thank you. The next question is from the line of Scott Hanold with RBC Capital Markets. You may proceed.

Toby Rice:

Yeah. So I sort of segregate the LNG into two categories, the Gulf Coast and the East Coast. From a Gulf Coast perspective, it's really more about looking at the best ways we can commit our supply to projects. I don't think that the capital is needed down there to get projects off the ground. On East Coast, for us, I think there's an opportunity for us to help identify projects and work with developers to get these projects off the ground. So, I mean, we're doing some feasibility work and some high-level assessments of what some of those projects would look like, but not a significant amount of dollars being thought up to apply to East Coast LNG. Obviously, for us, why spend dollars. Even on the feasibility side, I think East Coast LNG just could be so incredibly impactful to EQT and Appalachia, creating a demand source next to where we operate should help strengthen basis that would have an impact, not just on the volumes that we're able to supply to those facilities, but would also impact the amount of gas that we sell in basin. So there's just a lot of reasons why there's reasons for us to really want to push to get East Coast LNG and make that great idea a reality.

David Khani:

Yeah. So it really depends upon where the stock is and where the convert is. So right now, the convert is way in the money, and so it trades very much like the equity. There is a little bit of premium for – we'll call it, for future dividends and things like that that you have to account for. But effectively, it now, it's very much akin to equity. But there is a percentage that you would strive to the debt side as principle. So I think just know we have basically two tools in place, right? So we have the – we'll call it the direct way where we have our $1 billion buyback, and then we have the indirect way, which gets captured really in the $2.5 billion of debt principal that we have authorized to retire. So we have really two ways that gives us the flexibility to attack the equity. And where there's disconnects or things, we can try to play that arbitrage.

Toby Rice:

You’re welcome.

John Abbott:

Good morning, and thank you for taking my questions. Toby, the first question is for you. It's on inventory in West Virginia. During the first quarter call, you had mentioned the potential benefits of West Virginia signing in the pooling and utilization law. When you look at those 1,800 locations, the distribution, does that take into account those potential benefits? And have you had the time to assess what the benefits are to your inventory?

John Abbott:

Appreciate it. And the next question is for you there, David. It's going to be on your cumulative free cash flow outlook and on cash tax. For that six-year outlook, just curious, does that assume – does it have an inflation assumption baked in for 2023 already? And then second, on the cash tax, I recognize you would provide more color at some point later during the year. But as you sort of look out to 2027 or this is more of a calibration cash tax question, are you more of a 15% cash taxpayer or more of a 20% cash tax payer long term?

John Abbott:

Thank you very much. Thank you very much for the color and for taking our questions.

Toby Rice:

Thanks.