EQT Corporation (EQT) Q3 2022 Earnings Report, Transcript and Summary

Welcome to the EQT Q3 2022 Quarterly Results Conference Call. My name is Harry, and I will be your moderator for today's call. [Operator Instructions] I would now like to hand over to Cameron Horwitz, Managing Director of Investor Relations and Strategy to begin. Cameron, please go ahead when you are ready.

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.

Thanks Cam. And good morning, everyone. The energy macro landscape remains volatile as the world continues to grapple with a structural under supply of natural gas. Thanks to American source LNG, Europe has done a commendable job refilling its storage over the past few months. But those thinking that the singular goal is making it through winter failed to understand the scale of the problem at hand. Any doubt that the European energy crisis is going to be multiyear and duration ended a few weeks ago with the sabotage of the Nord Stream pipelines. Domestically natural gas production has increased as of late, which is helping to ensure the US has the energy it needs to meet demand this winter. That said, electricity prices in many parts of the country remain extremely elevated. Highlighting the continued challenges we face connecting natural gas supply with demand due to a lack of pipeline infrastructure. As many of since unveiling our Unleash US LNG campaign in March, we have been on a relentless mission to educate policymakers on the driving factors limiting US producers' ability to meet the critical energy needs of consumers, both domestically and abroad. The social pain caused by crippling energy prices around the world is unacceptable to us at EQT. The US has the recoverable resources if necessary to single handedly double the global LNG market, providing both energy security and meaningful decarbonization through the replacement of foreign coal. While recent setbacks around permanent reform has been unfortunate, we continue to believe the US public's overwhelming desire for additional natural gas production and infrastructure will be heard. To help ensure that this is the case we recently spearheaded the launch of a new coalition. The Partnership to Address Global Emissions or PAGE coalition. PAGE brings together responsible energy producers, leading climate advocates and labor groups to advocate for the infrastructure that is critically required to increase production and exports of US natural gas to lower global emissions, reduce inflation and provide energy security to America and her allies. PAGE provides another avenue for EQT to help progress truly sustainable energy solutions that are required to have a meaningful impact on lowering global emissions, while simultaneously providing a tool to end the global energy crisis that is bringing unnecessary pain to consumers around the world. Turning to the third quarter, it was an active one at EQT as we announced the bolt-on acquisition of Tug Hill and XcL Midstream, as highlighted on our conference call last month, this deal checks all of the boxes of our guiding M&A principles have significant industrial logics given direct offset to our existing lease sold in West Virginia, and brings over 11 years of core inventory that immediately competes for capital inside and in EQT's portfolio. The acquisition drive discretion on free cash flow per share, NAV per share, lowers our cost structure and de-risks our business all while maintaining our investment grade balance sheet. The acquisition implies we are paying a sub $3 per million Btu long-term natural gas price underscoring the attractive risk adjusted return profile for our shareholders. Given the low-cost nature of Tug Hill's assets, we expect our corporate NYMEX free cash flow breakeven to drop from approximately $2.30 to $2.15 per million Btus on a pro forma basis, which adds further resiliency to our free cash flow profile to all parts of the commodity cycle. As a reminder, we did not bake in any synergies when underwriting this deal, but we highlighted $80 million of per annum potential and additional subsequent work by our teams suggests the opportunity for further upside largely due to greater competence in water system integration benefits. We continue to expect the transaction to close in the fourth quarter of this year and look forward to providing pro forma guidance after closing. Concurrent with the Tug Hill acquisition announcement, we raised our year end 2023 debt reduction target by $1.5 billion to $4 billion and doubled our stock buyback authorization to $2 billion. We've made material progress toward our debt reduction goals with $830 million of debt retired year-to-date. On the buyback front while securities laws prohibited us from repurchasing stock for a significant amount of the quarter due to the Tug Hill transaction, we have been active post deal announcement repurchasing 3.6 million shares for approximately $150 million in mid-September. Recall, we repurchase roughly 10 million shares in Q1 at an average price of around $23 per share, and effectively retired 5.7 million shares through our convertible note repurchases in Q2 at an implied share price of $37 per share. Combined with our activity over the past few weeks, we have now reduced our fully diluted share count by more than 19 million shares this year at a weighted average price of $31 per share. Looking ahead, we still have approximately $1.6 billion remaining on our buyback authorization, providing significant dry powder to repurchase our shares at an extremely attractive valuation. We will also look to redeploy cash savings from retiring debt, repurchasing shares and our realization of Tug Hill synergies into additional base dividend growth moving forward. Also in the third quarter, we announced a collaboration with the state of West Virginia, BATTELLE, GTI Energy & Allegheny Science & Technology Appalachian Regional Clean Hydrogen Hub or ARCH2. Appalachia is ideally suited to lead the charge in clean hydrogen production in the United States. Given abundant, low cost, low emissions natural gas, interconnected infrastructure and storage, existing transportation networks and proximity to major end use markets. The ARCH2 team is comprised of entities with operations across the Appalachian region, banding the hydrogen value chain, as well as technology organizations, consultants, academic institutions, community organizations, and NGOs that will provide commercial and technical leadership for the development and build out of the hub. Coalition plans to apply for the DOE regional clean hydrogen hub funding opportunity, which seeks to provide $8 billion in federal funding to accelerate the deployment of US hydrogen technologies and contribute to decarbonizing multiple sectors, while enabling regional and community benefits. We plan to submit our concept paper to the DOE this winter and our full application by next spring. With final deal we hub selection expected in the fall of 2023. During preparation of the concept, paper and full application, EQT and the rest of the ARCH2 coalition will design the hydrogen hub and develop projects that spanned the hydrogen value chain from production to transportation and storage all the way to end use. For the Funding Opportunity Announcement issued by the Department of Energy in September, the winning hub teams will be awarded between $500 million and $1 billion which can help subsidize all the projects included in the application. In terms of EQT capital commitments, we do not anticipate incurring any significant spending related to ARCH2 until the latter part of this decade. The ARCH2 announcement comes in an ideal time as the world is demanding cheaper, more reliable and cleaner energy. And we believe the use of EQT's extremely low emissions natural gas to create clean hydrogen can act as a strategic foundation for America's transition toward decarbonization. Our participation in ARCH2 is just one of many pillars across our broader new venture strategy, which is designed to uniquely positioned EQT in forging new paths and opening new markets as we progress into a lower carbon future. Turning to operations as shown in slide 11 of our investor deck, our shift to combo development in 2019 as new management took over EQT has resulted in multiyear well productivity improvements. Our 18-month lateral normalized recoveries are up almost 45% since 2019, which is greater than 2x the productivity increase experienced across broader Appalachia over the same period. This outperformance has been largely driven by the implementation of our evolves well design and mitigation of parent child effects through large scale combo development. While our underlying well productivity has been strong, multiple third party and logistical constraints this year have led to almost 30% less wells turned in line versus our original plan, pushing activity into 2023. These third-party constraints along with water restrictions due to drought conditions in parts of the basin negatively impacted our 2022 production by more than 150 Bcfe or 7% compared with our original volume expectations. Strong low productivity and great work by EQT's team to optimize field operations has helped to buffer the impact and clawed back almost 50 Bcfe of this volume impact. The net effect is our full year 2022 production is trending to the low end of our prior guidance range, while our full year 2022 CapEx is also trending towards the lower end of our prior outlook. While third party challenges have been disappointing this year, they also underscored the opportunity we have in front of us to integrate the Tug Hill and XcL assets to maintain greater control over infrastructure build out, facilitating more pipeline connectivity and enable additional operational flexibility across our asset base moving forward. Shifting to market dynamics, we were very pleased to see EQT added to the S&P 500 Earlier this month. We view inclusion in this index as another testament to our premier asset base, excess of our modern, digitally enabled operating model and the overall sustainability of our business. I want to thank all of our employees for their hard work evolving EQT into a world class organization that competes with the top companies across all segments of the economy. I'll wrap up by saying that despite EQT's stock performing reasonably well on a year-to-date basis, we believe the market has not remotely begun to reflect at the intrinsic value of our business, or relative quality versus peers. We are at a unique point in time, as the North American natural gas market is in the process of an unprecedented structural shift, as it is the bottleneck through LNG and the world is increasingly recognizing the role natural gas will play in providing affordable, reliable, low carbon energy for decades to come. EQT is among the best position companies in the world to benefit from the secular trend underpinned by a capital efficient asset base, unrivaled depth and quality of inventory and declining midstream fees. We believe these characteristics combined to create a superior value proposition for investors and will ultimately be reflected in our share performance as these factors are converted into durable free cash flow that we can compound over time. I'll now turn the call over to Dave.

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.

Thanks Dave. To conclude today's prepared remarks, I want to reiterate a few key points. One, the pending Tug Hill and XcL acquisition underscores our disciplined M&A strategy, adding low risk bolt-on assets to our business with clear industrial logic, a compelling valuation, material cost structure accretion and the opportunity to capture meaningful synergies. Two, we have returned approximately $1.5 billion of capital to shareholders this year, including almost $600 million of share repurchases and convertible note retirements at an average price of $31 per share. And our updated capital returns framework on the back of the Tug Hill deal provides material room for additional shareholder returns moving forward. Three, our move to combo development has driven significant well productivity gains since we took over EQT in 2019. And this tailwind along with our team's optimization efforts, has allowed us to ameliorate the impact of third-party constraints this year. Four, the ARCH2 hydrogen hub collaboration has the potential to lay the foundation for the next leg of decarbonization efforts at EQT, taking advantage of differentiated access to vast low-cost low emissions natural gas in Appalachia. And finally, we were honored to join the S&P 500 earlier this month, and see our inclusion in the index representing another significant milestone on EQT' 's journey to becoming the operator of choice for all stakeholders. I'd now like to open the call to questions.

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

Good morning, Toby. One of the early things from earnings has been some of the midstream issues that we've seen in the Appalachian Basin. You guys talked about it in a range and Antero as well. So I was wondering if you could maybe describe what you're seeing in terms of on the ground in terms of the general constraints? And maybe specific to EQT, when do you anticipate to get resolution on some of the issues that did affect your TIL count this year?

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.

Got it. So for, you've highlighted $150 million prior some of the optimization work where you clawed back $50 million. If the buyside consensus has been around on a standalone basis, caught 2 Tcfe of production next year, do you think that you can get a range similar to that just given you are likely going to have some, I don't know if they're ducks, but you may have some tailwind from some of those wells that are in progress. But just general thoughts on output next year, as big as some of these constraints get better.

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.

And our next question comes from the line of Umang Choudhary of Goldman Sachs.

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?

Yes, Umang, so yes, I'd say the activity set should be fairly normal to for normal year. It's just the timing of when the wells will come online. So the bucket of wells that got pushed out in '22 have about a five-month lag time of putting them online due to the water issues that we had. And so that's why we'll get back to sort of that $500 million plus run rate by mid-year. But the activity set overall should be a cost standard fairly normal per year.

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.

Yes, conversations are still progressing across the LNG value chain from LNG developers, marketers and buyers. I'd say the desire for bringing more LNG into this world has continued to strengthen, and we're having some pretty good conversations, but we'll come back when we have anything that materializes into something material.

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

Good morning, Toby. I'd just circle back on the infrastructure; I was just trying to get a sense. So you talked about maybe just the degree of the curtailment between the different issues. I know, you mentioned the waters already been rectified. Just trying to find I guess, number one, what other issues were involved? And then secondly with obviously the XcL Midstream coming on, how much will that and some of the things you're done helped to sort of the situation going forward?

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.

Got it, okay. And then just a follow up. Could you talk and I am looking at that slide. I forget which one it is it shows with four rigs are running when you look now at the Northeast PA, Ohio, Utica, Southwest, West Virginia, Marcellus, is there any one or two there? Is that from returns is standout? Or are they just wondering, these days if you were to rank those, how you think about the four? Are they all sort of equally return basis these days in the ballpark?

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.

Now, the improved ops are obvious from the previous owners. Thanks, Toby.

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

Thank you. Good morning, everyone. Thanks for the time, Toby. I know you discussed a lot about this, but maybe if you could revisit just the original plan in '22 versus '23. I am trying to get sense on some of the moving parts. Obviously, the 30% fewer TIL this year, but is there any capital benefit from any wells that would be in process that we've met in 2023?

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.

Okay. And then I guess just a follow up on that, I guess as we think about '23. I suppose if you're thinking about like a balanced program between sort of core Western Pennsylvania versus West Virginia, Northeast PA, I guess, shall we see that kind of percentage of completions moving back to what we would have seen on a sort of a geographic blend in '21, '22 x maybe the additions with Tug Hill or I guess, would that activity be kind of shifted away from Northeast PA, back into the western region?

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 --

Okay. And if I could just sneak one in. Just in any way, the delay that you saw in '22, that delay your program understanding around sort of this enhanced completion design that you all have talked about kind of earlier in the year?

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.

And our next question is from the line of Scott Hanold of RBC Capital Markets.

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.

Sure, I think one thing that's very helpful with the Tug Hill asset is the fact that we will control and operate the midstream that's going to give us much more operational control and the ability to mitigate any issues. As far as production uplift is concerned. I mean, that's been the majority of the productivity gains has been well performance and also increasing, keeping, I'd say pure leading production uptime. Some of the other benefits that have come out of this and these efforts to enhance our ability to produce and meet schedule, there have been some best practices identified that will be incorporated and allow us to accelerate some volumes and shorten the cycle times on our base development plans going forward into the future. So there is a bright side of the dealing with these.

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.

Yes, so I mean, I think given where the stocks trading today and fact that are we can buy back our debt at pretty attractive levels. We're going to be aggressive towards, fulfilling the authorizations that we have in front of us on both aspects of that. Cam, did you have the number specifically in 3Q?

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

We've got $150 million, since -- September so.

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.

Our next question is from the line of John Abbott of Bank of America.

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?

Yes, on the water side, pretty tremendous opportunity. As you guys know, we've been building out our water network in West Virginia, to connect that water network to the Tug Hill assets, it's a very short jump, to put some water infrastructure in place to connect those two systems. This is going to allow us to manage produce water, pretty much across north, the western half of West Virginia. The benefits on the completion side, and surety on water delivery, the benefits on recycling, the benefits on just the logistics of handling produce water are very clear and a big part of the synergies that we're counting on so outside of the water, having the -- on the gathering side of things, being able to connect the Tug Hill system to some points we have in Ohio, that will streamline some of our gathering systems. And that will lead to some synergies as well. So the good thing with Midstream, I think the synergies that you can identify are typically pretty low risk. And so it's nice to see that we've got a complementary asset base that we can translate into synergies.

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?

Yes, that's a great question. I think, slide 7, we put a chart out there that I think really frames up how we think about this, when we think about new ventures, this is to help the energy transition that is taking place in the world. And the way that we look at energy transition is really in two parts. Number one, what can the United States do to continue to reduce emissions within its borders? But the most important question is, what can the United States do to reduce emissions outside of our borders, Unleash US LNG fits in the category of what the United States can do to lower emissions outside of our borders, that is the biggest green initiative on the planet. When we do that, we're going to be creating a surplus of natural gas in the United States, while slated for exports, it's going to create a number of opportunities where we can use natural gas to decarbonize the United States, and ultimately move from, gas to lower to zero carbon energy sources, like hydrogen, like carbon capture. And so while those concepts right now, I think, are a little bit unsure on what the profitability of those look like, we will invest modestly in those, I'd say more zero carbon technologies, this is going to allow us to achieve our higher purpose of lowering emissions in the United States. But before we would put any dollars, significant dollars there, we need to understand the profitability of those so really, the dollars that we're doing inside the US borders are really driven by the pilots to get an understanding of what the returns will look like. And then we'll get bring it back to our capital allocation framework. And see if this is the best use of our dollars, but we're definitely going to be leading on framing up what the type of returns perspective looks like, specifically around hydrogen and to have this coalition, this ARCH2 hub, is really going to position EQT to be very efficient with our time and dollars.

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

Hi, good morning. Couple of things. I wondered and probably we've touched on this already with Tug Hill now that you're a couple of months down the road since the announcement, could you just talk about sort of where they stood as far as their joining completion procedures? And also, any insight you have on sort of what they had done themselves on sort of parent child mitigation practices?

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?

Oh, well, just about parent child.

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.

Great. And just turning to the hydrogen project. Just wondering, do you have any thoughts at this point, as far as what maybe the technology evaluation process might be as far as hydrogen generation, I'm mindful, of course, that you have the relationship you struck with Bloom Energy. And so their fuel cell technologies being just one example. So at this stage, do you have any thoughts on what direction might go, whether you're going to be looking at casting a wide net of technologies to look at, or we have a pretty good idea of what sort of as you'd like to head down?

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.

Our next question is from the line of Daniel Lungo from Bank of America.

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?

Yes, so no, between the term loans, and the callable notes that's about a little over $2 billion. And we'll just figure out how we get the remaining piece, whether it's open market tender, whatever, we'll get to our targets. As you know, there's not a lot of friction in this environment, as the Fed is raising rates and, principal values keep coming down as a result of it. So we'll be able to achieve our targets, I think fairly efficiently.

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 --

Yes, I would say, we have cushion here because each range because of principal values have come down in our debt, so I just say, we'll, if for some reason, we have to make that choice, but that's going to be more of a game plan decision. Gotcha.

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.

Yes, I mean, the other thing to also think about is, we have so much free cash flow, even beyond '23. That we have to think about how we use that as well.

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.

[Operator Instructions] And our next question is from the line of Kevin MacCurdy of Pickering Partners.

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?

Yes, so as you know, we own 35% of that system. And what happens is we get a rebate effectively from the -- that doesn't hit our unit costs, it comes in as other basically. And that's just the function of as prices go up, our unit costs go up in that system, but then we get a rebate in this other area. And so that's how it works. So effectively, the unit costs are really netted down. Right now, we don't have any plans to sell it. I mean every once in a while, we get approached by outside buyers. But right now, as you can imagine we've made two acquisitions subsequent to Chevron, and they both had midstream, and so just know that midstream helps us control operations and lower our costs. And so the desire to sell midstream is probably low on our list.

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?

By the higher commodity prices. So it's -- yes, so our unit costs go up tied to M2, and then we get the 35% rebate effectively through our ownership. So you got to look at MCX, that will be -- determined.

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

Good morning, all. And thank you for taking my call. Just a quick one. I wanted to circle back on the budgeting process for 2023. I know you guys noted that you expect to be on kind of the lower end, the broader industry range. But that broader industry range has been a bit of a moving target. Could you give a bit of clarity on kind of where you guys see that going into that budgeting process and into next year?

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?

Understood. And actually, just drilling down a bit deeper on that. Are there any particular area you guys have seen through the budgeting process and the conversations thus far that -- what's the area you're least comfortable with? Any area that's given you a particular concern or anything you've noted?

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.

And we have no further questions. It would be my pleasure to hand back to Toby Rice for any closing remarks.

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.

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