Welcome to the EQT Q3 2022 quarterly results conference call. My name is Harry, and I'll be coordinating your call today. If you would like to ask a question during the Q&A, you may do so by pressing star one on your telephone keypad. I'd now like to hand over to Cameron Horwitz, Managing Director of Investor Relations and Strategy to begin. Cameron, please go ahead when you're ready.
Good morning, and thank you for joining our third quarter of 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, 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.
Thanks, Cam, and good morning, everyone. The energy macro landscape remains volatile as the world continues to grapple with the structural undersupply of natural gas. Thanks to American-sourced LNG, Europe has done a commendable job refilling its storage over the past few months. Those thinking that the singular goal is making it through winter fail to understand the scale of the problem at hand. Any doubt that the European energy crisis is going to be multi-year in 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 U.S. 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 you know, since unveiling our Unleash U.S. LNG campaign in March, we have been on a relentless mission to educate policymakers on the driving factors limiting U.S. 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 U.S. has the recoverable resources 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 permitting reform have been unfortunate, we continue to believe the U.S. 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 U.S. natural gas to lower global emissions, reduce inflation, and provide energy security to America and our 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, has significant industrial logic given direct offset to our existing leaseholds in West Virginia, and brings over 11 years of core inventory that immediately competes for capital inside EQT's portfolio. The acquisition drives accretion 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 BTU on a pro forma basis, which adds further resiliency to our free cash flow profile through 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 per annum potential and additional subsequent work by our teams suggests the opportunity for further upside, largely due to greater confidence 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 since mid-September. Recall, we repurchased 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, and Allegheny Science & Technology to form the 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, spanning the hydrogen value chain, as well as technology organizations, consultants, academic institutions, community organizations, and NGOs that will provide the commercial and technical leadership for the development and build-out of the hub. The coalition plans to apply for the DOE's Regional Clean Hydrogen Hub funding opportunity, which seeks to provide $8 billion in federal funding to accelerate the deployment of U.S. 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 DOE 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 span the hydrogen value chain from production through transportation and storage, all the way to end use. Per 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 at 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 position 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 two times the productivity increase experienced across broader Appalachia over the same period.
This outperformance has been largely driven by the implementation of our evolved 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 well productivity and great work by EQT's team to optimize field operations have 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 toward the lower end of our prior outlook. While third-party challenges have been disappointing this year, they also underscore 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, success of our modern, digitally enabled operating model, and the overall sustainability of our business.
I wanna 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 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 debottlenecked 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-positioned companies in the world to benefit from this secular trend, underpinned by our capital-efficient asset base, unrivaled depth and quality of inventory, and declining midstream fees.
We believe these characteristics combine 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 wells to just 16 versus our guidance range of 22-32. 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 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, bringing our total year-to-date free cash flow to approximately $1.7 billion. Our free cash flow also reflected a basis differential of $1.02 per Mcfe, wider than our guidance of $0.80-$0.90 per Mcfe due to wider local differentials and an 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 twelve-month net leverage stood at 1.3 times, down 0.3 turns from the prior quarter. To fund the Tug Hill and XCL Midstream acquisition, we raised $2.25 billion of debt, which is leverage neutral 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 our banks and our institutional investors. Despite a challenging credit environment, we priced our two tranches of senior notes at 175-200 basis point spreads to respective 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 as another testament to the underlying credit quality of our business and value the support we receive from our banks and bondholders. As highlighted with the deal announcement, we raised our year-end 2023 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 1-1.5 times using a conservative $2.75 per MMBtu NYMEX gas price.
We've already executed $830 million of debt reduction goals this year and expect to make material additional progress over the coming quarters, given 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 liquidity items to point out. First, we replaced approximately $180 million of letters of credit with surety bonds during the quarter. Second, we received $196 million from Equitrans Midstream subsequent to quarter end as we exercised our option to receive cash in lieu of a portion of near-term fee relief. Now moving over to hedging.
As mentioned on our Tug Hill acquisition call, we added to our legacy hedge book in the third quarter, taking our hedge volumes 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 and an average ceiling of $10.80 per MMBtu.
On a pro forma basis, we have approximately 60% of our 2023 production hedged with floors at 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 out our hedge position. Turning to guidance, as Toby mentioned, the third party and logistical constraints have reduced our planned 2022 wells by approximately 30% versus our original outlook. Strong underlying well performance and well optimization have mitigated the impact to 2022 sales volumes, which are now expected to be 1,925-1,975 Bcfe, or roughly in line with the lower end of our prior guidance range.
We are also lowering our full-year capital expenditure guidance to $1.4 billion-$1.475 billion, excluding acquisitions to reflect the lower drill 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 multi-year 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 that are at the lower end of broader industry ranges for next year. Given our structurally superior hedge 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 wanna 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. 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.
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. 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.
If you would like to ask a question, please dial star followed by one on your telephone keypad now. Our first question of the day is from the line of Arun Jayaram of JPMorgan . Arun, your line is now open.
Good morning, Toby. One of the early themes from earnings has been some of the midstream issues that we've seen in the Appalachian Basin. You guys talked about it, you know, Range and Antero as well. 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 drill count this year?
Yeah. Good morning, Arun. One thing I think that's worth noting is the waterline issues have been resolved. The pipelines have been fixed, and 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 be nagging at us, but we're doing everything we can to build in more flexibility into our program. I'd say all of these impacts together largely are behind us, and I think we should be back on pace by mid-2023 with that 2 TCF a day run rate production base.
So for, you know, you've highlighted, you know, 150 Bcf, you know, prior to some of the optimization work where you clawed back 50. You know, if the buy-side consensus has been around on a standalone basis, call it 2 TCFe of production next year, do you think that you can, you know, get to a range similar to that just given, you know, you are likely gonna have some, you know, I don't know if they're DUCs, but you may have some tailwind from some of those wells that are in progress. Just general thoughts on output next year, as maybe some of those constraints get better.
Yeah, 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. 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. I think, I mean, the punchline is, you know, the team has shown the ability to claw back and we're still fighting for every Mcf and every Mcf. You know, we think there could be an opportunity for us to get there, but it'll be dependent on those actions.
All right. Fair enough. Thanks, Toby.
Thanks.
Our next question comes from the line of Umang Choudhary of Goldman Sachs. Umang, your line is now open.
Hi. Thank you. Good morning. I just wanted to follow up on the question from Arun. I understand that you're working through your budget and that you had fewer wells this year. How does that, given that wells is probably gonna have an impact to your first half 2023 production, would love your preliminary thoughts on 2023 activity. Should we expect your activity levels to go back for the legacy asset to keep it flat to around 90-100 wells per year? Or would it be higher next year as you try to grow production sequentially exit to exit this next year?
Yeah, Umang. Yeah, I'd say the activity set should be fairly normal for a normal year. It's just the timing of when the wells will come online. The bucket of wells that got pushed out from 2022 have about a five-month lag time of bringing them online due to the water issues that we had. That's why we'll get back to sort of that $500 million plus run rate by midyear. The activity set overall should be. I'll call standard, fairly normal for a year.
Got it. That's really helpful. My second question was really on the LNG strategy. Any update on the discussions which you're having with the LNG customers, as it comes to you know, diversifying, you have exposure to international markets?
Yeah. Conversations are still progressing across the LNG value chain from LNG developers, marketers, and buyers. You know, I'd say the desire for bringing more LNG to this world has continued to strengthen, and we're having some pretty good conversations. We'll come back when we have anything that materializes into something material.
Got it. Thank you.
You're welcome.
Thank you. Our next question is from the line of Neal Dingmann of Truist. Neal, your line is now open if you would like to proceed.
Good morning, Toby. If I can just circle back on the infrastructure. I was just trying to get a sense. Toby, you talked about maybe just the degree of the curtailment between the different issues. I know you mentioned the water has already been rectified. Just trying to find, I guess, number one, what other issues were involved. Secondly, you know, with obviously the XCL Midstream coming on, how much will that and some other things you all have done help to, sort of the situation going forward?
Yeah. Outside of the waterline issues that have been repaired, you know, getting access to some equipment, there's been some longer lead times. That's sort of the supply chain issue we talk about. You know, with all of this, we've got backup plans. 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. That's sort of the X factor that is driving sort of the weather impacts that we laid out on that chart.
Got it. Okay. Just to follow up, could you talk? I'm looking at that slide. I forget which one it is that shows what four rigs are running. You know, when you look now at the Northeast PA, Ohio, Utica, Southwest Penn, West Virginia, Marcellus, is there any one or two areas that from a returns that stand out or are they? Just wondering, like these days, if you were to rank those, how you think about the four? Are they all, you know, sort of equally, return basis these days in the ballpark?
Yeah, Neal Dingmann, I'd say, you know, 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 returns perspective. I'd also say over in the Utica, some of the science work that we've done, primarily, you know, widening spacing, you know, no surprises shown, you know, increased recoveries per foot makes those returns more attractive. Our ultimate goal is to sort of, you know, get to a place where we can improve the economics across all inventory. We're seeing that right now. I think as we drive our schedule, it's really gonna be dependent on these surface factors, number of wells, lateral lengths, combo development. That, that's sort of what drives the schedule on the makeup.
I would say one of the things we do look at is a board that shows the returns across every single project. You know, we are driving to drill our best acreage and our best wells first. You know, over 80% of our schedule is factoring on the projects that are in the top quartile of our inventory base.
No, the improved ops is obvious from the previous owners. Thanks, Toby.
Thanks.
Thank you. Our next question is from the line of David Deckelbaum. David, your line will be open now if you would like to proceed with your question.
Thank you. Good morning, everyone. Thanks for the time, Toby.
Morning.
I know you've discussed a lot about this, but maybe if you could revisit just the original plan in 2022 versus 2023. I'm trying to get a sense of some of the moving parts. Obviously, the 30% fewer fills this year, but is there any capital benefit from any wells that would be in process that would benefit 2023?
The benefit of moving wells back in 2023, I mean, I guess you could argue maybe you're bringing some of the service cost environment. We do hope that the service costs will abate a little bit. That could be one of these benefits. Right now, we'd like to have these volumes today with the current prices back where. We're pushing to get some of that as well.
Yeah. I'd say the other thing is, if you noticed in slide 11, more of ability to pull things back with the optimization. That was cycle time improvement that we were able to eke out off the flowback. That cycle time improvement will carry forward with our wells forward.
We'll get some of that back directly in the
Toby can push forward.
Okay. Then I guess just to follow up on that, I guess as we think about 2023, I suppose if you're thinking about, like, a balanced program between, you know, sort of core Western Pennsylvania versus West Virginia and Northeast PA, you know, I guess should we see that kind of percentage of completions moving back to what we would have seen, on sort of a geographic blend in 2021, 2022 except maybe the additions with Tug Hill or. I guess, would that activity be kind of shifted away from Northeast PA back into that western region?
Yeah. I think our mix that we took to a good baseline to start with going forward. I would say one of the other things that will help with Tug Hill coming on board is this will just increase our flexibility to be able to make up for any operational weather.
If I could just speak on, in any way, the delay that you saw in 2022, did that delay your program understanding around sort of this enhanced completion design that you all had talked about kind of earlier in the year?
Yeah. We we hoping to get better insight and clarity on fast-forward with our science. These delays and some of the tilts has happened on some of our science projects. Yeah, insight has probably been pushed back, I'd say four-six months on the science as well.
Thanks for the update, guys.
Thank you. Our next question is from the line of Scott Hanold of RBC Capital Markets. Scott, your line is now open.
Yeah. Thanks. You know, I'm gonna ask a couple questions and I think you might have answered part of it in, you know, that last set of answers, but it sounded like there was some choppiness in his line that was hard to hear. Just to clarify, it sounds like with Tug Hill, you don't anticipate any of these, you know, midstream issues to impact, you know, Tug Hill once you get that, you know, part of, you know, as part of EQT. You know, also as part of that, can you give us a sense of how much of the, you know, relative well outperformance, underlying well outperformance, you know, benefited EQT over the last, say, quarter or so?
Sure. I think one thing that's very helpful with the Tug Hill assets is the fact that we will control and operate the midstream. That's gonna 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, you know, I'd say peer-leading production uptime. Some of the other benefits that have come out of this in these efforts to, you know, 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.
There is a bright side of dealing with
Got it. Then, you know, my follow-up is on the shareholder return plan. Obviously, you guys have had, you know, previously talked about, you know, doubling that, the buyback pace and you've got a, you know, pretty good authorization out there, you know, $1.6 billion, and I think that goes through 2023, along with the debt reduction. Is the goal here to, you know, really kind of eat through that authorization given your free cash flow profile, you know, over the next year? Should we expect you trying to utilize that as aggressively as possible? With the buybacks, if you can clarify exactly how much was done in the third quarter too.
Yeah. I mean, I think given where the stock's trading today and the fact that we can buy back our debt at pretty attractive levels, we're gonna be aggressive towards, you know, fulfilling the authorizations that we have in front of us on both aspects of that. Connie, do you have the numbers specifically on in 3Q?
I think it was probably $75 million, I think, or
We've done $150 million since.
Yeah, that's.
November.
I think he's asking just for 3Q versus 4Q.
Right.
I think it's about roughly half was done in the third quarter, maybe a little bit more. Then a touch was done in the fourth quarter. Obviously we'll probably do more. We'll obviously do more in the fourth quarter.
Appreciate that. Thank you.
You're welcome.
Our next question is from the line of John Abbott of Bank of America. John, your line is now open.
Hey. Good morning, and thank you for taking my questions. Toby, I wanna go back to a question that Neil had asked a little bit earlier about XCL Midstream optimization. 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 do that on that extent on your existing asset base? You do have dedication. 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 kinda work?
Yeah. On the water side, pretty tremendous opportunity. You know, 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 produced water pretty much across 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 produced water are very clear and a big part of the synergies that we're counting on.
Outside of the water, on the gathering side of things, being able to connect the Tug Hill system to some of some points we have in Ohio, that will streamline some of our gathering systems and that will lead to some synergies as well. The good thing with midstream, I think the synergies that you can identify are typically, you know, pretty low risk. 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. For the second question, it's gonna be on the new ventures. I mean, you discussed hydrogen here, and you are exploring other opportunities. What is your appetite to spend more on the new venture front at this point in time?
Yeah, that's a great question. I think, you know, slide seven, we put a chart out there that I think really frames up how we think about this. You know, when we think about new ventures, this is to help the energy transition that is taking place in the world. 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? The most important question is, what can the United States do to reduce emissions outside of our borders? Unleash U.S. 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 are going to be creating a surplus of natural gas in the United States while slated for exports. It's gonna create a number of opportunities where we can use natural gas to decarbonize the United States and ultimately move from, you know, gas to lower to zero carbon energy sources like hydrogen, like carbon capture. 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, you know, lowering emissions in the United States. Before we would put any dollars, significant dollars there, we need to understand the profitability of those.
Really the dollars that we're doing, you know, inside the U.S. borders are really driven by pilots to get an understanding of what the returns are gonna look like, and then we can 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 look like, specifically around hydrogen. To have this coalition, this ARCH2 hub, is really gonna position EQT to be very efficient with our time and dollars.
Appreciate it, and thank you for taking our questions.
You got it.
Our next question comes from the line of Noel Parks of Tuohy Brothers. Noel, your line is now open.
Hi. Good morning.
Morning.
Morning.
Couple things. I wondered, and probably you'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 drilling and completion procedures? Also, any insight you have on sort of what they had done themselves on sort of parent-child mitigation practices?
Yeah. I think the Tug Hill team has done a really good job with that asset base. I think it's gonna be, you know, really confident we're gonna be able to at least replicate the success that they've put out there. I also am optimistic in thinking that, you know, our drilling and completions teams will be able to showcase operational efficiency gains like what we've done in the Alta assets. That's simply a function of, you know, having access to the best technology, the best crews. That certainly is gonna give us some tailwinds in doing that. What was the second part of that question, bud?
Just about parent-child mitigation.
Yeah. As far as the development approach with the Tug Hill team, and this is one of the things we look at when we're looking at acquisitions, is this asset going to be suitable for, you know, large scale comp development? Tug Hill assets are, because the Tug Hill team was intelligent in adopting, you know, full pad development. 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 comp development.
Great. Just turning to the hydrogen hub 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. You know, their fuel cell technology as being just one example. At this stage, do you have any thoughts on what direction you might go, whether you're gonna be looking at casting a wide net of technologies to look at, or you have a pretty good idea of what sort of paths you'd like to head down?
Yeah, I think the most exciting technology is technology that produces hydrogen and a solid form of carbon. We'll be testing some of that technology. You know, just standard technology that we know to make hydrogen today, to compare that with carbon capture, we can generate hydrogen, you know, sub-$1.50 per kilogram. Right now we look at hydrogen, the issues are really two issues before getting, you know, 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 cost for transportation and the actual infrastructure it takes to move hydrogen, you're looking at around $20 per million BTU. You know, why would the world choose that energy when they can buy natural gas for a price that's significantly less than that?
What's really amazing is to think about when we unleash U.S. LNG, we will be creating an opportunity to rebuild, you know, 50 BCF a day of new infrastructure in this country. When we build that infrastructure, we can build it hydrogen ready. That means Unleash U.S. LNG can underwrite a significant portion that is necessary to achieve the hydrogen economy of the future in this country. If we can do that, then the feasibility of hydrogen becomes that much more attainable. It's something that is a really nice benefit of unleashing U.S. 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. This is really the chicken and the egg.
People haven't used hydrogen because people aren't making it, and people aren't making it 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 gonna be a great, really great example of the collaboration necessary to make these exciting zero carbon solutions a reality.
More to come.
Great. Thanks a lot.
You got it.
Our next question is from the line of Daniel Lungo from Bank of America. Daniel, your line is now open.
Hey, guys. Thanks for taking my question. I just wanna make sure that I have the debt reduction well understood. You guys have done $830 million to date next year between the term loan, the convertibles and the 3 no-call 1 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?
Yeah. No, between the term loans and the callable notes that's about little over $2 billion.
Yep.
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, you know, our principal values keep coming down as a result of it. We'll be able to achieve our targets, I think, fairly efficiently.
Yep. In terms of if natural gas prices, say 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 a $4 billion reduction by the end of 2023? How are you thinking of which is more important for cash flow? Which is the first use for cash flow?
Yeah. I would say, you know, we have cushion here because Equitrans, our principal balances have come down and our bond debt. I'd just say, you know, if for some reason we have to make that choice, that's gonna be more of a game-time decision.
Gotcha.
That's right. I mean,
Thank you very much.
We'll take a balanced approach to that and look at the value of our stock and look at the debt and where it's trading and make the best decision.
Yeah. I mean, the other thing to also think about is, you know, we have so much free cash flow even beyond 2023, that we have to think about how we use that as well.
Oh, yeah. It's not a question of you getting there, it's just if you get there by year-end 2023. Gotcha. Sounds good. Thank you.
Thanks.
As a reminder to ask a question, please dial star followed by one on your telephone keypad now. Our next question is from the line of Kevin MacCurdy of Pickering Energy Partners. Kevin, your line is now open.
Hey, good morning, guys. I think all the questions on the delayed turn-in lines have been answered, shifting gears a little bit. We noticed in the financials there was a more positive impact from Laurel Mountain Midstream than we anticipated. Can you talk about the financial impact of that heading forward and maybe any strategic plans for that asset?
Yeah. As you know, we own 35% of that system. What happens is we get a rebate effectively from the and that doesn't hit our unit costs. It comes in as other basically. 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. That's how it works. 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.
Right now, as you can imagine, we've made two acquisitions subsequent to Chevron, and they both had midstream, you know, and so just know that midstream helps, you know, us control operations and lower our costs. The desire to sell midstream is probably low on our list.
Great. The impact of Laurel Mountain 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. You know, yeah. Our unit costs go up tied to M-2, and then we get the 35% rebate effectively through our ownership. You got to look at M-2.
Thanks.
That'll be term.
Okay. Thank you for my question.
You're welcome.
Thank you. Our next question comes from the line of Paul Diamond of Citi. Paul, your line is now open.
Good morning, all. Thank you for taking my call. Just a quick one. 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 of the broader industry range, but that broader industry range has been a bit of a moving target. Can you guys give a bit of clarity on, you know, kind of where you guys see that, you know, going into that budgeting process and into next year?
Yeah. I think the industry range is somewhere between 10% and 20% inflation, so we should probably be at the lower end. 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. If you look at steel pricing, it's come down. You look at some of the commodities that have come down. I think inflation in some of the equipment looks like it's slowing down. I think we feel good about what we have contracted and kind of what the outlook for the open stuff is. It should put us in a position.
As you know, we invested in our sand infrastructure that reduced the last mile delivery. You see we invested in the water system, which you can see how critical that is, and when we hook that into the Tug Hill system. 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 2023 into 2024.
Understood. Thanks. Actually just drilling down a bit deeper on that, is there any particular area you guys have seen through the budgeting process and the conversations thus far that, you know, any, what's the area you're least comfortable with? Any area that's given you particular concerns or anything you've noted?
Yeah, I'd say 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. We're continuing to focus on that.
Understood. Thanks for your time.
Thanks.
We have no further questions. It'll be my pleasure to hand back to Toby Rice for any closing remarks.
Thanks, everybody, for joining us on this quarterly call. You know, the world is certainly more volatile, but one thing that is consistent is our asset performance continues to show improvements. Our cost structure continues to decline. We have a free capital profile that's gonna allow us to essentially retire our market cap and achieve our long-term leverage targets in the near term. We've got a good track record doing some really smart consolidate deals on the consolidation front that's driven accretion and value creation for shareholders. You know, 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. That is gonna present a pretty exciting and compelling opportunity for sustainable growth for our shareholders.
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.