EQT - EQT Resources - Earnings Call Transcript Q3 2021

Operator: Hello, everyone, and welcome to the EQT Third Quarter 2021 Results Conference Call. My name is Nadia, and I'll be coordinating the call today. . I'll now hand over to your host Andrew Breese, Director of Investor Relations to begin. So Andrew, please go ahead.

Andrew Breese: Good morning and thank you for joining today's conference call. With me today are Toby Rice, President and Chief Executive Officer; and David Khani, Chief Financial Officer. A replay for today's call will be available on our website for a seven-day period beginning this evening. In a moment, Toby and Dave will present their prepared remarks, and then we'll open up the line for a question-and-answer session. Additionally, we've posted an updated Investor Presentation on our website. I'd like to remind you that today's call may also contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in our third quarter 2021 earnings release, in our Investor Presentation, in the Risk Factors section of our 2020 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 non-GAAP financial measures. Please refer to our third quarter 2021 earnings release and our most recent Investor Presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Thank you. And I'll now turn the call over to Toby.

Toby Rice: Thanks, Andrew and good morning, everyone. Since we last reported in July, we have seen a fundamental shift in the natural gas market. Current world events demonstrate the critical importance that natural gas will play in our energy future. Natural gas futures for 2022 through 2026 have rallied approximately $0.75, which has translated to a meaningful increase to our near-term free cash flow projections. World events have underscored the important role that natural gas plays in the world's energy ecosystem, not only in reliability and costs, but in meeting our global climate goals. What we are witnessing in Europe and Asia is a crisis borne out of an undersupplied of traditional energy sources, one that highlights the dislocation between the perceived good intentions of addressing climate change through policies of elimination, and how these policies play out in the real world. We are unfortunately seeing the predictable outcomes of an underinvestment in traditional energy resources with both continents having to ration energy in hopes of maintaining sufficient supply to make it through the winter. While defenders of these policies may claim that these events are isolated and transitory, we believe they are chronic symptoms due to a structural underinvestment in traditional energy resources. And unfortunately, but yet predictably, we are seeing the adverse environmental ramifications of this. As just a couple of weeks ago, China has announced that is rethinking the pace of its energy transition and ramping up coal production. This is not the way to address climate change. As one of the largest exporters of natural gas, the United States needs to recognize the role it plays not only in the solution, but also the problem. The solution is American shale. We are fortunate to be one of the few countries in the world that has an abundance of energy resources, and more so an abundance of the lowest cost, lowest emissions energy resources that is exportable, namely Appalachian natural gas. During the shale boom, technological breakthroughs, investor support and the innovation and efforts of American natural gas workers translated American shale into low cost reliable clean power, replacing high emissions coal and laying the foundation for solar and wind to play a supporting role with the results being the U.S. leading industrialized countries in emissions reductions. This model is replicable on a global stage, but only if the United States takes on a leadership role. For example, if we were to replace only China's new built coal power plants with natural gas, we would eliminate approximately 370 million tons of CO2 equivalent per year. That number is roughly equivalent to the emissions reduction impact of the entire U.S. renewable sector, which leads to the problem. The problem is that the United States and advocates for policies of elimination have failed to understand the key role that American shale plays in the global energy ecosystem. The United States represents about a quarter of global natural gas supply. Appalachian alone represents almost 10%. What that means is that global demand has looked all around the world and instead we need almost one-tenth of our natural gas coming from Appalachian. Regrettably, we've cancelled multiple pipelines in the last several years LNG facilities have stalled; capital has been pulled out of the system. All the while demand has grown, and now we're seeing the results. U.S. natural gas and more specifically, Appalachian natural gas has the opportunity to provide affordable, reliable, clean energy to the world but to do that we need support in building more infrastructure. A failure to support pipeline and export infrastructure would effectively abdicate the leadership role that the United States is poised to play in addressing global climate change to countries that likely do not have the resources or political desire to do so. Now to talk more about the gas macro specifically and how it is impacting our business. There are a number of bullish trends for the global natural gas market that we believe underpin a long-term structural change of the curve. First, severe underinvestment and supply across all hydrocarbons and associated infrastructure over the past few years has contributed to a global scarcity of accessible traditional energy sources. Second, solar and wind have reached enough scale in global power markets that there intermittency is driving structural volatility, driving demand for reliable energy sources like natural gas to stabilize the grid. Third, environmental pressures and governmental regulations on infrastructure have limited the ability for energy to go where it is needed most, creating market inefficiencies and restricting investments across the space, limiting the ability of producers to react to supply/demand imbalances. And fourth, a continued focus on low cost reliable and clean energy sources has increased the prominence of the role of coal to gas switching as one of the most impactful, actionable and speedy opportunities for significant progress in reducing global emissions. These are the main reasons that global natural gas prices rose over $20 per dekatherm during the quarter. With the backend of the futures curve having also revved nearly $1 in the past six months. There also why we see structural change in the curve sticking. While we have been vocal about our bullish view of natural gas prices for some time, the speed of the current price escalation came sooner than we anticipated. Our reasons for hedging 2022 production at the levels we did while continuing to keep 2023 exposure open is simple. We believe that regaining our investment grade rating, and reducing absolute debt levels, best positions EQT shareholders to fully capture these thematic long-term tailwinds in the commodity. As you look across the energy sector, it's clear that traditional energy companies are being valued at a steep discount. We believe this is principally a result of views on a long-term sustainability of traditional energy sources impacting terminal value. We believe that markets have overshot in this regard, especially so as it pertains to natural gas and that events like the current global energy crisis in particularly as to how they are contributing to a step backwards in our efforts to address climate change will make this readily apparent to policymakers and investors alike. And we believe that at that time, there will be a rerating within the sector, principally concentrated on companies like ours that are differentiated in their sustainability, both financially and on an ESG basis. Now, I'd like to give an update on our free cash flow projections. The structural shift in the commodity curve, along with some hedge repositioning in 2021 and 2022, have had a positive and material impact on our free cash flow projections. In 2021, we're now expecting to deliver approximately $950 million in free cash flow generation. In 2022, our preliminary estimates are $1.9 billion with 65% of our gas hedged. As our hedges roll-off in 2023, we see free cash flow generation potential growing even further to approximately $2.6 billion equating to an approximately 30% free cash flow yield for a company that expects to be investment grade, highlighting how robust the free cash flow generation is from our business. In addition to the shifting commodity market, we have several other factors driving improved free cash flow generation, including our contracted gathering rate declines, more efficient land capital spending, shallowing base declines and FTE optimization, which we have just announced. As such, we're updating our 2021 through 2026 cumulative free cash flow projection to over $10 billion, a 40% increase since our July estimate and materially above our current market cap. This extensive free cash flow generation provides us with the ability to return substantial capital to shareholders, while simultaneously enhancing our balance sheet. And as previously mentioned, we think they're still running them. Further, this structural gas price improvement has solidified our execution of shareholder friendly actions in 2022, which we intend to formally announce before the end of 2021. While we're acutely aware of the investor appetite for return of capital, one of the key considerations as we finalize our plans is leverage management. However, we want to be clear that attaining investment grade or certain leverage target is not a precondition to initiating shareholder returns. With our hedge position and strong free cash flow, we can accomplish both debt reduction and shareholder returns as we create our debt retirement glide path. This business is capable of returning tremendous amount of capital to shareholders, while maintaining optimal leverage. Bottom line is we're projected to have approximately $5.6 billion in available cash through 2023 and if 100% of that cash is allocated to shareholder returns, we would still be left with leverage of sub one and a half times. Those are some very compelling stats, and we look forward to executing on this robust capital allocation strategy in the very near-term. I'll now turn the call over to Dave.

David Khani: Thanks, Toby, and good morning, everyone. I'll briefly cover our third quarter results before moving on to some strategic and financial updates. Sales volumes for the second quarter were 495 Bcfe at the high-end of our guidance range. Our adjusted operating revenues for the quarter were $1.16 billion and our total per unit operating costs were $1.25 per Mcfe. During the third quarter of 2021, we incurred several one-time items totaling approximately $116 million, which impacted our financial results and free cash flow generation. First, we purchased approximately $57 million of winter calls and swaptions to reposition our hedge book to provide upside exposure to rising fourth quarter 2021 and all of 2022 prices, which I'll discuss in more detail in a moment. Second, we incurred transaction-related costs mostly from Alta of approximately $39 million. And finally, we incurred approximately $20 million to purchase seismic data covering the area associated with the Alta assets, which hit exploration expense. Our third quarter capital expenditures were $297 million in line with guidance. Adjusted operating cash flow was $396 million and free cash flow was $99 million. Rising commodity prices and actions taken to unwind fourth quarter hedge ceilings have resulted in an increase to our fourth quarter free cash flow expectations of approximately $200 million. Detailed guidance can be found in the earnings release filed yesterday. But at the mid-point, we expect fourth quarter sales volumes to be 525 Bcfe, total operating costs of $1.25 per Mcfe, capital expenditures of $325 million, and free cash flow generation of $435 million. Turning to some more strategic items, I'd like to discuss the actions taken during the third quarter to optimize a firm transportation portfolio. First, we successfully sold down $525 million a day of MVP capacity, which when combined with $125 million a day previously sold down amounts to approximately 50% of our original capacity. The terms are governed by an Asset Management Agreement, pursuant to which EQT will deliver and sell certified responsibly sourced gas to an investment grade entity for a six-year period. EQT will manage the capacity and retain access to the premium Southeast markets, while the third-party entity will be responsible for all financial obligations related to the capacity. This transaction meaningfully reduces our firm transportation costs. Going forward, we believe that retaining our remaining $640 million a day of MVP capacity provides appropriate diversity to our transportation portfolio. And we do not intend to sell that any additional capacity at this time. During the quarter, we were also successful in securing $205 million a day of Rockies Express capacity with access to the premium Midwest and Rockies markets. As part of the agreement, the parties agreed to significantly discounted reservation rates during the first three-and-a-half years of the contract, which result in material uplift to price realizations and margins during that period. In the aggregate, we expect these arrangements that lower our go-forward firm transportation costs by approximately $0.05 per Mcfe, while simultaneously improving realized pricing. Additionally, we are currently working on several smaller firm transportation optimization deals, which if executed, are expected to further enhance margins and price realizations. Furthermore, our RSG program is ramping up. The six-year $525 millionday contract, we believe represents the largest RSG transaction done in the marketplace, and highlights the accelerating end market demand for low methane in intensive natural gas. I'll now move on to some hedging activity initiated during the quarter, which effectively unlocked upside exposure rising prices. Since the end of the second quarter, we have seen the Henry Hub contract price appreciate, backed by modestly tightening U.S. fundamentals and rising volatility. Couple that with energy shortages occurring around the world, we believe the U.S. could see extreme price events this winter. By early August, we have revised our hedge positioning to one that participates in more upside, while still locking in the necessary cash flows for progressing back to investment grade. In essence, we removed approximately 28% and 13% of caps or ceilings for the balance of 2021, and all the 2022, and lowered our floor percentages by 11% and 9%, respectively. We were able to do this by purchasing a significant number of winter call options at very attractive prices and strike levels that are currently in the money. These call options maintain our downside protection, capitalize on rising volatility and open our portfolio to increased realizations. In addition to our winter call options, we also purchased swaps in 2022 by taking advantage of the backwardation in the market to purchase swaps at points on the curve we felt to be undervalued. This is expected to allow us to capture stronger pricing in 2022, well after we're through the winter. These actions resulted in a one-time cost of approximately $57 million in the third quarter and approximately $18 million in the fourth quarter. With the current market value sitting at well over three times the execution costs. For our 2023 hedge book, which sits at under 50% we expect to hedge with a more balanced and opportunistic approach as we have reduced debt and achieved our investment grade metrics in 2022. At a high-level, we envision a lower hedge percentage, utilizing structures that enable upside participation to capture our anticipated long-term appreciation of natural gas prices and increased volatility. Last, we remain relatively unhedged on our liquid volumes for 2022 and 2023 at less than 15%, which represents about 5% of our volumes and 7% of our revenues. Moving on to a quick update of leverage and liquidity. Pro forma the full-year impact of Alta and the removal of margin postings, our year-end 2021 leverage sits at 1.8 times and is expected to decline to 0.9 times by year-end 2022, and zero leverage by year-end 2023 without the impact of shareholder returns. If we add all our free cash flow through 2023, plus the $700 million in current cash margin posting, we are looking at $5.6 billion in cash available for shareholder returns and leverage management. So we have the ability to retire substantial debt, achieve optimal leverage and provide robust returns to our shareholders. Stay tuned for more formal framework before year-end. As of September 30, our liquidity was $1.2 billion, which included approximately $0.7 billion in credit facility borrowings, largely related to margin balances tied to our hedge portfolio. As of October 22nd, our margin balance sits at approximately $0.4 billion and our liquidity will end October at around 1.5 billion. With respect to margin postings, we've been able to manage these nicely by working with our hedge counterparties, many of which are also submit center revolver. We continue to make progress on lowering our letters of credit postings under the credit facility, which dropped approximately $0.1 billion during the third quarter to $0.6 billion, and it's declined another $0.1 billion through October 22. From mid-2020, we have effectively cut our letters of credit in half from approximately $0.8 billion to an anticipated $0.4 billion by year-end 2021. And as a final reminder on liquidity, virtually all margin postings and letters of credit go away when we achieve investment grade rating. We are one notch away from IG with all three agencies, and when combined with a structural gas macro tailwinds and EQT's robust free cash flow profile, we believe it's only a matter of time until we regain our investment grade rating. I'll now turn the call back to Toby for some final remarks.

Toby Rice: Thanks, Dave. To conclude today's prepared remarks, I'm very excited about the catalysts on the horizon, which I expect to shine a spotlight on the inherent value of our business and the value proposition for investors. These include one, the compelling and structural positive momentum driving the gas macro backdrop, setting up robust and sustained free cash flow generation. Two, the announcement of the shareholder return framework that is right around the corner. Three, an investment grade rating that is on the horizon, further driving increased free cash flow generation and improved liquidity. And lastly, our modern approach and ESG leadership will continue to drive sustained long-term value creation for all of our stakeholders in the sustainable shale era. With that, I'll open the call up for questions.

Operator: . Our first question today comes from Arun Jayaram of JPMorgan. Arun, please go ahead. Your line is open.

Arun Jayaram: Yes, good morning. Toby, I was wondering if you could outline -- you highlighted your expectations for free cash flow generation between now and 2026, how you'd prioritize uses of free cash flow between buybacks, potential shareholder returns to dividends or further A&D activity?

Toby Rice : Sure. Thanks, Arun. Yes, so how we're thinking about the capital allocation. We're certainly looking forward to getting to more details before the end of the year. But I'd say the priority is going to be on buybacks and dividends, less so on M&A. Obviously, that's going to be dependent on where our stock is trading, the value we see on the consolidation framework. But right now, where we're sitting, the priority will be to be on buybacks. I do think dividends will be a part of the program. I think having a base dividend is sort of going to be the ticket to play in sustainable shale eras. So you will see something that is modest but meaningful. And looking forward to laying all that in more detail by the end of the year.

Arun Jayaram: Great. Great. And just my follow-up is just on the firm transportation optimization. You guys highlighted the impacts of selling down, call it, 0.5 Bcf a day on MVP. And I just want to get through a little bit of the math, because you talked about a $0.05 improvement in your -- from transportation cost structure. On our model, that would represent about $125 million, $150 million per annum in savings. We had previously thought, Toby, that there would be a drag on your realizations as you sold, call it, a bit of a higher mix in the local market and away from maybe a premium Southeast market. But in the press release, you mentioned that you think that this would actually improve your realized pricing. So I was wondering if you could give us a little sense of the magnitude and how does the RSG fit into that?

David Khani: Yes. So this is Dave. So we have a sales agreement with the buyer, who's -- and so we will make, on top of the -- on top of the cost of shipping the pipe -- of taking the pipe, we have a fee on top of that, that we -- that includes both the cost of the gas as well as the RSG. So there's, we'll call it, a premium that's on top of the cost of the pipe.

Arun Jayaram: And David, could you give us maybe a sense of the magnitude or just to think about what this could mean in terms of the cash flow for the company?

David Khani: It's very meaningful. I think we can't -- it's a confidential contract, so we can't disclose it, but it's very meaningful. And again, it's embedded in our forecast that we gave for 2022 and really the full impact of 2023 and beyond.

Operator: Our next question today comes from Neal Dingmann of Truist Securities. Neal, please go ahead. Your line is open.

Neal Dingmann: Good morning, all. Toby, I'm just wondering, you guys have done a great job, of I'd say, doing some reposition to hedges to unlock not only the fourth quarter, but 2022 incremental free cash. I'm just wondering, is there, in today's environment, more that you can do on that? For you or Dave, hear from either one of you all, on a go forward or do you just pull up most of what you can out of that?

David Khani: Yes. So if you've noticed, we repositioned hedges earlier in 2021 when already hit. And so we had looked and figured out that when gas had dropped down to, we'll call it, 240, we were able to reposition. So yes, we'll consistently reposition our portfolio. We'll take advantage of the volatility. So we're not done yet.

Neal Dingmann: Okay. And then just one last one. You mentioned on the liquids. I'm just wondering, is there any thoughts about regionally shifting so that you can bring out even more liquids, I don't know, early or let's say through 2022?

Toby Rice: Yes, Neal, our program is pretty baked, I'd say, for the next six to nine months. But we do look at our schedule every quarter, every month to prioritize, to put the best rate of return projects on the schedule and see if we can put those as close to the front of the line as possible. Obviously, the move in liquids has increased the economics of our liquids-rich wells. And certainly the acquisition from Chevron gives us an inventory of those opportunities. And the team is looking to prioritize those type of projects and bring those sooner up in the schedule. But I don't anticipate any change in the next six to nine months of what we're putting out.

Operator: Our next question today comes from Umang Choudhary of Goldman Sachs. Umang, please go ahead. Your line is open.

Umang Choudhary: Great. Thank you and good morning. My first question was around RSG certification. Can you walk us through where you are on the certification from the third-party auditor? And what needs to happen to get the requested certification to supply the gas to the investment-grade counterparty?

Toby Rice: Yes. So we have two certifications. We have Project Canaria when we have EOMIQ. We're both done on that. So we have effectively, we'll call it, up to four Bcf per day of certificates. And so we've, I'll call it, had now three contracts, one which obviously was a very large one. And we're working on several others.

Umang Choudhary: Great. And then you have also completed two attractive transactions over the last year. So maybe if you can provide your latest thoughts around consolidation in the basin.

Toby Rice: Sure. So yes, the two deals that we did, Chevron and Alta, I think have proved to be very accretive. One of the driving factors there is we, I think, did a pretty conservative underwriting, do not have to pay for significant inventory. And we did those transactions at a 2 60, two 70 strip. Obviously, where the strip has moved is going to show that those -- the values of those assets have risen considerably. I think today, looking at where the market is, I think from a consolidation standpoint, probably not going to be our best way to create sustainable value at these prices. So we've essentially put our consolidation efforts on pause. And we'll continue to be disciplined, as always, to look for the best ways to create sustainable value creation for our shareholders. And we think with the opportunity that this company has, it's just looking at the value disparity in our stock. And now that we have had some tools to start correcting that, that will be where a consolidation will be focused. We'll be now potentially buying back our stock.

Operator: Our next question comes from John Abbott of Bank of America. John, please go ahead. Your line is open.

John Abbott: Hey. Thank you for taking my questions. The first question, Toby, is for you. Now you've had Alta in-house for quite a bit now. Have there been any positive surprises?

Toby Rice: Yes, there's been some positive improvements. I wouldn't say there's been surprises. We've identified some best practices. The way that Alta was doing. Compressor maintenance, I think, was the best practice and we'll tuck in. We're early on taking over operations, but in very short order, the drilling team has showed their strengths. The first pad we started developing and I think it was a 9-well pad, two wells were already drilled. The drilling team has already almost essentially doubled the drilling speeds on those locations. They did that through reevaluating landing zones, tweaking the fluid design, switching out the direction of tools from rotary steer -- from conventional mud motors to directional -- to rotary steerables. And we've seen rate penetrations take up. I mean, it's pretty much what this drilling team has done on when they took over here at EQT. So that's been a big improvement. And the impact of cost there, I'd say historical costs on Alta from the drilling side was around, call it, $240, $250 on the horizontal portion. That's a dollar per foot. And the new drilling techniques and the performance is taking drilling costs down to around $140, $150 a foot. So big positive improvement there, but not surprised that the team is executing.

John Abbott: That is very helpful. And then the second question, David, this is for you, it's on the MVP deal. So that deal is six years. So are there extensions possible for that deal? And then after that six year horizon, how do the FT costs sort of change on a unit basis?

David Khani: So the first part of your question, yes, both parties have an option here to be able to extend this out. So we will have that discussion, we'll call it as we get closer to year-end six. And we get the opportunity to restrike the AMA fee as well. And so that would be good for us. And then just to know that, that pipe, we'll call it, it sits in the upper $0.70 range. And that effectively, should we route the same level pipes that over time can ask for higher rates. But as of now, we would anticipate it to be about that high $0.70 rate.

Operator: Thank you, John. Our next question comes from Josh Silverstein of Wolfe Research. Josh, please go ahead. Your line is open.

Josh Silverstein: Yes, thanks. Good morning guys. Just on the forward outlook in free cash flow. Is this a maintenance outlook that's underpinning this? And let's say, it's time for EQT to grow based on where the forward prices are, where does the incremental production go? Is it all into the local market? Or given the FT that you have, you'll be able to send it into the -- whether it's the Rockies now or down to the Southeast?

Toby Rice: Josh, our free cash flow forecast is underpinned by a maintenance program. We are not contemplating growth.

David Khani: Yes. And if we did, by the way, you hit it right, there's less gas going forward in basin because of those two types that come -- that are on and what we get yet. So in theory, it would probably stay in the local market. But we're -- going forward, that number is a much smaller percentage.

Josh Silverstein: Got it. Okay. And then you did say and show that 30% free cash flow yield in 2023. Right now, it certainly feels like that's an eternity away. Is there any way for you guys to take advantage of that free cash flow yield now? Or do you really just have to wait for these hedges to start rolling off? Or I know you mentioned you may want to put in some collars or some other hedges for 2023. It just feels like the stock hasn't moved in six months at all because of the current hedge book. So is there anything that you guys can do to try to take advantage of that now?

David Khani: Yes. So just think about -- in the fourth quarter, we're going to have roughly $450 million of free cash flow. We're going to have, we'll call, a significant portion of the margin posting going away as incremental cash, okay? Right now, we're calling that $300 million based upon October 22. And we obviously also have our E-Train stock, that's another, we'll call it, $250 million. So there's $1 billion sitting right there, we'll call it -- that's circled before we even touch 2022. Did that answer your question, Josh? I guess we moved on.

Operator: I'm just going to move on to the next question then. So our next question today comes from David Deckelbaum of Cowen. David, please go ahead. Your line is now open.

David Deckelbaum: Thanks Toby, and David and team for taking my questions. First off, I wanted to just ask, you remarked earlier, Toby, about kind of reworking some of the hedge book, especially going into winter and some of the risk around price spikes with some seasonality there. We did talk about like a base program obviously doesn't grow. But is there anything that would happen on the production side in the field level that you guys could be prepared to do, whether it's opening chokes further to take advantage of seasonal swings in pricing?

Toby Rice: Yes. Operationally, we do execute a managed choke program for all new wells that we turn in line. So we're naturally choking back our wells for the first six to nine months. So that is an opportunity that lets us -- it's a lever we can pull to increase gas supply and take advantage of near-term price volatility. We have turned some of those wells open to get some -- to grab some extra production in the short term. And then as far as like our hedge book is concerned and sort of to the prior question that was asked earlier, is there anything else we can do there? The repositioning of our hedge book that we've done has really been focused on sort of the short term, which we think we have a much better read on how the macro will play out. And so we'll continue to assess the environment as we get closer toward -- as we get through this winter through 2022, we'll always be looking at optimizing our hedge book to match what we think is going on in the market.

David Deckelbaum: Sure. This is the second one for me, and Josh alluded to this earlier, is the drag on the stock with the hedge book. I think that there's also some perceived negativity around the letter of credit postings and the margin postings, which obviously go away with an investment-grade rating. You talked about this as being near-term. I guess, can you give us a sense of how frequently you think that you're being assessed by the rating agencies and maybe a calendar of when you think you're going to get the next fair look at the state of the business?

David Khani: Yes. So just to understand, one, every month that rolls off, our margin posting comes down. So most of it goes away really, we'll call it, over the next four, five months just naturally through -- and so they really become much less of an issue. And October 22, we said our margin posting was $400 million. So it's really less of a drag. It's actually going to be more of a tailwind. So let's just start off with that. And then second, we do speak to the rating agencies on a fairly regular basis. And we think as we initiate our debt retirement, we'll have the ability to be, we'll call, investment-grade metrics sitting probably somewhere in the first quarter or second quarter of next year.

David Deckelbaum: I appreciate that. If I could just lob in the housekeeping one real quick. Just so I can contextualize all of the moving pieces of the E-Train gathering agreement and the firm capacity agreements on the other side, it looks like all in, if we think about gathering transmission and processing of sort of $1.05 on an Mcfe basis for this year, that next year that, that level should be roughly flat at the corporate level. Is that fair?

David Khani: Yes, that's fair.

Operator: Thank you, David. Our next question comes from David Heikkinen of Pickering Energy Partners. David, please go ahead. Your line is open.

David Heikkinen: Good morning and thanks for the time. Just on the operating side, the $240 a foot down to $150 on Alta sparked the question of what are your expectations for completed well cost per foot kind of for the remainder of the year and then into next year? And any inflation expectations as well?

Toby Rice: Sure. At a very high level, our Southwest PA Marcellus wells, we still are expecting to come in, in that 6 75 to six 80 range. At a corporate level, I think our ultimate goal is to get all the wells that we do to average around $700 a foot, has taken into account the West Virginia Marcellus, which is planned at $775 a foot and the Northeast Pennsylvania assets with Alta, which is going to be closer to $750 a foot. We're going to see probably the biggest gains from a performance perspective on West Virginia and the northeastern side of things. That's going to set us up to be in a position to deliver well cost around $700 a foot. That is taking into account some inflation. We are seeing single-digit inflations on -- focused on things like steel, diesel and labor. Steel is probably the one that we think could correct itself in the near term. So we're being very selective in what we procure on that front. Diesel, we've sort of insulated ourselves from the impact of the rise in diesel cost, and that's primarily due to the move to electrified frac fleets. We've eliminated well over 25 million gallons of diesel consumption per year from our program. And then the last one is labor. And I think this is every industry is struggling with shortage of labor. One thing I would say is that one of our biggest moats that EQT has against service cost inflation is the efficiency of our base operations. It's important for EQT to drill, to have really great operating efficiencies on the amount of horizontal feet we drill, the amount of we frac each day. Because those operational efficiencies are translating to efficiencies with our service providers, and it allows us to be more efficient and combat inflation going forward. So while we are planning for some, I think we've set the company up to still have an opportunity to continue to drive down our costs.

David Heikkinen: Okay. And then just on the modeling detail side, would it be possible to either walk through where your fourth quarter hedges are, take it offline and we can just kind of make sure we dial things in right with the changes you all made so we can make sure we get our marks correct?

David Khani: Sure. So in the fourth quarter, we have a floor level of about 74%. We have a ceiling level of about 70%. So we -- by taking those caps off, we've really opened up the ceiling in the November, December time period now where gas prices are rallying here, we're actually at 60% ceiling. That's -- and at a 70% -- 72% floor, that's the same spot we're sitting in the first quarter. So we really have opened up the winter. And then for 2022, we're sitting at about 64% floor and about 72% ceiling.

Operator: Thank you, David. Our next question comes from Scott Hanold of RBC Capital Markets. Please go ahead. Your line is open.

Scott Hanold: Yes. Thanks. Good morning. Toby, you had mentioned, obviously, M&A doesn't seem to be something that is attractive right now. And can you just talk big picture about your strategic positioning? Very focused in Appalachia. I know a lot of -- some of your peers have been moving down toward the Haynesville. Now there are, I think, a couple of potential sizable opportunities in the Haynesville right now. But like can you talk strategically about being in Appalachia versus thinking about the Haynesville and accessing the global gas market?

Toby Rice: Yes. And I think it's a great question, we get that question a lot. Getting exposure to LNG, I think, is important. But when you look at our portfolio, a lot of people don't recognize that EQT, we have exposure to the Gulf Coast. We've got over 1.2 Bcf a day of FT down to the Gulf, which is almost -- almost the largest position of any producer down there in the Haynesville. So we've got a significant amount of exposure down there. So really that strategic box is sort of checked, and it just comes back to what are going to be the most accretive opportunities for us to look at. And I think you got to understand what we have here in Appalachia is really special. You've got very low maintenance CapEx requirements up here. We've obviously got really great -- really super low F&D costs. And it's a little bit of a different story down there in the Haynesville with higher well costs, higher declines. And we just got to sort of balance that. But strategically, we've got the FT down there to access to the international markets, and that's something that the teams are really, really working on optimizing some more there as well.

Scott Hanold: Okay. Understood. And I think this one is for David here. And on hedging, you obviously talked about being a little bit more, I guess, deliberate or pragmatic going forward on the hedging. Could you give us a little bit more color on that? And just talk to how your reduced leverage position and also your lowering breakeven point going forward kind of forms and shapes your view of what are the right points in structures to utilize?

David Khani: Yes. So just if you step back, in the way we hedged before, we had -- we call it a defensive part of our hedge, which locked in a leverage ceiling and locked in a certain amount of free cash flow, and was very purposeful because we had a maturity wall that we had to pay off, including that we'll pull now, the last bit of it which is the $600 million of 2022 notes. And then we had what we call the offensive piece, where we would try to grab our price view and be more offensive in that nature. And then the other piece I'd just say is whenever we did acquisitions, we get layered on hedges to make sure that we locked in that free cash flow and the economics of what we did. So going forward, if we're not -- if first we don't do any acquisitions, we're just going to really look at the defensive piece now the percentage that we need to hedge as our leverage comes down as -- and the fact that we don't -- won't have any, we'll call, purposes -- the debt that we really have to take out, we will be able to hedge and we'll call a much lower level from a defensive position there. And then for the offensive side, we're going to sit and decide at what percentage we want to hedge up to. But we can also change, I'll call it, the tools in which we use. We can use more collars. We can use more puts to be able to not just put a ceiling in place, but just put a floor in place. So those are things that we're working on. We have a little bit of time to do because we're really thinking about this really more for how do we layer on hedges for 2023.

Scott Hanold: Yes. And just strategically, like can you -- as you think about those forward hedges in 2023 and beyond, like is -- maybe looking at it as a relative percentage of production being hedged. Is that a good way to look at it? Or is it -- if you put in floors, it becomes a little bit, I guess, a little bit different kind of conversation?

David Khani: Yes. It's always about a percentage of our production, but we're trying to solve for a leverage ratio and, in some cases, a free cash flow number. And so that percentage, because of defensive nature, will drop meaningfully. So for example, in the past, that number was sitting, call it, between 40% and 60% the last two or three years because of our leverage and the amount of debt we need to pay down. That number is going to drop very meaningfully now because of our leverage and the fact that we will solve the maturity wall.

Toby Rice: But I'd just say, as far as the types of instruments we use, swaps were largely used in the past, I think, to get our floors. I think the floor as you'll see going forward are going to come more from puts, whether we just purchase those outright or use those as part of a cost as collar. At the end of the day, it's going to be a more balanced approach. I think in the past, it's been more focused on getting that prioritizing the floor. Now the balance is going to be making sure we have a floor, but also recognizing the upside, because we do believe volatility will continue and we have a balance sheet that will allow us to take a more balanced approach, and that's what we're going to deliver.

Operator: Thank you, sir. Our next question comes from Kashy Harrison of Piper Sandler. Kashy, please go ahead. Your line is open.

Kashy Harrison: Good morning, everyone and thank you for taking the questions. Toby, I really enjoyed the macro discussion earlier in the call. I was wondering if you could provide us with some just current thoughts on how many new LNG projects you think might hit FIB maybe over the next several quarters? And then I know the global market, the global gas market is obviously extremely short right now. But it does seem like a wave of projects is coming from the U.S., Qatar, Russia, maybe Mozambique, if it becomes a little bit safer over there. So is it possible that we could go from an undersupplied global market to an oversupplied global market over the next several years?

Toby Rice: Yes, great question. I think in the short term, the projects that are in queue will see LNG export capacity go to around 17 Bcf a day over the next few years. But I think that the bigger question is really going to be how much more natural gas does the world need? Obviously, significantly more. I think when international companies are looking at -- countries are looking at where they're going to source their gas, there's three countries: it's Qatar, Russia or United States. And this is a major opportunity for this country to lead in being the provider of natural gas because the emissions from natural gas producer in Appalachia is 1/10 of that in Russia. And I think the world, hopefully, is starting to get a clear picture on what the future of energy looks like. And we think that energy is going to be -- has the following criteria: it's the cheapest, most reliable and the cleanest form of energy. And when you look at energy through that lens, natural gas is the clear leader. And so we'd like to see natural gas play a leading role in our energy future. I think when you look at what's going on in the world today, you look at what's happening at Europe and Asia, it seems to get our focus there. But there's other issues happening all around the world as it relates to having a lack of clean, reliable, low-cost energy. We started looking at some data, and there's a country that has experienced over 19,000 blackouts because they don't have enough access to reliable, low-cost, clean energy, 19,000. That country does experience a blackout every four hours, and this is over the last 10 years. That country is the United States, and people are surprised to hear that. And we also need to think about the amount of natural gas that needs to be deployed here domestically. It's a clear sign that if there's issues with the reliability of our grid, we obviously see the reliability issues around the world. There's so much more that natural gas can do. And I think with a comprehensive energy policy that prioritizes natural gas as the leading energy choice, American shale will be there to supply that energy. We've done it to bring energy independence to the country. We'll be here to provide energy security for the world. But we need to see comprehensive policy that supports infrastructure, LNG exports and let American shale be unleashed to do the great work that it can do and meet the energy needs that the world demands.

Kashy Harrison: That's great color, Toby. And then my follow-up, and maybe you sort of just answered this. But let's say, FT is not an issue, what multiyear, let's call it, five year average price -- index price would you need to see before you'd even consider transitioning from maintenance to growth?

Toby Rice: Yes. I think you look at the strip we have right now, and it's certainly backward dated. But the returns today would justify more investments, but that's not -- it's not the only factor that we're looking at. To generate sustainable value creation, it's -- we need more than just short-term price signals. We need to see that we've got long-term demand for our product. And that's why infrastructure is important. That's why public policy is important. And I think you're going to need to see those things to prioritize operators to pick back up and deliver the energy that this world so clearly needs.

Operator: Thank you. And our final question today comes from Noel Parks of Tuohy Brothers. Noel, please go ahead. Your line is open.

Noel Parks: Just had a question. I apologize if you touched on this already, but -- and I realize it's kind of early, but given the Alta acquisition and of course, a much better SEC price this year than we had last year, is there anything that's clear and obvious at this point, that might not be obvious to us, as far as what reserves might look like at the end of the year? Just thinking about, in addition to Alta, the -- maybe the SEC CapEx horizon sort of changing as you evaluate the blended inventory.

David Khani: So this is Dave. So if you think about it, we're running maintenance. So the activity level is not -- the five year dollars are not going to be changed materially from where they were last year on the base. We have, we'll call it, the incremental Alta reserves, which I think we talked about midyear and that around the acquisition. The only real change, I would say, materially will be a little bit of tails tied to the -- tied to the change in the commodity price. And so -- and that's really it. So I wouldn't imagine the reserves changing materially because of that. I think if we were ramping up activity on either our base or the Alta acquisition, then you could see us probably book more proved reserves. But that's not going to be the case.

Noel Parks: Great. And I guess, again, I'd really just touch on quite a few macro topics. But as we are kind of, again round in the bend of the year, do you have any sense, maybe just talking about U.S. demand, about -- with all the demand uncertainty we've had, whether there's -- is the market worrying too much? Or is there too much volatility because of sort of the COVID-specific, I guess, the price change specific parts of sort of demand uncertainty? Because it's always tempting to sort of look at the strip and think about our current patterns and try to extrapolate into a new normal. And then at times, it's important to sort of step back and say wait, we're coming off of an extraordinary couple of years, you can't really -- you can't really extrapolate into 2022, 2023 based on what we've seen during this rally.

Toby Rice: Yes. Good question. I mean, I think there is an over -- there has been an overreaction, but not as it relates to the need and grab for natural gas, that is clearly justified, and that's due to the significant underinvestment that we've seen in traditional energy over the past five years. The overexaggeration, I think, that a lot of people are seeing right now is as it relates to sort of the environment and climate change. And some of the reasons why we've seen some of these extreme situations play out in Europe is because people have prioritized the green aspects of energy over and sacrificed low-cost reliable for that. And I think at the end of the day, we need to take a realistic, practical approach, balanced approach, toward the energy that we utilize. And it's got to be low cost. It's got to be reliable and it has to be clean. And I think that an effective policy is going to be one that prioritizes natural gas, which is obviously the best at meeting all three of those criteria.

Operator: Thank you. This brings us to the end of today's Q&A session. I will now hand the call over to Toby for any closing remarks.

Toby Rice: Thanks, everybody. It's certainly exciting times in energy, and we look forward to capturing even more opportunities and creating more value for our stakeholders. Thank you to everybody and the crew for all the hard work this quarter really excited about the future ahead. Thanks.

Operator: Thanks everyone for joining the call today. You may now disconnect your lines.