Good morning. Welcome to today's EQT Q4 quarterly results 2022 and outlook conference call. My name is Candice, and I will be your moderator for today's call. All lines will be muted during the presentation portion of the call, with an opportunity for question-and-answer at the end. Operator instructions: I would now like to pass the conference over to our host, Andrew Breese, Director of Investor Relations.

Good morning, and thank you for joining our fourth quarter and year-end 2021 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 for a seven-day period beginning this evening. The telephone number for the replay is 1-866-813-9403 with a confirmation code of 523084. In a moment, Toby and Dave will present the prepared remarks and the 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 also contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of factors described in yesterday's earnings release, 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 any forward-looking statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby.

Thank you, Andrew, and good morning, everyone. 2021 has been another transformative year for EQT, and I am excited today to reflect on the year, to discuss our fourth quarter results and reveal our 2022 financial and operational outlook. But before I do that, I would like to take a step back and talk about the investment opportunity that EQT presents. The value opportunity for EQT has never been stronger than it is today. In two years, this team has righted the ship and set EQT on a trajectory that will allow us to benefit from and support the growing importance of natural gas in today's energy ecosystem. At January 31 strip pricing and including the free cash flow generated in 2021, EQT is projected to generate free cash flow through 2026 in excess of $10 billion, representing 125% of our current market cap. Further, our 2022 free cash flow yield is roughly 20%, and despite backwardated strip pricing, grows to 30% in 2023 as our hedges roll off. The value opportunity goes beyond the near term. EQT is a differentiated, long-term natural gas investment opportunity. When compared to the other natural gas peers, we believe EQT has the longest runway of high-quality, contiguous inventory of any operator and any gas play. In our most recent investor presentation, we have updated our inventory position. And as of year-end, we have approximately 1,800 net mapped out locations in our core inventory position, representing nearly 22 million lateral feet of drilling. That line of sight on our operations is differentiated from any peer, and with a roughly 100 well turn-in-line program represents more than 15 years of inventory in a maintenance production scenario. This translates to a long runway of production and sustainable free cash flow generation. When it comes to increasing value for our shareholders, I'd like to now highlight several drivers to increase our free cash flow picture. First is a stronger balance sheet that we expect to be upgraded to investment grade as early as the first half of this year. Investment grade status unlocks multiple benefits such as improved cost and access to capital, as well as the ability to sign long-term domestic and international sales contracts. Second, building on the past two years of work in our stronger financial position today, we have begun implementing an updated hedging strategy that provides downside protection while leaving large upside exposure to higher natural gas prices and what we continue to believe is a structurally bullish backdrop for the commodity. Third, we have contractually declining gathering rates that fall by around $0.18 from current levels over the coming years and provide additional free cash flow growth even without production growth. Fourth, our operational excellence has translated into strong efficiency improvements, which has allowed us to ramp our methodical well design testing program, which I will expand on in a moment. Lastly, our corporate base decline rates continue to shallow with our current 12-month base decline equal to approximately 30% and declining to the low 20s, resulting in less activity and capital required to maintain production and further insulating our business from future inflationary pressures. In addition to these drivers that will improve the sustainability of our business, we recognize that we can generate further value through the improvement of our price realizations. First, our hedge program now provides us with the ability to capture rising prices. For every $0.10 increase in unhedged realized price above our corporate breakeven of less than $2.30 per million Btu, we get an incremental $200 million of free cash flow or $0.50 of free cash flow per share. Second, on our expansive RSG footprint, of which we've already certified approximately 4 Bcf a day, we have signed 10 deals encompassing roughly 1.2 Tcfe in total for around $60 million in premiums to date. We expect the value of RSG will improve further as the market develops and as the cost of carbon increases. Lastly, we are attracting interest from several LNG parties across the whole value chain to gain exposure to international prices. While these catalysts provide an exciting future for EQT, we have not lost sight on the value of our core business and the way in which we operate is a key differentiator for EQT and provides meaningful, sustained value creation opportunities. When we campaigned to join EQT, we introduced combo-development, which is large-scale, simultaneous development of multiple adjacent wells and pads. Combo-development requires coordinated efforts to create the long-term schedule and requires a large contiguous asset base, unconstrained by legacy parent well depletion as we see in other plays. In these two-plus years, these efforts are bearing their fruit. The real results of our efforts are evident in our improving EURs, decreasing costs and limited inflationary pressures. We are now developing 20 to 30 wells sequentially from adjacent pads with 300,000 to 400,000 lateral feet per combo on average. This modern approach to shale development leverages EQT scale to drive down costs, maximize long-term asset value and minimize future well interference to drive multiyear, consistent results. On slide 15 of our investor presentation, we show you what combo-development looks like. And through our long-term 2026 guidance window, we expect that greater than 80% of our activity to be combo-development, which means sustained capital efficiency and repeatable free cash flow. Another contributing factor to our consistent results is our approach to well design. Since joining EQT, we've streamlined the number of well designs, allowing us to better forecast the performance of our wells and minimize variability. With the operations humming, we began weaving in small-scale science pilots starting in 2020. These dollars were small in the past couple of years. And now with our scale, consistent development along with the findings from our small-scale piloting, we have confidence in beginning to phase in a next-generation well design in 2022 that is geared towards driving further improvements in well productivity, drilling economics, leading to long-term free cash flow and value creation as we apply these learnings across our long runway of core inventory. Given the standard time frame between spud to turn-in-line and our planned phased deployment, we expect to have preliminary results by the end of 2022 and full visibility by late 2023. The investment is roughly $50 million in 2022, which translates to approximately $90 per foot on our Southwest Pennsylvania Marcellus well costs, which we believe will be more than offset by the expected production enhancements to understand the potential impact. Next-generation well design could materially increase our five-year free cash flow forecast by more than $300 million, and with full implementation could offer multiples of that when applied across our entire inventory. We expect this next-generation well design will also afford us the ability to maintain production volumes with fewer wells, increasing the capital efficiency of our operations, while also extending our core inventory runway even longer. This is a great segue into what to expect from EQT in 2022. The story here is simple. To run a disciplined maintenance program to produce approximately 2 Tcfe annually, implement a hedging philosophy that provides downside protection while providing substantial upside participation, generate free cash flow that we can reward our shareholders with, and improve our balance sheet in pursuit of leverage of 1 to 1.5 times. Slide 13 in our investor presentation highlights the continued momentum of our 2022 program, with maintenance production of approximately 5.5 Bcfe per day and capital expenditures of $1.3 billion to $1.45 billion. We expect to generate $3.1 billion to $3.3 billion of adjusted EBITDA and $1.4 billion to $1.75 billion of free cash flow. As mentioned before, this represents a roughly 20% free cash flow yield in 2022. Our 2022 capital program assumes a $1 per foot cost for Southwest PA Marcellus wells of approximately $760 per foot, compared to our full year 2021 average of $690 per foot. This is not inclusive of our investment in our next-gen well design program, but does reflect expected inflation of $70 per foot or about 10%. However, we recognize that dollar per foot is not a fully representative picture of our capital allocation decisions, which is why we also look at our program through the lens of CapEx efficiency, or the total capital spend for the net sales volumes delivered. Slide 18 further details this concept. Our CapEx efficiency is inclusive of all capital costs beyond reservoir development, a nuance that dollar per foot ignores. Further, because we are investing in our next-generation well design that is expected to deliver higher per well production, capital efficiency on a per-volume metric provides a better illustration of the value being created from the capital invested. In the same vein of capital allocation, I'd like to provide you with our current view on M&A. Despite the pickup in M&A over the past nine months, we have chosen to remain disciplined as we have observed a widening divergence between the value of public equities and where assets have traded. The timing of the two significant transactions that we have already integrated could not have been better. In closing our asset acquisition from Chevron, our team has reduced operating expenses by over 30%. And with the increase in strip pricing, we believe the value of those assets has more than doubled since closing. Similarly, the integration of Alta is now complete, and our operations teams are already driving cost improvements in the field as evidenced by a 15% decrease in drilling cost on the first wells we took over despite inflationary pressures. As a reminder, the Alta assets included over 250 core net locations and more than 600 total net lower Marcellus locations plus 300,000 net acres and also included substantial midstream infrastructure and mineral ownership. Recent transactions imply a value of Alta of more than double what we paid only six months ago. As a large shareholder myself, my excitement for EQT has never been greater and the value proposition never more compelling. And as of December 2021, we now have the ability to capitalize on this opportunity to the use of our $1 billion share repurchase program. Since that announcement, we have not waited to begin repurchasing shares. In roughly one month, we repurchased $50 million of our shares, representing 2.5 million shares outstanding. While it's prudent to be methodical in our repurchasing efforts, we recognize the rare opportunity available to us today to buy stock in a nearly investment-grade company with a 30% 2023 free cash flow yield at strip on top of some of the best natural gas assets in the country. We look forward to updating the market on our progress. I'd now like to pass it to Dave to discuss hedging strategy, our balance sheet, liquidity and year-end reserve results.

Thanks, Toby. I'll begin with a summary. We reported solid 4Q 2021 results, implemented our updated hedge strategy, announced and executed our capital allocation program, have line of sight to achieve our investment grade goals and realized a 158% proved developed reserve replacement ratio, excluding the impact of the Alta acquisition. As a proxy for value, our before-tax PV-10 of $21.5 billion is 60% above our total enterprise value of $13.4 billion, which is based on drilling only 3.75 years or less than 20% of our multi-decade inventory. As Toby has laid out the sustainability of the operations, we are creating a strong balance sheet and free cash flow outlook to complement it. We are nearing completion of paying off the $3.5 billion maturity wall we faced in early 2020, which has allowed us to shift from a defensive hedging strategy with nearly all swaps to a more balanced approach. Our strategy now provides downside protection to maintain investment-grade metrics, while allowing us to benefit from rising natural gas prices. We designed and implemented this strategy for 2023, and we will continue to execute it in outer years as appropriate. For 2023, we laid on an overall floor of approximately $3 and a ceiling of approximately $5. We are now about 42% hedged for 2023, which locks in free cash flow to execute on our shareholder return program. As a result, we preserved our ability to capture 100% of the recent run-up with these additional hedges for 2023, which is a movement we have expected for some time and wanted to position ourselves to capture. In the effort to provide more details, we provided a quarterly view of our hedging portfolio on slide 21 of our investor presentation. Now I'd like to talk about basis pricing and how we manage it. First, we have a strong firm transportation portfolio that we always optimize. Last quarter, we added some Midwest REX capacity. Second, we further lock in our basis with financial and physical hedges. For 2022, we have only had in-basin price exposure on approximately 15% of our production. On slide 22 of our presentation, we have further laid out our exposure by market. For further transparency, we have shown that for every $0.10 move in local pricing, our 2022 free cash flow forecast would change by approximately $30 million or less than 2% of this forecast. There are a lot of moving parts that impact basis. First of all, the correlation between basis and NYMEX sits between 70% and 80%, and our hedging program tightens this up further. Historically, weather has been a large factor in driving volatility in local pricing, as well as storage levels, pipeline outages and modest product growth. The fourth quarter 2021 and the first quarter of 2022 demonstrates this volatility. The weather in the fourth quarter was significantly warmer than normal. We had approximately 15% of our local exposure open, hoping to capture colder weather, resulting in a wider basis differential than our guidance range. However, despite pricing pressure, we still delivered solid fourth quarter free cash flow results of $422 million. All other key production operating costs and CapEx were in line as expected in the fourth quarter. Now looking forward, our first quarter basis will be much tighter than the fourth quarter, since winter weather has returned to more normal levels. The cold weather in January and the start of February has created a storage deficit, which with several other positives, should add approximately 1 Bcf per day year-over-year demand. First, firm transportation out of the basin is flowing at increased utilization compared to prior years and new capacity has been added to the Appalachian region. Second, we are witnessing growing in-basin power and industrial demand, bolstered by approximately 2.7 gigawatts of coal retirements and tightness of Appalachian coal supply. As a result, coal contracted prices in the fourth quarter have nearly tripled, setting a much higher bar for switching dynamics. We will keep track of in-basin production, which will offset some of these positive fundamental trends. I'd like to now shift gears and discuss our balance sheet and liquidity. Having a strong balance sheet and liquidity underpins our valuation and ability to execute our capital allocation plan. As of December 31, 2021, our net debt position was roughly $5.4 billion, representing a last 12-month leverage of 2.3 times. Over the next 12 months, we plan on meaningfully paying down additional debt, repurchasing a significant amount of stock and distributing our above-average dividend. Our 2022 and now 2023 hedge position support our free cash flow outlook and confidence to be able to execute our plan. Based on the strip and our stated capital allocation plan, we forecast our year-end 2022 and 2023 net leverage to be around 1.4 times and 1.5 times, respectively, which includes a buildup in cash reserves that we can use for retained flexibility. Our balance sheet plans are straightforward. We're committing to paying down $1.5 billion of absolute debt by year-end 2023 and expect to benefit from a rising interest rate environment. With this, we believe that we are on the doorstep of investment-grade rating, which will unlock multiple benefits such as interest cost savings and the ability to secure attractive, long-term customer contracts. Our conversations with the rating agencies are frequent and have been positive, and we are confident about the strength of our balance sheet. A recent tailwind that is benefiting our near-term cash position and enabling our ability to repurchase shares is our improving liquidity position. As of December 31, 2021, our liquidity position was $2.2 billion, an improvement of $1.1 billion from the third quarter. During the fourth quarter, we paid down approximately $700 million outstanding on our revolver and reduced our letters of credit posted by approximately $200 million. In addition, we reduced our collateral and margin deposits by $566 million, which positively impacted our working capital and operating cash flows for the quarter. In January of 2022, we also paid down an additional $206 million of long-term debt. Lastly, I would like to conclude by providing some insight on our reserves. At year-end 2021, we reported 25 Tcfe in total proved reserves, up 26% from 2020 and up 6% normalizing for the reserves associated with the Alta acquisition. Our total before-tax PV-10 for the year ending 2021 was $21.5 billion, an increase of $17.5 billion from 2020. This increase was driven by a substantially higher SEC price deck. As previously noted, our total before-tax PV-10 is over approximately 60% higher than our current enterprise value, despite only reflecting 3.75 years of PUD bookings. For reference, the year-over-year pricing difference used in the calculation was $1.31 per Mcf representing NYMEX less regional adjustments. I will now let Toby conclude our prepared remarks, before we open up for Q&A.

Thanks, Dave. To conclude, I want to take us back to what I said at the beginning of the call. EQT is a differentiated, long-term natural gas investment opportunity. Everything we have done to date has been focused on being able to make this assertion, and I believe we've checked this box. By substantially reducing our operational and financial risk organically, we can now play to what we see as the medium and long-term strengths of our company and unparalleled core natural gas inventory, a base business with a cost structure that will decline over time, an ability to access differentiated pricing markets and a macro pricing dynamic with greater upside skew. Underpinning our excitement about the medium- and long-term investment opportunity is the growing appreciation of the role of natural gas in addressing climate change, in particular, as it relates to US LNG. As we and others continue to do more work on the best way for the United States to influence global climate change, it is apparent that a ramping of US LNG is an emissions reduction opportunity that can be executed at scale, with speed, at a low cost here in America. This opportunity cannot be replicated anywhere else in the world. The macro events that we are seeing are forcing a conversation grounded in reality. We believe that conversation will end with a significant call on US natural gas. And EQT, America's Natural Gas Champion, will be ready to answer that call. I'd like to now open the call up for questions.

Thank you. Our first question is from Arun Jayaram from JPMorgan. Your line is now open. Please go ahead.

Yeah, good morning gentlemen. My first question is on your thoughts on return of capital. As, you know, investors continue to differentiate the E&Ps on return of capital yields, you have about a 2.5% dividend and $1 billion buyback authorization through year-end. And I wanted to get your thoughts on any urgency on flexing the buyback given you outlined 20% free cash flow yields on your guide this year going to 30% next year.

Hey good morning, Arun. This is Toby. Great question on buyback and pace. Certainly, it's an exciting opportunity in front of us. Just a little bit about what we've done to date to help you understand the pace that we've been working at: the $50 million over the first month, if you ran that forward 12 months, that would put us at about $600 million annualized on the buyback. A couple of things influencing that pace. One, I think that we started off with a pretty warm winter. And given the fact that it seems the market is very short-term focused, we've been a little disciplined to see how the weather played out. And that may have had us be a little bit more conservative because, obviously, if we had a warmer winter, that would have created an even more compelling opportunity for us to buy back our stock. But we're here now, we're through winter, and I think you can see us look to accelerate the pace going forward on the buyback. As far as the dividend is concerned, while we haven't really talked too much about it, the ultimate game plan for our dividend is to position this company to be a consistent dividend grower. And that's the last part of our capital allocation plan that we'd like to provide some color on in the future.

Great. And my follow-up, you outlined a $1.6 billion free cash flow target this year. It is a bit below what you outlined in mid-December. So I was wondering if you could walk us through the delta and perhaps a frequent question is how the impact or the delay on MVP is affecting your 2022 and 2023 free cash flow forecast.

Yeah, hi. So first and foremost, when we provided guidance, you'll notice that we provided wider ranges for free cash flow in our basis, just given the fact that gas is very volatile. We started and put the guidance out, prices were actually $0.80 higher. And so what we did was we put some conservatism into our guidance ranges, so that we have a cushion here so that we can handle that volatility. So that's part one. And the other part of the delta is, if you noticed, our CapEx is up about $75 million versus what we've put out before at $1.3 billion; $50 million of it is actually tied to our new well design. And so that's going to bear a lot of fruit for us. I'll also note that within our guidance is about $20 million of incremental year-over-year pneumatics, which will get paid back in RSG and then some. Those I call the two things. And then, obviously, we dealt with a little inflation. So when you factor that in, I would say that, along with the fact that basis was wider and with MVP being pushed, those are probably the majority of the items that drive the delta between what we put out before and what we're putting out now.

Great. Thanks a lot.

Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Your line is live. Please go ahead.

Yeah. Thanks. Just maybe staying on the MVP subject. Obviously, it's very topical. I'd be interested to get your views on where you think that goes, if you can provide some color. But also related to that, there were obviously some fee relief, but some payments that could occur in the event that it gets delayed. Can you just discuss like what is your positioning on how you look at that and what we should assume going forward?

Yeah. So if you noticed in the slides, because we had something on our firm transportation portfolio, and how our gas moves around, we provided for 2022 and 2023. We had to pick a spot on where we thought MVP was going to come online. And we did that as a placeholder before E-Train puts out their update in about a week or so. So we picked midyear 2023. So effectively, we set about a year delay as the placeholder. But again, I think that is a placeholder that we'll adjust once E-Train puts out their updated guidance. So when you look at the impact to us, I would say, basis widened in 2022, basis wide in 2023, we lose the benefit of the fee relief, but we also don't pay the high 70s cost on the portion that we retained. And we also don't pay, we'll call it, the Henry Hub kicker piece as well. So when you net it out, it's a modest negative for 2022. It's a little bit bigger negative for 2023. But if you look out actually over the six-year period or so, actually, it's an overall net benefit from a total free cash flow perspective, irrespective of what basis and does.

Yeah, Scott. Just some high-level comments on what's going on in the world right now, and really just to read through how important pipeline infrastructure is in this country, specifically MVP. Two weeks ago, we got a letter from senators in New England saying that they're basically looking for more supply into their areas. The reason why they're paying extreme prices in New England is because of lack of pipeline infrastructure, plain and simple. And without these pipelines, we're going to continue to see these extreme pricing scenarios, which, by the way, we don't like as energy providers. We want to provide low-cost, reliable energy to every American. What's happening in New England is relevant to people in the southeastern United States. There is a pipeline that is going to allow people to benefit from low-cost, reliable clean energy. This is something that people need to be aware of because what's happening in Europe and what's happening in New England starts with things like what's happening right now with MVP in the southeastern part of the United States, and we really are looking forward to that pipeline project being completed.

Appreciate the color. And as my follow-up, you identified, I think, 1,800 core locations that you all have left. And I think, Toby, you mentioned it's about 100 TILs for maintenance. But this new well design could kind of cut into that a little bit. Can you give us a sense of what kind of productivity uplift you can get from these well designs? And what could that TIL count look like if it works?

Sure. So the EUR uplift we're looking at right now are going to be double-digit increases on a percentage basis. We're not able to say exactly what that will be dialed in to yet. We have, just to give you some color on what we're doing, our small-scale science testing program that we've done over the last couple of years was testing different pieces of our 37 different well design parameters. Each of those well design parameters that we picked have shown uplifts. And now we're combining all of those, the best well design parameter uplifts, putting those together and that's making up our next-gen well design. So if we assume that we got the uplift from all of those pieces that we're putting together, it would be pretty exciting. We're taking a conservative approach right now. So I think by the end of 2022, we'll have a full assessment of what the total impact for all of these is. But each of these individual tests were exciting by themselves and putting them together is something that we're looking forward to assessing in 2022. And that percentage increase that we get in the EURs will dictate the amount of activity reductions we'll need.

Understood. Appreciate it.

Thank you. Our next question comes from Holly Stewart from Scotia Howard Weil. Your line is now open, please go ahead.

Good morning, gentlemen. Maybe first, Dave, just to take it a step further on MVP. How are you thinking about that cash option that expires at the end of 2022 and then as well as your current stake in E-Train?

Yes, Holly, it's a great question. Just to make sure everybody knows, we have all of 2022 to determine whether we want to take back the fee relief that we put in place for, we'll call it, through the next three years, subject to when MVP comes online, and that fee relief was about, we'll call it, $250 million roughly. We could take that back as a check of cash for approximately $200 million. So the determination really will be when do we think MVP comes online, right? That's going to be the question mark. And so we'll sit and wait and look and see what E-Train says as sort of the timing, and then we'll think about whether we pull the trigger on pulling that cash.

Okay. And then your stake in the shares?

Yes, we actually sold some shares in the fourth quarter, and we'll be thoughtful in when we want to sell them again. And so I think with the specter of timing unknown on MVP, we'll probably be a little patient here, given the stock is now below $8. And so we'll wait until we get the view on MVP and the timing, because I think that's creating obviously a cloud over E-Train stock.

Yes, indeed. Okay. Thank you. And then, Toby, maybe you mentioned kind of the two big acquisitions that certainly you've done as CEO. Maybe touch on both those deals. What you've learned and why, I guess, having those in your asset base kind of excites you as you move into 2022. It looks like about 10% of your TILs will be in that Alta area. Chevron obviously isn't as hard to separate, but just thinking about those deals specifically.

Yes. Number one, lessons learned. I think we're pretty excited about the fact that we've taken a pretty disciplined approach to underwriting these deals. We've learned that we were conservative and proven to be conservative, seeing the operational performance improvements on Chevron with the OpEx dropping by over 30% and the drilling efficiencies we're seeing in Alta. Hopefully we continue to see more efficiencies as we step more into completion. So I think it's a really great example of this modern operating model we've built and the teams here can unlock the value that we conservatively underwrite. So that's been great. I think we're always looking at deals in the future. But anything we do, whether it's M&A or buybacks, it's all about putting our dollars to the best investments, best rate of return. And given the market today on the M&A landscape, nothing competes with buying our stock, and that's been our focus.

That's great color. Thank you guys.

Thank you. Our next question comes from Neil Mehta from Goldman Sachs. Your line is now open, please go ahead.

Thank you team. First question is just on unit cash costs. They do move higher in 2022 versus 2021. And just one, to get your perspective—are we seeing some signs of inflation there? How much of that's a function of higher natural gas prices? Any color around that would be great.

Yes. So we have some a little bit of midstream impact that went up. We have a little bit of non-op—some non-op cost went up. And then we also signed our water agreement with E-Train in Pennsylvania. Those are probably the three pieces that really drove the increase. You can classify a little bit of that as inflation, but I think it's also some updated contracting that we did with E-Train on the water deal.

David, it sounds like you have a pretty high confidence that's not moving around a ton despite some of the inflationary environments that we're seeing?

Yes. Just an overall view on guidance. When we provide guidance, we do it with very high confidence and our goal is to beat guidance and move it up. And so just look at our last two years' track record; that's been our goal—when we set guidance we want to beat our guidance.

Okay. And the follow-up is just can you take us into the room for your conversations with the ratings agencies. And so is everything on track to get to investment-grade? And are your credit ratings agencies comfortable with you guys taking an aggressive posture on share repurchases as you've indicated you'll take on this call?

Yes. We try to—with all our investors and our commercial banks—we have lots of conversations with the rating agencies, and we want to make sure they are very comfortable in our glide path back to investment grade. So we've had multiple conversations about our shareholder and capital allocation plan. If you notice, our buyback is very much paired with our debt reduction. We feel that's very prudent from our standpoint to how we manage our balance sheet. I think they feel comfortable with where we're setting our balance sheet and our goals and our long-term leverage. It's not about just taking leverage down because that will happen with higher prices. It's really about taking absolute debt down, and that's very important to them and it's very important to us.

Thanks.

Thank you. Our next question is now from Neal Dingmann from Truist Securities. Your line is now open. Please go ahead.

Good morning, Dave and Toby. I'm unsure who want to take it. Just could you talk a bit about, Toby, I love the $10 billion you laid out in free cash flow. Could you just talk about some of the assumptions that longer term, such as what you're expecting on pipelines or efficiencies, cost pace—Dave, maybe highlight items of that?

I'll let Dave put some color on some of the cost assumptions. But I think one of the key things to call out and probably one of the most important is the long-term free cash flow forecast we have is assuming strip pricing, which we know is backwardated. So you're talking about $3 in '25 and '26. Obviously, this business can generate a ton more free cash flow in a higher price environment. So I think that really is probably going to be a big mover. And I think the call on clean energy and the demand for reliable clean energy has never been greater, and we think that what we're seeing with prices here can be a read-through to what we can see in the future. Energy prices got pretty extreme very quickly over this past winter season, but let me remind you, this was not a cold winter. What keeps prices sustainable and still relatively low cost—but not so volatile—is going to be infrastructure and commitment and investment and a call on natural gas. We've got the resources to do it, and I think it's going to be a compelling macro setup for us in the longer term of our free cash flow forecast. Dave, do you want to talk about some of the costs we have in there?

Yes. So first and foremost, know that embedded into 2022 is the new well design cost, slightly over $50 million. We really don't have any material benefit of that new well design in our production for 2022. We have embedded into our 10-year free cash flow picture cash taxes rising over time, basis actually narrowing because of an expectation not only just of MVP coming online, but also the forward curve basis improving as well. We have a modest amount of inflation built in there. We have maintenance capital, which declines over time based on our underlying decline rate, as well as the lower gathering rates that we highlighted also due to the gathering agreement that we saw with E-Train. So it tries to accomplish a static picture with improvement of declines and declining gathering rates, which offset with a little bit of inflation and rising cash taxes.

Great point. And then just one follow-up. Could you just talk about how you think about the cost benefits of a number of your environmental initiatives? I mean, obviously, a lot of your gas, you talked about becoming RSG, most recently, you have a low carbon initiative, and you have many other initiatives. It seems like you all seem to be leaning more into these than nearly all your peers. How do you think about this in a cost-benefit analysis?

I think there's real value here with our ESG initiatives, specifically on the environmental front. Where is the value? The value is in restoring the reputation of natural gas as the solution for the lowest cost, most reliable, cleanest form of energy. There is a major market opportunity for natural gas, as we've outlined on one of our slides here. Globally, there's over 400 Bcf a day of natural gas demand that's currently being filled by burning coal. In a world that cares about climate change, the number one thing we can do is replace coal with clean burning natural gas. The answer to do that is with natural gas. How are we going to get on the playing field and play a leading role in this? We've got to improve our status and showcase how great we produce and how great we operate from an environmental perspective. If you look at slide 23, one of the simple ways we can do that is by saying that we're net-zero on methane. Let's take methane emissions off of the table, which has been a question we've been getting a lot. Methane emissions is something that this industry is going to knock out of the park. We've laid out our pneumatic device program. That's the biggest thing we can do across the country at EQT. As Dave mentioned, we're accelerating our pneumatic device retirement program. We're going to be eliminating over 8,000 pneumatic devices this year for a cost of less than $20 million. That's going to be a big step towards us getting to net-zero. By doing that, Stage 1 for our reputation is eliminating methane emissions. The next step is illuminating the performance, and that's coming with our RSG certification programs. EQT is one of the largest—or is the largest—producer of certified natural gas with over 4 Bcf a day. That's over 5% of US natural gas volumes now certified just from EQT alone. Then you look at the rest of industry and everybody is picking up their part of it and being transparent and rushing to do the RSG certification. So the transparency is going to be there. Then with eliminating methane emissions and illuminating how good we are, we can start talking about replacing coal with natural gas around the world. What's this ultimately going to do for us? There are higher-priced markets where people are paying higher prices for energy. If we can get infrastructure in place, then we can connect low-cost Pennsylvania Marcellus and Appalachia gas to these higher-priced markets, and that's going to create a tremendous opportunity for our investors and also a tremendous cost saving opportunity for millions of Americans and billions of people around the world. It's a process, but I'm really excited about the opportunity in front of us.

Well said. Thanks, guys.

Thank you. Our next question comes from John Abbott from Bank of America. Your line is now open. Please go ahead.

Good morning and thank you for taking our questions. David, I'm going to direct the first question at you. You went over your hedging strategy in the opening remarks. And then you just discussed the volatility that we're seeing with gas prices. If you look at the cumulative free cash flow through 2026, you're talking about $10 billion. Do you take a more offensive view on hedging at this point in time just to lock in more of that cash flow given gas volatility?

Yes. I think the way we approach it now—and it's really an evolution of what we've done before—we look at our balance sheet and our needs. So we put in hedges with protection that give us the needs that we need to cover. What are those? One is we want to cover CapEx, we want to cover our dividend, we want to cover our debt retirement and we want to cover our stock buyback. In the past, we used swaps to do that. Now, with the market, we can use collars. By having a strong balance sheet, we don't need to hedge at as high a percentage. So we can hedge a regional percentage to give us that protection. The risk of going too far out into the future is that volatility, and we can see how that volatility caught people in 2021. So for us, we're going to add hedges methodically, and we're not going to go out beyond, call it, two years because we think that volatility will create opportunities for us in the future to be able to walk it in when we want to lock it in and not put us in a position where we hedge too early and too much.

Appreciate it. And the other question here is for you, Toby, just going back to the new completion design. Just want to clarify, so the $50 million, this is being spent in Southwest PA. Is this across a portion of the wells? Is it across all the wells? And have you tested this up in the Northeast or in West Virginia at this point in time, or is this really applicable to Southwest PA?

Yes. This is applicable to Southwest PA. It's around 30% of our wells that are going to have this next-generation well design initially. But the thing we're looking forward to is applying this next-gen design across the entire portfolio. That would mean West Virginia and Northeastern Pennsylvania as well. That's really exciting for us. Scale gives us the ability to invest in two things: infrastructure and technology. While we've shown you what we've done on the infrastructure side with the big water network in West Virginia, technology is being showcased here. To get these answers and make these design improvements, it costs a company the roughly $50 million to get these answers. The difference with scale is that that $50 million investment for us is going to translate to many multiples of value creation because we can apply it across our scale. We're excited about the results here in 2022, and we'll keep everybody updated on the progress as it comes in.

Thank you for the color. Appreciate you taking our questions.

Thank you. Our next question comes from Jeoffrey Lambujon from Tudor, Pickering, Holt & Co. Your line is now open. Please go ahead.

Good morning, and thanks for taking my questions. If I could ask maybe one follow-up to the well design on the technical aspects, I appreciate the color on the expected free cash flow improvement across the plan and what the testing entailed pulling from all the different well designs you used historically. But is there anything more you can share just on what some of those parameters are that are moving around in these new designs and maybe what the improvement at the well level could look like, assuming things play out in line with how you are modeling it internally?

I don't want to get too much into the technical details, but I will tell you this: one of the biggest factors to improve well design is spacing, and we're not touching spacing. So the things that we are doing are going to be things where we still have flexibility. We're not setting ourselves up to completely commit to a fixed spacing. We are preserving a lot of flexibility in the design parameters that we selected for this next-gen design. That's really important. We're confident it's going to be favorable, but we have that flexibility baked in. There are still other big parameters like spacing or other levers we can pull. Those are more prone to the gas environment you expect, but that's another lever that's in the back of our minds that we're evaluating as well.

Okay. Great. That's helpful. And then maybe just on the service outlook and understanding that inflation is the main driver of the year-over-year increase in well cost before considering that new design. I was just hoping to get a sense of what you're seeing today, if it's below that $760 per foot level and it's something you expect to trend higher throughout the year to kind of average at that level, or if you're already there looking for it to steady from here? And then longer term, it would just be great to hear what kind of inflation is embedded in the multiyear outlook at this point.

With inflation, we've got a lot of our services locked in. So feel like that's pretty much there. There are some things that we think will hopefully alleviate in the back half of this year or toward the end of the year, and that's largely one of the bigger drivers of inflation that you're seeing across the country—steel. We're optimistic that that will correct towards the end of this year. Then other constant operational items are materials and logistics. Those are things we can proactively manage every day to stay ahead of and mitigate some of the inflation impacts. And yes, we are anticipating that inflation will persist in the near term, but we do have inflation baked into our forecast.

Okay. Appreciate it.

Thank you. Our next question is from Nitin Kumar from Wells Fargo. Your line is now open. Please go ahead.

All right. Good morning and thanks for squeezing me in. I'm going to start with a big picture question for you guys. Toby, you mentioned the opportunity for the U.S. and EQT in particular. But you are kind of landlocked and it's hard to access international markets. Some of your peers took a different approach last year, going outside the basin. I heard you talk about M&A in your prepared remarks. What is your sense of comfort that things might open up—if not this year or next year, but in some foreseeable future—or does that force you to maybe look outside the basin for that growth?

One thing to say is LNG exports, whether at the Gulf Coast or elsewhere in the United States, will benefit natural gas producers by creating new demand. We have access to Gulf Coast through our firm transportation portfolio and we can touch that. As far as being landlocked, this will require more than EQT; it requires leadership to use their voice and claim energy security. We need to take a look at pipeline projects and address concerns about rising energy prices in New England. There are about 8 Bcf a day of pipeline projects out of the Northeast that have been canceled or opposed—those are projects that, if revived, could bring energy security to places like New England. Our largest natural gas fields—Marcellus—will be the key to supplying more LNG to the world and to the rest of America. Getting pipeline access out of Appalachia has to be a major focus given the amount of reserves here. To put this in perspective, Appalachia has more reserves in place than Russia. So it's incredibly important to focus on this. The prize is absolutely tremendous, both domestically and internationally.

Great. And from my follow-up, when you did the Alta deals, pro forma production was about 5.6 Bcfe a day. Guidance for this year is not too terribly different, but it is a little bit weaker, despite 30% of the wells having this new technology. Just want to understand the puts and takes here. Is this just timing? Is it risk? Just help us understand the slight decline in production despite a maintenance program.

We actually did conservatively set production guidance. Over the last couple of years, as we've shown productivity and efficiency improvements in our wells, we've often chosen to take CapEx down instead of growing production. So we could choose to grow a little bit this year and not take that efficiency, or we'll continue to solve for reducing our CapEx, which is probably what we'll end up doing. I wouldn't read too much into our production guidance.

Great. Thanks for the answers, guys.

Thank you. Our next question comes from Noel Parks from Tuohy Brothers. Your line is now open, please go ahead.

Good morning. On the ESG front, I very much resonate with your comments about the industry's role in educating policymakers and the public on the importance of natural gas while on the road to alternatives. In Europe, they've been more aggressive on climate goals over the past decade and there's more realism there, even within environmental groups, about the need for natural gas. Do you see signs of that awareness moving over here, either in rhetoric or more concretely in terms of international or European concerns approaching you to talk about long-term supply agreements?

We have seen a lot of movement and change favorably toward natural gas in Europe. Europe is probably about five years ahead of the United States in how they think about climate and influencing policies—they've put over 25% of their grid on renewables and they're seeing some reliability issues. It's a useful lesson for us. Energy outages are showing up here in the United States; there have been over 19,000 blackouts in the U.S. over the last 10 years—roughly a blackout every three hours—so clearly we need more reliability and energy security. The good news is we've got a solution: U.S. natural gas. We have a lot of it and can provide low-cost, reliable clean energy. A balanced approach is needed: more renewables and more natural gas. It's going to be a team effort, and natural gas is a major part of the solution.

Great. Thanks a lot.

Thank you. Our next question comes from Josh Silverstein from Wolfe Research. Your line is now open. Please go ahead.

Thanks. Good morning, guys. Maybe just sticking to the investment-grade question here. What happens right away when that trigger happens? How much working capital can come off? Letters of credit go right away? And on the same subject, you mentioned in the slides that you need investment grade for potentially doing something related to LNG pricing. What is that referring to? Are you able to contract something tied to international pricing like JKM? A little more detail there would be helpful.

When we get upgraded to investment grade, materially, if not all, of our letters of credit—about $400 million—will go away, which would increase our liquidity by roughly that amount. We have other benefits too: for each upgrade step we get about a 25-basis improvement on our 2025 and 2030 debt, so our interest expense will improve. At some point we'll redo our revolver, which will be a net benefit by extending our maturity. We're having lots of conversations with LNG players across the whole chain. Our goal would be to have something locked up where pricing is tied to international prices rather than just Henry Hub. That would help drive realizations meaningfully when we do it.

Got it. And then second for me: you mentioned the REX deal and more generally if pipelines don't get built, what are other ways you work around that? Do you buy access into other pipelines or structural things you can do?

If interstate pipelines don't get built, the Marcellus remains throttled and that means a continued disciplined maintenance program. EQT will still generate a lot of free cash flow in that situation. One unique thing about EQT is our ability to grow free cash flow per share even in a maintenance mode. Even with gas prices down in 2023 at strip, our free cash flow is expected to grow, and our yield is expected to go from 20% to 30% from 2022 to 2023. We hope to see sustainable demand and infrastructure that secures higher prices. Until then, we'll continue to push for infrastructure and look for commercial solutions like optimizing firm transportation and financial hedges to access different markets.

Thanks.

There are no additional questions waiting at this time. I'll pass the conference over to Toby Rice for closing remarks.

Thank you. Over the past couple of years, I got asked a lot: Toby, why are you doing this—the takeover and the turnaround of this business? It was incredibly a lot of work. The reason why we went through this is to be in this position today. The momentum that this company has built over the years is tremendous. The free cash flow momentum we have is really starting to show up, and we're really excited about continuing this rate of change story and delivering for our shareholders. Thank you.

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