Good morning. Welcome to today's EQT Q4 Quarterly Results 2022 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. If you would like to ask a question, please press star followed by one on your telephone keypad. I would now like to pass the conference over to our host, Andrew Breese, Director of Investor. 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 their prepared remarks in 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 in 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, discuss our fourth quarter results, and reveal our 2022 financial and operational outlooks. 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 31st 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 in 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 and 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 12-month 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 10-cent 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 to value chain to gain exposure to international prices. While these catalysts provide an exciting future for EQT, we have not lost sight of the value of our core business. The way in which we operate is a key differentiator for EQT. 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 2+ years, these efforts are bearing their fruit with 300,000-400,000 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 multi-year consistent results. On slide 15 of our investor presentation, we show you what combo development looks like. 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. 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 timeframe between spud to turn in line and our planned phase 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. 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 1-1.5 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-$1.45 billion. We expect to generate $3.1-$3.3 billion of adjusted EBITDA and $1.4-$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 dollar 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 $ 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 spent 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%. 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 costs 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 across 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. As of December 2021, we now have the ability to capitalize on this opportunity through 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 Q4 2021 results, implemented our updated hedge strategy, announced and executed our capital allocation program, have aligned our sights 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 pre-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 layered 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 only have 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 10-cent move in local pricing, our 2022 free cash flow forecast, which 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%-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 production growth. The fourth quarter of 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 of year-over-year demand. First, FT 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 twelve-month leverage of 2.3x. Over the next twelve 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, our year-end 2022 and 2023 net leverage to be around 1.4 and 0.5 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 PV10 for the year ending 2021 was $21 and a half billion, an increase of $17 and a half billion from 2020. This increase was driven by a substantially higher SEC price deck. As previously noted, our total before tax PV10 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, an 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 U.S. 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 U.S. LNG is an emissions reduction opportunity that can be executed at scale, with speed, at a low cost, and 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 U.S. nat gas. EQT, America's natural gas champion, will be ready to answer that call. I'd like to now open the call up to questions. Thank you. If you will like to ask a question please press star followed by one on your telephone keypad. If for any reason you will like to remove your question please press star followed by two. Again to ask a question it is star followed by one. If you are using a hands dial please pick it up before asking your question. Our first question is from Arun Jayaram from J.P. Morgan. 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 a $1 billion buyback authorization through year-end. 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. Yeah, great question on buyback and pace, certainly is an exciting opportunity in front of us. Just a little bit about what we've done to date to sort of help you understand the pace that we've been working at. You know, 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 bit 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. You know, we're here now, we're sort of 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 you know really talked too much about it, I mean, the ultimate game plan for our dividend is to position this company to be a consistent dividend grower. That's the, I'd say, the last part of our capital allocation plan that we'd like to provide some color on in the future. Great. In 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. I was wondering if you could kind of 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, this is Dave. First and foremost, when we provided guidance, you'll notice that we provided wider ranges for free cash flow and our basis, just given the fact that gas is very volatile. You know, when we started and put the guidance out, prices were actually $0.80 higher. 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. That's part one. 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, actually a touch above it, is actually tied to our new well design. That's gonna 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 we'll get paid back in RSG and then some. Those I'd call two things. Then obviously we dealt with a little inflation. When you factor that in, I would say that along with the fact the 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. You're welcome. Thank you. Our next question comes from Scott Hanold from RBC Capital Markets. Your line is now open. 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. Also, you know, related to that, there were obviously some fee relief, but some payments that could occur, you know, in the event that it gets delayed. Can you just discuss what is your positioning on how you look at that and what we should assume going forward? Yeah. If you notice in the slides, because we had a, we have something on our FT portfolio and how our gas moves around, we provided for 2022 and 2023. We had to pick a spot in where we thought MVP was gonna come online, and we did that as a placeholder before Equitrans puts out their update in about a week or so. We picked mid-year 2023, so effectively we say to set about a year delay. Again, I think that is a placeholder that will adjust once Equitrans puts out their updated guidance. When you look at the impact to us, I would say, you know, basis widens in 2022. If basis widens in 2023, we lose the benefit of the fee relief, but we also don't pay the high seventies costs on the portion that we retained. We also don't pay, we'll call it the Henry Hub kicker piece as well. When you net it out, you know, it's a modest negative for 2022. I'll call it a little bit bigger negative 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, irregardless of what basis NMO does. Yeah, Scott, this is Toby. Just some high-level comments, just what's going on in the world right now, and really just a read-through on how important pipeline infrastructure is in this country, specifically MVP. You know, listen, 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, you know, extreme prices in New England is because of lack of pipeline infrastructure, plain and simple. You know, without these pipelines, we're gonna continue to see these extreme pricing scenarios, which, by the way, we don't like as energy providers. We wanna provide low-cost, reliable energy to every American. Why is what's happening in New England relevant? It's relevant to the people in southeastern United States. You need to understand that there is a pipeline that is gonna allow you to benefit from low cost, reliable, clean energy. This is something that people need to be aware of because you know, what's happening in Europe, what's happening in New England, you know, is starts with things like that's happening right now with MVP in the southeastern part of the United States, and we really are looking forward to getting that pipeline project completed. appreciate the color. As my follow-up, you know, you identified, I think, 1,800 core locations that you all have left, and I think, Toby, you mentioned it's about 100 wells, you know, 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 can you get from these well designs? And what could that well count look like, you know, if it works? To keep the. Sure. The EUR uplifts we're looking at right now are gonna be double-digit increases on a percentage basis. We're not able to say exactly what that will be dialed in. You know, we have just to give you some color on what we're doing, you know, our small-scale science testing program that we've done over the last couple 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. If we assume that we got the uplift from all of those pieces that we're putting together, it would be you know, pretty exciting. We're taking a conservative approach right now. I think by the end of 2022, we'll have a full assessment of what the total impact for all three of these. I mean, each of these individual tests were exciting by themselves, and putting them together is something that we're looking forward to assessing in 2022. You know, that percentage increase that we get on 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, David, just take it a step further on MVP. You know, how are you thinking about that cash option that expires at the end of 2022, and then as well as your current stake in Equitrans? Yeah. Holly, it's a great question. You know, 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. That fee relief was about, we'll call it, $250 million, roughly. We could take that back as a chunk of cash, but for approximately $200 million. The determination really will be when do we think MVP come online, right? That's gonna be the question mark. We'll sit and wait and look and see what Equitrans says as sort of the timing, and then we'll think about whether we'll pull the trigger on pulling that cash. Okay. Your stake in the shares? Yeah. You know, we actually sold some shares in the fourth quarter, and we'll be thoughtful in when we wanna sell them again. 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. We'll wait until we get the view on MVP and the timing, 'cause I think that's creating obviously a cloud over Equitrans stock. Yep, indeed. Okay. Thank you. You know, Toby, maybe you mentioned kind of the two big acquisitions that certainly you've done as CEO. Maybe touch on both those deals, you know, what you've learned and why, I guess, having those you know in your asset base kind of excites you as you move into 2022. It looks like about 10% of your wells will be in that Alta area. Chevron obviously isn't as easy to separate. You know, just thinking about those deals specifically. Number one, you know, 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, you know, we're conservative and proven to be conservative. Seeing the operational performance improvements on Chevron with the OpEx dropping by over 30%. The drilling efficiencies we're seeing in Alta, hopefully, we continue to see more efficiencies as we step more into completion. I think it's a really great example of, you know, this modern operating model we've built, and the teams here can unlock the value that we conservatively underwrite. That's number one. Number two, you know, again, just being disciplined. We didn't pay for any of the what we consider the lesser quality inventory. We always said, you know, in these both these packages, there's a significant amount of Tier two acreage that, you know, we always said if gas prices ever get to $2.75, there's gonna be a tremendous amount of option value unlocked. Well, you know, this is where we're at today. Again, all to say, just to be conservative in our approach there. You know, 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, I mean, it's all about- Putting our dollars to the best investments, best rate of return. Given the market today on the M&A landscape, you know, nothing competes with buying our stock, and that's been our focus. That's great color. Thank you, guys. Thank you. Thank you. Our next question comes from Neil Mehta from Goldman Sachs. Your line is now open. Please go ahead. Yeah. Thank you, team. First question is just on unit cash costs. They do move higher in 2022 versus 2021. Just wanted 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. Yeah. We have a little bit of midstream impact that went up. We have a little bit of non-op costs went up. Then we also signed our gas, I'm sorry, our water agreement with Equitrans in PA. 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 Equitrans on the water deal. David, it sounds like you have a pretty high confidence interval that that's not moving around a ton, despite some of the inflationary environments that we're seeing. Yeah, I know. Just an overall view on guidance. You know, when we provide guidance, we do with very high confidence, and our goal is to beat guidance and move it up. You know, look at our last two years' track record. You know, that's been our goal when we set guidance. We wanna, you know, beat our guidance. Okay. The follow-up is just, can you take us into the room for your conversations with the ratings agencies? Is everything on track to get to investment grade? 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? Yeah. You know, we try to, just like we try to, with all our investors, our commercial banks, you know, we have lots of conversations with the rating agencies. You know, we wanna make sure they're very comfortable in our glide path back to investment grade. We've had multiple conversations about our shareholder and capital allocation plan. If you notice, you know, our buyback is very much paired with our debt reduction, right? We feel that's very prudent from our standpoint to how we manage our balance sheet. I think they feel comfortable that where we're sitting our balance sheet and our goals and our long-term leverage. It's not about just taking leverage down, because that'll 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, Dave. Thank you. Our next question is now from Neal Dingmann from Truist Securities. Your line is now open. Please go ahead. Morning, David, Toby. Guys, question, I'm sure who would like 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, you know, what you're expecting on pipelines or efficiencies, costs, pace, you know, you or David, maybe the sort of high item, the highlighted items of that? Yeah. I'll let David put some color on some of the cost assumptions. You know, I think one of the key things to call out and probably one of the is the long-term free cash flow forecast we have. I mean, is assuming you know strip pricing, which we know is backwardated. You know, so you're talking about $3 in 2025, 2026. Obviously, this business can generate a ton more free cash flow in a higher price environment. I think that really is probably gonna be a big mover. You know, I think the call on clean energy and the demand for reliable clean energy has never been greater. We think that what we're seeing with prices here is a read through to what we can see in the future. I mean, Neil, I think energy prices have gone a little, I think have gotten pretty extreme very quickly over this past winter season. Let me remind you, this was not a cold winter. What solves, you know, what keeps prices, you know, sustainable and still low cost but not so volatile is gonna be infrastructure and a commitment and investment and call on natural gas. We've got the resources to do it, and I think it's gonna be a compelling, you know, macro setup for us in the longer term of our free cash flow forecast. Dave, you wanna talk about some of the costs we have in there? Yeah. First and foremost, know that embedded into 2022 is the new well design cost, we'll call it slightly over $50 million. We really don't have any material benefit of that new well design in our production. Just know that as a starting point. You know, we have embedded into our 10-year free cash flow picture, you know, cash taxes rising over time, basis actually narrowing because of an expectation not only just of MVP coming online, but also the forward curve for 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 having the lower gathering rates that we've highlighted are also due to the gathering agreement that we signed with Range Resources. It tries to accomplish basically we'll call it a static picture with improvements in declines and gathering rates offset with a little bit of inflation and rising cash taxes. Great point, guys. Just one follow on. Go ahead, Toby, sorry. I was just gonna wrap up. I mean, all those things that Dave mentioned are gonna be represented in what we're calling our breakeven cost- Right. You know, to run the business. Which sub $2.30. Yep. Yeah. Which is sub $2.30 today and going lower. Great add. Just one follow-up, Toby. Could you just talk about how you think about sort of 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. I mean, to me, it seems like you all seem to be leaning more into these than nearly all your peers. Just wondering how you think about this maybe on a cost-benefit analysis. Yeah. I mean, I think there's real value here, with our ESG initiatives, specifically on the environmental front. You know, where's 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. You know, 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 foreign coal with clean burning natural gas. Hands down, full stop, the biggest impact we can make on arresting climate change is arresting coal. The answer to do that is with natural gas. How are we gonna get on the playing field and play a leading role in this? We've gotta 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. Let's take methane emissions off of the table, which has been a question that we've been getting a lot. This is great because methane emissions is something that this industry is gonna 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 gonna be eliminating over 8,000 pneumatic devices this year for a cost of less than $20 million. That's gonna be a big step towards us getting to be net zero. By doing that's stage one for our reputation is eliminating the methane emissions. We're going to do that. 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 U.S. net gas volumes are now certified just from EQT alone. Then you look at the rest of industry and everybody's, you know, picking up their part of it and being transparent and rushing to do the RSG certification. The transparency is going to be there, with eliminating the methane emissions, illuminating how good we are, then we can start talking about the alternative, you know, coal with natural gas around the world. You know, what is this ultimately gonna do for us, Neil? You know, 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 natural, Pennsylvania, Marcellus, West Virginia, Ohio, low-cost Appalachia gas to these higher-priced markets. That's gonna 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. I mean, it's a process, but you know, really, really excited about the opportunity in front of us. Well said. Thanks, buddy. Got it. 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 gonna 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. You know, 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 just given gas volatility? I think the way we approach it now and really it's I'll call it an evolution of what we've done before. You know, we look at our balance sheet and our needs. We put in hedges with protection that give us the needs that we need to cover. What are those? One is we wanna cover our CapEx, we wanna cover our dividend, we wanna cover our debt retirement, we wanna cover our stock buyback. In the past, we would use swaps to do it. Now, with the market, we can use collars. By having a strong balance sheet, we don't need to go and hedge at a much higher percentage. We can hedge at, call it, 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 us in 2021. I think for us, we're gonna go out and we're gonna add hedges methodically, and we're not gonna go out beyond, or call it, two years, because we think that volatility will create opportunities for us in the future to be able to lock it in when we wanna lock it in and not put us in a position where we feel like we hedged too early and too much. Appreciate it. The other question here is for you, Toby. Just going back to the new completion design. Just wanna clarify. So this, the $50 million, this is being spent in Southwest PA. Is this across a portion of the wells? Is this across all the wells? 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? Yeah, this is applicable to Southwest PA. It's around 30% of our wells are gonna have this new next gen well design. But the thing we're looking forward to is applying this next gen design across the entire portfolio. That would mean West Virginia, that would mean Northeastern Pennsylvania. That's really exciting for us. I think, you know, we talk a lot about how EQT can leverage our scale. We say, well, 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's gonna cost any company, you know, call it $50 million to get these answers. The difference with scale is that $50 million dollar investment for us is gonna translate to many multiples of value creation because when it's applied to our scale. You know, that's. We're excited about looking forward to 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. Got it. Thank you, John. 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 new well design, maybe on the technical aspects. I appreciate the color on the expected free cash flow improvement across the plan and, you know, what the testing entailed, pulling all from all the different well design you've 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? You know, just assuming things play out in line with how y'all are modeling it internally. Yeah. I don't wanna get too much into the details, but I will tell you this. One of the biggest factors to improve well design is spacing, and we're not touching spacing. 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 this. We are preserving a lot of flexibility in the design parameters that we selected as this next gen design. I think that's really important. We're confident it's gonna be favorable, but you know, we've got that flexibility baked in. There's still other, like I said, other big parameters like spacing or other levers we can pull. Those are more, you know, prone to the gas environment you expect, but that's another lever that's in the back of our heads that we're evaluating as well. Okay, great. That's helpful. Maybe just on the service outlook and, you know, 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 from what you're seeing today, if it's, you know, below that $760 level on well cost and, you know, it's something you expect to trend higher throughout the year to kinda average at that level. Or, you know, if you're already there and looking forward to kinda steady from here. Longer term, would just be great to hear what kind of inflation is embedded in the multi-year outlook at this point. Sure. With inflation, you know, 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 towards the end of the year. That's largely one of the bigger drivers in inflation that you're seeing across the country, and that's steel. We are hopefully optimistic that that will correct towards the end of this year. Just sort of the other stuff that you know is the constant grind every day is just making sure we have the right access to the right amount of materials, logistics. Those are things that we can do proactively, hustling every day to stay ahead of it and hopefully mitigate some of the inflation impacts that we're seeing. To your last question, yeah, going forward, I mean, we are anticipating that inflation will abide. 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. Hi, good morning, and thanks for squeezing me in. I guess I wanna start with a big picture question for you guys. You know, Toby, you've mentioned the opportunity for US and EQT in particular. But you are kinda landlocked, and it's hard to access those 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, but just, you know, what is your sense of comfort that things might open up, if not this year, next year, but in some foreseeable future? Or does that force you to maybe look outside the basin for that growth? Well, one thing I would say is LNG exports whether it's in Gulf Coast or anywhere in the United States is gonna benefit natural gas producers just serving as an outlet by creating new demand for every operator. While we do have access to Gulf Coast through our FT portfolio, we do have the opportunity to touch that. As far as, you know, your question about being landlocked, you know, this definitely is gonna be. It's gonna require more than EQT. It's gonna require more than just this industry. It's gonna require leadership to use their voice and claim their energy security. This means we need to take a look at pipeline projects and, you know, people that are concerned about rising energy prices in New England. Let's remind them that there's 8 BCF a day of pipeline projects out of the Northeast that have been canceled or opposed. Those are projects that we can revive, breathe life into, bring those back in line, and give the energy security to places like New England. One thing that's really key to understand, though, is, you know, our biggest natural gas fields in the country and in the world, the Marcellus, is going to be the answer for doing more, supplying more LNG to the world and to the rest of America. Getting pipeline access out of Appalachia has got to be a, you know, very big focus for us, just given the amount of reserves that we have here in Appalachia. Just to put this in perspective for everybody, Appalachia has more reserves in place than Russia. It's incredibly important that we focus on this. I think people have identified the issues with the energy ecosystem. The answer is the Marcellus. The answer is more pipelines out of New England. It really is that simple. The prize is absolutely tremendous, both here domestically and for you know, the world being able to get off of foreign coal. Great. Yeah, from, I guess, for my follow-up question is a little bit narrower focus. You know, 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 wanna understand the puts and takes here. Is this just timing? Is it risking? Just if you can help us understand the slight decline in production despite a maintenance program. Yeah. Yeah, Nitin, we actually do hedge our production, but I would just say, again, we put guidance out that hopefully we're gonna meet or beat. I think just stay tuned and you'll see how we execute this year. You know, last couple years as we've showed the productivity and the efficiency improvements in our wells, we effectively, instead of growing production, we've actually taken CapEx down. You know, we can decide if we wanna grow a little bit this year and not take that efficiency, or we'll continue to solve for, or call it, 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. You're welcome. Got it. Thank you. Our next question comes from Noel Parks from Tuohy Brothers. Your line is now open. Please go ahead. Hey, good morning. Good morning. Morning. Just had a couple things. On the ESG front, I very much resonate with your comments about the industry's role in educating policymakers, the public on the importance of natural gas while on the road to alternatives. Something I've heard for some time is that in Europe, they have been more aggressive on climate goals over the past decade or so, that there is more realism there, even within the environmental lobby about the need for natural gas. I just wonder if you see signs of that awareness moving or making its way over here, either in terms of, you know, the rhetoric or even more concretely in terms of, you know, international European concerns approaching you, trying to talk about long-term supply agreements. Yes. We have seen a lot of movement and change, favorably towards natural gas happening in Europe. I think most significantly is marking nuclear and natural gas as green energy options. That's really exciting. In my perspective, Europe is probably five years ahead of the United States when it comes to how they think about climate and influencing policies. Europe has put over 25% of their grid on, you know, renewables, and they're seeing the impacts of sacrificing reliable, clean energy and just prioritizing the green stuff. It's a good lesson for us to look at here. Yeah, I mean, there's issues that are showing up here in the United States, specifically New England, but not just in New England. I mean, energy outages are a thing across the country. I think last call I talked about, you know, there being over 19,000 blackouts in the United States over the last 10 years. A blackout happening every 3 hours. We clearly need more reliability, more energy security here in the United States. The good news is we've got a solution, and it's U.S. natural gas, and we've got a lot of it. We can provide the lowest cost, most reliable clean energy in the world here. Yeah, I mean, we've got a really credible solution. I think people are opening their eyes to, you know, that this needs to be a balanced approach. We need to do more renewables. We need to do more natural gas. It's gotta be a complete team effort here. I think natural gas is the best player we can put on the field. Total, it's definitely gonna be a team effort. Great. Thanks a lot. I just wanted to ask about inflation and a higher interest rate environment. I just wondered what sort of impact that might have on your thinking strategically, either in terms of M&A or in terms of maybe, you know, divestment of some of your less core areas. I mean, thinking about the difference between, say, whether inflation is and higher rates are gonna be like a one-year story, essentially just a ripple off of COVID, or whether we're looking for more like, I don't know, say a five-year story of inflation and higher rates. I just wondering in your modeling how you look at that cost of capital impact. It's actually a very interesting question you ask because obviously people are looking at inflation and everybody's very aware of the accelerating inflation. On one hand, you think about it, commodities are the natural net beneficiary of a rising inflationary environment. The underinvestment across all commodities is driving some of that. That means as demand you know continues to grow, supply is not keeping up. We're gonna get the net beneficiary of rising natural gas prices, and it's also exacerbated by this inflation by the you know the rise in the cost of carbon and the impacts it has on coal and you know more we'll call it polluting fuels from a carbon basis. We'll, you know, gas will be the net beneficiary. On the flip side, we're generating rising free cash flow, and we're gonna retire our debt. When you have a rising interest rate environment, that will drive our, you know, our yields a little bit higher, our principal payments down a little bit as well. We'll be able to retire our debt a little bit cheaper as well. Then, you know, the way we effectuate our cost to capital is by buying back our stock. We can meaningfully close the gap on what our equity cost to capital is, and we can actually lower our cost of debt by retiring our debt. Our capital allocation program is absolutely helping us drive our weighted average cost of capital down over time. It's a really good question. It's a really good theoretical question that we're trying to make sure that we catalyze it into real value. Great. Thanks a lot. Thank you. Our next question comes from Josh Silverstein from Wolfe Research. Your line is now open. Please go ahead. Yeah, thanks. Good morning, guys. Maybe just sticking to the investment grade question here. What happens right away when that trigger happens? Like how much working capital can come off? Do the letters of credit go right away? Then on the same subject, you mentioned 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 at JCC or JKM pricing? Just a little bit more detail there. Yeah. When we get upgraded to investment grade, we'll call it materially, if not all of our letters of credit, the $400 million will go away. That means our liquidity will pop by another, we'll call it $400 million. We have some—I'll call some other things that will happen. You know, for each upgrade, we get 25 basis point improvements on our 2025 and 2030 debt. Our interest expense will come down. I think we have another 50 or 75 basis point improvement there. Our interest expense will improve. At some point we're gonna redo our revolver, and that obviously that'll be a net benefit for extending out a revolver. We'll call it, you know, 4 or 5 years. That's called, we'll call it the capital part of it. We're having lots of conversations right now with LNG players across the whole chain. Our goal would be to have something locked up for 2022, and obviously our goal would not be to sign something up, we'll call it with a Henry Hub price. It would be to tie it to international prices. That would be something that help us, you know, drive our realizations up pretty meaningfully when we do it. Got it. Second for me, so you mentioned kind of the Herculean effort that's needed to get new infrastructure built, but what happens if nothing gets built? Like, do you buy access into other pipelines like you did with the REX deal? How do you work around that? Yeah. What happens is, you know, the potential of the Marcellus, you know, stays throttled. That's gonna mean a continued maintenance discipline program, and EQT will be generating a lot of free cash flow in that situation. You know, one of the unique things about EQT, 'cause let's always think about how can companies grow. One of the unique things about EQT is we are going to grow our free cash flow per share even in a maintenance mode. I think that is incredibly unique for us. You know, even with gas prices going down in 2023, our free cash flow is going to grow, and our yield is gonna go from 20% to 30% from 2022 to 2023. Listen, I hope we have the opportunity. I would love to see sustainable demand where we can secure, you know, higher prices than what we're getting locally here. We can secure that supply with the long-term demand, so we're not throwing the supply demand fundamentals out of whack. That opportunity I hope presents itself, and we'll be pushing for it. You know, up until then, we're sort of just out here letting everybody know the solution that's here, and we're more than willing to go out there and help. We definitely have growth in our business, but it's not gonna be from production without the sustainable demand signal. Got it. Thanks guys. Thank you. There are no additional questions waiting at this time, so I'll pass the conference over to Toby Rice for closing remarks. Thank you. You know, I over the past couple years, I got a question a lot is, you know, "Toby, why are you doing this?" You know, the takeover, 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. This is the prize. 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 line.