Good morning, ladies and gentlemen. Thank you for attending today's EQT Q2 2022 quarterly results conference call. My name is Tia, 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 questions and answers at the end. If you would like to ask a question, please press star one on your telephone keypad. I would now like to pass the conference over to your host, Cameron Horwitz. You may proceed. Good morning, and thank you for joining our second quarter 2022 earnings results conference call. With me today are Toby Rice, President and Chief Executive Officer, and David Khani, Chief Financial Officer. The replay for today's call will be available on our website beginning this evening. In a moment, Toby and Dave will present their prepared remarks with a question -answer -session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements because of the factors described in yesterday's earnings release, in our investor presentation, in the Risk Factors section of our Form 10-K, and in subsequent filings we make with the SEC. We do not undertake any duty to update any forward-looking statement. Today's call may also contain certain non-GAAP financial measures. Please refer to our most recent earnings release and investor presentation for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. With that, I'll turn the call over to Toby. Thanks, Cam, and good morning, everyone. Since our first quarter call, we have seen significant commodity price and equity market volatility. However, one thing that has not changed is the growing recognition that the world needs more clean, low -cost U.S. natural gas supply in order to achieve its climate goals, drive down inflation, and provide energy security both domestically and to our allies abroad. We're seeing this recognition play out on a global stage with positive signposts of support for natural gas as a key fuel source for decades to come. One such example is the recent vote from the EU Parliament to include natural gas investment as climate friendly under the European taxonomy starting in 2023. Decisions like this highlight the global shift toward embracing pragmatic energy solutions that can address climate change by attacking the largest source of global emissions, which is foreign coal. In short, at a time when the world is being forced to determine what the best option is for affordable, clean and reliable energy, it is overwhelmingly turning to natural gas as the solution. Here at home, recent nationwide polling data shows the U.S. public is speaking loud and clear in support of more domestic natural gas development. Specifically, the polling data shows nearly two-thirds of voters rank strengthening U.S. energy independence and reducing energy costs as their top priority today. Nearly 70% of voters support increasing U.S. natural gas production, and a similar amount support building new natural gas pipelines, with majority support running across all party lines. Voters are more likely to support a candidate that supports natural gas development by a 33-point margin. Put simply, the American public is demanding that U.S. natural gas play a leading role in providing affordable and reliable energy to the world while also addressing climate change by replacing foreign coal. In a world that recognizes and acts on the need to unleash U.S. natural gas, EQT will thrive for several key reasons. First, we are the largest producer of natural gas in the U.S. with a multi-decade high return inventory. As shown on slide 12 of our investor deck, we highlight break even pricing of our entire 1,800 core Marcellus inventory, with every location generating a 10% or higher return at a natural gas price below $3 per Mcf. We note this core inventory has very rigid inclusion criteria, and a de-risked view of our portfolio shows more than 2x upside to this location count across our broader acreage position. We believe this combination of depth and quality of our inventory is unrivaled among peers and gives us significant confidence in our ability to generate strong shareholder returns for as far as the eye can see. Second, our investment grade credit ratings underscore the strength of our balance sheet, which we see as a key tenet for the long -term sustainability of our business and allows us to opportunistically lean into value-creating investments across commodity cycles. Year -to -date, we have repurchased approximately $830 million of debt principal, and we plan to further fortify our balance sheet as we are raising our year-end 2023 debt reduction goal by $1 billion to $2.5 billion to tactically capture the market discount currently available. Third, we have among the best ESG credentials across the entire energy sector, which is backed up by the progress highlighted in our recently released 2021 ESG report. As shown on slide 14 of our deck, we have lowered our Scope 1 and Scope 2 GHG emissions by 36% on an absolute basis and reduced our methane intensity by a similar amount in just three years. Our track record gives us tremendous confidence in achieving our net zero goal by or before 2025, and we highlight the credible path it will take to get there on slide 15 of our deck. In summary, we have what the world needs. A leading inventory of low -cost, low emissions natural gas with the balance sheet and scale to support long-term development. These characteristics position EQT at the tip of the spear to meet the growing natural gas needs of both domestic and international end users via LNG. As highlighted in our last call, we continue to have discussions with LNG end users across various geographies. As a reminder, our firm transportation portfolio delivers approximately 1 Bcf per day of production to the Gulf Coast, and we are looking at various paths to unlock LNG opportunities along the East Coast. Turning to second quarter results. We executed on the midpoint of our production guidance as we were able to ameliorate the logistical issues that slowed down frac times in Q1. As shown on slide 13 of our deck, pumping hours per frac crew during the quarter increased by 25% sequentially and were up 7% year-over-year despite a significantly tighter oilfield service backdrop. We tip our hats to our operations teams here as they have enabled continued efficient execution of our combo development strategy even in the face of a challenging operating environment. We continue to make progress on the evolution of our new completion design, with several key projects successfully executed in Q2 and several more planned for Q3 and Q4. While we are still in various phases of assessing our science work, recent indications give us incremental confidence in the productivity uplift associated with our new design, and we plan to make a decision in 2023 as to broader implementation across our asset base. As a reminder, full implementation of this new design would be expected to both reduce annual long-term well count and capital needed to produce the same level of volumes. Turning to capital returns, as shown on slide nine of our investor deck, we are augmenting the framework we originally laid out to the market last December. First, we recently raised our base annualized dividend by 20% from $0.50 to $0.60 per share, which is a sign of the growing confidence we have in the sustainability of our business and longer-term natural gas prices. We believe a strong and growing base dividend is one of the best read-throughs to the long-term value proposition of an organization, and this adjustment reflects exactly that. We plan to continue reassessing our base dividend at least annually and see material room for long-term sustainable growth. Second, we are increasing our debt reduction target by $1 billion to $2.5 billion by year-end 2023. While we had planned incremental debt retirement beyond 2023, given our long-term leverage goal of 1x-1.5 x, we are taking the opportunity amid robust commodity prices to accelerate delevering and unequivocally fortifying our balance sheet. The recent rise in broader interest rates has created a unique opportunity as our bond prices have declined despite our strengthening underlying credit quality. Taking this action ensures long-term business sustainability, drives asset value to our equity holders, and gives us significant flexibility to invest throughout cycles. We are keenly focused on deploying capital to the best risk-adjusted return opportunities available to us, and a pristine balance sheet is a key enabler for us to compound value for our shareholders over time. On share repurchases, recall we rolled out our $1 billion authorization last December, noting we would be opportunistic with deployment. After aggressively repurchasing $230 million of stock in Q1 at an average cost of $23 per share, our stock more than doubled in value at certain points during the quarter. At the same time, we saw some early warning signs of recessionary risk, and as such, we temporarily tapped the brakes on our buyback, highlighting that we will remain disciplined on all forms of capital deployment and firmly focused on earning the best risk-adjusted return for our shareholders. As our stock pulled back toward the end of Q2, we started opportunistically retiring our convertible notes, which are trading virtually in parity with our common shares. With the $213 million we spent repurchasing convertible notes during and subsequent to the end of Q2, we lowered our fully diluted share count by almost 6 million shares at an effective equity price of approximately $37 per share while simultaneously eliminating a debt obligation and simplifying our balance sheet. In total, our updated framework allocates roughly $4 billion toward shareholder returns by year-end 2023 and leaves approximately $3.5 billion of retained free cash flow flexibility at recent strip. With the continued resiliency of longer-dated natural gas prices, we now see approximately $22 billion of cumulative after-tax free cash flow from 2022 through 2027 at current strip. This is up from the prior $17 billion we highlighted last quarter and equates to approximately 140% of our current equity market cap, underscoring the tremendous value opportunity embedded in EQT shares. I'll now turn the call over to David. Thanks, Toby, and good morning, everyone. I'll briefly summarize our second quarter results before discussing our balance sheet, hedging, basis, and guidance updates. Sales volumes for the second quarter were 502 Bcfe, in line with the midpoint of our guidance. As Toby mentioned, we implemented new technologies during the quarter to address the tight trucking market we experienced in the first quarter. This is paying off as we saw material improvement in completion efficiency on a sequential basis. Our adjusted operating revenues for the quarter were $1.6 billion or $3.21 per Mcfe, and our total per-unit operating costs were $1.37. As a result, our operating margin was $1.84 per Mcfe, about $0.80 cents or 75% higher than last year on higher volumes and price realizations. Capital expenditures were $376 million, in line with the high end of our guidance range. Adjusted operating cash flow was $915 million, and free cash flow was $543 million, bringing our total year-to-date free cash flow to more than $1.1 billion. Our capital efficiency for the quarter came in at $0.75 per Mcfe, which was up sequentially due to greater spending on science associated with our new completion design and continued inflationary pressure. Turning to the balance sheet, recall we achieved investment grade with credit ratings from Fitch and S&P earlier this year, underscoring the material progress we made in creating a more sustainable company for our stakeholders. As Toby mentioned, we are taking even more action to bulletproof our balance sheet through all parts of the commodity cycle by raising our year-end 2023 debt reduction target by $1 billion- $2.5 billion. This will reduce our gross debt to approximately $3 billion and accelerate achieving our long-term leverage target of 1x-1.5x using a $2.75 gas price. We are not wasting any time executing our goals as we deployed approximately $390 million over the past several weeks, including repurchasing approximately $175 million of senior notes and $213 million of convertible note principal and premiums. We note that the retirement of convertible notes executed to date has lowered our fully diluted share count by approximately 6 million shares, while also simplifying our balance sheet. At the end of the second quarter, a trailing 12-month net leverage stood at 1.6x, down 0.3 turns from the prior quarter. Note our net debt at quarter end reflects the impact of approximately $690 million of working capital usage during the quarter, the bulk of which should reverse in the second half of the year. At recent strip pricing, we forecast our year-end 2022 and 2023 net leverage to be approximately 1x and -0.1x respectively, which contemplates executing the remainder of our buyback authorization and accounts for our 20% dividend increase. We ended the quarter with approximately $2.2 billion of liquidity, and we recently renewed our $2.5 billion unsecured revolving credit facility with a five-year maturity. Two key points to note here. First, we added two new banks to our bank syndicate. Second, we were easily able to maintain our credit size while most revolvers have shrunk by approximately 15%, both of which showcase the underlying credit of our business and the strength in our bank relationships. As noted in an SEC filing earlier this month, we exercised our option to receive a cash payment of $196 million from Equitrans Midstream in lieu of a portion of near-term fee relief. We expect to receive proceeds by late 3Q or early 4Q. As shown in slide 18 of our investor deck, this cash election does not impact the $0.15 per Mcfe long-term gathering rate reduction from today's levels. Also, we still model an MVP start-up in fourth quarter 2023. Moving over to hedging. During the quarter, we opportunistically restructure our hedge book for 2023. Specifically, we converted the bulk of our remaining 2Q through 4Q 2023 swap positions into costless collars. For the summer, we placed approximately $4 floors and $6.25 ceilings, and in the winter, $7.30 floors with $11 ceilings. The positive market skew at the time enabled us to set $3 of upside with only $1 downside, tying to our plan to provide stakeholders with strong risk-adjusted upside. Separately, as we've seen signposts of global economic slowdown, we thought it'd be prudent to add floors to our 2023 hedge book, buying approximately $4.55 puts with premiums that we were able to defer into 2023. With these actions, we are now approximately 50% hedged on our 2023 volumes, predominantly with wide collars and puts. As an illustration of the resiliency of our forward outlook, if NYMEX retraced to approximately $3 per MMBtu in 2023, we would still expect to generate approximately $1.6 billion of free cash flow next year or a 10% free cash flow yield. Conversely, if natural gas averaged a $7 per MMBtu level, we would expect to generate almost $6 billion of free cash flow in 2023 or nearly a 40% free cash flow yield. Now turning to LNG. As Toby mentioned, we are making progress on our strategy and seeing increasingly bullish set up for global natural gas fundamentals on a multi-decade basis. We expect global natural gas demand outside of North America to grow from approximately 285 Bcf per day today to 375 Bcf per day by 2050. This means supply growth equivalent to doubling the entire U.S. natural gas production base is necessary to balance the global market in less than 30 years. There is a growing recognition both domestically and abroad that we are unlikely to meet this demand without significant incremental production from Appalachia, which is home to the longest runway of low break-even, low carbon intensity natural gas inventory in the world. As noted in our Unleash U.S. LNG deck, resource quality and longevity dictate that 70% of incremental U.S. LNG export growth will ultimately need to come from Appalachia. EQT is currently in various stages of discussion for supply agreements covering approximately 1 Bcf per day of FT capacity to the Gulf Coast. We are looking at ways to catalyze East Coast LNG, which could have meaningful ramifications to our Appalachian production long term. Turning over to guidance. As we noted last quarter, we saw pricing pressures broaden across all service lines. We experienced some further inflationary impact since our first quarter call. As such, we are raising our 2022 CapEx guidance range to $1.4 billion-$1.5 billion. The midpoint of which is in line with the high end of our prior guidance. As highlighted in slide 13 of our slide deck, our contracting strategy provides significant risk mitigation on a go-forward basis. The most notable is our long-term sand supply agreement and frac crew contracts, which extended to 2024 and 2025. We are reiterating our 2022 EBITDA and free cash flow guidance ranges, but see bias towards the upper end. Note that our guidance reflects strip pricing as of July 22. Given a structurally superior hedge position next year, our 2023 free cash flow should expand by approximately 100% year-over-year, providing differentiated free cash flow for share growth even with flat production volumes. Again, using strip pricing, we see approximately $22 billion of cumulative free cash flow through 2027, which is net of all expected cash taxes and hedges pre-hedge premiums. I'll now turn it over to Toby for some concluding remarks. Thanks, Dave. To conclude today's prepared remarks, I want to reiterate a few key points. One, Americans are voicing clear support for more domestic natural gas, which is critical to reducing extreme energy costs, increasing America's energy independence, and tackling global climate change by replacing international coal. Two, our depth and quality of inventory, investment-grade balance sheet, and our peer-leading ESG credentials differentiate EQT as a leading producer on a global scale, and we stand ready to meet the long-term call on natural gas demand. Three, we are outperforming our emissions reduction targets and have a clear and credible path to net -zero by 2025, which can be achieved with current technologies and at a very affordable price tag. Finally, our updated capital returns framework shows a resounding commitment to our shareholders, with $4 billion earmarked through year-end 2023 for debt reduction, share buybacks, and our increased base dividend. With plenty of room for upside, given we expect to generate $22 billion of cumulative free cash flow through 2027. I'd now like to open the call to questions. We will now begin the question and answer session. If you would like to ask a question, please press star followed by one on your touch tone keypad. If for any reason you would like to remove that question, please press star followed by two. Again, to ask a question, press star one. As a reminder, if you are using a speakerphone, please remember to pick up your handset before asking your question. We will pause here briefly to allow questions to generate in queue. The first question is from the line of Arun Jayaram with JP Morgan. You may proceed. Yeah, good morning. Toby, you've announced some incremental action on shareholder return, the $1 billion in incremental debt reduction plus the dividend increase. My question is regarding when do you think the company would provide more clarity around the retained flexibility category? You know, on your updated guide, you know, $6.4 billion of free cash flow if the strip holds over the next six quarters. If you back out debt reduction and the dividend, you'd have, you know, just under $4.4 billion of unaccounted for free cash flow. Just some thoughts on that and perhaps the pace of buyback activity given under your current authorization. Sure, Arun. Good morning. As it relates to our capital allocation framework, I think what we've done is set out authorizations that we know we can execute. As you mentioned, we do have flexibility to go above there. I think the flexibility is important because we wanna make sure that we are matching the allocation decisions to the environment that we're in. I think there's a lot of clarity on the debt retirement goals that we've stated. To put a little bit more color on our buyback approach, our buyback approach is opportunistic, and we believe that's appropriate given the current volatility that we see in this world. Understand that that's tough to model, the buyback pace that we have. I'd ask you to look at what we've done in the past. In Q1, we've taken advantage of our buyback authorization and bought back over $240 million worth of stock, retiring about 9.9 million shares. In Q2, we repurchased about $213 million of convertible notes, and that has the impact of retiring around 5.7 million shares. Over the past two quarters, you know, we've retired over $400 million of shares. You know, retiring about 15 million shares at an average price of around $31 per share. We think the approach is providing some pretty good results. You know, look at what we can do in the future. You know, we have the opportunity to continue that pace. We're obviously stepping into a more robust free cash flow generation phase of this business, and think the opportunity for us to do more is appropriate. Fair enough. Perhaps for David. David, EQT repositioned your hedge portfolio. Getting, you know, some question on the impact to your free cash flow outlook. I know the repositioning started in the fourth quarter of this year. Can you give us a sense if we kind of, you know, put in strip in the model, what kind of impact that had to cash flows from those moves? And was there any cost associated with this repositioning activity? Yeah. I'll answer that question. Yeah, no cost. Everything was done at market, and so no cost to us. Just to step back and just to give you high levels, right now, with our hedges in place. We basically have a $2.92 floor, and we have approximately $4.95 ceiling. That's the bounds of. We're about 50% floors, and we're about 45% ceiling. That, you know, provides the risk-adjusted benefit. If the floors were reached, we'd be about $1.5 billion. If the ceilings would be reached, or breached, it would be about almost $4 billion. That just gives you a sense of range of outcome there. With the repositioning, we basically converted our swaps, which we'll call it about 10% of our hedge position was converted into costless collars. As I said earlier on the prepared comments, the SKU was about $3 up and $1 down. If you look at the value today, that position that we did is about $110 million into the money. If we hit the ceilings of that of what we just did, we would create about $450 million of upside on free cash flow. That gives you a sense of magnitude of what we did, and it allows the investor to understand how we think about the risk-adjusted upside. Thanks for that color. Appreciate it. You're welcome. Thank you. The next question is from the line of Umang Choudhary with Goldman Sachs. You may proceed. Hi, good morning, and thank you for taking my questions. My first question was on the well performance. Any from the next generation completions, any early read-through there? If it is successful, how would that change slide number 12? How much of that inventory would you be able to add with the sub-$250 breakeven? Umang, good morning. It's early on our science. We are encouraged, but I will say that the wells are still in flat time in our choke management program. We'll get a better read once these wells enter closer towards the decline periods of their lives. That's why we're sort of you know refraining from being any more, but we are leaning positive right now. For slide 12, the couple impacts on the enhanced well design. One, it's obviously going to improve the economics of the inventory that we put there. You'll see those sticks shift down the cost curve, which would be good. That will also pull some more what we consider non-core and give that a shot of lowering their breakevens. Two, this will also have the impact of extending our inventory life. Because, you know, if this hits, this will allow us to reduce the number of wells that we need to drill each year to maintain volumes. That will extend our inventory life past the 18 years of core inventory. Those are really the two dynamics that are at play right now. That's helpful. Thank you. Maybe next question is on the LNG strategy. You mentioned that you're in discussion with a lot of LNG customers. How are the discussions progressing, and what are the key points which the customers are looking for more clarity on? Yeah. I would just say right now, we probably have an opportunity to lock in contracts with probably about three or four different facilities. The question for us is duration in which we wanna do. If we want international markets, what toll rates are we willing to accept? Then we're trying to work on with the end market, specifically, a collar structure where we give ourselves some protection on the downside, but allow us to get that risk-adjusted upside. Those are the things that we're looking at right now. I'd just say there's great demand from a producer standpoint, these facilities need gas supply. It gives us the option right now to figure out who we wanna use and who we wanna go through. Got it. That's helpful. Thank you. You're welcome. Thank you. The next question is from the line of Neal Dingmann with Truist. You may proceed. Morning. Toby, can you talk a little bit about just the availability of capacity going forward? It seems like you'll have some availability going forward. Your thoughts on if there is, your thoughts on wanting to grow. Oh, production capacity. Yeah, Neal. Pipeline capacity in Appalachia. We've finally reached the limit of the midstream takeaway capacity in Appalachia. As long as that's the case, we are gonna remain disciplined in maintenance production mode. We put a slide in our deck that sort of shows the dynamics of what's taking place on slide 29. You know, one of the questions we get a lot is people have said, you know, we say, "Well, why aren't we able to add more supply? We've got the biggest natural gas field in the world, and we cannot use that to help lower energy prices for Americans. Why is that?" And we say, "Well, because we don't have pipelines. They've been blocked, canceled, and opposed over the last 10 years." People say, "Well, we've been blocking pipelines for the last 10 years, and we've been able to experience low energy prices." Well, the reality is we've always had excess pipeline takeaway capacity out of this basin during those times when those pipelines were canceled. Those would have added to that capacity. We've hit the wall now. That's why, you know, EQT is gonna continue to remain disciplined. It's an opportunity for this country to recognize this and say that, and get more pipelines and LNG infrastructure built in this country so we can address the growing demand for natural gas. Yeah, that's great to hear, and then not in the type capacity, but the other. My thought is, again, given where gas prices are, obviously the returns are fantastic. You know, do you weigh, like when you and Dave are looking at it? You know, is there, number, I guess, sort of two-part question. Are there opportunities to roll in, I don't know, either bolt-ons or some bigger deals? If so, is it just simply comparing that to, you know, you have ample acres, no question, being the largest gas player. Is it just simply a comparison of what the deal price looks like maybe on PDPs or however you want to value them versus what your organic growth would be? Yeah. Neal, I think anything any asset you look at, I think you wanna make sure you're getting quality. We definitely compare asset quality versus ours. I think you look at Alta and the cost structure that asset base did. It lowered our cost structure of this company, lowered our breakevens by over a $0.05. That's one consideration. I mean, at the end of the day, everything we do on M&A is gonna be. It's gotta be more creative than buying back our stock. That's the ultimate decision. Yeah, you all have been very disciplined. It's great to see. Great quarter. Thanks, Toby. Thanks, Neal. Thanks, Neal. Thank you. The next question is from the line of Scott Hanold with RBC Capital Markets. You may proceed. Thanks. Good morning. I have a question just to delve into a little bit more into the LNG discussions as well as you know that you know potential free cash flow use that's not allocated at this point. When you step back and look at it, you know, obviously there's been you know some larger peers that have gone out and made a announcement of a potential agreement to invest in a you know Gulf Coast LNG facility. Where do you stand on using some of that free cash flow potentially to you know invest in a facility? And are you really looking at. If so, is that more of an East Coast initiative that you think would make most sense for y'all? I sort of segregate the LNG into two categories, the Gulf Coast and the East Coast. You know, from a Gulf Coast perspective, it's really more about looking at the best ways we can commit our supply to projects. I don't think that the capital is needed down there to get projects off the ground. On East Coast, you know, for us, I think there's an opportunity for us to help identify projects and work with developers to get these projects off the ground. I mean, we're doing some feasibility work and some high-level assessments of what some of those projects look like, but not a significant amount of dollars being thought of to apply to East Coast LNG. Obviously, for us, you know, why spend dollars, even on the feasibility side? I think East Coast LNG just could be so incredibly impactful to EQT and Appalachia. Creating a demand source, you know, next to where we operate should help strengthen basis that would have an impact, not just on the volumes that we're able to supply to those facilities, but would also impact, you know, the amount of gas that we sell in basin. There's just a lot of reasons why. There's reasons for us to really wanna push to get East Coast LNG and make that great idea a reality. That's great. Good to hear. My follow-up question is, you all talked about going after the converts versus, you know, directly targeting, I guess, the outstanding equity on your buyback program. Could you give us a little high-level view. You know, I think there are a lot of benefits to that, but can you just walk us through at what point does it make sense to target the equity versus the converts? Or do you feel there's somewhat of an indifference to doing that? Yeah. It really depends upon where the stock is and where the convert is. You know, right now the convert is way in the money and so it trades very much like the equity. There is a little bit of premium for, we'll call it, for future dividends and things like that that you have to account for. Effectively, it's very much akin to equity. You know, there is a percentage that you would ascribe to the debt side and its principal. I think, you know, we have basically two tools in place, right? We have what we'll call the direct way, where we have our $1 billion buyback, and then we have the indirect way, which gets captured really in the $2.5 billion of debt principal that we have authorized to retire. We have really two ways that gives us the flexibility to attack the equity, and where there's disconnects or things we can try to play that arbitrage. Understood. Thanks. Welcome. Thank you. The next question is from the line of John Abbott with Bank of America. You may proceed. Good morning, and thank you for taking my questions. Toby, the first question is for you. It's on inventory in West Virginia. During the first quarter call, you had mentioned the potential benefits o f West Virginia signing the pooling and utilization law. When you look at those 1,800 locations, the distribution, does that take into account those potential benefits? Have you had the time to assess what the benefits are to your inventory? Yeah, great question. There was some legislation that was passed recently in West Virginia that basically allows modern unitization to take place. This is a tool that is available to operators now that really helps address if there's unknown heirs, which is something that happens in West Virginia a lot. If the majority of landowners have signed up an ability to unitize. As far as the way we view this is really this is more of a backup plan in case we run into some of those roadblocks. We have not had to use this legislation but it's nice to know it's there. It's there. Ultimately, the way this reflects in our inventory is just a higher level of confidence that the sticks that we put on the map we're gonna be able to develop because we've got modern legislation in place that will facilitate that. For us, another read-through, you know, we're out, you know, advocating for more pipeline infrastructure and the permitting policy reform. I think you look at what we've done in West Virginia, you know, helping to get that legislation put in place. I'm optimistic. I'm hopeful that we can continue to influence on a national level and help bring common sense, pragmatic permit reform so that we can get these pipelines and LNG facilities built, so we can address the energy crisis that's currently going on in the world. Appreciate it. The next question is for you there, David. It's gonna be on your cumulative free cash flow outlook and on cash tax. For that six-year outlook, just curious, does that assume does it have an inflation assumption baked in for 2023 already? Second on the cash tax, you know, recognize you're to provide more color at some point later during the year. As you sort of look out to 2027, this is more of a calibration cash tax question. Are you more of a 15% cash taxpayer or more of a 20% cash taxpayer long term? Yeah. As far as inflation, in our 2023 numbers, yes, they're in there. As far as cash taxes, whether 15% or 20%, I think longer term, it's towards the 20%. But obviously, as we consume our NOLs and, it'll trend up over time. I would just say one other factor just that you should be aware of, Pennsylvania just announced a corporate reduction in cash taxes by about 3%. That should help, you know, that should help on the margin, with some cash taxes in the future. Thank you very much. Thank you very much for the color and for taking our questions. You're welcome. Thanks. Thank you. The next question is from the line of Vin Lovaglio with Mizuho. You may proceed. Yeah, thanks for getting me on, guys. I really appreciate the vision on LNG. Projects tend to be longer lead, and Appalachian, as you said, is offtake constrained. I'm wondering if you see yourselves as having a role to play in stimulating regional demand growth, and if there's anything that you could say around opportunities on that end, especially on the industrial side. Thanks. Yeah. There's an opportunity to increase gas demand locally. I don't think anything has the type of scale that we're talking about with LNG. There's new technology. I mean, natural gas, I think can be transformed into low carbon energy solution like blue hydrogen. A lot of the new ventures work that we're doing is focused on what is the sustainability of hydrogen and what can we do to help mature that, the confidence and the sustainability of hydrogen. There's also technology that's out there right now that instead of decarbonizing the product before it gets consumed, which is what would happen with blue hydrogen. There's also technologies out there that will set the table for carbon capture, you know, while the energy is converted into electricity. There's a lot of new technologies out there, a lot of low -carbon solutions that we're looking at. Right now, though, the key thing for us to do is, as energy providers, is understand the true sustainability of these options. You know, what is the actual cost? What's the profitability? What is the actual, you know, emissions, full cycle emissions associated with it? How big could this be from a scale perspective? Those are sort of the things that we're thinking about as we're understanding these solutions. Yeah. I just add, as we've gone back to investment grade, we're now being approached for, I'll call longer term firm sales contracts to some of the industrial space. I'd just say, you know, stay tuned on that progress. Got it. Great. I guess flipping over to the cost side, one thing that's really stuck out for us has been tubular pricing. Seems like a supply chain bottleneck, low inventories type of issue. I'm wondering, you know, how that, if it has affected your planning, you know, if at all for 2023 compared to a more, you know, quote-unquote, 'normal year'. Thanks. Yeah. When we set our budget for 2022, you know, we did account for inflation, but you see we did tick that up a little bit here this quarter. What's changed between, you know, the planning exercises at the end of the year and where we're at today, I think the assumption was that steel was gonna be able to to rebound in pricing, and we'd get some steel relief in the back half of this year. Unfortunately, the war in Ukraine has just put more strain on supply chains when it comes to steel, and you know, we're seeing those. We're not seeing the lower prices that we anticipated towards the end of the year. That's what's baked into our plan today and also into 2023 as well. Yeah. I'd just add, so you know, there's obviously the intricacies of tubulars, but then if you look at the steel sector in general, steel prices have come down pretty materially. Metallurgical coal, which is a feedstock into steel, has dropped from $600 a ton down into the $200 and change. And then iron ore has come down pretty hard. So you have the makings of steel and tubulars to come down in price. It's just gonna have to work its way through the processing side. Makes sense. Thanks, guys. Bye. Welcome. Thank you. The next question is from the line of Noel Parks with Tuohy Brothers. You may proceed. Hi, good morning. Morning. I just wanted to pick up on the comment you just made about blue hydrogen and your research there. I'm just curious if you have any general thoughts on timeframe of when you think some technologies might mature, and also might be able to achieve scale, and just to give a sense of whether you're looking at sort of like a wide set of, you know, players or technologies or more of a short list. Yeah. My view of hydrogen right now, blue hydrogen specifically, we think we can make blue hydrogen for a cost of $20 per million BTU. That would include the carbon capture of that as well. You know, I remember a year ago looking at that and saying, you know, "Wow, it's too expensive. Why would anybody pay $20 for hydrogen when you can buy natural gas for lower than that?" Well, you know, $20 per million BTU doesn't seem that high compared to what Europe's paying today. When you look at the majority of the cost of blue hydrogen, how do we get that to a sustainable pricing level? You know, majority of the cost to make blue hydrogen isn't in the actual transformation of natural gas to the hydrogen and capturing carbon. The majority of the costs come in the infrastructure it takes to move the hydrogen. Now, what's really interesting and what we're highlighting here is how can we bring the infrastructure cost down? Our Unleash U.S. LNG campaign initiative, one of the byproducts of that is we have the ability to execute this plan and increase production in the United States by an incremental 50 Bcf a day slated for exports to replace foreign coal. We would have the opportunity to rebuild approximately 50 Bcf a day of pipeline infrastructure. When we do that, we're looking at ways to make sure that when we build that pipeline, we build it so that they're hydrogen ready. If we can do that, then we've just set the table for the hydrogen economy here in the United States. It will basically secure natural gas's future, but, you know, the role of natural gas may transform from being an end-use product to being a feedstock for blue hydrogen. We're looking at that. The other technology I'd say that's out there in hydrogen is the technology to keep an eye on is the technology that, you know, natural gas goes in, hydrogen comes out, and solid carbon comes out as opposed to gaseous CO2. That's obviously gonna really lower the logistics for actually what we do to actually capture that hydrogen. That's some new technology that's out. That is probably, you know, three to five years out, but well within a timeframe as we're figuring out these different options. Great. That was a really, really nice view of the explanation of the waterfront out there. I guess in general, when you're talking about how it does seem all roads or many roads at least lead to greater reliance on Appalachian gas and that to get there, of course, the pipeline situation has to be addressed. What do you sort of see as maybe the catalyst or what party or piece of the puzzle do you think might be the first to budge, whether you think it's on the financing side, on sort of like the state initiative side? Any ideas of kind of what might start to unlock you know a greater access to new pipeline projects? Yeah. I think it starts by, you know, a shift in sentiment and a shift in understanding how important natural gas plays in this world. You know, we are seeing the reality of a world that is, that is undersupplied with hydrocarbons, and the result is this energy crisis we're facing today. Unnecessarily high energy prices, rampant inflation, war in Ukraine, and by the way, emissions around the world are still rising because without natural gas, people are using more coal than they've ever used before. That, I think, is being recognized, and I think you're starting to see a shift in that sentiment shift translated to policies, the EU declaring natural gas is green. We're seeing that with the customers around the world. You're seeing that here domestically, the Inflation Reduction Act that Manchin and has put together. You know, to talk about, to include in that, pipeline reform, permitting reform that's necessary so that we can get the pipeline infrastructure and energy infrastructure built, on an accelerated timeline, in a more pragmatic way. That is another precursor that you're starting to see here. And then on top of all that, you just look at the polling of Americans. Americans get it, over 70% saying we need more natural gas. The Americans support this, the world is showing there's clearly a need for it, and now you're seeing governments, you know, adjust their policies to you know make it easier for us to bring this energy into the world. But we're seeing the signs right now. And then to sort of follow through then, the financing then follows or will follow, you anticipate sort of a natural consequence. Yes. Yes. This is David. Yes, absolutely. Yes, the banks will be there. I think, you know, everything's got to be done obviously with a really, with a low to no emissions kinda profile. People are not, you know, financing's not gonna open up the kitty here unless emissions and things are being done on a very, we'll call it, responsible manner. If it's done, I think that's it. Then you'll see the financing absolutely be there. Terrific. Thanks a lot. Thanks. Thank you. Thank you. There are no additional questions at this time. I will pass it back to Toby for any closing remarks. All right, everybody, thanks for your time this morning, and we look forward to continuing to work hard at great value for our stakeholders. Thank you. That concludes today's conference call. Thank you. You may now disconnect your-