EQT Corp Q2 FY2022 Earnings Call

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. Operator instructions were provided. 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-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we will reference certain slides during today's discussion. I'd like to remind you that today's call may contain forward-looking statements. Actual results and future events could materially differ from these forward-looking statements, because of the factors described in yesterday's earnings release, in our investor presentation and 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.

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 US 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 and 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. Systems 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 US 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 US energy independence and reducing energy costs as their top priority today. Nearly 70% of voters support increasing US natural gas production and a similar amount support building new natural gas pipelines with majority support running across all party lines, and 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 US natural gas play a leading role in providing affordable and reliable energy to the world, while also addressing climate change by replacing foreign coal. And in a world that recognizes and acts on the need to unleash US natural gas, EQT will thrive for several key reasons. First, we are the largest producer of natural gas in the US with a multi-decade high-return inventory. As shown on slide 12 of our investor deck, we highlight breakeven 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 two times 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 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 we 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 one 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 9 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 one to 1.5 times, we are taking the opportunity amid robust commodity prices to accelerate delevering and unequivocally fortifying our balance sheet. The recent rise of 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 through our 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 the 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 six 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 towards shareholder returns by year-end 2023 and leaves approximately $3.5 billion of retained free cash flow flexibility on 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 Dave.

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 a 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 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 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 bull-proof our balance sheet through all parts of the commodity cycle by raising our year-end 2023 debt reduction target by $1 billion to $2.5 billion. This will reduce our gross debt to approximately $3 billion and accelerate achieving our long-term leverage target of one to 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 six million shares while also simplifying our balance sheet. At the end of the second quarter, our trailing 12-month net leverage stood at 1.6 times, 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 one time and 0.1 negative times, respectively, which contemplates executing the remainder of our buyback authorization and accounts for a 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 the 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 restructured our hedge book for 2023. Specifically, we converted the bulk of our remaining 2Q through 4Q 2024 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 would 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 $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 see an increasingly bullish setup 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 US 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 breakeven, low carbon intensive natural gas inventory in the world. As noted in our unleash US LNG deck, resource quality and longevity dictate that 70% of incremental US LNG export growth will ultimately need to come from Appalachia. EQT is currently in various stages of discussion for supply agreements covering approximately one Bcf per day of firm transportation 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, and as such, we are raising our 2022 CapEx guidance range to $1.4 billion to $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 we 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 2022. 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 per 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 hedge premiums. I'll now turn it back 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. And finally, our updated capital returns framework shows a resounding commitment to our shareholders. With $4 billion earmarked for year-end 2023 for debt reduction, share buyback 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. Operator instructions were provided. The first question is from the line of Arun Jayaram with JPMorgan. You may proceed.

Yeah, good morning. Toby, you've announced some incremental action on shareholder return, the $1 billion in incremental debt reduction and the dividend increase. My question is: when do you think the company will provide more clarity around the retained flexibility category? On your updated guide, there is $6.4 billion of free cash flow if the strip holds over the next quarters. If you back out debt reduction and the dividend, you have just under $4.4 billion of unaccounted-for free cash flow. So any thoughts on that and perhaps the pace of buyback activity given your current authorization?

Sure, Arun good morning. So as it relates to our capital allocation framework, I think what we've done is set out authorizations that we know we can execute, but as you mentioned, we do have flexibility to go above there. I think the flexibility is important because we want to make sure that we are matching the allocation decisions with the environment that we're in. I think there's a lot of clarity on the debt retirement goals that we've stated. But 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. But understand that that's tough to model, the buyback pace that we have. So 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. So over the past two quarters, we've retired over $400 million of shares, retiring about 15 million shares at an average price of around $31 per share. I think the approach is providing some pretty good results. But look at what we can do in the future, and 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 I think the opportunity for us to do more is appropriate.

Fair enough. Perhaps for David. David, EQT repositioned your hedge portfolio. Getting 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 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. So I'll answer that question. Yeah, no cost. Everything was done at market, and so no cost to us. So if you step back and just 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 our hedge structure, and we're about 50% floors and about 45% ceilings. So that 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. So that just gives you a sense of range of outcome there. With the repositioning, we basically converted our swaps, which we'll call about 10% of our hedge position, into costless collars. And as I said earlier in the prepared comments, the skew 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. And if we hit the ceilings of what we just did, we would create about $450 million of upside on free cash flow. So that gives you a sense of magnitude of what we did and it allows investors to understand how we think about the risk-adjusted upside.

Thanks for that color. Appreciate it.

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 question. My first question was on the well performance. Any early read through there from the next-generation completions? And then 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? And maybe next question is on the LNG strategy. You mentioned that you are 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?

Umang, good morning. So it's early on our science. We are encouraged, but I will say that the wells are still in flowback time in our choke management program. So we'll get a better read once these wells enter closer towards the decline periods of their lives. And so that's why we're refraining from being definitive right now — but we are leaning positive. For slide 12, the couple of impacts on the enhanced well design: One, it's obviously going to improve the economics of the inventory that we put there. So you'll see those sticks shift down the cost curve, which would be good. That will also pull some of 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 if this hits, this will allow us to reduce the number of wells that we need to drill each year to maintain volumes. So 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.

Yes. So, I would just say, right now, we probably have an opportunity to lock in contracts for with probably about three or four different facilities. And so the questions for us are duration and what toll rates we are willing to accept. We're also working with end markets specifically on a collar structure where we give ourselves some protection on the downside but allow us to get risk-adjusted upside. So 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. And so it gives us the option right now to figure out who we want to use and who we want to go through.

All right. 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, could you talk a little bit about the availability of capacity going forward? It seems like you'll have some availability. What are your thoughts on whether there is an opportunity to grow? And given where gas prices are and that returns are strong, are there opportunities to roll in bolt-on acquisitions or pursue larger deals? Or is it simply a comparison to organic growth, comparing the deal price based on PDPs or however you want to value them versus expected organic growth?

Production capacity, yes, Neal. Pipeline capacity in Appalachia — we've finally reached the limit of the midstream takeaway capacity in Appalachia. And as long as that's the case, we are going to 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. One of the questions we get a lot is people have said, 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. And 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. And that's why EQT is going to continue to remain disciplined. And it's an opportunity for this country to recognize this and say that we need more pipeline and LNG infrastructure built in this country so we can address the growing demand for natural gas.

Yeah. It's great to hear. And then, on the M&A point, will you weigh opportunities to bolt-on or larger deals? Do you simply compare asset quality versus yours?

So I think anything you look at, you want to make sure you're getting quality. So we definitely compare asset quality versus ours. I think you look at how deals lower cost structure. For example, our acquisition of Alta lowered our cost structure and lowered our breakevens by over $0.05. So that's one consideration. At the end of the day, everything we do on M&A has to be more accretive than buying back our stock, and that's the ultimate decision.

Yes. You all have been very disciplined and it's great to see that. 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 a lot. Good morning. I have a question just to delve a little bit more into the LNG discussions as well as that potential free cash flow use that's not allocated at this point. When you step back and look at it, obviously, there's been some larger peers that have announced a potential agreement to invest in a Gulf Coast LNG facility. Where do you stand on using some of that free cash flow, potentially, to invest in the facility? And are you really looking at — if so, is that more of an East Coast initiative that you think would make more sense for you all?

I sort of segregate LNG into two categories, the Gulf Coast and the East Coast. 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 capital is needed down there to get projects off the ground. On East Coast, 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. We're doing some feasibility work and some high-level assessments of what some of those projects would look like, but not a significant amount of dollars being thought up to apply to East Coast LNG at this point. Obviously, for us, why spend large dollars even on feasibility if East Coast LNG could be so incredibly impactful to EQT and Appalachia — creating a demand source 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 the amount of gas that we sell in-basin. So there's a lot of reasons for us to really want to push to get East Coast LNG and make that idea a reality.

That's great, good to hear. And then, my follow-up question is, you all talked about going after the converts versus directly targeting the outstanding equity on your buyback program. Could you give us a little high-level view on — at what point does it make sense to target the equity versus the converts, or are you somewhat indifferent to doing that?

It really depends upon where the stock is and where the convert is. Right now, the convert is very in the money, and so it trades very much like the equity. There is a little bit of premium for future dividends and things like that that you have to account for. But effectively, it's very much akin to equity. There is a portion that you would strive to the debt side as principal. So just know we have basically two tools in place: the direct way where we have our $1 billion buyback, and then the indirect way, which gets captured in the $2.5 billion of debt principal that we have authorized to retire. So we have two ways that give us flexibility to attack the equity, and where there are disconnects we can try to play that arbitrage.

Understood. Thanks.

You're 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 on inventory in West Virginia. During the first quarter call, you had mentioned the potential benefits of West Virginia signing in the pooling and unitization law. When you look at those 1,800 locations, does that distribution take into account those potential benefits? And have you had time to assess what the benefits are to your inventory?

Great question. There was some legislation 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 unknown heirs, which is something that happens in West Virginia a lot. If the majority of landowners have signed up, the ability to unitize, as far as the way we view this is, 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 is there. Ultimately, the way this reflects in our inventory is just a higher level of confidence that the sticks we put on the map we're going to be able to develop, because we've got modern legislation in place that will facilitate that. For us, another read-through is we're out advocating for more pipeline infrastructure and permitting policy reform. I think you look at what we've done in West Virginia, we helped lead to get that legislation put in place. I'm optimistic and 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, and we can address the energy crisis that's currently going on in the world.

Appreciate it. And the next question is for David on the cumulative free cash flow outlook and on cash tax. For that six-year outlook, does that assume inflation baked in for 2023 already? And on cash tax, are you more of a 15% cash taxpayer or more of a 20% cash taxpayer long term?

Yes. As far as inflation in our 2023 numbers, yes, it's in there. As far as cash taxes, longer term, it's towards the 20% range. As we consume our NOLs, it will trend up over time. One other factor to be aware of is Pennsylvania just announced a corporate reduction in cash taxes by about 3%, and so 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.

Welcome.

Thanks.

Thank you. The next question is from the line of Vin Lovaglio with Mizuho. You may proceed.

Yes, thanks for getting me on guys. I really appreciate the vision on LNG projects tending to be longer lead and Appalachia, as you said, is off-take in stream. 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.

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, but there's new technology. Natural gas can be transformed into a 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 confidence in the sustainability of hydrogen. There's also technology that's out there right now that instead of decarbonizing the product before it gets consumed, there's technologies that will set the table for carbon capture while the energy is converted into electricity. So there's a lot of new technologies out there, a lot of low-carbon solutions that we're looking at. The key thing for us as energy providers is to understand the true sustainability of these options: what is the actual cost, what's the profitability, what are the actual full-cycle emissions associated with it, and how big could this be from a scale perspective? Those are the things we're thinking about as we evaluate these solutions.

And I'd just add, as we've gone back to investment grade, we're now being approached for longer-term firm sales contracts in some of the industrial space. So stay tuned on that progress.

Got it. Great. And flipping over to the cost side, one thing that's really stuck out for us has been tubular pricing. It seems like a supply chain bottleneck and low inventories type of issue. Wondering how that has affected your planning for 2023 compared to a more normal year? Thanks.

When we set our budget for 2022, we did account for inflation, but you see we did take that up a little bit here this quarter. What's changed between the planning exercise at the end of the year and where we're at today is that the assumption was steel would rebound in pricing and we'd get some steel relief in the back half of this year. Unfortunately, the war in Ukraine has put more strain on supply chains for steel. So we're not seeing the lower prices we anticipated toward the end of the year. That's what's baked into our plan today and into 2023 as well.

And I'd just add, look at the steel sector in general: steel prices have come down materially, metallurgical coal has dropped from about $600 a ton down into the $200s and iron ore has come down too. So you have the makings of steel and tubulars to come down in price; it's just going to have to work its way through the processing side.

Makes sense. Thanks guys.

Thank you. The next question is from the line of Noel Parks with Tuohy Brothers. You may proceed.

Hi, good morning.

Good morning.

I wanted to pick up on the comment about blue hydrogen and your research there. I'm curious if you have any general thoughts on the timeframe of when you think some technologies might mature and be able to achieve scale. Also, are you looking at a wide set of players or technologies or more of a short list?

My view of hydrogen right now, blue hydrogen specifically, is we think we can make blue hydrogen for a cost of about $20 per MMBtu. That would include the carbon capture as well. A year ago that price looked very high compared to natural gas, but $20 per MMBtu doesn't seem that high compared to what Europe is paying today. When you look at the cost of blue hydrogen, the majority of the cost isn't in the transformation of natural gas to hydrogen and capturing carbon. The majority of the costs come in the infrastructure it takes to move the hydrogen. What's interesting is how can we bring infrastructure costs down. Our Unleash US LNG initiative would increase production and build pipeline infrastructure as part of increasing supply. If we can rebuild pipeline capacity and make that infrastructure hydrogen-ready, we've just set the table for a hydrogen economy in the United States. That could transform natural gas' role from an end-use product to a feedstock for blue hydrogen. Another technology to watch is processes where natural gas is converted to hydrogen and solid carbon comes out instead of gaseous CO2; that would lower logistics for capture. That technology is probably three to five years out but well within the timeframe we're considering for these options.

That was a very helpful explanation. Given that many roads lead to greater reliance on Appalachian gas and pipelines need to be addressed, what do you see as the catalyst that might unlock greater access to new pipeline projects? Financing, state initiatives, policy changes — what might start to budge?

I think it starts with a shift in sentiment and understanding how important natural gas is. We are seeing the reality of a world undersupplied with hydrocarbons, which has resulted in the energy crisis — high energy prices, rising inflation, the war in Ukraine, and global emissions rising because people are using more coal. That is being recognized. You're starting to see a shift in policy: the EU declaring natural gas as green, and domestically there are signs such as elements in the Inflation Reduction Act and bipartisan conversations around permitting reform that would help pipelines and LNG infrastructure get built on an accelerated timeline. Americans also support more natural gas — over 70% in polling. So the combination of public sentiment, global need and changing policies are precursors to unlocking projects. Once those policy and sentiment shifts are in place, financing will follow, provided projects show a low or no-emissions profile.

Yes, absolutely. Financing will be there if projects are done with a strong emissions profile. People and banks are looking for responsible, low-emission projects, and if that standard is met, financing will follow.

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 to create value for our stakeholders. Thank you.

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