Greetings and welcome to the Antero Resources First Quarter 2022 Earnings Conference Call. At this time all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brendan Krueger, CFO of Midstream and Vice President, Finance, Treasurer. Thank you. Please go ahead.

Thank you for joining us for Antero's first quarter 2022 investor conference call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would like to first remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, President and CEO; Michael Kennedy, CFO; and Justin Fowler, Senior Vice President of Gas Marketing and Transportation. I will now turn the call over to Paul.

Thanks, Brendan. Good morning, everyone. I'd like to begin by discussing the overall macro environment and the factors that led to the recent increase in commodity prices. During the last year, 2021, commodity prices were strengthening, driven by a resurgence in demand as we came out of the pandemic. On the supply side, the shift towards maintenance capital plans and supply chain constraints led to moderated global supply growth. Then during the first quarter of 2022, as you all know, this bullish fundamental backdrop was further strengthened by the geopolitical events in Europe. Unlike prior commodity price spikes, these events had a large impact on the futures curve, where we saw the natural gas strip move up 45% throughout the curve all the way to calendar year 2026. As Europe looks to strengthen its energy security, it has become clear that there will be a significant call on U.S. shale gas in the coming decades. Importantly, with Antero's 2.3 Bcf a day of firm transportation to the LNG fairways, we are uniquely positioned to supply the increase in international demand. Today, we are already selling nearly 1 Bcf a day of natural gas to LNG facilities on a mix of long-term and short-term contracts. As additional LNG export capacity is built out, we think our premium to NYMEX will increase and will become more closely linked to international prices. Let me just comment a little bit on terms of contracts and make an important point. We're happy where we are right now on shorter-term deals, whether it's selling on the day or on the month. We deliver to premium locations in the LNG fairway, such as ANR Southeast Head Station, where as many as three LNG liquefiers are bidding for our gas. But we're not interested in longer-term supply deals unless we receive significantly higher premiums. There is too much optionality today to get locked in prematurely. Since the last cycle, the industry has shifted from one of outspend and growth to free cash flow, maintenance capital and return of capital to shareholders. It's because of this shift, along with other fundamentals that we'll touch on later that we remain constructive on commodity prices going forward. Slide number 3 titled Structurally Higher Prices ahead compares historical NYMEX natural gas spot prices versus the corresponding natural gas surplus or deficit to the running five-year average. The red circles highlight the historical natural gas price during periods when storage levels are in line with the five-year average. During the shale growth era from 2015 to 2019, natural gas prices averaged $2.50 to $3.25 per MMBtu, reflecting high storage levels. The green circles on the right represent natural gas prices when storage levels are low, as we see during the maintenance era from 2020 to today. During this period, prices have averaged over $4 per MMBtu. We believe that a structural shift has occurred with respect to pricing versus storage levels. The primary driver behind this shift is the supply side with limited access to capital, limits on infrastructure build-out and also supply chain constraints that limit production growth. Also supporting a higher price outlook is, number one, inventory exhaustion; two, continued LNG export growth; and three, low global storage levels. We believe this bodes well for commodity pricing moving forward and Antero is best positioned to directly benefit from higher prices. Now let's shift focus to Antero's significant exposure to rising commodity prices. Slide number 4 titled Leading Commodity Price Exposure depicts our 2022 and 2023 hedge portfolio relative to our peer group. Notably, we have not added any natural gas hedges since 2020 which is a testament to our natural gas and liquids commodity fundamentals teams that remain bullish on the outlook for both natural gas and NGLs. Antero is less than 50% hedged on expected 2022 natural gas production and has no liquid hedges. We are virtually unhedged on all commodities in 2023, except for 16 Bcf or just 2% of our production in 2023. These hedges were put on in 2020. This remains a sharp contrast to our peers who are, on average, 74% hedged on natural gas for the remainder of 2022 and 57% hedged on natural gas in 2023. As previously mentioned, we continue to see favorable fundamentals for the commodities and are very comfortable with where we are today from a balance sheet, diversified product and destination mix. Antero's industry-leading firm transportation portfolio allows us to deliver the majority of our gas and liquids to premium markets. This attribute is unique to Antero and will allow us to capture the upside to growing LNG and LPG export demand. With this in mind, we've invited our Senior Vice President of Gas Marketing and Transportation, Justin Fowler, to be on the call today. I'll now turn it over to Justin and let him expand.

Thank you. Over the last few months, natural gas prices have reached our highest level since 2008. Monthly NYMEX prices have touched 13-year highs, supported by global supply concerns and geopolitical tensions across several key regions. Yesterday, we saw the expiration for the May contract above $7 per MMBtu for the first time since 2008. Taking a closer look at storage levels and current supply expectations, let's turn to Slide number 5 titled Working Gas and Storage. Through the first four months of 2022, U.S. natural gas supplies have averaged around 93.5 Bcf per day. This resulted in a storage level of around 1.45 Tcf at the end of the withdrawals season. Consensus estimates call for the end of injection storage of approximately 3.5 Tcf prior to the 2022, 2023 winter heating season. The chart on this slide depicts the supply required to hit back consensus target in November. Assuming similar demand levels that we've seen over the last several years, adjusted for the higher exports we have today, production would need to average over 97 Bcf every single day beginning today through November. This represents a nearly 4 Bcf per day increase from current production levels. If supply does not increase to that level in the near term, we will likely need production in excess of 100 Bcf in the back half of 2022. While we do expect to see supply increase in the coming months, we believe the eventual supply growth in 2022 has underwhelmed. Further, we continue to see very strong power generation and industrial demand that is averaging 3% to 4% above these historical levels. LNG exports are also only assumed at the year-to-date average of 13 Bcf per day, which is expected to increase as incremental capacity comes online this year. This suggests even higher supply growth will be required to fill storage ahead of next winter. Now turning to Slide number 6 titled Antero's Peer-Leading Exposure to LNG Fairways. This slide highlights what Paul touched on earlier with our 2.3 Bcf a day of firm transportation to the U.S. Gulf Coast and to the Mid-Atlantic at Cove Point LNG terminal. As shown in the inset chart, this 2.3 Bcf a day represents approximately 75% of Antero's total natural gas production. As depicted, this has significantly higher direct exposure to growing LNG demand than any of our peers. We are currently selling nearly 1 Bcf a day of natural gas directly to LNG facilities, which includes 4 of the 7 facilities that are in service today. This includes counterparties such as Gale of India at Cove Point, Chubu Electric at Freeport, Cheniere Energy at Sabine Pass and Venture Global at Calcasieu Pass Phase 1. Specifically, we have 1.4 Bcf of firm transport along the Columbia Gulf, Tennessee Gas and Gulf Express pipelines. These pipelines deliver our gas to the doorstep of many of the new build LNG terminals that are already in service or are being discussed today. For context, when we began building our firm transportation portfolio to the LNG corridor in 2011, there was careful consideration to the firm delivery points that were negotiated with the interstate pipeline companies. The ANR 600 MMcf per day capacity delivers the primary points that can supply Cheniere's Sabine Pass and Venture Global's Calcasieu Pass Phase 1 and Phase 2 terminals. Additionally, the Antero 570 MMcf per day on the Tennessee gas pipeline has the ability to feed the proposed Venture Global Plaquemines LNG terminal or the New Fortress recently announced offshore liquefaction terminal. Finally, the Colombia Gold Firm Transport Southbound is capable of supplying Sabine Pass, Tellurian Driftwood, Sempra Cameron and other various contemplated LNG projects. As additional trains and terminals are completed, we expect the pricing hubs that these pipelines access will see larger and larger basis premiums to NYMEX. With the expected increase in LNG exports, both on an absolute and relative percentage of overall U.S. supply, we believe these premium hubs will see price increases more dramatically than NYMEX as they link directly to international prices. This environment will provide further support to Antero's strategic position today accessing LNG markets. This large firm transportation portfolio, combined with a deep resource base that includes more than 20 years of drilling inventory makes Antero a preferred partner for both LNG suppliers and international buyers. We are excited about the opportunities to increase our margins and gas realizations as this market develops further in the months and years ahead. With that, I will turn it over to Mike.

Thanks, Justin. I'd like to start on Slide number 7 titled 2014 versus now, why this cycle is different for Antero. To expand on how Antero has positioned itself to capitalize on rising commodity prices. The four charts on this page compare Antero's positioning in 2014 compared to today. As you can see, in the past seven years, Antero has grown production significantly and is now a top five natural gas and top two NGL producer in the U.S. During this time, Antero has dramatically reduced its absolute debt and leverage as a result of transitioning from an outspend to a consistent free cash flow generator. Despite this transformation to a more sustainable business model, Antero's valuation remains well below what it was during the last cycle when E&Ps were being rewarded and valued for growth. As the industry continues its focus on maintenance capital development, we believe investors will favor E&Ps like Antero that have scale, healthy balance sheets, sustainable free cash flow generation and attractive return of capital strategies. The next slide highlights the increase in our free cash flow targets. With the increase in commodity prices, Antero's 2022 development plan is now expected to generate over $2.5 billion of free cash flow. We are also expecting a similar level of free cash flow in 2023 despite the backward dated strip prices as our hedges roll off. This brings our current five-year cumulative free cash flow target to approximately $10 billion, which is essentially in line with our current market cap. This substantial free cash flow will enable us to continue returning capital to our shareholders while also continuing to pay down debt. In February, Antero's Board of Directors authorized a share repurchase program for the company to repurchase up to $1 billion of outstanding common stock. Despite commencing the share buyback program in late February, Antero was able to repurchase approximately $100 million of stock at an average share price of $27.11 during the first quarter. This amount approximated 25% of our initial free cash flow estimate for the quarter. Based on current commodity prices, Antero is targeting excess of 25% of free cash flow will be used for share repurchases in the second quarter. Once the credit facility has been repaid, which we expect to occur later in the second quarter, we expect to increase the share repurchase program to greater than 50% of free cash flow. Now let's turn to Slide number 9 titled AR, Lowest Leverage, Highest Return. The benefit to our shareholders of having already significantly reduced our debt is that we can return more of our free cash flow to shareholders. The scatter plot shown here highlights our leverage position and cash return relative to the Appalachian peer group. As you can see, AR has the lowest leverage, which supports a 10% cash return, the highest among our peers. Another noteworthy item is this puts Antero in a similar position as the majors and well ahead of the S&P 500. As further debt reduction opportunities become limited later this year, we expect to maintain a very high cash return profile relative to other E&Ps. To summarize on Slide number 10 titled Antero Investment Highlights, Antero is well positioned to execute in Shale 3.0 and capitalize on rising commodity prices. Antero has the strongest balance sheet in Appalachia with sub $2 billion of debt and a 1.1 times leverage ratio that is expected to go below 0.5 turn this year. We have significant scale as the fifth largest natural gas producer and second largest NGL producer in the U.S., providing product diversity at attractive prices. Our limited hedge position and industry-leading firm transport portfolio provide direct exposure to rising natural gas and liquids prices driven by rising global demand. Lastly, if we assume today's strip prices, we are forecasting substantial free cash flow generation in excess of $10 billion through 2026, which is our current market cap. With the lowest leverage and highest free cash flow yield of our peer group and a trading multiple of sub four times, we believe Antero is uniquely positioned to continue to deliver attractive multiple expansion and value to our shareholders. With that, I will now turn the call over to the operator for questions.

Ladies and gentlemen, the floor is now opened for questions. The first question today is coming from Arun Jayaram of JPMorgan Chase. Please go ahead.

Yes, good morning. Mike, maybe for you. I wanted to see if you can elaborate on potential cash returns to shareholders this year. You mentioned how things could accelerate once you paid off the revolver. But your updated guidance is for $2.5 billion or so in free cash flow. How much debt can you efficiently repay this year? And what does that mean you think in terms of buyback for the year? I mean, do you think you could do the full $1 billion authorization this year and potentially even reload just given the free cash flow numbers that you're talking about this morning?

Yes. I mean that's what the commodity prices would suggest would happen, Arun, right now. In the last call, we highlighted we have approximately about $800 million to $900 million of debt paid down on an efficient basis. We paid down $200 million of that in the first quarter. We still have an additional $385 million on the credit facility, which we will pay down in this quarter. So that's $600 million. And then we thought you could maybe get $200 million to $300 million in efficiently of the remaining non-callable bonds. So that's the plan around the debt. If these commodity prices hold and are supportive, that would leave $1.6 billion remaining with the majority of that being used for share repurchases. So that would suggest you would exhaust the $1 billion and have to put in an additional program sometime later this year.

Great. Thanks for that. I had one maybe housekeeping question on both NGL and gas pricing. The first one regarding C3+ pricing, your realized price of pre-hedging was about 60 150 and you guys do a nice job of giving us kind of what the quarterly numbers would be with your update. And I think the benchmark was close to the 64, so a little bit of a gap there. Just wondering if there is something unusual in the quarter and would you expect those to trade at parity? Same thing on the gas side, your pre-hedged premium relative to NYMEX about $0.06, and I think the guidance is $0.15 to $0.25. So just trying to understand any implications from 1Q realizations for the rest of the year in your guidance?

Yes, Arun, thanks for the point out on our weekly – we do a terrific job on a weekly basis of publishing what our NGL prices, and we've done that for a couple of years now, and it's always very close to actuals. This quarter, there was a one-time adjustment to those prices related to the carrying value of our line fill and NGL inventory. Without this adjustment, we would have approximated that weekly pricing around, like you mentioned, to the $64 per barrel. So we continue to expect whatever we publish on a weekly basis will be very close and this is just a one-time item. On the gas, another kind of one-time item is really related. We are a $0.06 premium. Our guidance for the year is $0.15 to $0.25 premium. This related to in February, if everyone would recall, there was – I think it was around $1.50 increase on the last day of the trading for the February monthly contract and it pushed that monthly contract up to $6.28 per Mcf. And then the subsequent daily trading for that month fell all the way back down, I think, to $4.50. So what happened is that 1st of the month pricing was $6.28, the dailies averaged well below that as we have a portion that's sold on 1st of the month and a portion that's sold on dailies, we got a much lower price in that month that that 1st of the month would have suggested. So that was kind of a one-time item. We don't see that happening going forward. So we know we kept that $0.15 to $0.25 premium guidance and we expect to obviously be higher than that in the second, third and fourth quarters to average that for the year.

Great. Thanks a lot, Mike.

Thanks, Arun.

Thank you. The next question is coming from Neal Dingmann of Truist Securities. Please go ahead.

Good morning all. Paul, Mike and the teams are doing a great job, obviously, with the lack of hedges. I'm just wondering on a go forward and look at that Slide 4, is there anything that would cause you to change that to – I know, look, you're obviously finances are going to be pristine. But is there anything that where prices might go or we've heard a number of anecdotes for collars are pretty fantastic out there that would cause you to change your opinion to put some hedges on.

Hi, Neal. Good question and – but no, we're not tempted to put any hedges on. The other collars were pretty strong there for a while. But our sense, our read of product prices for both gas and NGLs is that it's a pretty bullish outlook that we have. And so, no plan to hedge any commodity for the foreseeable future as – you're right, we have – are headed towards a pristine balance sheet and so that's a great position to be in. And so really our strategy and philosophy is to remain on the front of the curve, sell on the front of the curve and not hedge into a backward dated curve at all. So, no plans to hedge in the foreseeable future. I know we used to be the kings of hedging in a contango environment. But now we're on the opposite end, just reaping the benefits of staying on the front and remaining unhedged. And with that, our delevering will occur that much quicker.

Sure. Fantastic call. And then just one follow-up on ops. You guys look to be very stable going forward with the 3 rigs over there. The Marcellus, is there on that side, too, if you're able to bring on some incremental capacity or another LNG contract or something of the likes would anything like that, again, I mean, again, once again, having the financial flexibility to do so. What anything on that front caused you to, I don't know, later this year, early next year, add a rig or think about a bit different in activity?

No, nothing contemplated there. We feel good about where we are in terms of maintenance cap with our drilling partnership, there might be a small increase in production, production net, but not that much. So nothing in the cards that would get us stirred up in order to add another rig and start growing again, feel pretty good with where we are now.

Fantastic. Thanks, Paul.

Thanks, Neal.

Thank you. The next question is coming from Subhash Chandra of Benchmark Company. Please go ahead.

Hi, Subhash.

Hi. Good morning, Paul and Mike. So the question, I guess, is on the LNG premium. Are there any specific hubs we should be watching? Or are there any specific cuts that are developing that kind of did, I guess, in the Permian world, right, Magellan East and so on. That would express that international premium to NYMEX.

No, haven't seen that at all. We mentioned our hubs and we're pleased with where we delivered to, as Justin Fowler said. We negotiated that all and made the right calls on where we deliver two years ago. We were pitched deals maybe through Cheniere where there would be a sharing mechanism. We didn't bite on those, but we kept tracking those. And certainly, during the downturn, those would have been deeply underwater. So glad we didn't even nibble. But there is no particular hub, I would say, that if there were a deal to emerge where you could somehow get into that or between JKM, let's say, or TTF versus Henry, if you could capture some of that $10 plus premium while minimizing the risk, that would be of interest that we're studying it, but we haven't seen anything that tempting. So – but I do think the premium hubs we go to are in very good stead for most of the players in the LNG fairway.

Got it. Then I guess on LPG, a lot of things happening, right. We got the typical seasonal shoulder and we have lockdowns and war, et cetera. How do you sort of see the spring and summer even autumn play out?

No, we're very bullish still on the LNG, I mean on the LPG prices. You saw a very low inventory levels on propane, very low days of supply on propane, see a lot of constraints around propane growth. We have our own ownership and processing and fractionation and don't see any growth in Appalachia. Yes, there's low growth out of some other basins, but nothing that would overwhelm the market, and we still see very much – a lot of demand coming from Asia. So, the LPG story continues to be very bullish and we're unhedged, as we mentioned on in the second largest producer. So we feel very good about it.

All right. Thanks. And just if I could ask a bit of a housekeeping question. But I guess, this quarter, I was expecting in terms of GP&T costs probably be higher than it was. It seems that sequentially at least transportation costs went down quite a bit and helped blunt some of the processing increases. You gave the guide for the year, but what sort of – what kind of dynamic should we be looking for in 2Q and rest of the year?

Yes. When I look at that, I would include the marketing expense with the GP&T because what happens is the transport expense is better than expected as we used more local firm and so that has less cost associated with it. Conversely, the transport that was – had a little bit of unused in it was the longer haul to the Gulf transport. So our marketing expense was a bit higher than our guidance. So in combination of those two, they were still at the low end. So we've obviously built conservatism into our ranges, so that they were still good numbers, but in combination, they weren't quite as low as the transport expense would suggest. So we consider – I think those will kind of reverse in the summer months. We'll start using our longer haul transport and with the local basis widening, not use the local. And so, you'll probably see those flip transport expense a bit higher with marketing expense a bit lower. So we left the guidance the same.

Okay. Yes, makes sense. Thank you.

Thank you. The next question is coming from Umang Choudhary of Goldman Sachs. Please go ahead.

Thank you and good morning and thank you for taking my questions.

Hi, Umang.

You have highlighted a positive view on gas and NGL market. I was wondering if you can talk a little bit about risk and risk management here. I'm just trying to understand if you would look to deploy all of the free cash flow, which we'll generate this year towards the share repurchase program or would you think about building some cash on your balance sheet?

No. The first call on that is for debt reduction, of course. But once that occurs, I mean, we'll have half a turn of leverage, no callable debt, nothing efficiently to get in. It will be in and around in the low $1 billion worth of debt for a company that on current commodity prices. I think it's $2.5 billion plus free cash flow, so in a really good shape there. So no reason to build any cash balances. And then when you look where our stock trades adding at a 25% free cash flow yield, sub-four times, and that actually continues into 2023 and beyond. The market caps covered with the five-year free cash flow right now. That would suggest you should really be buying in the shares as quickly as you could. So once that debt gets down on the credit facility, we'll be deploying the majority of that cash to share buybacks.

Got it. That's helpful. And then I just wanted to follow up on that question around the premium to Henry Hub for the Bcf per day, which you will sell to LNG facilities on short-term contracts. Can you help us with the framework as to how we should think about that premium in the near-term? How could that look like?

Yes. It's lower numbers. So it would be from NYMEX flat to maybe NYMEX plus $0.12 or $0.13, that's probably the range right now as we get liquefiers bidding for the quantities of gas.

But I think the key to that is that's the current spot. We see that the optionality around that as being substantial for Antero because you just don't know where that's going to go with the next wave of LNG being built. There is going to be a lot of competition for that gas and we're the ones with the transport. So I think that's the whole point is that we retain that optionality. All these volumes are on a spot basis. And over the next couple of years, we're going to see where that goes because they're going to have to compete to try to secure that supply. And like I mentioned, there is a finite amount of transport down to the LNG corridor. So, we're in a really good position.

Got you. That's helpful. Thank you.

Thank you.

Thank you. The next question is coming from David Deckelbaum of Cowen. Please go ahead.

Good morning everyone. Thanks for taking my questions.

Hi, David. Good morning.

Just had a quick question first on just you guys pointed out the fact that you did not add any hedges in the quarter when the whole commodity complex moved quite a bit higher. Should we take that as an indication of your view on the market and your view forward on the strength of commodities or just the evolution of risk management, considering the buyback – the balance sheet is in such great shape?

Well, of course, it's both, but I think more primarily, it's our bullish outlook on the commodity itself. We just – we like everyone are watching supply and demand and uses in the power stack and so on. And we just feel good about higher prices ahead and didn't want to hedge in new, as I've said, a backward dated curve or even a flat curve that we just don't want to give up our optionality. We see brighter times at even above where we are now.

Fair enough. And then just a little bit of color just on the cadence of buybacks. I know you said that you would be triggered to using 50% of free cash once you paid down the revolver this quarter, which was used to redeem the notes in 1Q. I guess the timing, I think you alluded to you acquired the shares of the $100 million or so in the first quarter in the last six weeks of the quarter. Was that just in coincident with completing the redemption of the senior notes? Or is that – that's sort of the window that you had to work with that time? Or that was something...

No. If you recall, David, we didn't reach our under $2 billion target for debt until mid-February, which was consistent with our conference call. So we did not initiate the share buyback program until a couple of days after that conference call, which left us six weeks in the first quarter. What we did is we looked at our free cash flow estimates at the time it was a $1.5 billion to $1.7 billion forecast on the commodity prices, about $400 million of that would occur in the first quarter. So, we put in a 10b5-1 plan to buy back $100 million by March 31st. Of course, prices went higher. We performed better than we thought. So we ended up having free cash flow of $465 million, but couldn't change the 10b5-1 plan because we are outside an open window. But still, we're very confident in our ability to hit that $400 million, so we put $100 million in. Of course, going forward now, we look at the free cash flow estimates are well in excess of what we originally assumed. We do have that $388 million of the credit facility that will be paid down during the quarter. But anything above that during the quarter for your free cash flow estimates, it's a pretty good assumption of what's going to be bought back during the quarter.

Absolutely. And I guess just along those same lines, how often are you communicating with the Board around authorizations?

There was one communication. It's when we get it authorized for the $1 billion. We report back to them on our progress against that number, but that's the communication.

Perfect. Thanks, Mike.

Thanks, David.

Thank you. The next question is coming from Nitin Kumar of Wells Fargo. Please go ahead.

Hi. Good morning gentlemen and thanks for taking my call – my questions. I want to start with the buyback commentary. Obviously, it's a phenomenal place to be getting to the debt targets earlier and leaning in there as you indicated. But any thoughts of a dividend or your stock is up almost 100% this year. I just want to understand like why are you still focused on – what are you looking at that makes you feel like your stock is still undervalued and...

Well, I think anything with a 25% free cash flow yield qualifies as being undervalued, also sub four times EBITDA. And if you look at it on a PDP basis, it's like a PDP 18. I mean, it's just – you put these type of commodity prices on there. If anything close to that occurs, we are substantially undervalued. So we should be buying back shares as quickly as we can. And so, that's what we're doing. Once the $1 billion is done, of course, we'll reassess, look at it in that time frame. Once that is exhausted and see what further return of capital strategies we have, but we're firmly behind this first initial $1 billion share buyback program.

All right. Thank you. That makes sense. And I guess the other question is you mentioned the firm transport and your position in supplying LNG gas. Are you seeing any movement on their FID or potentially FID projects out there for LNG, but in terms of incremental ability to get the gas to the Gulf Coast, are you seeing any discussions or movement there?

No. We – it's a difficult time right now to do pipeline expansions as you're aware, whether it's new builds or even installing compression on existing lines. So there's nothing material that is happening to boost, say potential firm transportation from Appalachia or even down the Chicago corridor, let's say, there's nothing particularly happening that's going to boost LNG into the fairway, at least from as far north as where we are. I know there are a number of ideas in the Haynesville of newly arrived players in the Haynesville that are continuing to circle and try to figure out a way to get their gas to the Gulf economically. So it could be some new builds or enhancements coming out of Haynesville, but it's about all I can think of. From further north in Appalachia, I don't see anything.

But that's why we continue to highlight our 2.3 Bcf of transport. I mean, such a finite resource, and we've captured such a significant portion of it. So we don't need really any further pipelines to be built to have our LNG exposure. We're already at 75% of our gas. So we're in a good position.

Great. That's very helpful. Thank you gentlemen.

Thank you.

Thank you. The next question is coming from Holly Stewart of Scotia Howard Weil. Please go ahead.

Good morning, gentlemen.

Hi, Holly.

Two quick ones – two quick ones for me. First, I think, Mike, one of your peers highlighted the impact of cash taxes on their free cash flow portfolio over the next five years. I'm assuming you guys probably have that in your numbers here that you updated as well. Any – can you give us any inclination on kind of when that kicks in, in the magnitude?

Yes. Of course, our free cash flow projections already include the projected cash taxes. Just to remind everyone, we have $2.3 billion of NOLs, the vast majority of which are 100%. We also have over $800 million of capitalized IDCs from prior periods that we did not need them, but we can use going forward and we have leases that are not in our 15-year plan that can be expensed as well. So we have a lot of tax attributes. However, when you have an excess of $2.5 billion of free cash flow this year and next, you chew through those pretty quickly. So not this year, but right now, these commodity prices sometime in late 2023 is when we would become a cash taxpayer.

Okay. That's helpful. And then maybe, Paul, just an update on your ownership in AM. I mean you've highlighted here this morning $10 billion of free cash flow over the next five years. Just maybe give us some thoughts around that ownership?

Yes. We own 139 million shares, which is about 29%. It's a terrific asset, the first mile of the LNG story, huge inventory behind it, a lot of throughput. So, we want to own it and have no plans of divesting any.

All right. Thank you guys.

Thanks, Holly.

Thanks, Holly.

Yes. Thank you for joining us on today's call. Please reach out with any further questions. Thank you.

Ladies and gentlemen, thank you for your participation. This concludes today's event. You may disconnect your lines at this time, and enjoy the rest of your day.