Greetings and welcome to the Antero Resources Third Quarter 2021 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. I would now like to turn the conference over to your host, Brendan Krueger, Vice President of Finance.

Thank you for joining us for Antero's third quarter 2021 investor conference call. We'll spend a few minutes going through the financial and operational 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 Dave Cannelongo, Vice President of Liquids Marketing & Transportation. I will now turn the call over to Paul.

Thank you, Brendan. Let's begin with slide number 3 titled Antero Strategy Evolution. Antero's business strategy has evolved over the last decade. Ten years ago, during what we would call 'Shale 1.0', our focus was on increasing scale through acreage acquisition, building out the necessary midstream infrastructure through long-term commitments, and delineating our resource base. As we entered 'Shale 2.0', we focused on growing production to achieve scale and become a leading U.S. natural gas and NGL producer. During this time, we proactively hedged our production into a strong Contango forward curve in order to lock in attractive returns and to ensure that we delivered on our growth targets. We also consolidated our acreage position through land acquisitions and swaps to secure the contiguous position we have today. Lastly, through technology and innovation, we optimized our drilling and completion techniques to maximize recoveries and reduce well costs. Today, Antero is in the shale 3.0 phase. Our focus is on maintenance capital programs that hold production flat and maximize free cash flow. The results of this program have been dramatic. We reduced debt by $1.4 billion in less than two years, and lowered our leverage from 3.8 times to just 1.6 times at the end of the third quarter. Our strong Balance Sheet and low leverage combined with low maintenance capital, allows for less hedging than was previously targeted. We are currently the least hedged in our Company's history on the natural gas side as we entered 2022. We also have very little NGL's hedged and no propane as of October 1, the beginning of this month 2021. Slide number 4 titled Peer Hedging Comparison, shows our 2022 Hedge portfolio relative to our peer group. We have not added any natural gas hedges in over 18 months. A testament to our management and our natural gas and liquids commodity fundamentals teams that have remained bullish on the outlook for both natural gas and NGLs heading into next year. We are only 50% hedged on natural gas in 2022 and have no liquids hedges. We are essentially unhedged in 2023 on all commodities and going forward. Now, let's discuss drilling inventory in the Appalachian Basin. Slide number 5 titled Peer Leading Premium Core Inventory provides a summary of the core inventory remaining in the Appalachian Basin as we see it. We regularly perform a technical review of peer acreage positions, undrilled acreage, and location potential. We also analyzed BTU, well performance, and the URs. Based on these results, we've subdivided the core of the Southwest Marcellus and the Ohio Utica into premium and tier-2 sub-areas. We've identified approximately 5,200 premium locations—premium undeveloped locations for the industry in the Southwest Marcellus, which is shown with the red outlines on the map. Of that, we estimate Antero holds approximately 1,865 of those premium locations or 36% of the total, which includes more than 1,000 liquids rich locations. In the Ohio Utica, we estimate roughly 1,100 premium undeveloped locations for the industry, of which Antero holds 210 or 19% of the total. Beyond that, we estimate that there are 1,600 tier 2 locations remaining, which you can see located within the blue lines. You can see that much of the acreage is covered up with existing Marcellus and Utica productive horizontal wells, which are the red lines on the map. Ultimately, we believe the idea of 'Inventory Fatigue' and the limited number of premium drilling locations will be a critical distinction between the 'haves' and 'have nots' across Appalachian producers. Based on our maintenance level development plan which assumes 60 to 65 wells per year, Antero has at least 15 years of premium liquids drilling locations remaining, with many years of dry gas locations on top of that. This analysis leaves us optimistic about Antero's competitive advantages as we look towards the future. Turning to slide number 6 titled, Rightsizing Firm Takeaway Commitments, we highlight our declining commitments over the years. On October 1st, we released 200 million a day of capacity, reducing our annual transportation fees by $45 million. This firm transportation was originally intended to be filled with Utica volumes. However, given our development focus now on the liquids rich Marcellus acreage, it was prudent to release this underutilized capacity. We have released a total of 400 million cubic feet a day of firm transportation commitments, reducing annual transportation fees by just over $60 million a year. We will continue to optimize our firm transportation portfolio to best match our current maintenance capital program and our development focus. Now let's turn to Slide number 7 titled Diversity of Product and Destination. This slide illustrates the benefits of Antero's unique business strategy that focuses on liquids-rich developments and maximizing out-of-basin product sales. Starting with the chart on the top left side of the page, as you can see, Antero is the largest liquids producer in the Appalachian Basin. Moving to the chart on the bottom left, we are not only the largest liquids producer, but with our ability to export half of our C3 plus NGLs, we captured the highest liquids pricing in the basin. Now, let's look at the natural gas side of the business. The chart on the top right highlights our industry-leading firm transportation portfolio, that allows us to sell 100% of our natural gas out of basin. The direct result of this is best-in-class natural gas realizations. As illustrated on the chart on the bottom right, we realized a $0.30 per Mcf premium to NYMEX during the third quarter. Looked at another way, this competitive advantage resulted in price realizations that were a $1.07 better than in-basin Appalachian pricing, which averaged $0.77 back of NYMEX. The combination of our FT portfolio with significant exposure to export markets and our low hedge profile, makes Antero the most efficient way to gain direct exposure to NYMEX and Mont Belvieu prices. With that, I'm going to turn it over to our Vice President of Liquids Marketing & Transportation, Dave Cannelongo for his comments.

Thanks, Paul. The bullish backdrop for Liquids Pricing has manifested in C3 plus. Having increased 20 to 25%, ethane prices up 35%, and oil prices up over 15% during that time. For Antero, we are currently realizing our highest pricing for C3 plus NGLs since the polar vortex of February 2014 and are on track at current strip pricing for our highest quarterly C3 plus price in company history. Current C3 plus NGL pricing is over $60 per barrel, more than double the year-ago period. Focusing on the propane market, I'll refer you to Slide number 8 titled Propane Market Fundamentals. Previously, we had predicted that we'd see U.S. propane inventories peak around 75 million barrels to 80 million barrels this fall. Ultimately, we ended up at the low end of this range as illustrated on the slide. The lower-than-expected year-end inventories were a result of strong LPG export volumes out of the U.S. throughout the summer and into the fall. Despite the sharp increase in pricing at Mont Belvieu, the export arc has remained open. Where the U.S. will end withdrawal season remains to be seen, but with inventory levels currently 23 million barrels below last year, we anticipate it will be a dynamic winter for propane with the risk for pricing skewed heavily to the upside. Turning to LPG demand, we've talked in the past about the nearly 550,000 barrel a day increase in LPG demand in China from 2021 to 2023, and over 110,000 barrels a day of European and North American PDH growth during that same time period. What many did not anticipate was the global pressure for hydrocarbons this fall and winter, that resulted in elevated LNG prices in Europe and Asia. This is driving additional demand for LPG in these markets, through its use in industrial heating and power applications in lieu of today's high cost of natural gas. On a BTU equivalent basis, LPG is nearly half the price of LNG delivered in the Far East markets. The impact from this incremental demand for LPG is a widening export arc. Slide number 9 highlights the propane export arc reaching $6.25 per gallon this week, the highest level in 2021. As we enter the winter, we expect the export arc to remain open. A result of strong demand in reliance globally for U.S. export volumes. Looking forward, Antero has been fully unhedged on its propane since October 1. And our remaining butanes and pentanes plus hedges are expiring at the end of this quarter. Resulting in Antero being completely unhedged on all NGL and oil volumes beginning on January 1, 2022 or approximately just 60 days. This positions Antero with tremendous exposure to NGL prices and free cash flow generation, given both the near and longer-term fundamentals that we see for these markets. With that, I will turn it over to Mike.

Thanks, Dave. I would like to start on Slide number 10, highlighting Antero's financial strength. During the third quarter, we generated $91 million free cash flow which we used to reduce net debt. Our net debt of $2.3 billion at the end of the third quarter represents a $660 million decrease from year-end 2020. The top right quadrant of the slide illustrates the LTM EBITDAX improvements from just over $1 billion at year-end to over $1.5 billion at the end of the third quarter. Total debt reduction combined with an improvement in LTM EBITDAX decreased leverage to 1.6 times at the end of the third quarter, down from 3.1 times at year-end 2020. As we look ahead to the coming quarters, we will continue to maximize free cash flow and reduce debt, which is expected to result in leverage below one times in the first quarter of 2022. As we approach our absolute debt target of below $2 billion, we can begin to use expected free cash flow to return capital to shareholders. Lastly, on slide number ten, the bottom right quadrant highlights that dramatic improvement in our EBITDA margin, which more than tripled from the fourth quarter of 2020. These commodity exposures highlighted on slide number 11 titled, Enhanced Free Cash Flow Profile. The increase in natural gas and NGLs strip pricing results in a substantial free cash flow outlook at Antero. We forecast over $900 million of free cash flow in 2021, with substantially higher free cash flow expected in 2022. Further, looking out through 2025, we are now targeting over $6 billion in free cash flow, signifying significant annual free cash flow through that time period, despite the backward dated commodity strip. To put the in excess of $6 billion in context, our current market cap is approximately $6 billion and our enterprise value is approximately $8.5 billion. Turning to Slide number 12 titled Recent Credit Enhancements, you see the benefits of our improved financial strength. In early October, we received ratings upgrades from both Moody's and S&P. This week, we extended our credit facility to 2026 with a borrowing base increase of 23% to $3.5 billion. Despite this increase, we elected to reduce our commitments from—given our balance sheet strength with an essentially undrawn balance and our substantial free cash flow outlook over the coming years. As a result of these upgrades, our letters of credit were reduced by $107 million. The release of the firm transportation commitments that Paul discussed earlier, results in a further $20 million reduction in our letters of credit. And lastly, we were able to replace another $80 million of letters of credit with surety bonds, further enhancing our liquidity profile. Next, let's turn to Slide number 13. This chart provides a look at which Appalachian producer is best positioned to return capital. At the bottom of the chart is a period in which each company is expected to achieve one times leverage. The left-hand side indicates cumulative free cash flow as a percentage of enterprise value through 2023. Both of these estimates are based on facts and consensus estimates. As you can clearly see, not only is Antero projected to achieve 1 times leverage the earliest, but Antero also has the most attractive free cash flow outlook. Said another way, we will be the first Appalachian company to have the balance sheet and the appropriate position to return capital to shareholders. And as we look at the world today, share buybacks certainly look to be an attractive option. We're also excited about our ESG momentum during the third quarter, as outlined on Slide number 14. In July, we announced our pilot program with Project Canary's TrustWell Certification process. By using a third party to review the process and procedures, we aim to validate the high environmental standards by which we produce our natural gas. In August, we received the ratings upgrade from MSCI to Triple B. And we have also committed to the World Bank's Zero Routine Flaring initiative beginning this year. And in early October, we published our 2020 ESG report, which we expect to drive further ratings upside in the coming months. To summarize, the impressive operating and financial momentum continues for Antero. Slide number 15 highlights—titled Key Investment Highlights, summarizes the position of strength we're in today following this execution. We have significant scale as the fourth largest natural gas producer and second largest NGL producer in the U.S., providing best-in-class exposure to relatively unhedged, strengthening commodity prices. And extensive core inventory with more than a thousand premium liquids locations remaining. Since the beginning of our deleveraging program, we've reduced debt by approximately $1.4 billion, and we expect to have leverage below one times in the First Quarter of '22. Lastly, assuming today's strip prices, which include a backward dated NGL and natural gas strip, we're forecasting substantial free cash flow generation of over $6 billion through 2025. These operational, financial and ESG metrics place Antero among a small group of EMPs with significant scale, low leverage, sustained free cash flow generation, and leading ESG performance. With that, I will now turn the call over to the operator for questions.

Thank you. We'll now begin the question-and-answer session. Please hold on while we gather the questions. The first question today is from Neal Dingmann of Truist Securities. Please go ahead with your question.

Morning all! My question is you guys have obviously had a fantastic call on liquids, gas, and even turned what we kind of be seeing on the dry gas. Now I’m thinking of the hedges coming off next year during a pretty good time. So, Mike, given the returns you all have at even a $3 price, are you tempted to put at least some collars or something on the dry gas side as it pertains to—?

Hi, Neal, it's Paul. Good question, but we're looking forward to being completely unhedged to take advantage obviously of the higher prices and that will accelerate our delivery. We're quite aware of the collars that are out there, highly skewed to the upside, as you know, but we feel we're in pretty good position, have pretty good understanding of the fundamentals of the gas market. Really feel that there is a shortage across the world, and as you are aware of, more and more exports. So, even though we’re aware of things like collars to get some of the upside, the way we're looking at it right now is just not hedging that gas at all.

Okay, fair enough. It makes sense, especially with the lower balance sheet going forward. And then, Paul, just to follow-up. Really, it looks good on your firm's outlook; it continues to be improved but my question is more on—when you look at capacity both on the liquid and the dry gas side, any sort of issues you see out there in your crystal ball? I mean, let's say delivering, you hear so louder. Given the plan to sort of put it out there, is there anything like that that gives you any concern?

Good question, but no, we don't see any reason for concern at all. We have plenty of liquids takeaway. We have plenty of natural gas takeaway to the premium markets. And so even though we have let go of some firm transportation recently as we talked about, of course, we analyze it before we let it go, and we feel that we still have quite enough to get it to the premium markets, primarily Gulf Coast, Chicago, Midwest, and Cove Point, which is NYMEX-based market there for us. I feel good about where we stand with the firm transport and also with liquids takeaway.

Very good. Thanks for your time, Paul.

The next question is from Arun Jayaram of JPMorgan. Please proceed with your question.

Yeah. Good morning, gentlemen. Maybe for Mike. Mike, I was wondering if you could give us kind of the path forward in terms of when do you think the management team would be comfortable perhaps unveiling your capital return framework and maybe the path towards when you think you could be in the market buying back stock if the strip holds and it does appear that you are going to try to pay down some additional debt next year beyond the $2 billion target.

Yeah. All of that occurs in the First Quarter of 22. Arun, with strip where it is today will be below that $2 billion debt target sometime in the first quarter. And then that's when we would look to put in place some form of return on capital and like you mentioned, in addition continue to pay down that.

Fair enough. Fair enough. In the slide deck, you guys have highlighted how your production cost trend down call from the range is $233 to $240 this year and then longer term—is that a long-term average of the $214 to $219? And I was wondering if maybe you could help us over the next couple of years how that stair steps down?

Yeah. It comes off as it's tracking the backward-dated strip pricing on the costs. The only real variable there is the taxes, ad-valorem, and severance taxes. And that's just the commodity price coming off over that time.

Got it. But the implication is the longer-term average is $214 to $219 per Mcf, is that right?

Yeah. Yeah. And then also like that chart shows in the firm transport, the unutilized firm transport continues to decline on an annual basis.

Great, I'll turn it over thanks.

Yeah. Thank you.

The next question is from Umang Choudhary of Goldman Sachs. Please proceed with your question.

Hi. Good morning and thank you for taking my questions. I wanted to get your thoughts around spending and also on cost inflation next year. Any initial read around inflation pressures you're seeing on your Appalachian drilling and completion activities? And also as you think about next year's annual Drilling JV with Quantum and elections around that, should we assume that you will probably elect to go towards the lower end of the range, the 15% to 20% range, given the strength in commodity prices?

Yeah, good question. Maintenance capital is around $600 million for this year. There's obviously been some inflationary pressures; we're determining that right now. We also have some efficiencies that come online in the fourth quarter, mainly our local sand sourcing, which will offset some of that. But it's looking like $600 million plus, from a maintenance capital perspective in 2022. And like you mentioned, we do have the election of having Quantum if they choose to participate either out of 15% or 20% level.

In 2021, it was at a 20% at today's commodity prices; you can imagine what kind of returns we're generating. So we will most likely elect to have them be at 15%. So that would add a little bit of capital as well but $600 million plus still going to determine it. And we will have to assess the inflationary pressures over the next couple of months for our final budget coming out at the beginning of the year.

Great thank you.

Yeah, thank you.

The next question is from David Deckelbaum of Cowen. Please proceed with your question.

Good afternoon guys. Thanks for taking my questions today.

Sure. Yeah. Good to hear from you David.

Likewise. Mike, I actually just want to follow up on the in-basin sands. Just the impact on '22. Is this all locally sourced sand from your Beaver projects and then I guess is it going to be covering the totality of all of your frac jobs next year?

This is Paul. Yes, this is local sand we've been developing it for a while and have been talking about it for probably the last year and yes, it will cover virtually the totality of our programs. There may be some supplemental Northern White on an as-needed basis, but most likely it's going to be our local sand. And how much can that save? The math really comes down to, we're going to be around $20 a ton with this local sand versus $55 prior. So it's about a $35 a ton savings and we do 2,000 tons a well, so it's about $600,000 to $700,000 a well. A lot of savings that come from and that's why we think we can offset some of those inflationary pressures going into '22.

That's pretty clear. That certainly will offset some of the inflationary pressures. My next question is just on the propane markets and just Antero's base program. You go forward, obviously, can highlight a compelling case for being in maintenance mode. But it seems like with the fractionation capacity built out so far, particularly in the Marcellus and the Sherwood facilities, etc. I guess, is there a—how do you think about just growing propane volumes over time or any C3+ volumes over time with the way that some of the agreements are with fractionation capacity coming online?

We have plenty of fractionation capacity, processing capacity, as well, David. So between Sherwood and Smithburg, which is our latest plant in that complex, we have room for more processing, but we fractionate both at—generally at Hopedale. We can also frac at Majorsville or Houston, but I think there's plenty of capacity at Hopedale. So I don't think we have any physical constraints. It's—and we do have the inventory to continue developing high BTU gas that would have plenty of propane in it. But it's just maintaining our discipline and overall keeping the damper on growth. And—but certainly like the economics quite a bit, but no plan to accelerate.

Sure. And just a last one for me. You guys highlighted at the beginning, I certainly remember you being five years hedged back in 2013, well above the strip. And obviously, today, the business is different. There isn't that requirement, but as you think about C3+, especially propane, and given the fact that there's so much international demand coming online and the macro case that you lay out, certainly lays out the shortage in the coming years, especially with some of the dehy plants coming online. Are you getting in-bounds or is there an interest on your side of signing either off-take agreements for demand contracts that would sort of have a floor in place where you would be providing supply surety?

We're not tempted. You know that we learned our lesson last spring. We were told this story before, but we stepped in and hedged in propane, butane last spring. We felt good about the fundamentals of propane, butane, but LPG across the world. But we just had a little bit of this just wonderful dream and we're going to wake up and it's going to go away. So we did hedge LPG propane, butane for the second and third quarters. And it was into a backward dated curve and sure enough that we ended up what we projected, which was a lower price because of the backwardation from last spring. And so today, fast-forward that curve is still backward dated. And so we believe pretty strongly that it's best to live on the front of the curve. There are—there's a lot of appetite for LPG out there. I think Dave Cannelongo would say there's not a cargo that we've lifted that we've exported where the receiving parties haven't asked if they can have more or have it sooner. We're quite aware that there is strong appetite, but we're happy with the situation we have for export at Marcus Hook at the dock that we get paid locked in our write down in there, and just keep selling on the front physically, and really no temptation to step back into the hedging market and hedge into that backward dated.

Thank you guys. Appreciate the answers.

Thanks.

The next question is from Jeoffrey Lambujon, of Tudor, Pickering, Holt. Please proceed with your question.

Good morning. Thanks for taking my questions. First, I just wanted to follow up on the return of capital discussion as you guys quickly approach your balance sheet objectives as you highlighted. If things hold here as far as strip goes and free cash is not too far off from $2 billion next year, and the debt target's reached, you can still deliver further while buying back free cash flow at a nice discount to intrinsic value. I just—I want to get your thoughts that'll be reasonable to think about something in the 50% range as a possible mix of free cash that can go to buybacks next year.

We haven't done the math on that yet. Just looking at our debt or ability to pay down that, you can identify probably about $800 million right now of the $2.3 billion that you could actually control and buy-in. Either through calling it or issuing equity clause or from a credit facility standpoint. So anything outside of that is probably going to be open market repurchases, which is probably difficult from a liquidity ability to get any sort of size. And from that, so once you get to a billion-up dollar level, it will be slow going on reducing debt much further after that. So when you do get below that, I think there probably will be a little bit more allocated to share buybacks or some form of internal capital than prior to that when we can absolutely call in all that debt.

That's very helpful. And then, secondly, I just wanted to get how you're thinking about the GP&T and production that Gulf accessed with higher commodity prices, and maybe what some of the offsetting benefits might be on GP&T specifically as you think about the firm transport optimization?

Yeah, the increase is solely because of that. The taxes I think are around 4.7% or 4.8%. So every time commodity prices go up, the realized price we have. In your models, have 4.8% as it's the taxed portion of that. The actual gathering, processing, and transport should be relatively flat, so there shouldn't be any increase from that. It's really just taxes. We're optimizing all of our gas to the Gulf Coast, right now are the Midwest or out of the basin, so we're already utilizing the higher-cost transport right now that's resulting in that $0.30 premium to NYMEX pricing we're getting. That won't go up any further. GP&T will be flat, just taxes will be the swing whether commodity prices go up or down, is how that will affect those tax expense items.

Alright, great. Thank you.

Thank you.

The next question is from Subash Chandra of The Benchmark Company. Please proceed with your question.

Hey, Paul. how are you thinking about—

Hey Subash.

Good morning. How are you thinking about the Utica these days? That's nice details there on premium locations in the Utica certainly can be valuable to someone else as much or more than for your portfolio and your five-year activity levels. But, I mean, I think you do have some activity coming back in that five-year scenario, but how do you think about that?

Yeah, we think about it. We've moved a rig over to the Utica this year, and it's the first time since 2018. And we've come a long way on our drilling techniques in general, it's gone well over in the Utica. And so we still have some ahead of us but the economics are just, they're much better, probably both geologically and in drilling but the drilling is just a little more expensive over in the Utica. The priority is going to be on the Marcellus that more than 90% of our capital will be pointed in that direction into the Marcellus rig. Is the Utica as near and dear to our hearts as the Marcellus? No, it's certainly a good project, but not as good as the Marcellus. And so that's where we'll be focusing our capital.

This question might have been asked a million different ways. You probably answered it a million different ways, so I'm just going to try it again. Only because one of your peers competitor yesterday suggested that, post '22, they might step in to grow in order to replace fading inventory in the Basin. And, of course, you're probably in equally or better position with regards to inventory. What are the conditions for growth for you?

No. You're right, we are fortunate to have quite good inventory for quite a long time, so we feel good about that. Conditions for growth, don't know. We're really just stuck to our needing and really are quite determined after what we, and really the rest of the industry, has gone through, but especially independents with too much debt. We just—before we can really lay any plans for growth, we just want to reduce the debt. As I get down to that—we'll pass to that $2.0 billion of absolute debt and debt in the first quarter as Mike elaborated on. We'll see where we go after there, but it just feels really good to deliver so dramatically. So I think you'll see that more. I will try and be creative with the different ways that we can buy back debt or whatever to reduce leverage that much more, but really, we're staying away from growing, we're happy with—where we are right now and just focusing on that free cash flow. Having been tempted and just want to see de-levering and getting the balance sheet in pristine shape.

Thank you.

Thank you.

The next question is from Gregg Brody of Bank of America. Please proceed with your question.

Hey, guys. I appreciate the commentary about paying down debt as a credit analyst. You haven't actually used the word investment-grade. I'm just curious. I noticed that the new credit facility has a covenant in there that security falls away. If you do a GM has been greater, does that was that intentional or is that something that you wanted in there because there is a target? So you get to investment grade.

I don't know what's the target, but it was intentional, Gregg. Our conversations with the rating agencies do stress how we do map to investment grade currently. They've already upgraded us three times this year, and they said it's unprecedented how fast they've gone, and our response was always it doesn't matter where we—we got to look at where we are. You should rate us based on where we are and we do map to investment grade today. I would expect further improvements in the ratings going forward if this free cash flow generation occurs from the strip prices, and we pay down the debt. So we'll definitely be thinking we should be investment grade, and that's why we designed the credit facility that way.

They usually want to hear that, that you want to be investment grade to get there. So let me—your comments earlier.

We express that quite often, Gregg. Quite frequently, they respond. It just takes time.

Got it. That's helpful. And then last question for you is that $6 billion free cash flow number you had out there, is there an expectation for taxes in there? And if so, how are you thinking about that?

Yeah, I mean, it's actually over, I think, the next four years and that's inside our tax horizon. We have sneak on that well and with our development program, our capital right now, generating further deduction. We don't—we're not a cash taxpayer in that four-year time frame, so that $6 billion looks good, probably to the point where you start paying some tax, but prior to that, we're not a taxpayer.

And I just have to say what a difference a year makes. Nice talking to you.

Yeah, I agree to that. That's so true. Yes.

If there are no additional questions at this time, I would like to turn the call back over to Brendan Krueger for closing remarks.

Nice. Yes. Thank you for joining us on today's call and please reach out with any further questions. We're available.

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.