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. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. 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 forecasted 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. 10 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 maximizes 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 3.8x to just 1.6x 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 history on the natural gas side as we enter 2022.
We also have very little NGLs hedged and no propane as of October 1, the beginning of this month, 2021. Slide 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 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 analyze BTU, well performance, and EURs. Based on these results, we've subdivided the core of the Southwest Marcellus and the Ohio Utica into premium and tier two 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 two 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, quote-unquote, inventory fatigue and the limited number of premium drilling locations, which will be a critical distinction between the haves and have-nots across Appalachian producers.
Based on our maintenance level development plan, which assumes 60-65 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 toward the future.
Turning to slide 6, titled Right sizing firm takeaway commitments, we highlight our declining commitments over the years. On October first, 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 unutilized or underutilized capacity.
Year to date, 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 7, titled Diversity of product and destination.
This slide illustrates the benefits of Antero's unique business strategy that focuses on liquids-rich development 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+ NGLs, we capture 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 $1.07 better than in-basin Appalachia pricing, which averaged 77 cents 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 and Transportation, Dave Cannelongo, for his comments.
Thanks, Paul. The bullish backdrop for liquids pricing has manifested C3+ having increased 20%-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+ NGLs since the polar vortex of February 2014 and are on track at current strip pricing for our highest quarterly C3+ price in company history. Current C3+ 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 8, titled Propane market fundamentals. Previously, we had predicted that we'd see U.S. propane inventories peak around 75-80 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 arb has remained open. Where the U.S. will end withdrawal season remains to be seen. 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 pet chem 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 into the Far East markets. The impact from this incremental demand for LPG is a widening export arb.
Slide number 9 highlights the propane export arb reaching $0.0625 per gallon this week, the highest level in 2021. As we enter the winter, we expect the export arb to remain open, a result of strong demand and 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 in approximately just 60 days. This positions AR 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'd like to start on slide 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 improvement 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 1.6x at the end of the third quarter, down from 3.1x 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 1x 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 10, the bottom right quadrant highlights the dramatic improvement in our EBITDAX margin, which more than tripled from the fourth quarter of 2020.
This commodity exposure is highlighted on slide 11, titled Enhanced Free Cash Flow Profile. The increase in natural gas and NGL 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 backwardated 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 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, 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. 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 13. This chart provides a look at which Appalachian producer is best positioned to return capital.
At the bottom of the chart is the period in which each company is expected to achieve 1x 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 FactSet consensus estimates.
As you can clearly see, not only is Antero projected to achieve 1x 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 in the appropriate position to return capital to shareholders. As we look at the world today, share buybacks certainly look to be an attractive option. We are 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 a ratings upgrade from MSCI to BBB, and we have also committed to the World Bank Zero Routine Flaring Initiative beginning this year. 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 highlight, 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. We have extensive core inventory with more than 1,000 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 1x in the first quarter of 2022. Lastly, assuming today's strip prices, which includes a backwardated NGL and natural gas strip, we are forecasting substantial free cash flow generation of over $6 billion through 2025.
These operational, financial, and ESG metrics place Antero among a small elite group of E&Ps 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. At this time, we'll be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we pull for questions. The first question today is from Neal Dingmann of Truist Securities. Please proceed with your question.
Morning all, great day out there. Mike and team out there. Obviously, the data out there. My question is you guys have obviously had a fantastic call on not only liquids, gas, but even sort of what was kind of the pricing and what we've been seeing on the dry gas. My question is, now that we continue to see, you know, of course, gas isn't quite back in recession, but you look to 12 months is still now quite high.
I'm just thinking, you know, you all talked about the hedges coming off next year, but I'm thinking of it, Mike, given the returns you all have at, you know, even $3 plus, are you tempted to put at least some collars or, you know, something on that on at least on the dry gas side as it pertains to 2022?
Hi, Neal. It's Paul. A good question, but we're looking forward to being completely unhedged to take advantage obviously of the high prices and that will accelerate our delevering. We're quite aware of the collars that are out there, highly skewed to the upside, as you know. No, we feel we're in pretty good position, have pretty good understanding of the fundamentals of the gas market. Really feel that there's a shortage across the world, and as you're aware, more and more exports.
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 nat gas at all.
Okay. Fair enough. Makes sense, especially with the lower balance sheet going forward. Then Paul, just to follow up, really it looks good on, you know, your firm transportation continues to be, you know, 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 you're sold out or, you know, given the plans that y'all are sort of putting out there, is there anything like that that gives you any concern?
Yeah, good question. 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. Even though we have let go some FT 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 a NYMEX-based market there for us. Feel good about where we stand with the FT and also with liquids takeaway.
Very good. Thanks for the time, Paul.
Thank you, Neal.
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, you know, when you think the management team would be comfortable perhaps unveiling your capital return framework and maybe the path towards, you know, when you think you could be in the market, buying back stock if the strip holds. I do. It does appear that you are gonna try to pay down some additional debt next year beyond the $2 billion target.
Yeah. All that occurs in the first quarter of 2022. Arun, we're with the strip where it is today, we'll 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 of capital, and like you mentioned, in addition, continue to pay down debt.
Fair enough. In the slide deck, you guys have highlighted how your, you know, your production costs, you know, trend down from, you know, the range is $2.33-$2.40 this year. Longer term, is that a long-term average of the $2.14-$2.19? 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 kind of tracking the backwardated strip pricing on the cost. The only real variable there is the taxes, the ad valorem and severance taxes, and that's just the commodity price coming off over that time.
Got it. The implication is the longer term average there is 214-219 per Mcfe. Is that right?
Yeah. Yeah. Also, you know, like that chart shows on the firm transport, the unutilized firm transport continues to decline on an annual basis.
Great. I'll turn it over. Thanks.
Yep. 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.
Sure.
I wanted to get your preliminary thoughts around spending and also on cost inflation next year. Any initial read around inflation pressures you're seeing on your Appalachia drilling and completion activities? Also, as you think about next year and your drilling JV with Quantum and elections around that, should we assume that you'll probably elect to go towards the lower end of the range, the 15%-20% range, given the strength in commodity prices?
Yeah, good question. You know, the maintenance capital is around $600 million for this year. There's obviously been some inflationary pressures. We're kind of 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. It's kind of looking $600 million+, from a maintenance capital perspective in 2022. Then, like you mentioned, we do have the election of having Quantum, if they choose to participate, either at a 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 would most likely elect to have them be at the 15%. That would add a little bit of capital as well.
You know, $600 million-plus still going to determine it, and we'll have to assess the inflationary pressures over the next couple of months for our final budget coming out at beginning of the year.
Great. Thank you.
Yep. 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 wanted to follow up on the in-basin sands, just the impact on 2022. Is this all locally sourced sand from your Beaver projects? I guess, is it going to be covering the totality of all of your frack jobs next year?
Yeah. This is Paul, David. Yeah, this is local sand. We've been developing it for a while, talking about it for probably the last year. Yes, it will cover virtually the totality of our program. There may be some supplemental Northern White on an as-needed basis, but most likely it's going to be our local sand.
How much can that save?
Yeah, the math really comes out to we're gonna be around $20 a ton with this local sand versus $55 prior, so it's about a $35 a ton savings. We do 2,000 tons a well, so it's about $600,000-$700,000 a well. A lot of savings that come from it, and that's why we think we can offset some of those inflationary pressures going into 2022.
Yep. No, that's pretty clear that certainly would offset any. My next question is just on the propane markets and just Antero's base program. Going forward, obviously you can highlight a compelling case for being in maintenance mode. It seems like with the fractionation capacity built out so far, particularly in the Marcellus and, you know, the Sherwood facilities, et cetera. 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?
You know, we have plenty of fractionation capacity, processing capacity as well, David. Between Sherwood and Smithburg, which is our latest plant in that complex.
We have room for more processing, but we fractionate both at Hopedale, generally. We can also frack at Majorsville or Houston, but I think there's plenty of capacity at Hopedale. I don't think we have any physical constraints. We do have the inventory to continue developing high BTU gas that would have plenty of propane in it. It's just maintaining our discipline and overall keeping the damper on growth. I certainly like the economics quite a bit, but no plan to accelerate.
Sure. Just the last one for me. You know, you guys highlighted at the beginning, I certainly remember you being 5 years hedged back in 2013, way above the strip. Obviously, today the business is different. There is a net requirement. 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 a shortage, in the coming years, especially with some of the dehy plants coming online.
Are you getting inbounds, or is there an interest on your side of signing either offtake agreements or demand contracts that would sort of have a floor in place where you would be providing supply surety?
Yeah, we're not tempted. You know, we learned a little lesson last spring. We've told this story before, but we stepped in and hedged some propane butane last spring. We felt good about the fundamentals of propane butane, but LPG across the world. We just had a little bit of a, "Is this just a wonderful dream, and we're gonna wake up, and it's all gonna go away?" We did hedge LPG propane butane for the second and third quarters, and it was into a backwardated curve.
Sure enough, you know, we ended up what we projected, which was a lower price because of the backwardation from last spring. Today, fast-forward, the curve is still backwardated.
We believe pretty strongly that it's best to live on the front of the curve. 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's a strong appetite, but we're happy with the situation we have for export at Marcus Hook, at the dock, that we get paid, lock in our ARB right then and there, and just keep selling on the front physically, and really no temptation to step back into the hedging market and hedge into that backwardated curve.
Thank you, guys. Appreciate the answers.
Yeah. Thanks.
The next question is from Jeoffrey Lambujon of Tudor, Pickering, Holt & Co. 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, you know, quickly approach your balance sheet objectives, as you highlighted. If things hold here as far as strip goes and free cash flow is not too far off from $2 billion next year, you know, the debt targets reach, and you can still delever further while buying into free cash flow at a nice discount to intrinsic value. I just—I wanna get your thoughts on if it'd be reasonable to think about something in the 50% range as the possible mix of free cash that could go to buybacks next year.
Yeah. We haven't done the math on that yet. You know, just looking at our debt, our ability to pay down debt, 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. Anything outside of that, it's probably gonna be open market repurchases, which is, you know, probably difficult from a liquidity ability to get any sort of size in, from that. You know, once you get to the $1.5 billion level of debt, it'll be slow going on reducing debt much further after that.
When you do get below that, I think there'd probably be a little bit more allocated to share buybacks or some form of return of capital than prior to that when we can absolutely call in all that debt.
Great. That's very helpful. Secondly, just wanted to get how you're thinking about the GP&T and production ad valorem taxes 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 it runs like 4.7% or 4.8%. Every time commodity prices go up, the realized price we have in your models have 4.8% as the tax portion of that. The actual gathering processing transport should be relatively flat, so there shouldn't be any increase from that. It's really just taxes.
We're in full optimizing. All of our gas is going to the Gulf Coast right now or 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.
All right. Great. Thank you.
The next question is from Subash Chandra of The Benchmark Company. Please proceed with your question.
Yeah. Hey, Paul. How are you thinking about-
Hi, Subash.
Hi, good morning. How are you thinking about the Utica these days? You know, that's a you know nice detail there on premium locations. The Utica certainly can be you know valuable to someone else as much or more than for you know your portfolio and your five-year activity levels. I mean, I think you do have some activity coming back in that five-year scenario. How do you think about that?
Yeah, we think about it. You know, we've moved a rig over to the Utica this year, and it's the first time since 2018. You know, because we've come a long way on our drilling techniques in general, it's gone well over in the Utica. We still have some ahead of us, but the economics are just that much better, probably both geologically and in drilling, that 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, right. 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.
That's where we'll be focusing our capital.
Okay. You know, this question might have been asked a million different ways, you probably answered a million different ways. I'm just gonna try it again. You know, only because one of your peers, competitors yesterday sort of suggested that, you know, post 2022, they might step in to grow in order to replace fading inventory in the basin.
Right.
You know, of course, you're probably in equally or better position with regards to inventory. What are the conditions for growth for you?
You know, 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've really just stuck to our knitting and really are quite determined after what we and really the rest of industry has gone through, but especially independents with too much debt. We just before we can really lay any plans for growth, we just wanna reduce the debt, get down to the.
You know, we'll pass through that $2.0 billion of absolute debt in the first quarter, as Mike elaborated on. We'll see where we go after there, but it just feels really good to de-lever so dramatically. So I think you'll see that more.
We'll try and be creative with the different ways that we can buy back debt or whatever to reduce leverage that much more. Really, we're staying away from growing. We're happy with where we are right now and just focusing on that free cash flow. Haven't been tempted and just wanna see delevering and getting the balance sheet in pristine shape.
Excellent, guys. Thank you.
Thank you.
The next question is from Gregg Brody of Bank of America. Please proceed with your question.
Hey, guys. I appreciate all the comments 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 attain investment grade. Was that intentional? Was that something that you wanted in there because there is a target to get to investment grade?
I don't know if it's a target, but it was intentional, Greg. 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 say that's unprecedented how fast they've gone. Our response is always, I mean, you gotta look at where we are. You know, you should rate us based on where we are, and we do map to investment grade today.
I would expect further, you know, improvements in the ratings going forward if this free cash flow generation occurs from the strip prices and we pay down the debt. We'll definitely be thinking we should be investment grade, and that's why we designed the credit facility that way.
They usually wanna hear that you wanna be investment grade to get there. Your comments are all here.
We express that quite often, Greg. Quite frequently. Their response is it just takes time.
Got it. That's helpful. Then last question for you. That $6 billion free cash flow number you had out there, is there an expectation for taxes in there? If so, how are you thinking about that?
Yeah, I mean, it's actually over, I think, the next 4 years, and that's inside our tax horizon. We have significant NOLs, and with our development program, our capital right now generating further, you know, deductions. We're not a cash taxpayer in that 4-year timeframe. That $6 billion gets you probably to the point where you start paying some tax, but prior to that, we're not a taxpayer.
Great. I just have to say what a difference a year makes. It's nice talking to you guys.
Yeah, I agree, Greg.
True.
Yes.
There are no additional questions at this time. I'd like to turn the call back over to Brendan Krueger for closing remarks.
Great. Thanks. Yeah, 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.