Antero Resources Corporation (AR) Q4 2021 Earnings Report, Transcript and Summary

Greetings, and welcome to the Antero Resources Fourth Quarter 2021 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Brendan Krueger, CFO of Midstream, Vice President of Finance and Treasurer. Please proceed.

Good morning. Thank you for joining us for Antero's Fourth 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 3 titled 2022 activity. In 2022, we are targeting a maintenance capital plan with average volumes of 3.2 to 3.3 Bcf equivalent per day. We expect production to increase through the year as completion activity accelerates in the third and fourth quarters. The chart on the top of the slide highlights that our completion schedule is weighted to the second half of the year, which will drive volume growth during that period and into 2023. The chart on the bottom of the slide illustrates our production cadence. We expect first half 2022 production to average 3.1 to 3.2 Bcf equivalent per day, increasing to 3.3 to 3.4 Bcf equivalent per day in the second half of the year. This second half growth will result in 4% to 5% exit-to-exit growth in 2022 versus 2021. Turning to Slide 4, let's discuss our 2022 capital budget. This slide depicts a waterfall chart bridging our 2021 capital program with our 2022 budget. Our drilling and completion capital budget of $675 million to $700 million reflects an impact of approximately 5% from service cost inflation. This inflation includes the net benefit of expected sand savings from our regional sand mine. Our sand mine is expected to reduce well cost by $400,000 to $500,000 per well, further improving the capital efficiencies of our operations. Entering this year, we also elected to increase our working interest in our drilling partnership by 5% due to the strong commodity price backdrop. This higher working interest results in $35 million to $40 million of incremental D&C investment during the year. This additional investment is highly accretive to cash flow given the attractive rates of return that our liquids-rich wells are generating today. Further, this higher working interest will drive low single-digit production growth in 2023 as compared to second half 2022 volumes. Now let's turn to Slide 5 titled Peer Leading Premium Core Drilling Inventory. We have seen an increase in both public and private acquisitions over the last couple of years. During this time, we've maintained our focus on our core acreage footprint. As opposed to larger transactions that can dilute your equity result in a large overhang and lever your balance sheet, we have preferred to pick up smaller, more tailored acreage packages within our core liquids-rich position in West Virginia. As an example, in the fourth quarter, we spent $30 million on land, a portion of which was used to add 20 additional drilling locations at less than $1 million per location. This approach is much more cost effective relative to many of the recent larger M&A transactions that averaged $1.5 to $2 million per location. Making this even more attractive, these locations are in the core areas we're focused on today, providing further liquids development runway and improving our overall operating efficiencies. The map on this slide provides a summary of the core inventory remaining in the Southwestern part of the Appalachian Basin as we see it. We recently completed our annual technical review of peer acreage positions, undrilled acreage and location potential. We also analyzed BTU, well performance and EURs. As you may recall, we provided an update on our views at the beginning of each year. Based on these results, we bifurcated the core of the Southwest Marcellus and Ohio Utica into premium and Tier 2 subareas. We've identified approximately 4,700 premium, undeveloped locations for the industry, not just ourselves but for the industry in the Southwest Marcellus which are located within the red outlines on the map. Of that, we estimate Antero holds 1,550 of those premium locations or 33% of the total, which includes more than 925 liquids-rich locations. The decrease in Antero's drilling locations relative to last year's analysis reflects an optimization of our development program that increases average lateral length by 1,000 feet to over 13,000 feet of lateral length per well. In the Ohio Utica, we estimate roughly 800 premium, undeveloped locations for the industry, of which Antero holds 180 or 23% of the total. Beyond that, we estimate that there are 1,600 Tier 2 locations remaining, which you can see are located within the blue lines. You can see that much of the acreage in Southwest Appalachia is covered up with existing Marcellus and Utica producing horizontal wells, which are the red lines on the map. However, based on our maintenance level development plan, which assumes 60 to 65 net 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. Ultimately, we believe inventory fatigue and the limited number of premium drilling locations will be a critical distinction between the haves and the have-nots across Appalachian producers. We also believe this will be a critical driver for commodity prices in the coming years as a shift to Tier 2 acreage will continue to require higher commodity prices to incentivize the drilling required to hold supply levels flat. Against this backdrop, we believe Antero is uniquely positioned to prosper over both the short- and long-term time horizons given our deep core inventory position. With that, I'll turn it over to our Vice President of Liquids Marketing & Transportation, Dave Cannelongo for his comments. Dave?

Thanks, Paul. My comments today will focus on our current view of the liquids markets, more important than ever given we are fully unhedged on all oil and NGL production as of the start of 2022. The past few months, we have seen crude prices reaching their highest levels since 2014, with Brent and WTI touching these 7-year highs supported by global supply concerns and geopolitical tensions across several key regions. At the same time, demand has surprised to the upside and market demand forecasts have been revised upward, primarily due to the more muted impact of Omicron on global consumption compared to previous COVID variants. NGL prices have also benefited in the current bullish price environment. For Antero, we are currently buying for another quarterly C3+ price record in the first quarter of 2022. And at current strip pricing, we are on pace for our highest annual C3+ pricing. Slide 6 titled NGL Price Strength illustrates how NGL prices relative to WTI have tightened in recent years. This is due to increased U.S. export capacity that has resulted in NGL's pricing as global commodities as opposed to pricing being predicated on domestic drivers in prior years. Also contributing to higher prices relative to WTI is continued global demand growth and relative limited supply growth due to the barriers to entry that exist in NGL production that starts with having access to high-quality, rich gas acreage, priority processing and fractionation capacity and takeaway to markets where demand for those products is robust. We believe that these factors have created a market shift for NGL prices that should remain over 60% of WTI going forward. As a reminder, Antero has been fully unhedged on its propane since October 1 of last year, and our remaining butanes and pentanes hedges expired at the end of 2021, meaning that Antero has been completely unhedged on all NGL and oil volumes since January 1, 2022. 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. Turning to Slide 7. Let's discuss the propane market in more detail. Although propane prices have retreated from the levels seen early in the fourth quarter of 2021, they have remained at around 60% of WTI since the beginning of 2022, even as crude prices have escalated. Temperatures thus far this winter have been relatively mild in the U.S. and particularly in Asia, resulting in a more moderated withdrawal season. Additionally, U.S. buyers have shown a willingness to bid up Mont Belvieu pricing in order to keep barrels in the domestic market as needed, resulting in several occasions this season where the arb is closed causing lower export levels and sometimes incentivizing midstream companies to buy back export cargoes, keeping the local market adequately supplied. These factors have prevented a propane price blowout despite continued type fundamentals. Even with a mild winter and lower exports, U.S. propane inventories are still sitting 15% below last year's levels and days of supply is trending around 20% below the 5-year average for this point in the winter season. As we look towards the coming quarters, it appears likely that we will see some degree of liquid supply growth as drillers take advantage of the high commodity price environment, particularly in the Permian Basin. However, outside of the U.S., geopolitical challenges across multiple regions are creating dynamic supply risks and have the potential to offset the impact of growing U.S. supply. On the demand side, we have recently seen several nontraditional factors impacting demand in the Far East, including power rationing, emissions controls and 0 tolerance COVID policies which include lockdowns in large cities and restrictions on the movement of citizens. These factors have dampened Asian demand for liquids in recent months, but their impact is likely temporary. In the near to medium term, we see general upside for global demand as COVID moves from pandemic to endemic and supply chain issues are gradually resolved. As we have discussed previously, we anticipate a nearly 550,000 barrel per day increase in propane-related pet chem demand in China from 2021 to 2023 and over 110,000 barrels per day of European and North American PDH growth during that same period. Finally, we would like to highlight that we anticipate 2022 will be transformative for the Marcellus ethane market with the new Shell worldscale steam cracker in Pennsylvania and other new demand projects coming online dramatically increasing regional feedstock demand. Antero is an anchor supplier to the new Shell cracker with 30,000 barrels per day slated to feed the new facility. Overall, we anticipate nearly doubling our recovered ethane volumes from current levels by this time next year. This increase in ethane recovery will immediately be economically accretive to Antero and our ethane portfolio will increasingly shift towards gas-linked pricing, as we have mentioned in prior quarters. With that, I will turn it over to Mike.

Thanks, Dave. I'd like to start on Slide 8, highlighting Antero's financial strength. During the fourth quarter, we generated $237 million of free cash flow, which we used to reduce our absolute debt. Our total debt of $2.1 billion at the end of the year represents an $876 million decrease from year-end 2020 and $1.6 billion decrease over the past 2 years. The top right quadrant of the slide illustrates the LTM EBITDAX improvement from just over $1 billion in 2020 to over $1.6 billion for 2021. Total debt reduction, combined with an improvement in LTM EBITDAX decreased leverage to 1.3x at the end of the year, down significantly from year-end 2020 and at the lowest level for any natural gas peer. Now let's turn to Slide 9, titled Strong and Sustainable Balance Sheet. In January, we called the remaining $585 million of 2025 senior notes, which will be funded through free cash flow by the second quarter of 2022. This redemption will reduce our annual interest expense by $30 million or $0.03 per Mcfe. Importantly, this balance sheet momentum has positioned us to begin returning capital to our shareholders. As you can see on this slide, the remaining maturities are not callable until 2024, which means once the balance of the '25 notes are paid off, free cash flow be increasingly directed toward capital returns. Our 2022 development plan is expected to generate $1.5 billion to $1.7 billion in free cash flow with a similar level projected in 2023 based on current commodity prices. This substantial free cash flow enables us to begin returning capital to our shareholders while also continuing to pay down debt. We are currently the least hedged in our company history with approximately 50% of our expected natural gas production hedged in '22, and we have no liquids hedges in place. We are also essentially unhedged in 2023 and beyond on all commodities. Further, our industry-leading firm transportation portfolio allows us to sell 100% of our natural gas out of basin. This generates best-in-class natural gas realizations and provides confidence that we can deliver on our free cash flow and production guidance. This is an area of our business we believe will continue to prove valuable with the delay in MVP and likely limited infrastructure being built in Appalachia going forward. Now let's discuss in more detail the return to capital framework we just announced. Starting with Slide 10, titled Strongest Balance Sheet in Appalachia Supports Shareholder Returns. During this first quarter of '22, we achieved our debt target of below $2 billion, which was the threshold we set internally before initiating a shareholder return program. Going forward, we intend to initially return 25% to 50% of free cash flow to our shareholders. This significant cash return is supported by our peer-leading net debt level as shown in the chart at the top of the slide. The chart on the bottom of the slide compares our leverage profile for our peer group as well as the S&P 500 average and is in line with major integrated companies. Slide 11 highlights why share buybacks are the most attractive form of capital return for Antero today. On the left hand of the slide, you can see we have the highest free cash flow yield whether you look at it relative to market cap or enterprise value. We believe the more appropriate metric is your free cash flow to enterprise value as it reflects your debt levels and is more sustainable through commodity cycles. On this basis, we lead our peer group in 2022 with a 16% yield. The chart on the top right-hand side of the slide highlights our discounted trading multiple. Based on consensus estimates, AR's stock is valued at just 3.7x enterprise value to EBITDAX, sharply below the peer average. An important note, these estimates are based on consensus numbers. If we looked at the guidance provided today, AR trades at a 25% free cash flow yield on market cap and trades at approximately 3.5x enterprise value to EBITDAX. And lastly, the chart on the bottom right-hand side of the slide illustrates that the capital return program that we announced today positions Antero as a leader in cash returns at 10% of our market cap, assuming the midpoint of our capital return program. The combination of highest free cash flow yield and lowest trading multiple makes share buybacks the most accretive use of free cash flow at the onset of our capital return program. We're also excited about our continued ESG progress as detailed on Slide 12. Last quarter, we highlighted an important ratings upgrade at MSCI and the publication of our annual ESG report. Today, we are excited to announce that we received Responsibly Sourced Gas Certification through a pilot with Project Canary. We view this success as an important first step ahead of expanding the certification across our asset base. In addition, driven by the success of our emissions reduction program to date, we have expanded our 2025 net zero target to include Scope 2 emissions. We are very proud of these recent accomplishments and believe that through our ambitious targets, we can positively impact global energy poverty with a reliable, affordable and responsibly produced natural gas and liquids while also reducing overall global emissions by replacing more carbon-intensive fuels with clean U.S. natural gas. To summarize, the impressive operating and financial momentum continues for Antero. Slide 3 titled Key Investment Highlights summarizes the position and strength we're in today. We have significant scale as the fifth largest natural gas producer and the second largest NGL producer in the U.S. providing best-in-class exposure to relatively unhedged, healthy commodity prices. We have extensive core inventory with nearly 1,000 premium liquids locations remaining. Since the beginning of our deleveraging program, we reduced debt by $1.6 billion in just 2 years, and we expect to further reduce the absolute debt in 2022 with leverage well below 1x. These strengths truly differentiate Antero, and we expect this to significantly benefit the shareholders moving forward. Lastly, if we assume today's strip prices, which includes a backwardated NGL and natural gas strip, we are forecasting substantial free cash flow generation in excess of $6 billion through 2026 considered as free cash flow outlook against our enterprise value of $8 billion. With the lowest leverage and highest free cash flow yield of our peer group and a trading multiple of approximately 3.5x, we believe Antero is uniquely positioned to deliver attractive multiple expansion and value to our shareholders. With that, I will now turn the call over to the operator for questions.

[Operator Instructions]. Our first question is from Arun Jayaram with JPMorgan.

Perhaps for Paul or Mike, I wanted to ask around -- the intentions around cash return in 2022, kind of if the strip holds. Mike, on Slide 11, you're showing the midpoint of the 25% to 50% free cash flow range, about 10% return to cash yield. So the question from the buy side this morning is how should we think about what would drive you towards the low end of the 25% to 50% or the upper end of that with, again, very limited debt reduction options outside of the 2025s which you outlined.

Right. So the midpoint of our free cash flow guidance is $1.6 billion. So $600 million of that is to call the 2025 notes. So in addition to that, we hope that we have the ability to repurchase on the open market or through some other efficient debt transaction, a couple of hundred million plus of further debt reduction. And so if you think about that, that gets you up to $800 billion, $900 billion level. Above and beyond that, we'll probably be focused on share buybacks. So if commodity prices do hold, I think you'd be trend more towards the upper end of that range. And so we just wanted to provide flexibility around that.

Great. And just as my follow-up, you've outlined $6 billion of plus in free cash flow from 2022 to 2026. And I was wondering, the 25% to 50% range, how do you see that evolving over time? And maybe just give us a sense of how that return to capital could evolve over the time as well as thoughts on looking at a dividend for Antero in the future?

Yes. So over time, obviously, it would trend higher than the 25% to 50% because you run out of debt to pay down. $6 billion out of total $8 billion, you only have $2 billion of debt to start with. So Obviously, that would suggest a lot more going return on capital than paying down debt. And I think a dividend would be something we would consider, obviously, at the start this program is focused on share buybacks just because of the discount we trade at and those opportunities to capture 25% free cash flow yields and 3.5x debt-to-EBITDA type or enterprise value [indiscernible] type metrics. So we're focused on free cash flow there. I mean on share buybacks there. But then after that, we'll reevaluate once this program is complete and [indiscernible] could be a dividend at that time. But that's definitely focused on share buybacks this year.

[Operator Instructions]. Our next question is from Gregg Brody with Bank of America.

Just a follow-up on that. You talked about reducing debt further. Is there a debt level you're targeting after you get past this year? Or are you there once you...

No, it would just be opportunistically, Greg. I mean, after this year, I mean, you'd be down to $1.3 billion, $1.2 billion of debt, which is basically half time -- 0.5 EBITDA turn. So I would just see if there's further opportunities, we do have some debt that we'd like to pay off at a higher coupon like the 2026 8.38%, and then we've got 7.58% '29. So that's efficient to buy those type of coupons in, but no real target after that. We've just hit our target of $2 billion. And with the call to '25 notes it will be at $1.5 billion. So those are targets well below what we thought possible this time last year.

Yes, I'm not going [indiscernible]. I just wondering [indiscernible]. So that's...

[indiscernible] Certainly an opportunistic, can we efficiently get to that end. And if we can efficiently get it in, then we will.

And great job there. Look, you spent a lot of time talking about your inventory and how you've been focused on adding it with small bolt-ons of acreage. So I'm just going to ask this question thinking you may have answered this already. But just to be clear, are you thinking about outside of basin opportunities? Is that something that would make sense to you? Or is it -- or just the core inventories there and it's easier just to stay in your sandbox?

Greg, it's Paul. Yes, it's the ladder that stay inside our sandbox, we just have such a wealth of quality inventory. We monitor all basins. We understand Permian, Haynesville, Bakken, you name it, just because we do such things to appraise where the supply could come from in future years. But we are really focused on our corner of the world, and there's no need to go elsewhere. We really like our position, both quality of the inventory, the liquids-rich nature of it, the controlling of processing, fractionation, takeaway to premium markets. So we like where we are and don't see ourselves leaving the basin going outside of it.

And last one for you. Are you able to give some framework on how to think about cash taxes going forward?

Yes. And that $6 billion, that's net of cash taxes that we see in the 5-year period. For the first 3 years, there aren't any, Gregg. Just to remind you, we have a $2.3 billion approximate NOL position. So that serves us well over the next 3 years. But in year 4 and 5, you do start having a little bit of cash taxes.

That's it for me, guys. And just congrats on getting [indiscernible]. It's been very impressive.

Our next question is from Neal Dingmann with Truist Securities.

First question, just on takeaway. I'm just wondering -- do you all anticipate additional export opportunities? I'm just wondering where maybe you see the best takeaway opportunities to receive stronger prices.

Well, certainly, there's more and more LNG in the Gulf that is coming online. And so we already sell to Cheniere at Sabine, [indiscernible] at Freeport. We are now establishing a relationship and selling to Venture Global at Calcasieu. And we have 2.2 Bcf a day of firm transport that goes to that LNG fairway. So more opportunities. We do see prices being bid up at places like ANR Southeast Head station to be a premium to Henry Hub. So we're delivering to the right places and establishing relationships with a number of the LNG facilities and liquefiers. So we do see growth there, and we'll continue to move our gas to the most attractive buyers in the [indiscernible] see it growing. I'm sure you're following it as well. And there's a lot of -- because of prices across the world, there's a lot of impetus inertia for more facilities going FID.

Yes. Absolutely agreed. And then my second [indiscernible]. I know your prepared remarks I mentioned about Mike was talking about inflation being partially offset by the sand savings. I'm just wondering in your basin. Are you seeing kind of the cost inflation that the Permian and other areas are? Or maybe you could just talk about that? And are there sort of contracts and things you're doing to help even offset some of that?

It definitely will, of course, we shop around, but we have some very reliable suppliers in drilling and in completions. So there is definitely pressure both on drilling, completions and then steal as many people are noting. So tubulars, et cetera, are going up, but we lock them in as we can in advance to take advantage of any pricing discounts, which we've done. So definitely pressure on the hard asset side and diesel and so on. So we're pleased with our local sand mine and being able to offset some of those pressures upward by moving it down a little bit. But I think we're seeing probably about what others are seeing, although I think you can see more and more reports of sand shortages in other basins and prices have gone up quite a bit. So that makes our local sand that much more valuable. But we are seeing pressures just like much of the industry.

Our next question is from Holly Stewart with Scotia Howard Weil.

Maybe Paul, I'll kick one to you first, just on the hedging strategy. I know for a couple of quarters now, you guys have certainly been talking about your updated hedging philosophy. And then I think you mentioned kind of 2023 being essentially unhedged on all commodities here now. So curious if you can kind of talk about bridging the gap, you've put out the guidance here of 25% to 50% of your free cash flow going to shareholders. How do you balance those 2 concepts here going forward?

Yes. Well, Yes. We've -- I think we've read the market right, and we backed off on natural gas hedging. So we haven't put in natural gas hedges for, I think, 22 months, something like that, dating back to just as we're entering the spring of 2020. And so those were the last hedges we put in, as we said. As discussed on this call, we're down to just our natural gas hedges for half of our production with no intention of adding anymore and then completely unhedged, as Dave Cannelongo was just saying on the liquid side. But we have the balance sheet now and a lot of opportunities to really pay down debt more quickly if we're just willing to stay on the front of the curve. We don't want to hedge into a backwardated curve. So it's working out well. No plan to hedge and live on the front and really don't step into backwardated curves. As you know, it's more moderate on the natural gas side, but pretty steep on the NGL side. So no need to do that with the dynamics that we've outlined here. So no hedging in the foreseeable future, and I think that, that gives us a stronger and stronger balance sheet as we continue to be right by laying back on the front one. And so that's our plan.

Okay. Great. And then maybe, Mike, 1 for you, just on the expense guidance. Can you maybe just help us understand some of the components the cash production expense. I mean if you -- I think if you look at it relative to the fourth quarter, it looks like things come down pretty nicely over the course of 2022. So just trying to and maybe even thinking about kind of total production expense, just trying to think about some of those components as it relates to the 4Q actuals versus the guide.

Yes, compared to the 4Q guide, it's really just the decrease in commodity prices. The averages for '22 are well below what we realized in the fourth quarter. So it's just production and [indiscernible] taxes. That's really the only floating component. There's a little bit of fuel as well and fuel comes off to just because, again, it's commodity-based, but everything else is fixed, Holly.

Okay. So anything -- I know you guys had some FT that rolled off maybe this year and next year, whereas you think about that...

Yes, that was in the marketing expense, so marketing expense is down year-over-year. We were just talking to the cash production expense there. But we definitely had that REX roll off October 1, and that's about $40 million a year of less marketing expense. So we'll realize the full benefit of that in '22.

Okay. So as we think about that GP&T line...

The GP&T line does not have marketing expense in it. The marketing expense is a different line item.

Sure. I understand that. Just thinking about that component of the total cash production expense guide relative to last year?

Yes. I mean it's relatively flat.

Our next question is from Umang Choudhary with Goldman Sachs.

My first question was on share repurchase. Given you're planning to pay down $600 million in debt in March, can you talk to the cadence of free cash flow allocation towards share repurchase over the course of 2022?

Yes, we'll start to share repurchase this Monday. So we're starting as soon as we can. We've reached that $2 billion target that we mentioned. We are essentially at it at the end of January. So got there, and so that's why we're initiating right now, and we'll start it in the first quarter. We have the luxury of being able to buy back shares and pay down that at the same time because the cash flow generation pretty explosive at these commodity prices. So that's what we'll do. If you think about the $1.6 billion, and that's divided by 12 months, it's about $130 million a month of free cash flow. You didn't have anything drawn on the credit facility at year-end, $130 million a month. So these are all just round numbers, but that allows you to pay off that $600 million in the 5-month period and still have some share buyback. So that's what we plan to do.

Got it. That's helpful. And then turning to a long-term question, more for 2023 question. Part of the increased spending in 2022 was because you're electing to take higher working interest in your wells. How does that impact your 2023 production outlook and spending outlook. I was looking through your multiyear guidance. It seems like your production outlook is higher on average between 2020 to 2026.

Yes, it does go up a little bit. It's about 1% to 2%, just that election of going from the drilling JV partner participating in a 20% to 15%. It's really just '23. The drilling JV is set up for when the wells are spud. So that only applies to the well spud in '22. So there's about a 9-month lag time between well spud and first production. So really aren't going to see much of that in 2022, but definitely we'll have 1% to 2% growth because of it in '23.

Our next question is from Subash Chandra with Benchmark.

Just a quick clarification. Mike, could you say the buyback program began on Monday or begins on Monday.

Begins -- we're in a blackout window. So you have to wait till 48 hours after your earnings before you can start anything. So that's why it's Monday.

Yes, This coming Monday.

This coming Monday. You can't enter a buyback program 3 days before your earnings.

Yes. Well, that's what I was curious about. Is there like a...

That is Tuesday. President's day is Monday. So Tuesday, I was too ambitious.

Okay. I'll make that adjustment to my calendar. But is there a 10b-15 or something that can get you through the blackout periods?

Yes. Before -- I mean we are in a blackout period when we achieve that $2 billion at the end of January. So there's nothing we can do there. You have -- when you put it in a 10b5-1 plan, you have to be in an open window. And so that's what we've done in the past and probably our intention going forward is you put in a 10b5-1 plan. So it goes through any blackout windows and then you opportunistically repurchase as well if you see opportunities.

Okay. Great. The second question is, so these lateral lengths are getting quite a bit longer 2022 versus '21. How do you think about EURs per foot? Will you maintain them proportionately? Or what do you see happening there?

Yes, that's a good question, but the answer is, yes, we've not seen any tailing off in EURs per 1,000 feet of lateral as we go longer and longer. I think -- I know our longest lateral is 2 feet short of 20,000 feet, 19,998. But we are looking at our profiles all the time, and we don't see any diminishing of production as you get out to the far end and we look at that all the time. We're able to break down the [indiscernible] toe of the lateral as much as 20,000 feet, just need a little more pumping capacity on the surface, but haven't had a problem breaking it down and so we don't see a limit yet. Certainly, 20,000-plus is -- you have to take that seriously. But we think we can reach at least that long. And so we're getting longer all the time. On the books, we've got quite a few 15,000 to 18,000 footers that are coming up over the next couple of years.

Got it. And then I think in 4Q, you had some Utica dry gas completions. Some of this could just be a catch-up work or something. Any change in sort of ambitions there economics, anything like that to want to recommit to the basin?

No, we're good as we are. We like the Utica, but the Marcellus, there's more operating efficiencies there. We still have, as you know, the completions for later this year in the Utica. We selected particularly rich gas with free liquids over in the Utica. And so that's what we'll be bringing on later this year. It's being completed right now. So pretty selective in what we do. There's big dry gas volumes over in the Utica as well. But our economics are just stronger over in the Marcellus. So that's where virtually all of our budget will be going out the next couple of years.

Yes. And when you look at it, Subash, over the next 5 years, it's generally maybe a paddy or nut shift to keep the REX FT full, the 400 million a day full. So we contemplate that when we make our investment decisions wanting to keep the transport full.

Okay. Got it. Great work, guys.

Our next question is from Nitin Kumar with Wells Fargo.

I want to start with we noticed the $0.10 to $0.15 premium to Henry Hub that you guided for -- or $0.15 to $0.25 premium and all that's related to your FD. Could you remind us -- I know you had some coming off this year. But what is the schedule for that FT that you have? And what are your plans given some of the recent developments on MVP and other basin outlets?

Yes. REX came off, but what's coming off in the next couple of years and this is just regional. There's no long-haul. So we still have, I guess, 2/3 going to the Gulf, 20% going to the Midwest and then some going over to Cove Point [indiscernible]. So we still have the premium transport and getting our gas to the premium basin. So no change there.

Okay. Great. And then I guess the other question is, congrats on getting the project Canary certification, but I'm curious -- are you seeing a premium pricing? Some of your peers have talked about premium pricing for certified gas. But I'm just wondering if you can give us some color on whether that's an economic opportunity in addition to being a license to offer it.

Yes. No, we don't view it as an economic opportunity. We haven't seen anything. We just think of it as a license to operate, like you said, just have a sustainable business. It's something that's required. So that's how we view it.

Ladies and gentlemen, we have reached the end of the question-and-answer session, and I would like to turn the call back over to Brendan Kruger for closing remarks.

Yes. Thank you for joining us on today's call. Please follow up with any questions. We're available. Thank you.

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