ANTERO RESOURCES Corp Q2 FY2021 Earnings Call

Greetings and welcome to Antero Resources Second Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. The question-and-answer session will follow the formal presentation. Please note this conference is being recorded. I'll now turn the conference over to host Brendan Krueger, Vice President of Finance and Treasurer of Antero Resources. Thank you. You may begin.

Thank you, operator. Thank you for joining us for Antero's second 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'd also like to direct you to the home page 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'd 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 and Transportation. I will now turn the call over to Paul.

Thanks, Brendan. Let's begin with slide number three, titled best exposure to rising commodity prices. During the second quarter, our business models delivered EBITDAX of $319 million and free cash flow of $105 million. Our financial results highlight the significant leverage we have to rising natural gas and C3+ NGL prices. During the second quarter, our C3+ NGL price averaged $40.32 per barrel, a 159% increase from the year ago period. Our firm transportation portfolio led to an unhedged realized natural gas price at an $0.18 per MCF premium to NYMEX. Further, these strong realizations led to an increase in guidance for our realized price premium relative to NYMEX. Despite widening differentials in the Appalachian basin, we now expect to realize a premium to NYMEX in the range of $0.15 to $0.25 per MCF for the full year 2021, which is $0.05 higher than our previous guidance. Our firm transportation portfolio not only provides flow assurance to NYMEX-based markets during periods of pipeline capacity constraints but delivers premium realized prices. Looking ahead, we are currently the least hedged in our company history on the natural gas side entering 2022 and have very little NGLs hedged and no propane after October 1 of this year, 2021. This is a testament to our commodity fundamentals teams that have remained bullish on the outlook for both natural gas and NGLs heading into this winter. The combination of our FT portfolio and our low hedge profile makes Antero the most efficient way to gain direct exposure to the NYMEX and mass value prices. Now let's turn to slide number four, which illustrates the benefits of Antero's firm transportation portfolio. As illustrated on the chart, our FT portfolio has significantly reduced realized pricing volatility, especially when compared to Appalachian basis differentials. During the second quarter, this competitive advantage resulted in price realizations that were $0.90 per MCF better than in-basin Appalachian pricing, which was $0.72 per MMBtu back of NYMEX. This premium pricing and liquids-rich focus has allowed Antero to consistently generate peer-leading EBITDAX margins and capture upside from both natural gas and NGL prices. Importantly, this basis volatility over the last year has been occurring in an overall no growth environment in Appalachia, and we see the potential for wide basis to continue into the future. Slide number five details the historical and future Appalachian basis differentials in green compared to the net gas production, which is shown in red, versus takeaway capacity shown in green. As you can see, when overall production exceeds the takeaway capacity, the basis blows out. Looking at last year, you see circled in yellow, that basis has been very volatile, even in this no growth environment. As depicted on the right-hand side of the page, futures prices continue to widen due to tight takeaway capacity and the uncertainty of future projects like MVP. What we expect to see is price-related shut-ins or realized prices at a wide discount to NYMEX by our Appalachian peers who are short, firm transportation. These attributes results in Antero being the best way to gain direct exposure to rising NYMEX prices. Turning to slide number six, let's discuss the dramatic drilling and completion efficiency gains that are helping to drive our well cost lower. Starting with the chart in the top left. During the second quarter, our average lateral length drill per well continued its steady progression higher, averaging 13,908 lateral feet per well. This represents an 11% increase compared to the average lateral length in 2020. Note also our new record lateral length of just under 19,000 feet, which is a record for us in both Marcellus and Utica. Moving to the chart on the top right, we averaged more than 6600 lateral feet drilled per day during the second quarter. Our completion efficiency also continued to improve, averaging 9.8 stages per day during the quarter, which was a company record for a quarter and a 23% increase compared to the 2020 average. Finally, our average drill out feet per day has continued to increase each year and averaged 4092 feet per day in the second quarter. With that, I'm going to turn it over to our Vice President of Liquids Marketing and Transportation, Dave Cannelongo, for his comments.

Thank you, Paul. The positive trends we highlighted in the NGL market during the first quarter have continued through today. We observed a consistent increase in prices for all NGL products from the second quarter into the third quarter, fueled by strong crude prices, ongoing tightness in the LPG market, and rising natural gas prices. Consequently, we are seeing the highest sustained prices for C3+ NGLs since 2014 and for ethane since early 2019. Regarding the US propane market, I direct your attention to slide number seven, which outlines propane market fundamentals. The storage situation this injection season has not been enough to close the significant gap to historical levels that we mentioned in the first quarter. Propane days of supply are currently 21% lower than the five-year average, and total inventories are 24% down compared to the same time last year. Looking ahead, most industry analysts expect propane storage in the US to peak at 75 to 80 million barrels this fall by the end of the injection season. On this slide, we estimate that the US will reach the midpoint of that range, 77.5 million barrels, in early October. We then project a repeat of last year’s weekly withdrawals during the winter of 2020-2021. It’s worth noting that the 2020-2021 winter season, although remembered for severe cold, was overall much warmer than usual and followed a disappointing crop drying season. This would lead to the US ending the withdrawal season with approximately 15 million barrels in storage, significantly below the five-year minimum. This situation would result in only about five to nine days of supply next spring, assuming demand and export levels mirror those of spring 2021. This is considerably lower than the previous low of 13.5 days observed right after the historic polar vortex in 2014. We believe the likelihood of the US actually hitting the unprecedented low storage levels shown in the graph is very small. However, this scenario clearly demonstrates that Mont Belvieu prices need to rise further in the upcoming months to reduce exports and prevent domestic propane shortages. Analyzing the forward market alongside current LPG waterborne freight costs, we find that the market is pricing in a conservative view for propane and butane that does not account for the fundamentals I just discussed. Holding a positive outlook for NGL pricing, we remain almost completely unhedged on our LPG starting from October 1 and throughout 2022 and beyond, as we aim to capitalize on the pricing discrepancies we anticipate this winter and into next year. As indicated on slide number eight, the Asian Far East Index for propane has historically reached 110% of Asian naphtha prices per metric ton during peak winter months over the past decade, influenced by inelastic winter demand in the region. Last winter, Asian prices were even stronger relative to naphtha, rising to 124% in December 2020. When factoring in US dock fees and shipping costs to the Asian market, the current Mont Belvieu forward curve implies an assumption that FEI propane will trade at about 110% of Asian naphtha this winter. This suggests potential upside of $0.20 to $0.25 per gallon for Mont Belvieu propane prices if last year's pricing patterns repeat this winter with tighter inventory levels. Turning to the petrochemical market, margins for cracking propane in the US, Northwest Europe, and Northeast Asia have decreased over the past year compared to margins from cracking other feedstocks like ethane, naphtha, and butane. Thus, we believe that most flexible crackers have switched away from propane as a feedstock for some time now, suggesting that we are at or near a bottom regarding global steam cracker propane use. Therefore, we see limited further risk of steam crackers moving away from propane to other feedstocks this winter as prices rise. Simultaneously, new LPG petrochemical demand is emerging, including a combined 170,000 barrels per day of new propane demand from PDH facilities in China in 2021, with an additional 155,000 barrels per day expected in 2022 and over 180,000 barrels per day of new capacity possible in 2023, if all projects progress as planned. This is in addition to 110,000 barrels per day of non-China PDH demand expected to come online during the same timeframe across Europe, North America, and Vietnam. Overall, the global demand for LPG continues to grow, and Antero is well-positioned to benefit on multiple fronts. Not only are we reaching this international demand directly through our capacity, but we also see a macro uplift in Mont Belvieu pricing, now free from past capacity and shipping constraints. With that, I will turn it over to Mike.

Thanks, Dave. I'd like to start on slide number nine highlighting our balance sheet, which is a significant strength for Antero. Over the last 12 months, we have transitioned to substantial free cash flow generation, successfully executed our asset sale program, and rebalanced Antero's senior note maturity profile. In May, we used proceeds from a $600 million senior note offering due 2030 to redeem all of the senior notes due in 2023. Following this offering, our next maturity is not until 2025. During the second quarter, we generated over $100 million of free cash flow, further enhancing our financial position. As depicted on the top left portion of the slide, this free cash flow, along with the $51 million contingency payment received from the ORRI transaction, was used to reduce net debt by $158 million during the second quarter. This brings our total debt to approximately $2.4 billion. The top right quadrant of the slide illustrates the LTM EBITDAX improvement from just over $1 billion at year-end to over $1.4 billion at the end of the second quarter. This improvement was a direct result of Antero's differentiated business strategy that Paul discussed earlier with a focus on liquids development and a firm transportation portfolio that provides best-in-class price realizations. Total debt reduction combined with an improvement in LTM EBITDAX decreased leverage to 1.7 times at the end of the second quarter, down from 3.1 times at year-end 2020. This debt reduction during the quarter resulted in liquidity increasing to $1.9 billion. As we look ahead, we expect to continue maximizing free cash flow and reducing total debt. Our leverage is expected to fall below 1.5 times by year-end 2021 and below one times in 2022 and we achieve our absolute debt target of below $2 billion in early 2022. Now to put first-quarter financial results into perspective, let's turn to slide number 10 titled, financial strength relative to peers. The top of the slide highlights our balance sheet positioning. On the left, you see our $2.4 billion of total debt ranks second among our peers. However, the chart on the right-hand side of the page shows that our net debt-to-EBITDAX of 1.7 times ranks first against our Appalachian peers. The bottom of the page focuses on financial performance year-to-date. We have generated $838 million of EBITDAX and $521 million of free cash flow during the first half of 2021, which ranks first in the peer group and well above our other peers. Free cash flow is nicely above all of our peers and highlights the financial exposure we have in a rising commodity price environment. This exposure is highlighted on slide number 11 titled enhanced free cash flow profile. The increase in the natural gas and NGL futures strips results in a substantial free cash flow outlook at Antero. We forecast over $750 million of free cash flow in 2021 and even higher free cash flow expected in 2022. Further, looking out through 2025, we are now targeting over $3.5 billion in free cash flow signifying substantial annual free cash flow growth through that time period, despite the heavily backward-dated commodity strip. This year is also an exciting year for Antero's ESG initiatives as we make progress towards our 2025 goals. We're happy to announce our pilot program with Project Canary's TrustWell certification. 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. Antero's certification process is set to begin in the fourth quarter of 2021 and to be completed in 2022. The TrustWell certification also aligns with Antero's long-term goals, which are shown on slide number 12 titled, natural gas producers have the lowest emissions. These goals include achieving net zero carbon emissions, reducing our industry-leading GHG intensity, and methane leak loss rates. We also plan to complete and publish our TCFD analysis with our 2020 ESG performance results later in 2021. To summarize, the impressive operating financial momentum continues for Antero. Slide number 13 titled key investment highlights summarizes the position of strength we are in today following this execution. We have significant scale, as the fourth-largest natural gas producer and second-largest NGL producer in the US providing attractive exposure to strengthening commodity prices. Since the beginning of our deleveraging program, we reduced debt by approximately $1.4 billion, issued $2.1 billion of new senior notes, and redeemed our 2021, 2022, and 2023 maturities. The result is an undrawn credit facility and an extension to our average maturity date by over four years. We expect to achieve leverage of under 1.5 times by the end of 2021, as we approach our debt goal under $2 billion much sooner than anticipated. Lastly, assuming today's strip prices, which includes a backward-dated NGL and natural gas strip, we're forecasting substantial free cash flow generation of over $3.5 billion through 2025. These operational, financial, and ESG metrics place Antero among a small 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. Our first question comes from Subash Chandra with Northland Securities. Please state your question.

Yeah. Hi. Good morning, everybody. I was hoping to start with just the land budget. It is not a big number, I guess, in the grand scheme of things, but maybe relatively significant. What drove the decision and what you are trying to do there?

Hey, good morning, Subash. Yeah, what we're trying to do, it is relatively small amount, but our drilling is going very well. And so it's just continued blocking up in the areas that we're developing just small tracks here and there to perfect our drilling units.

Are you finding, in doing that, that this might be a one-time cost or should we expect that a similar budget on a recurring basis?

I am not sure but it'll set us up for the next at least two years.

Yeah, the other way to think about it too, is you've seen some recent M&A and that's really because of the constrained inventory, and not having locations or transport, and this really ensures our ability to continue to develop the type of areas and liquids and the performance we have going forward without really having to rely on M&A for future development.

Okay. And then a modeling question just on, I guess, GP&T, which from the outside is very hard for us to sort of figure out but could you provide some guidance as to what numbers specifically might look like on the strip? I mean, given just the surge in pricing perhaps offset by from the Mariner, etc. Would that number stay flat or goes up or down from here?

Yeah, the increase of the GP&T was really because of the rise in commodity prices and fuel costs and ad valorem taxes and severance taxes. So if there is no backwardation in the strip and these continued high prices continue, then you'd see a similar level to Q2 and Q3 and Q4 what we guided in the future. So it's probably flat unless that backwardation does occur and that would come off a little bit. What we have out on our guidance page, kind of long-term assumptions is for total cash production and net marketing expense, this year it's 229 to 236, but then in the out years, for the five-year period, the average is 210 to 215. So, some of that GP&T comes down and then that marketing expenses comes down as well. So, assuming the backwardation at GP&T should come off as the backwardation occurs.

That was helpful. Thanks, Mike. Just if I can just sneak one in because I'm not sure if I'm interpreting this correctly but did NGL hedges go up for the third quarter?

Yeah, they did, Subash. So, I think in early in the second quarter, we were seeing such strong, although backward-dated NGL prices, we pinched ourselves a little bit and we weren't used to such high prices. So we said, let's make sure this doesn't go away. So we did put in hedges for the second and third quarter. And in hindsight, you can see, well, we got the security but that's what happens when you hedge backward-dated curve and the prices stay flat or increase. So, that was our decision then. But again, a shout out to our commodities group, both on the liquid side and on the gas side. So, we are wide open beginning October 1 and for NGLs for fourth quarter, next year and beyond, so we can capitalize on the NGL prices and the good fundamentals outlook that Dave Cannelongo described. And then just to touch on the gas side, I know you didn't ask that but our last hedging on the gas side was 16 months ago or so as we were in the beginnings of the COVID crisis and going into borrowing the season. So we hedged out some and that was one of the things that a lot of people did during that time but haven't hedged any natural gas and have unwound some liquids as well. So, a reflection that we're bullish on both product streams.

Thanks, Paul. I'm looking forward to October. Thank you, guys.

Thank you. Our next question comes from Neal Dingmann with Truist Securities. Please state your question.

Good morning, all. My question, maybe Mike for - maybe for you Paul, just on that slide 15, just talking about your long-term outlook assumptions. Can you talk a little bit about sort of number one, just the NGL price assumptions? To me, they look actually quite - maybe conservative, if you could call that. I'm wondering, could you talk about how you're thinking about the NGL price assumptions? And then secondly, on the annual production, it looks like you're assuming relatively flat; could you talk about sort of the mix? Will that - is that likely going to be about the same, you think, as right now?

Yes, on the NGL prices, looking at the outlook, it just follows the strip. So, the strip right now on our NGL barrel, which if you remember, there is no ethane, and it's about 58%, propane, so very heavy barrel. It's about $50 for the second half of '21 and then it goes down to $40 in '22 and then down to $30 in '23, '24, and '25, so very backward-dated. So even on that backward-dated strip, and this assumes flat production, like you mentioned, and the same mix between gas and liquids, that's where we get over $3.5 billion of free cash flow. So, it's maintenance capital case, current production mix, heavily backward-dated strip $50 to $40 to $30.

And naturally, it is a backward-dated strip but we feel good about the fundamentals, the demand, the momentum in the liquids markets that Dave Cannelongo outlined a little bit ago. So we would hope that the front of the curve will roll forward at higher prices; it'll continue to be backward-dated, but if one lives on the front of the curve, we will reap the very highest prices to accelerate our debt repayment.

Yeah, and in the backwardation, NYMEX gas - it is $2.75 gas in those '23, '24, and '25 timeframes. It's just we're following the strip.

Okay. And then the mix of the annual production, can we assume that would be approximately the same as before?

Yes.

And then just lastly, I think I know the answer to this, but again, given your solid FT position, is there an opportunity to move - I mean, you guys are already very, very NGL focused, I understand that. Do you have the ability, Paul, with the cadence kind of going forward to move around because it seems like your ample FT, I know some people are constrained and not able to do that as much some other operators. You may be talk about where your FT sits now and maybe the optionality when it comes to operations that that might give you.

Yeah, it does give us certainly operational flexibility. With our direct drilling partnership, as you know, one of the advantages of that was that the drilling partner with their gas fills more of our FT as their production as well as ours comes on. So, they benefit, but they also fill some of that. And then we do have a healthy marketing group that buys a lot of third-party gas at places like Clarington. So we were in that market; we certainly buy Clarington gas and take it to Chicago, and there's a very good spread; they’re even paying a premium to M2 prices. So definitely in the market and filling, taking gas to the Gulf, taking it to Chicago, and of course also to Cove Point, which is a NYMEX based market. So, filling with distressed third-party gas and capitalizing and working to offset any unutilized FT and the demand charge that's associated with them.

Very good. Thank you both.

Our next question comes from Umang Choudhary with Goldman Sachs. Please state your question.

Hi, good morning, and thank you for taking my questions. My first question is really on the framework for cash return to shareholders. Can you help us with a framework and once you achieve your target debt of sub-$2 billion early next year?

Yeah, good question. We are paying down debt much more rapidly than anticipated even from this first quarter and so it should be in early 2022. I think previously, we thought it would be kind of mid-'22, so that's been accelerated. So we will be evaluating the return on capital for 2022 and we'll continue to monitor the markets and see how people value certain ways of returning capital. But depending on the valuation, at the time, we'll be opportunistic on how we move forward. I will say based on our current valuation, where we trade about four times EV to EBITDA for '21 and '22, over 20% free cash flow yield for those same years and even approaching a 15% free cash flow yield on an enterprise value basis. Now share buybacks do look attractive at today's levels. And as you know, we saw dislocation last year as well and we did buy back almost 20% of the company, so we have a history of trying to take advantage of those dislocations.

Got it. That makes sense. I guess my follow-up question is on your activity levels next year, given a bullish on NGLs and natural gas for next year, like how does that determine your activity between liquid area and then dry gas area? And then we'd love your thoughts around natural gas outlook in general.

Yes, with our outlook on NGLs and gas, it's still - the economics are stronger drilling in our liquids-rich area, we do have a very good inventory there, in the liquids-rich fairway a little under 1000 locations that we still have to drill there and roughly the same on our dry gas side. But economics right now just because liquids are so strong, it definitely points us towards continuing the development in the liquids, natural gas liquids fairway, which we'll do. And then our outlook on gas, fundamentally, there's a lot of research out there but we see of course that higher power burn than we've seen in quite a while with natural gas. People are apparently more reluctant to switch to coal due to - for ESG reasons. We know the fundamental fixed appetite of LNG along the Gulf that continues to grow, we see a lot of those LNG facilities. But if it's at roughly 11 BCF a day, the feed gas capacity and spreads are very strong right now, as you know, to help some of the other projects that are on the drawing board go FID in relatively quick time. So we're seeing that, yes, production is out there at roughly 90 BCF a day but between power burn, LNG feed gas, and exports to Mexico, which are roughly six BCF a day, quite a bit of the 90 BCF a day is used up in those realms. And people are showing pretty good discipline in the natural gas basins and associated gas too, so we feel pretty good that the fundamentals are there that natural gas will remain strong.

Got it. That's helpful. Thank you.

Thank you. Our next question comes from an unidentified caller. Please go ahead with your question.

Good morning, guys. Thanks for taking the questions today.

Hi, David.

Mike, actually, you were just highlighting your strong track record of share buybacks. I'm curious in light of that and the valuation that you see as compelling right now, if we might see an active program happening before you hit some of those absolute debt metrics, especially given your view that the curve isn't really reflecting the reality of economics that you're going to experience?

All that's true, but what's also true is we really want low debt, and that's a priority of ours. So, we're going to achieve that below $2 billion before we contemplate any sort of return on capital.

Appreciate those priorities. Also curious, just on your discussions around - I thought it was interesting, in your prepared remarks, you guys commented on the NGL markets and the fact that you don't really see incremental risk from those that would switch; the flexibility of other crackers is sort of already in the market. With that being the case and demands being more centered around PDH in China, when you look at relationships like FEI propane versus naphtha, do you just see further dislocation over time where propane just is really an idiosyncratic product?

David, great question. I think you're exactly right in your assessment there. That's what we witnessed last year and we didn't see those levels for just a week or two; it was for three consecutive months in a row. And so we would agree with that assessment that previously, the steam cracker switching was part of the narrative around propane prices. And it's really taken a backseat as we've seen over the last year, year and a half. And with the additional petrochemical demand that is really only able to consume LPG, we see that historical relationship being less relevant going forward, and that upside, as you hit cold temperatures and strong petrochemical product demand growth, that should continue.

I guess in that vein, and this will be my last one. Given the importance of securing that product, are you seeing an increase in conversations or inbounds, particularly in foreign markets just for securing demand contracts, where you would effectively be able to set your price at levels where the curve might not be reflecting, and you have an interest in doing things like that?

Inbounds, yes, are certainly increasing. I mean, even looking at the more immediate term, I can't think of a vessel that we've loaded where the buyer hasn't wanted to try and accelerate that loading date just due to inventory levels and the destination markets that they were going to. So, yes, the interest is there. I don't know that - we believe that we're going to need to do anything long term on the contract side to be able to see those values. We do like the flexibility that our current export strategy gives us, which allows us to keep volume during the higher seasonal winter months, if prices demanded. So, we like that flexibility and not sure we'd be willing to give that up for a long-term contract at this point. We think ultimately there will be prices and prices will recognize that reality as we move along.

Appreciate the comments and the time. Hope you guys have some plan for the sub-$2 billion party.

We'll start planning now. Thanks, David.

Our next question comes from Arun Jayaram with JPMorgan. Please state your question.

Yeah, good morning. Paul, I wanted to see if you could elaborate on how you see Antero's hedging philosophy evolve as the balance sheet gets to much lower levels of leverage and you're generating a lot of free cash flow. And you did note that you hadn't added a gas hedge in 16 months, if I heard you correctly. So that's a bit of an unusual circumstance, given your historical focus on hedging a lot of the gas exposure.

Good morning, Arun. Yeah, good question. We have been historically, I imagine, we were the leading hedger over the last 15 years or so for nat gas. But it was a little more - it really worked for a number of years when the curve was in Contango and so we did very well. I think our cash gains are nearing $6 billion. So, it was very successful for its time, but it's been consistently now a little bit more of a picture of backwardation. And if you can live on the front or close to the front, you're going to reap the highest prices rather than hedging into a backward-dated curve. And so I do think, as our balance sheet has evolved, and we look at certainly fundamentals as well as momentum, but that says to live more on the front of the curve, and at least for the near term that, as I just mentioned, will accelerate the delivering, which is really a high priority for us after what we and the rest of the industry have been through the last 18 months or so. So, at least for now, it is, be patient and I'm not sure the run is over on nat gas; it's flirting with $4 and out for Cal 22 continuous decline. So, we're in no hurry. We are half-hedged, so 1.1 BCF a day for Cal 22 out of roughly 2.2 BCF a day expected and then virtually unhedged in Cal 23. So, we are enjoying the fundamentals. We see all the factors I mentioned, as well as inventory exhaustion in a number of plays, which is spurring M&A. So, we feel good that supply is going to be in that 90 BCF a day range and there's just more and more calls on that 90 BCF to go to LNG, go to Mexico, go to power burn, and so I think we've just changed a little bit over the last year and a half, and we have the luxury of being patient to ride the upside on natural gas and, as I mentioned before, NGLs too, very good fundamentals there.

Great. And my follow-up, Paul, you did kind of bump your - call it, your premium that you expect for your gas molecules relative to NYMEX, could you talk about what's driving that? I know you've mentioned for the second half of the year. And more importantly, how do you think about that premium as we think about 2022?

Yeah, that is better differentials or no differentials where we sell the gas. We just follow the strip markets on that when we update that. So those have improved the markets where we sell the gas and so that's the improvement. Looking out into 2022, it's still a similar premium. I think we're around the $0.10 premium going forward. So we did $0.18 in second quarter. We raised the guidance to up to $0.25 this year. But then going forward, we back it off to a $0.10 premium in those out years.

Great. Thanks a lot, Mike.

Our next question comes from David Heikkinen with Pickering Energy Partners. Please state your question.

Good morning, everybody. Thanks. Looking at slide 15, really just considering your 2021 to 2025 plan, particularly 2022 to 2025 on lateral feet that'll be drilled and completed, given you continued to stretch your lateral length. You have a drop in well count but I'm curious, have you given or can you give us some guidance as far as how you think about lateral lengths completed in the back, post '21 plan?

Yeah, we mentioned they're around 13,000 feet this quarter, I think they're 12,000 to 13,000 feet without any barriers here.

So, no further lengthening?

No, but in practice, I would think that's what we would try to achieve, based on our current acreage position, current ability to drill the wells is 12,000 to 13,000 feet, but we'll try to go longer.

Yeah, we'll try to go longer. Mike is talking average and we do have a number on the books in the plan that will be 17,000 foot plus in the Marcellus, so not across the board but there's a handful of those probably at least five, somewhere in that range out of 60 or 65 wells that will be in that 17,000 and 18,000 foot range.

Okay. All I had. Thank you.

Thank you.

Our next question comes from Holly Stewart with Scotia Howard Weil. Please state your question.

Good morning, gentlemen. Maybe the first one for - I think probably for Mike. Mike, can you just remind us of the FT roll offs that are coming and then any impact to the GP&T line?

Yeah, no, big event occurs on October 1, that's when our REX capacity goes from 600 to 400 million a day. So when you do the math on that, we're accelerating, it's about $0.50. So 200 million - that's about $35 million a year, $8.5 million a quarter. So that's the next big one and we have some Columbia rolling off as well. So, after that, it's a steady march down to 2024 when we meet the - when the FT actually meets our production, but the big one is October 1 of this year.

Okay, that's great. Helpful. And then just given the inflationary environment that we're in right now, can you just talk about how you're thinking about CapEx next year and any impact on those levels?

No, it is still maintenance capital. You should assume we're at that for the foreseeable future. You remember the drilling JV was really what allowed us to stay at maintenance capital for at least the next four years, and still grow volumes to meet some of that FT capacity and to achieve some midstream earn-out. So no need to come off that maintenance capital level; we already have the scale being the fourth-largest gas producers, second-largest liquids, and seeing the rapid de-leveraging that we're enjoying. So, maintenance capital is the plan definitely for '22 and beyond.

Okay, but don't expect any sort of inflationary pressures on that number.

No, we don't see any inflationary - and we obviously have measures in place to reduce well cost if there are inflationary; they should offset them.

Okay, great. Thank you, guys.

Yep.

Thank you. Our next question comes from Jeoffrey Lambujon with Tudor, Pickering, Holt. Please state your question.

Good morning, everyone. Thanks for taking my question. As you guys mentioned, the market, in terms of commodity and generally equity performance has been seeing the benefits of industry remaining at maintenance capital. So just given the shift in the forward curve, how are you thinking about the capital allocation to the drill bit over the next few years, as it relates to growth or lack thereof? I know you mentioned maintenance is what's assumed in the multi-year free cash flow outlook but more so just wanting to get your bigger picture mindset on drill-bit capital, since the free cash flow profile allows you to execute on a lot of your objectives from debt reduction to cash returns.

Yeah, it's really maintenance capital. Like I mentioned, we're really enjoying efficiencies we're seeing. We've got everything lined out well. All of our commitments needed to develop the field from midstream or transport are in place; no need to make more commitments. So it's really working out well for us. So we don't see any sort of deviation from that plan. And as you mentioned, we do get to debt down to substantially out of debt so there will be a lot of return to capital opportunities around that as well. So that's what we're going to pursue.

Thank you.

Thank you.

Thank you. That's the end of our question-and-answer session. I'll now turn it back to Brendan Krueger for closing remarks.

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

Thank you. This concludes today's conference. All parties may disconnect. Have a great day.