Greetings, and welcome to the Antero Resources Second 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. Please note this conference is being recorded. I will now turn the conference over to our 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 Q2 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 and 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 Liquid Marketing and Transportation.
I will now turn the call over to Paul.
Thanks Brendan. Let's begin with Slide number 3 titled Best exposure to rising commodity prices. During the Q2, our business model delivered EBITDAX of $319,000,000 and free cash flow of $105,000,000 Our financial results highlight the significant leverage we have to rising natural gas and C3 +NG oil prices. During the Q2, our C3 plus 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 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 that 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 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 Feet portfolio and our low hedge profile Makes Antero the most efficient way to gain direct exposure to Dynex and Mont Belvieu prices.
Now let's
turn to slide number 4 which illustrates the benefits Of Antero's firm transportation portfolio, as illustrated on the chart, our Feet portfolio has significantly reduced Realized pricing volatility especially when compared to Appalachian basis differentials. During the Q2, 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 a wide basis to continue into the future. Slide number 5 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 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 result in Antero being the best way to gain direct Turning to Slide 6, let's Discuss the dramatic drilling and completion efficiency gains that are helping to drive our well costs lower. Starting with the chart in the top left, During the Q2, our average lateral length drilled per well continued its steady progression higher, Averaging 13,900 and 8 lateral feet per well. This represents an 11% increase compared to the average lateral length in 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 6,600 Lateral feet drilled per day during the Q2.
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 4,092 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.
Thanks, Paul. In the NGL market, the bullish fundamental trends that we highlighted during the Q1 of this year have continued to take shape through today. We saw a steady climb in prices for all NGL products during the Q2 and into the Q3, driven by underlying strength in crude pricing, Continued tightness in the LPG market and higher natural gas pricing. As a result, we have experienced the highest sustained pricing we have Seen since 2014 for C3 plus NGLs and since early 2019 for ethane. Focusing on the U.
S. Propane market, I'll refer you to Slide number 7 titled Propane Market Fundamentals. The storage build thus far this injection season has been insufficient to make up the large deficit to historical levels that we discussed in the Q1. Propane days of supply remained 21% below the 5 year average, while total inventories are 24% lower than this time last year. Looking forward, most industry consultants anticipate that the U.
S. Will reach a peak propane storage level of 75,000,000 to 80,000,000 barrels this fall at the end of injection On this slide, we assume that the U. S. Reaches the midpoint of that range 77,500,000 barrels in early October. We then show a repeat of the same weekly withdrawals observed last year during winter 2020 2021.
As a reminder, The 2020 2021 winter season, while overshadowed by memories of cold temperatures in February, was overall substantially warmer than historical norms And followed an underwhelming crop drying season. This scenario would result in the U. S. Ending withdrawal season with only about 15,000,000 barrels in storage, Significantly below the 5 year minimum storage level. This would translate to only about 5 to 9 days of supply next spring, Assuming demand and export levels are similar to those seen in spring 2021, this is materially below the lowest days of supply observed in recent history, Which was 13.5 days directly following the historic 2014 polar vortex.
Ultimately, we believe that there is a very small probability The U. S. Actually reaching the unprecedented low storage levels illustrated in the graph. However, this scenario clearly indicates that Mott Belvieu prices need to move even higher over the coming months to curtail exports and avoid domestic propane shortages. Looking at the forward strip with the latest LPG waterborne freight pricing, we are currently seeing the market price in a conservative case for propane and butanes That do not reflect the fundamentals I just touched on.
Given our continued bullish view on the outlook for NGL pricing, we remain essentially unhedged on our LPG beginning on October 1st and through 2022 and beyond as we look to take advantage of the pricing dislocation we see this winter and into next year. As shown on slide number 8, Asian Far East Index or FEI Propane has historically reached 110% of Asian naphtha prices on a dollars per Ton basis during the peak winter months over the past decade driven by inelastic winter demand in the region. Last winter, Asian prices were even stronger on a relative basis climbing to 124 percent of naphtha in December of 2020. After taking into account U. S.
Stock fees and shipping costs to the Asian market, the Mont Belvieu forward curve is currently pricing in FEI propane trading at approximately 110% of agent naphtha this winter. This implies $0.20 to $0.25 per gallon Potential upside from Mont Belvieu propane prices if we see last year's pricing relationships play out again this winter with even tighter inventory levels. Finally, turning to the petrochemical market, margins for cracking propane in the U. S, Northwest Europe and Northeast Asia have trended lower over the last Compared to margins from cracking other feedstocks such as ethane, naphtha and butane. As a result, we believe most of the crackers With flexibility to switch away from propane as a feedstock have already done so for some time indicating that we are currently at or near a floor of global steam cracker Therefore, we believe further downside risk of steam crackers switching away from propane to other feedstocks is very limited As we look ahead to this winter in 2022 and higher prices.
At the same time, new LPG petrochemical demand continues to come online, Including a combined 170,000 barrels a day of new PDH demand for propane being added in China during 2021 With as much as an incremental 155,000 barrels a day in 2022 and more than 180,000 barrels a day of new build capacity possible in 2023 Should all projects move forward. This is in addition to 110,000 barrels a day of non China PDH demand coming online in the same time period Across Europe, North America and Vietnam. Overall, the global demand pull for LPG continues to materialize And Antero continues to benefit on multiple fronts. Not only are we reaching this international demand directly through our capacity on the Mariner East System, But we also benefit from the macro uplift in Mont Belvieu pricing, which is now unhindered by the dock capacity and shipping constraints that have impacted the market in previous years. With that, I will turn it over to Mike.
Thanks, Dave. I'd like to start on Slide number 9, highlighting our balance sheet, which is a significant strength for 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 600,000,000 Senior note offering due 2,030 to redeem all of the senior notes due in 2023. Following this offering, Our next maturity is not until 2025. During the Q2, we generated over $100,000,000 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 $51,000,000 contingency payment received from the Override transaction was used reduced net debt by $158,000,000 during the Q2. This brings our total debt to approximately $2,400,000,000 The top right quadrant of the slide illustrates the LTM EBITDAX improvement from just over $1,000,000,000 at year end To over $1,400,000,000 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 1.7x at the end of the second quarter, down from 3.1x at year end 2020. This debt reduction during the quarter results in liquidity increasing to $1,900,000,000 As we look ahead, we expect to continue maximizing free cash flow and reducing total debt.
Our leverage is expected to fall below 1.5x by year end 2021 and below 1x in 2022, And that we achieve our absolute debt target of below $2,000,000,000 in early 2022. Now to put Q1 financial results into perspective, let's turn to Slide 10 titled Financial Strength Relative to Peers. The top of the slide highlights our balance sheet positioning. On the left, you see our $2,400,000,000 of total debt ranked second among our peers. However, the chart on the right hand side of the page shows that our net debt to EBITDAX of 1.7x ranks 1st against our Appalachia peers.
The bottom of the page focuses on financial performance year to date. We have generated $838,000,000 of EBITDAX And $521,000,000 of free cash flow during the first half of twenty twenty one, which ranks 1st 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 future results in a substantial free cash flow outlook at Antero.
We forecast over $750,000,000 of Further looking out through 2025, we are now targeting over $3,500,000,000 in free cash flow, Signifying substantial annual free cash flow growth through that time period, despite the heavily backwardated commodity strip. This year is also an exciting year for Antero's ESG initiatives as we make progress towards our 2025 goals. We are happy to announce our pilot program with Project Canary's TrussWell 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. Antero's certification process is Set to begin in the Q4 of 2021 and to be completed in 2022.
The Trust Well certification also aligns with Entera'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 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 and strength we are in today following this execution.
We have significant scale as the 4th largest natural gas producer and 2nd largest NGL producer in the U. S, providing attractive exposure to Strengthening commodity prices. Since the beginning of our deleveraging program, we've reduced debt by approximately $1,400,000,000 Issued $2,100,000,000 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 4 years. We expect to achieve leverage of under 1.5x by the end of 2021 as we approach our debt goal of under $2,000,000,000 much sooner than anticipated.
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 $3,500,000,000 through 2025. These operational, financial and ESG metrics Antero among a small group of E and Ps with significant scale, low leverage, sustained free cash flow generation and leading ESG
Our first question comes from Subash Chandra with Northland Securities. Please state your question.
Yes. Hi. Good morning, everybody. I was hoping to start with just the land budget. It's not a big number, I guess, in the grand scheme of things, but maybe relatively significant.
What drove the decision and what you're trying to do there?
Hey, good morning, Subash. Yes. 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 one time costs or should we expect That similar budget on a recurring basis?
Not sure, but it'll set us up for the next At least 2 years.
Yes. And other way to think about it too is you've seen some recent M and 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 and A for future development. Okay.
And then a modeling question And just on, I guess, JP and T, which from the outside is very hard for us to sort of figure out. But Could you provide some guidance as to what that number specifically might look like on strip? I mean, given just the surge in Pricing perhaps offset by some of the Mariner contracts, etcetera. Does that number stay flat or What was that for down from here?
Yes. The increase of the GP and T was really because of the rising commodity price 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 that's probably flat unless that backward aid does occur and then it Does occur and that would come off a little bit. What we have out on our guidance page kind of long term assumptions As for total cash production and net marketing expense, this year, it's $2.29 to $2.36 but then in the out years For the 5 year period, it averages $2.10 to $2.15 So some of that GP and T comes down and then the net marketing expense, as we know, comes down as well.
So Assuming the backwardation at GP and T should come off as the backwardation occurs.
That was helpful. Thanks, Alex. 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 Q3?
Yes, they did, Subash. So I think early in Q2, we were seeing such Strong, although backwardated 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 2nd and third quarter. And in hindsight, you can see where we got the security, but was That's what happens when you hedge in a backwardated 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 4th quarter, next year and beyond. So we can capitalize on the NGL prices and the Good fundamentals outlook that Dave Cantelongo 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 Base 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. Thanks guys.
Yes. Thank you.
Thank you. Our next question comes from Neal Dingmann with Truist Securities. Please state your question.
Good morning, all. My question, maybe Mike 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 1, just the NGL price assumptions? To me, they look out actually quite Maybe conservative 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, 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, do you think, as you're at now?
Yes. On the NGL price, it's looking at the outlook. It just follows Strip. So the strip right now on our NGL barrel, which if you remember, there is no ethane in it, it's about 58% propane, so very heavy barrel. It's about $50 for the second half 'twenty one, and then it goes down to $40 $0.22 and then down to 30 dollars.23, dollars 24, dollars 25, so very backwardated.
So even on a backwardated strip and this assumes flat production Mike, you mentioned in the same mix between gas and liquids, that's where we get the 3 over $3,500,000,000 of free cash flow. That's maintenance capital case, current production mix, heavily backwardated strip, dollars 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 Cantelongo outlined a little bit ago. So we would hope that front of the curve will roll forward at higher prices. It will continue to be backwardated, but if one lives on the front of the curve, we'll reap the Very highest prices to accelerate our debt repayment.
Yes. And in the back of the day, NYMEX gas It's $2.75 gas in those 'twenty three, 'twenty four and 'twenty five timeframes. It's just we're following the strip.
Okay. And then the mix of the Annual production, is that can we assume that would be approximately the same as you're at now?
Got it. Yes.
And then just last, I I know the answer to this. But again, given your solid Feet position, is there 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 Feet, I know some people are constrained and not able to do that as much from other operators.
Can you maybe talk about Where your Feet sits now and maybe the optionality when it comes to operations that that might give you?
Yes. It does give us certainly operational flexibility with our drilling partnership. As you know, one of the advantages of that was That the drilling partner with their gas fills more of our Feet 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 3rd 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 there even paying a premium to M2 prices. So Definitely in the market and filling, taking gas to the Gulf, taking it to Chicago, Of course also to Cove Point which is a NYMEX based market. So filling with distressed third party gas and capitalizing Working to offset any unutilized Feet and the demand charge that's associated with that.
Very good. Thank you, both.
Our next question comes from Uman Choudhary with Goldman Sachs. Please state your question.
Hi, good morning and thank you for taking my questions. My first question It's really on the framework for cash return to shareholders. Can you help us with the framework and once you achieve your target debt of Sub $2,000,000,000 early next year?
Yes. Good question. We are paying down debt much more rapidly than anticipated even from this Q1, And so it should be in early 2022. I think previously, we thought it'd be kind of mid-twenty 2. So that's been accelerated.
So we will be evaluating the return of 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 4x EV to EBITDA for 'twenty one and 'twenty To over 20% free cash flow yield for those same years and even approaching a 15 Percent free cash flow yield on an enterprise value basis, share buybacks do look attractive at today's levels. And as you know, we saw dislocation last year as well, and we did buyback almost 20% of the company. So we have a history of trying to take advantage of those dislocation.
Got it. That makes sense. I guess my follow-up question is on your activity levels Next year, given your bullish on NGLs and natural gas for next year, like how does that determine your Activity between liquids area and then dry gas area. And then, would love your thoughts around natural gas outlook in general?
Yes. So yes, with our outlook and 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, Little under a 1,000 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 feed 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 Mexico, which are roughly 6 Bcf a day that 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.
Thank you. Our next question comes from David Deckelbaum with Cowen. 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 Sure, buybacks. I'm curious in light of that in the valuation that you see is 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. So And that's a priority of ours. So we're going to achieve that below $2,000,000,000 before we contemplate any sort of return of 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 Which 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 truly 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 2. It was for 3 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 back seat As we've seen here over the last year, year and a half and with the additional res comp and on purpose 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 on 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 do you have an interest in doing things like that?
Inbounds, yes, are certainly increasing. I mean even looking at on 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 in the destination markets that they were going to. So Yes, the interest is there. You know, 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 commanded. So 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 Bellevue prices and prices at the Mariner East Dock We'll recognize that reality as we move along.
Appreciate the comments and the time. Hope you guys have something fun planned for the sub-two $1,000,000,000 party.
We'll start planning now. Thanks, David.
Our next question comes from Arun Jayaram with JPMorgan, please state your question.
Yes, good morning. Paul, I wanted to see if you could Elaborate on how you see Antero's hedging philosophy You know, 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 circumstances given your historical Focus on hedging a lot of the gas exposure.
Yes. Good morning, Arun. Yes, good question. We have been Historically, I imagine we're the leading hedger over the last 15 years or so for Natgas. 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 $6,000,000,000 Right. 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 backwardated curve. And so I do think as our balance sheet has evolved and we look at certainly fundamentals as well as momentum, but That to us says to live more on the front of the curve and at least for the near term that as I just mentioned we'll accelerate the delevering Which is really a high priority for us after what we and the rest of industry have been through the last 18 months or so.
So At least for now, it's be patient and I'm not sure the run is over on net gas. It's Flirting with $4 and out for Cal 22 continues to climb. 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 and 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?
Yes. It was just 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 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 the 2nd 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.
Yes.
Our next question comes from David Heikkinen with Pickering Energy Partners. Please state your question.
Good morning, everybody. Thanks. Looking at your At Slide 15, it was really just considering your 2021 to 2025 plan, particularly 2022 to 2025 on a lateral feet That will be drilled and completed given you continue to stretch your lateral lengths. You have a drop in well count, but I'm curious Have you give or can you give us some guidance as far as how you think about lateral lengths completed in the back post 2021 plan?
Yes. We mentioned they're around 13,000 feet this quarter. I think they're 12,000 to 13,000 feet in any barriers here.
So no further lengthening?
No. But in practice, I would think that was what we would try to achieve. But based on our current acreage Current ability to drill the wells is 12,000 to 13,000. But we'll try to go longer.
Yes, we'll try to go longer. Mike 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 5 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 all.
Thank you. Thanks, David.
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 Feet roll offs that are coming and then any impact to the GP and T line?
Yes. No, big event occurs on October 1. That's when our REX capacity goes from $600,000,000 to $400,000,000 a day. So when you do the math on that, we're accelerating, it's about $0.50 So $200,000,000 that's about $35,000,000 a year or $8,500,000 a quarter. So that's the next big one.
And then we have Columbia rolling off as well. So after that, it's steady march down to 2024 when we meet When the FTE actually meets our production, but the big one is October 1 this year.
Okay. That's great. Helpful. And then just given the inflationary environment that we're And right now, can you just talk about how you're thinking about CapEx next year and any impact on those levels?
No, it's 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 Maintenance capital for at least the next 4 years and still grow volumes to meet some of that Feet capacity and to achieve some midstream Earn out. So no need to come off that maintenance capital level. We already had the scale being the 4th largest gas producer, 2nd largest liquids and And seeing the rapid deleveraging that we're enjoying, so maintenance capital is planned definitely for 'twenty two 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 also.
Okay, great. Thank you, guys.
Yes. Thanks, Ali.
Thank you. Our next question comes from Jeffrey 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 Industry remaining at maintenance capital. So just given the shift in
the forward curve, how are
you thinking about 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 multiyear free cash flow outlook, but more so just wanted to get your bigger picture mindset on drill capital since the free cash flow profile allows you to execute on a lot of your objectives from debt reduction to cash returns?
Yes, it's really maintenance capital. Like I mentioned, we're really enjoying the efficiencies we're seeing. We've got everything lined out well. All of our commitments needed to develop the field from midstream or transported in place, no need to make more commitment. 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 the debt down Substantially basically out of debt. So there will be a lot of return of 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 I'll now turn it back to Brendan Krueger for closing remarks.
Thank you for joining us on today's call. Please reach out to any further questions. Thank you all.
Thank you. This concludes today's conference. All parties may disconnect. Have a great day.