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CNX Resources Corporation (CNX) Q1 2021 Earnings Call Transcript

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CNX earnings call for the period ending March 31, 2021.

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CNX Resources Corporation (CNX 1.28%)
Q1 2021 Earnings Call
Apr 29, 2021, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day, and welcome to the CNX Resources First Quarter 2021 Earnings Conference Call. [Operator Instructions]

I would now like to turn the conference over to Tyler Lewis, Vice President of Investor Relations. Please go ahead.

Tyler Lewis -- Vice President Of Investor Relations

Thank you, and good morning to everybody. Welcome to CNX's first quarter conference call. We have in the room today, Nick DeIuliis, our President and Chief Executive Officer; Don Rush, our Chief Financial Officer; Chad Griffith, our Chief Operating Officer; and Yemi Akinkugbe, our Chief Excellence Officer. Today, we will be discussing our first quarter results. This morning, we posted an updated slide presentation to our website.

Also detailed first quarter earnings release data, such as quarterly E&P data, financial statements and non-GAAP reconciliations are posted to our website in a document titled 1Q 2021 Earnings Results and Supplemental Information of CNX Resources. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks, which we have laid out for you on our press release today as well as on our previous Securities and Exchange Commission filings. We will begin our call today with prepared remarks by Nick, followed by Chad, Don and then Yemi. And then we will open the call up for Q&A. With that, let me turn the call over to you, Nick.

Nicholas J. DeIuliis -- President And Chief Executive Officer

Thanks, Tyler. Good morning, everybody. I'm going to focus my comments on the first two slides of the deck that we posted this morning before turning it over to Chad Griffith, our Chief Operating Officer, to discuss our hedging strategy in gas markets. Then we're going to go over to Don Rush, our Chief Financial Officer, to talk about the financials, and then Yemi will wrap things up to talk about some thoughts on ESG that we've got. But starting now on Slide two. There's one main theme that I think is important to highlight, and the theme there is steady execution.

First quarter was another example of steady execution, and it's illustrated by us generating $101 million in free cash flow. This is the fifth consecutive quarter that the company generated significant free cash flow. Similar to last quarter, we used some of that free cash flow to pay down debt. That helped build further liquidity. And we use some of the free cash flow to buy back our shares in the open market at attractive pricing. So for the quarter, we repurchased 1.5 million shares at an average price of $12.26 per share at a total cost of $18 million.

We still have ample capacity of around $240 million under our existing stock repurchase program, which, as a reminder, that's not subject to an expiration date. Also in the quarter, we upped our free cash flow guidance by $25 million to $450 million. That's $2.04 per share compared to the previous guidance of $1.93 per share. Our steady performance drives our confidence in continuing to execute upon our seven year free cash flow plan, and we continue to expect will generate over $3 billion over those seven years.

Again, this is done by steady execution each and every day. Our long-term plan is largely derisked through our hedging program that supports us a simple operational program that consists of one rig and one frac group. We've worked hard to get the company to where we are today, and our focus is going to remain on successfully executing that plan. I want to jump over now to Slide three.

This is a slide that we have shown for the past few quarters now, but I think that it's a really powerful one. Our competition for investor capital is not so much among just our Appalachian peers, but more so across the broader market. And as you can see by three of the main financial metrics that we track, CNX streams incredibly well across various metrics and indices. We believe that these things matter most to generalist investors, along with what has become a much simpler differentiated story. CNX is a differentiated company due to the structural cost advantage we enjoy compared to our peers, mainly because we own our midstream infrastructure.

And this moat provides us with superior margins that drive significant free cash flow, which, in turn, puts us in a unique position to flexibly allocate capital across the full spectrum of shareholder value creation opportunities. While our near-term focus is to continue to reduce debt and opportunistically acquire shares, we continually evaluate all our alternatives that we've got. So last, in that regard, with respect to the often asked about potential M&A activity, our view remains consistent from last time we spoke.

Our two key screening metrics or the ability to deliver long-term free cash flow per share accretion and having good risk-adjusted returns. The strength of our company affords us the ability to be patient on this front to ensure that we avoid M&A missteps that too often permanently can destroy shareholder value. With that, now, I'm going to turn things over to Chad.

Chad A. Griffith -- Chief Operating Officer

Thanks, Nick, and good morning, everyone. I'm going to start on Slide four, which highlights some of the key metrics that make CNX an incredibly attractive investment today, particularly relative to our peers. For us, it begins in the upper right quadrant where we illustrate our peer-leading production cash costs. While our Q1 result of $0.66 is up roughly $0.05 quarter-over-quarter, we're still more than $0.11 better than our next closest competitor. It's also worth noting that, that $0.05 increase was driven predominantly by some reworking of our FT book, which allowed us to eliminate some unused FT and exchanges for some FT that is better matched up with our production locations.

As Don will go into more details momentarily, our low production cash costs allow us to generate more operating cash flow per Mcfe at a given gas price relative to our peers. And this operating margin creates -- this operating margin advantage creates many other advantages for CNX. First, we'll generate more EBITDA per Mcfe, which means we need less daily production to achieve the same level of EBITDA compared to our peers. This allows us to maintain that level of EBITDA, but less maintenance drilling, thereby consuming fewer of our acres each year.

The operating margin advantage also enhances each well's return on capital, which means a greater subset of our net acres are in the money. So fewer well each year from a broader amount of net acres means that we'll be able to sustain this formula for decades to come. By the way, the lower number of new wells required to maintain our EBITDA means that less of that EBITDA is consumed by maintenance capital expenditures.That is how we generate, on average, $500 million per year of free cash flow over the next six years at strip pricing.

Wrapping up this slide, you can see that we continue to trade at very attractive free cash flow yield on our equity, while continuing to pay down debt and returning capital to shareholders. Slide five is another illustration of our cost structure when you look at it on a fully burdened basis. That means that this cost illustration includes every cash cost that exists in our business. We expect cost to continue to improve, primarily driven by a reduction in the other expense bucket, which consists primarily of interest coming down and additional unused FT rolling off. We are expecting around $10 million of unused firm transportation to roll off in 2021, a modest amount next year in 2022 and then another $20 million rolling off across -- through 2023 through 2025.

These are simply contractual agreements that are expiring. So with these changes, and assuming all future free cash flow goes toward debt repayments, we would expect fully burden cost to decrease to around $0.90 per Mcfe and then lower in years beyond 2021. Before handing it over to Don, I wanted to spend a couple of minutes on our operations, the gas markets and provide a hedge book update. During the quarter, we turned in line five Marcellus wells, and we're in the process of drilling out another 13 that will be turned in line within the next two weeks.

Those 18 wells had an average lateral length of just over 13,000 feet and has an average all-in cost of less than $650 per foot per lateral foot.

Also during the quarter, we brought online two Southwest PA Utica wells, the Majorsville 12 wells. Deep Utica have continued to come down with the all-in capital cost for these two wells averaging $1,420 per lateral foot. Production from these wells are being managed as part of our blending program, but we're very encouraged by the data we're seeing.

As we've really discussed, we only have four additional SWPA Utica wells in our long-term plan through 2026, but based on what we're seeing so far at Majorsville 12, we're excited about the deep Utica's potential as either a growth driver if gas prices improve or as a continuation of our business plan for years and into the future. As for our CPA Utica region, as a reminder, we continue to expect about a pad a year through the end of the 2026 plan.

This continues to be an area that we are very excited about. Shifting to the gas markets, we saw weakening in the near-term NYMEX and weakening to the curve of in-basin markets. As a gas producer, we're always rooting for stronger prices. But fortunately, our cost structure and hedge book make higher prices a luxury for CNX, instead of a necessity as it is for many of our peers. The way we see it, there are four fundamental drivers of gas price that need to be in our favor to actually see higher gas prices.

One, moderate production levels; two, lower storage levels; three, higher weather-related demand; and four, sustained levels of LNG exports. If all four hit, expect gas prices to surge. But despite our optimism and others' dire needs, it's becoming less likely each year that all four of those factors line up in favor of strong gas prices. As an example, just last year, everyone was expecting all four factors to line up in 2021, and the forward curve surge, but a mild winter, lack of strong winter storage draw and growing drilling and completion activity have weighed on 2021 pricing.

The difficulty in having all four factors line up in favor of strong gas prices is why we will continue to focus on being the low-cost producer and protecting our revenue line through our programmatic hedging program. That's why we do not rely on full commodity cases to make projections or investment decisions. Insead, our free cash flow projections and investment decisions are based on the forward stroke.

Speaking of our hedging program, during Q1, we added 136 Bcf of NYMEX hedges, 15.5 Bcf of index hedges and 61.3 Bcf of basis hedges. For 2021, we are now approximately 94% hedged on gas based on the midpoint of our guidance range and after backing out 6% to liquids. That 94% includes both NYMEX and basis hedges or fully covered volumes, which are hedged at $2.48 per Mcf. It is a true realized price that we will receive in the year. We are also now fully hedged on in-basin basis through 2024. We will continue to programmatically hedge our volumes before we spend capital by locking in significant economics, which are supported by our best-in-class cost advantage. And with that, I'm going to turn it over to Don to review our financials and guidance.

Donald W. Rush -- Chief Financial Officer

Thanks, Chad, and good morning, everyone. I'm going to start on Slide six, which highlights our steady execution that Nick touched on in his opening remarks. Q1 was the fifth consecutive quarter of generating significant free cash flow and consistent execution of our plan. Our confidence in future execution supports a $25 million increase in our 2021 free cash flow guidance and our continued expectation to generate over $3 billion across our long-term plan. Slide seven is a new slide that highlights our superior conversion of production volumes into free cash flow.

The top chart highlights that CNX is able to convert production volumes into EBITDA more efficiently than our peers as a result of our low-cost structure generating higher margins. The bottom chart further highlights the superior conversion cycle through a reinvestment rate metric, which is simply capital divided by operating cash flow. As you can see, CNX has an incredibly low reinvestment rate, which supports our expectation to generate average annual free cash flow of $500 million across our long-term plan. Our profitability profile allows us to generate an outsized free cash flow per Mcfe of gas and per dollar of capital spending. Also, this low reinvestment rate demonstrates the company's commitment to generating cash used toward investor-friendly purposes, which include balance sheet enhancement and returning capital to shareholders.

Slide eight highlights our balance sheet strength. We have no bond maturities due until 2026, so we have a substantial runway ahead of us that provides significant flexibility. In the quarter, we reduced net debt by approximately $70 million. And after the close of the quarter, we completed our semiannual bank redetermination process to reaffirm our existing borrowing base. Lastly, as you can see on the slide, our public debt continues to trade in the 4% to 5% range. Now let's touch on guidance that is highlighted on Slide nine. There are a couple of updates on this slide. The first is the pricing update, which is simply a mark-to-market on what NYMEX and Basis are doing for cal 2021 as of April seven compared to our last update, which was as of January 7, 2021.

We also increased our NGL realization expectations by $5 per barrel as a result of the increase in expected NGL realizations. As we have already highlighted, we are increasing free cash flow for the year by $25 million. Lastly, there are a few other guidance related items to highlight that are not captured on this slide that I would like to address in advance of questions. We expect production volumes to be generally consistent each quarter throughout the rest of the year, with a very slight decrease expected in the second quarter. As for capital cadence, we expect capital to have a bit more variation.

Specifically, we expect our first half capital to be more than our second half capital, so Q2 should be near Q1 and Q3 and Q4 a bit less. As we have said previously, quarterly capex cutoffs are difficult to predict since a pad going a bit faster or a bit slower can change the period numbers materially without changing our long-term plan and forecast at all. With that, I will turn it over to Yemi.

Olayemi Akinkugbe -- Chief Excellence Officer

Thanks, Don. Good morning, everyone. I'm Yemi Akinkugbe, the Chief Excellence Officer here at CNX. A few of you may be wondering what exactly this role entail. The short answer is I oversee and manage all operational and corporate support function withing the company. The longer answer is what I want to speak about in more detail today. As Nick briefly mentioned in his opening remarks last quarter, we are the leader in tangible, impactful ESG performance in our space. We've been focused on the underlying tenets of ESG and its benefit with generation.

This is an effect or a means we only talk about to ponder up to certain interest for short-term end. That's not leadership. Instead, the concept was part of our fabric long before the current management team joined the company, and it will be part of our fabric long after it's gone. With that backdrop, let's talk for a minute where we have been and where we are heading on this front. A lot of you when it comes to ESG is simple and can really be summed up in three words: tangible; impactful; local. We've been the first mover across the board, and I just want to highlight a few of our significant accomplishments over the years.

First, we proactively reduced Scope one and two CO2 emissions over 90% since 2011, something that a few, if any, of any public company had claimed. Two, we were the early adopters and innovators of commercial-scaled coalbed methane capture in the 1980s. This resulted in historical mitigation of cumulatively over 700 Bcf of methane emission that would have otherwise been vented into the atmosphere. Annually, we capture nearly as much methane from this operation than the nation's largest waste management company does from its landfill. That ingenuity and leadership on a key tenet of ESG is what ultimately birth this company we see today.

Three, we were the first to fully deploy an all-electric frac spread in the Appalachian Basin. This improved our emission footprint, increased our efficiency and support our best-in-class operational cost performance. The elimination of diesel fuel in this operation is equivalent to taking 23,000 passenger vehicles off the road for a year. We recycled 98% of produced fluid in our core operation. This prevented unnecessary water withdrawal and eliminates the need for disposal. Our unique pipeline network decreases the need for water trucking, which have the dual benefit of reducing community impact of trucking, while reducing overall air quality emissions.

These achievements are important and impactful, but ESG is not just about proven track record. To us, it's about what we are doing now and how we'll continue to push the envelope through intangible, impactful and local accomplishments. Committing to target or goals decades into the future without a concrete path to accomplish them and without accountability for those words, in our opinion, is the epitome of flawed corporate governance. On a forward-looking basis, our ESG goals and results are directly linked to driving efficiency, safeguarding our license to operate, reducing our risk and growing intrinsic for every share of the company. These are the strategies that have allowed CNX to thrive for over 150 years and will continue to drive our success.

Let me introduce a few of our efforts this year. We introduced methane-related KPIs into our executive compensation program. We've committed to make substantial multi-year community investment of $30 million over the next six years to widen the path of the middle class in our local community, while growing the local talent pipeline. We've redoubled our efforts to spend local and hire locally. 100% of our new hires will be from our area of operation, and we will maintain at least 90% local contract workforce. We committed 6% of our contract spend to local, diverse and businesses in 2021 and dedicated 40% of the total CNX small business spend to companies within the Tri-State area.

We adopted a task force on climate-related financial disclosure, or TCFD framework and a FASB standard for both our E&P and midstream operation. In addition, the transparency and the financial sustainability of our business is second to none. One year into our seven year free cash flow generation plan, we have a low-risk balance sheet driven by the most efficient, lowest cost operation in the basin.

This leads to independence from equity and debt market when pursuing value creation. Finally, while you will hear more about this in the weeks and months ahead, I want to take the opportunity to announce that CNX is developing an innovative proprietary solution in combination with a few commercial solutions that allows us to significantly minimize from a blowdown and pneumatic devices, which make up about 50% of our emission source. The blowdown solution under development will also allow us to recirculate methane, which will otherwise be admitted into the atmosphere back into the gathering system.

This is yet another leadership step for a company that continues to lead and deliver tangible impactful ESG performance that is reducing risk and creating sustainable value for our shareholders. Tangible, impactful, local ESG is our brand of ESG. We don't follow the herd. We chart our own course and do what we know is right and impactful over the long term for employees, our communities and our shareholders. With that, I'll turn it over to Tyler for Q&A.

Tyler Lewis -- Vice President Of Investor Relations

Thanks, Yemi. And operator, if you can please open the line up for questions at this time.

Questions and Answers:

Operator

[Operator Instructions] And our first question today will come from Zach Parham with JPMorgan. Please go ahead.

Zach Parham -- JPMorgan -- Analyst

Hey guys, thanks for taking my question. I guess, Chad, maybe one for you. Can you give us a little color on the strength in NGL prices? You reported over $29 per barrel in 1Q, raised the guidance to $20 per barrel for the year. I mean, just based on what you're seeing now, do you view that guidance as still conservative? And maybe just a little color on kind of what you're seeing in the NGL market.

Chad A. Griffith -- Chief Operating Officer

Yes. Sure. Thanks for the question. So you're right, so about $29 a barrel realized for Q1. I think our view is that, historically, NGLs have been incredibly volatile. They really are over the place. We're less than a quarter removed from 2020 where NGLs averaged just about $13 a barrel. And in fact, if you go back to 2019, 2019 was a year in which Q1, I think our NGL barrels was somewhere in the upper 20s, $27, $28 a barrel, but then the full year ended up averaging right just under $20 a barrel.

So based upon the volatility we've seen historically, really, the difficulty in hedging those NGL markets and the NGL sales that we have, I feel like $20 for the full year is still a pretty good estimate of what we think the full year could come in at. I think on the NGL side, what we're focused on is being able to react as spot prices change, and we sort of demonstrated that by moving up our two Shirley fracs and bring those two pads online in order to take advantage of the strong NGL prices that we're seeing in 2021.

And suddenly, the flexibility of the midstream system that we own in Southwest PA provides us to be able to move damp volumes between dry outlets and processing plants, depending upon the spread between gas and NGLs. And I think if you look at the volumes, you'll see that our relative NGL yield came down during Q1.

Well, that's because we are optimizing that frac spread. And what happened on NGL prices generally stayed where they were, but gas prices improved relatively in Q1. So we knew some of those, call it, marginal volumes back to dry out, let's take advantage of the BTU uplift. And now that we've gotten through that strength of Q1 gas, and gas prices have come back down to where they are for the balance of the year, we will likely move some of those marginal volumes back to processing to, again, take advantage of the stronger NGL prices.

Zach Parham -- JPMorgan -- Analyst

Got it. Thanks for that. I guess, just one follow-up. Given that CNX is a consistent free cash flow generator now, when do you see cash taxes becoming a drag on free cash flow? And maybe just a little color on how you're able to continue deferring taxes.

Donald W. Rush -- Chief Financial Officer

Yes. So this is Don. So thanks for the question. As we've stated before, our plan through 2026, we're not material cash taxpayers during that plan. Most of it is the way we treat sort of the NOLs and utilize those as regards to the cash taxes that we'd have to pay and managing and optimizing that versus where the IDCs and the other attributes that you have on the tax side. So the color we'd be given to date is no material cash taxes through 2026 is current plan.

Zach Parham -- JPMorgan -- Analyst

Alright, thanks cha, that's good for me.

Operator

And our next question will come from Leo Mariani with KeyBanc. Please go ahead.

Leo Mariani -- KeyBanc -- Analyst

Guys, I wanted to follow up on a few of your prepared comments here. You talked about production dipping a little bit in second quarter. At the same time, I guess, it sounded like you had 13 new wells in the Marcellus coming online. Just looking for a little color around why the production is dipping a little bit here. And I guess, the follow-up to that would be which you expect production to start to rise again as we got into the third quarter.

Chad A. Griffith -- Chief Operating Officer

Yes. Not materially is the way I would sort of say it. The rest of the year is fairly consistent. Obviously, you had -- we had a big -- a whole bunch of new wells turned online in November. Then you had these other wells that are just getting turned online and getting to their line rates now. So again, nothing sort of -- like production should be mostly similar throughout the year, but I'd -- sorry if I gave the impression that Q2 is going to be a big difference. It'd be very slight, if any.

Leo Mariani -- KeyBanc -- Analyst

Okay. And then just a question on the capex. You guys talked about capex being higher in the first half versus second half. Is this materially higher? Are we talking like 60% of the spend in the first half? Or is it maybe just over 50%? Just trying to get a sense of how that plays out.

Chad A. Griffith -- Chief Operating Officer

Yes. I'd say just -- I'd say, yes, probably just slight is another way to sort of describe it. And part of that is, as Chad mentioned, we pulled off some activity to take advantage of the higher NGL prices, so brought in a spot crew to go ahead and get those things online sooner just because you don't know how long NGL prices stay good. So the best thing we can do is try to -- we've been working on is kind of call it quickly react instead of perfectly predict because it's very difficult to perfectly predict. So again, it's not in a meaningful manner, but we pulled up some stuff that was going to be in the back half of the year to the front half of the year. This is just the way to think about it.

Leo Mariani -- KeyBanc -- Analyst

Okay. And obviously, you guys were nice enough to talk a little about kind of NGL prices and the inherent volatility. I guess, if we're in a world over time where oil prices and NGL prices just stay significantly higher relative to gas, would you guys consider changing up the plans over the next couple of years to maybe focus a little bit more on some of the wetter areas as you look at your Ops?

Chad A. Griffith -- Chief Operating Officer

Yes. No, I think, like I said, we -- predominantly, our acreage footprint is dry. We do still have some wet areas. And as they -- we get pads ready, and we're reacting to NGL prices staying good, I mean, the sequencing, like we've talked, the pads that we're going to do over the next six or seven years are fairly static, but the sequencing in order, they would -- you would obviously try to change them and get some of the wetter ones moved up and have some of the dryer ones move back a little bit. So again, it's not going to materially change the production mix that CNX has, but making margins and moving things on the margin, it's real dollars. I mean, it's meaningful dollars that we're able to increase our cash flows by managing it that way.

Operator

Our next question will come from Neal Dingmann with Truist. Please go ahead.

Neal Dingmann -- Truist -- Analyst

My question really just on capital allocation. You guys, more recently, have really done a good job on the buybacks. I would say, thoughts, it's always a nice option to have is free cash flow continues to ramp like this. I know you've got to forget the exact amount, but still a bit left on that current buyback plan. Just your thoughts on buybacks versus dividends. There's a lot of other folks out there doing more allocation toward vertical dividends and all. So Nick, for you, or Don, just wondering how you guys think about that.

Donald W. Rush -- Chief Financial Officer

Yes. No, I think the way we've talked about it is we clearly want to go ahead and reduce our absolute debt, and that remains a focus of the business here over the next several quarters to get to that level that we want to achieve. And we've talked about having the wherewithal to go ahead and return capital to shareholders along the way, pending on sort of how free cash flow yield is moving or not moving, balancing with sort of patience and prudence just because as we talked with NGL is the same with equity or gas prices.

The volatility is something that I think is here to stay and trying to build capacity to take advantage of that volatility is a proper way to think about it going forward as well. As far as dividends, what we would look through there would be to get the balance sheet closer or where it wants to be first before we'd entertain that. And second, I think you have to just look at the other factors that are there at the time, what our free cash flow yield is doing to determine if returning capital to shareholders via share buybacks or dividend is a smarter investment.

Nicholas J. DeIuliis -- President And Chief Executive Officer

I think, Neal, Don summed it up really well there. You got, right now, first focus with free cash flow allocation to strengthen the balance sheet and reduce that. But at some point quickly here, right, we get to a leverage ratio, liquidity, debt profile that we're more than happy with. And then on the return to shareholder side, we do think that a good, sustainable business model for an E&P and a manufacturer, so to speak, of methane is to be able to have a component of your free cash -- to, a, generate free cash flow, but, b, have a component that does go back to shareholders. The share buybacks versus dividends, as long as we're at these yields on free cash flow, the rate of return, so to speak, of a buyback is very compelling relative to a dividend. If and when that changes and that closes on free cash flow yield and value gap, then something like a dividend makes, I think, much more sense.

Neal Dingmann -- Truist -- Analyst

Yes. It would be great. Maybe great color to add there, Nick. And then just one -- I had a second here as a follow-on. Want to add a little bit maybe different spin on cadence a little bit. You guys -- you continue to say just out there, natural gas prices are obviously always a bit seasonal. And I'm just wondering, I guess, Chad, for maybe you or Don, when you guys think about cadence, I think there is, what 37 or so TILs this year or even on a go-forward basis. Do you -- you guys are pretty highly hedged.

So I'm just wondering maybe or maybe not this matters when you -- because of the seasonality that we continue to have with natural gas prices. Does that impact how you sort of think about the cadence throughout a typical year like this year? Or -- so I don't know, maybe you can just talk cadence a little bit this year now and give me an idea of how you all think about it through just the typical seasonality.

Chad A. Griffith -- Chief Operating Officer

Sure. This is Chad. I'll start, and maybe Don fill in sort of loss or anything. The -- certainly, we're generally one rig, one frac crew, so that's generally pretty consistent throughout the year. So as far as timing, drilling or completions activity, it sort of -- it just sort of march along through the year. I think your question more comes along the lines of like what we did last year, where we saw last year the summer-winter arbitrage was probably the widest that I think I can ever remember seeing it. And so we curtailed some volumes. We shaped some volumes, cashed in some hedges, layered in additional winter hedges and take -- and took advantage of that strong summer-wintertime price arbitrage by timing, the production surged to sync up with a strong winter prices.

We're not seeing that big of a summer-winter arb going into this coming winter yet, but that is certainly something that we obviously keep an eye on every day. And if we see that arbitrage begin to widen to the point that it makes sense to the time production, then we will absolutely do that, just like we did last year. But right now, we don't have any active plans to do that based upon what the way the forward strip currently looks. But like I said, we're always looking to maximize the value of our molecules. And so if that arbitrage comes back with the money, then we'll absolutely be open to timing volumes, just like we did last year.

Donald W. Rush -- Chief Financial Officer

Yes. I'd only add. I mean, I think, similarly, I don't keep repeating volatility, but I think volatility is going to be higher going forward, just looking at the relative storage versus the production supply demand bounces that you have and all the factors that go into this stuff. And Chad talked a lot about deal -- we'll delay production and delay some timing to kind of catch up contango when prices are weak and then prices are better. But we've done the opposite too similar with NGLs. We've done it with dry gas prices.

If there is a bit of a spike in dry gas prices, we'll go ahead and get things online quicker. We have a bit of slack in the system to kind of do either one, sort of delay it a little bit or pull it up a little bit, depending on what those gas prices do because I think they're going to continue to be really volatile on both directions, up and down. And shaping it quickly is something that we've got the ability to do, and I think that will be a pretty good tool to use for the next several years as these things move pretty volatile?

Operator

And our next question will come from Michael Scialla with Stifel.

Michael Scialla -- Stifel -- Analyst

Yes. Want to follow up on a previous question. Don, you said you don't expect the cash taxes before 2026. Does that change at all if the Biden administration is successful in eliminating the intangible drilling credits? Or is that completely shielded with NOLs at this point?

Donald W. Rush -- Chief Financial Officer

Yes. I think, yes, just to make sure I clarify, no material cash tax payments through 2026. So there will some, but not material. Yes. So the way we think -- I mean, obviously, the Biden plan, there's a lot of moving pieces and where that actually settles and what gets approved is kind of to be determined. We're following it closely, and sort of some of the characteristics on the IDC changes that there might be utilizing could change when we would get into the cash tax paying level by a year or so, I'd say the easiest way to sort of think through it because of the profitability we do have as a business. I mean, clearly, we have the $1 billion worth of NOLs to help offset any kind of a change to tax provisions. But the easiest way to think about it is a year or so change and when we would be a cash taxpayer, if steady state business plan through 2026 as we've laid out, we continue on.

Michael Scialla -- Stifel -- Analyst

Okay. Good. And Chad, you mentioned the cost on the most recent Marcellus and Utica wells, pretty significant difference there. I just want to see how other turns compared between those and any other factors you look at when you're deciding to allocate capital between the two?

Chad A. Griffith -- Chief Operating Officer

Yes. So certainly, we believe that all of those areas generate returns -- attractive returns. It just becomes to us to prioritize our investment into the highest rate of -- risk-adjusted rate of return first. And so a lot of that has to do with taking advantage of the existing infrastructure. The -- we've made a huge investment into midstream and water infrastructure in Southwest PA really 2018, early 2019. And now really going into cash harvest mode, utilizing that infrastructure in Southwest PA and developing the SWPA Marcellus assets that we have in that area.

Leveraging those existing infrastructure assets does make the best returns of our portfolio, and that will sustain us predominantly through the six year plan through 2020 to 2027 at this point. With a little bit of deep Utica sprinkled in, I think what we're talking about now is about 75% Marcellus with about maybe 25% Utica sort of sprinkled in. Moving out of that area, obviously, going at the CPA, those are tremendous producers up in CPA deep Utica, the Bell Point six well that we've talked about. I think the latest public numbers we put out there are on the four, 4.5 Bcf per 1,000-foot type production levels.

When you combine that with the recent capital efficiency that we've seen in these SWPA deep Utica, the returns will be, again, very attractive. I think CPA, the plans, like I said, we will probably be about a pad a year sort of through the long-term plan until we build some -- we need some capital investment into a midstream system to truly unlock that area. And right now, I think we're just trying to assess what the proper timing of that is. It's sitting there, ready to go in the event gas prices would justify increasing production or trying to grow. And SWPA Utica is sitting there.

Again, by all intents and purposes, with the costs we've seen and the production levels we're seeing of the most recent pad, where -- we believe that those returns will be in the money as well. And like I said in my prepared remarks, that's sitting there ready to quickly take advantage of in a strong gas price environment, utilizing those existing asset infrastructure assets we have in SWPA or will be there to tackle under the tailings and sustain our business plan for years to come.

Nicholas J. DeIuliis -- President And Chief Executive Officer

Yes. So just to finish off what Chad said. So our best return areas right now are the Southwest PA, Central Marcellus and the CPA Utica. We're planning on doing about a pad at a year in the CPA Utica. That's kind of what can fit in the pipeline systems that are up there, and that mix has -- that's the -- 25% of it is Utica. It's predominantly the CPA Utica. As Chad mentioned, we only have four Southwest PA Utica in the plan just for blending purposes. And although the economics can work, we're focusing on our best two areas to definitely the near-term and through the plan.

Operator

And our next question will come from John Abbott with Bank of America. Please go ahead.

John Abbott -- Bank of America -- Analyst

Good morning, Thank you for taking my questions. The first question is on buybacks. You previously indicated that you could potentially allocate as much as $500 million of free cash flow toward potential buybacks over the next three years. If you continue to perceive a future free cash flow yield that's underappreciated, however, a number of times on this call, you've mentioned commodity volatility. When you think about that, how do you think about buybacks at this point in time, that $500 -- that potential $500 million target versus paying down debt?

Donald W. Rush -- Chief Financial Officer

Yes. Just so it's clear, we didn't lay out a $500 million target. We just said we had the wherewithal and the cash flow that we are generating. There's extra money that we'll have to utilize for other things that are not debt pay down. And it's hard to have a complete exact science with the volatility that we've talked about on equity markets, debt markets, the political environment, everything else that's out there with it.

So what we'll try to do is balance patience and being prudent with being opportunistic with share buybacks and returning capital to shareholders along the way to our, it's -- or call it, balance sheet targets and how much and the pace of those will be to be determined based on the facts and circumstances as they change over time.

Chad A. Griffith -- Chief Operating Officer

Yes. Also the -- obviously, the effectiveness, the impactfullness of growing per share value, buybacks really comes down to, in a large part, on timing, right, the price that obviously you'll acquire that and how it's discounted relative to fair value. And as Don said, that volatility really lends itself to many twist and turns on being able to react quickly.

There's power in that optionality. The second thought is that as we deploy free cash flow toward debt reduction in building liquidity, that is storage capacity. So it's a bit different in our minds from drilling the next pad or doing an acquisition where those are sound capital decisions. This is not necessarily sound capital decision. It's building liquidity and storing capacity to deploy it if and so when circumstances they're paid.

John Abbott -- Bank of America -- Analyst

Understood. And then my second question on -- is on M&A. Nick, you did a really good job in terms of addressing that during your opening remarks. Just one follow-up question on that. I mean, M&A is such a high hurdle for you just given your low-cost structure. Is there a scenario where some dilution would be acceptable to you?

Donald W. Rush -- Chief Financial Officer

Yes. I mean, this is Don. So I mean, obviously, we look at these things holistically, right? When you look at accretion dilution math on per share, on per enterprise value, cost structure, how much inventory sort of over there, the risk profile what it is that you're buying, the payback periods, the risk-adjusted returns. So we do look at all the components together when we're making these assessments.

So if one piece of the components aren't good, but the other ones are really good, then you can kind of overweigh to make the decision on this. So yes, we do look at it on all the factors and with the ultimate goal of just increasing the intrinsic per share value for our shareholders. So I think we continue to assess all the pieces. We're just going to be making sure that it advances the value for CNX's shareholders.

Nicholas J. DeIuliis -- President And Chief Executive Officer

And I think, too, that the term we often use to describe our approach on M&A is just ruthlessly clinical. We just -- it's just a simple matter of math. We follow math, and we're looking at both the acquisition cost and how we would finance that as well as the math of what we're acquiring in terms of the value. What we don't ever want to do is get into one or two position: one, where we acquired something and we sort of fall back on that classic descriptor of a strategic acquisition, which is typically code for something that's destroyed value; or two, something that is largely or hugely speculative on a gas price skew versus where the forward strips. So if you follow the math and your clinical about it, you typically -- more often than not, the vast majority of times, you avoid those two situations. If you don't, sometimes you get caught up in those. And maybe it comes out OK, but oftentimes, it doesn't and doesn't end well for shareholders. So we want to avoid those two types of scenarios.

Operator

And our next question will come from Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks -- Tuohy Brothers -- Analyst

Hi, Good morning.

Donald W. Rush -- Chief Financial Officer

Morning.

Noel Parks -- Tuohy Brothers -- Analyst

Just noticing that in the release, you sort of repeat of the detail on your planned lateral lengths where just what everything is 12,000 feet or better. And I was wondering, as far as the inventory you have that might be -- might only allow shorter laterals, with gas as strong as it is, we're at 2016 or better through 2023, I'm just curious what are the -- or what would the economics be like on some of the sort of laterals? And just wondering if those would have any appeal, cleaning up some of those during the time that you have the support of price takeout there.

Donald W. Rush -- Chief Financial Officer

Yes. No, we obviously look at all the components of the rate of return math whenever you're looking, the dispatching wells and optimizing lateral lengths and via leasing or swapping or any other of these pieces is just something that we're always sort of looking at and focusing on and what's the optimal lateral kind of changes depending on the loss of facts and circumstances.

But yes, I mean, as you say, as gas prices rise, just more things become in the money period, whether it's shorter or longer laterals or whether it's call it Tier two or Tier three areas, or I mean, heck, as gas prices go a little bit more, our CBM wells start being economic and developable at that point in time. So we look at all these things and some of the assets that kind of dispatch it at higher gas prices, and if that's a doable, that's something we just look at like we would anything else.

Noel Parks -- Tuohy Brothers -- Analyst

Okay. And I was just wondering, among your inventory, can you just sort of ballpark how many locations might fall into that shorter mile or less length and whether those are sort of scattered across your acreage position or whether you just have some places where the -- there's some geographic or lease risk constraint that keeps you from going longer?

Chad A. Griffith -- Chief Operating Officer

No. Look, I mean, there's -- most of the way we handle the development of our pads in inventory and well profiles well into the future, we're always kind of building and getting to where the pads optimized and efficient, starting many, many years in advance. So that from like geological constraints or something like that, there's really not a restriction on being able to continue to, call it, manage pad builds to efficient levels going forward.

Noel Parks -- Tuohy Brothers -- Analyst

And just a follow-up. Are you considering pushing your lateral lengths even longer where the lease allows?

Nicholas J. DeIuliis -- President And Chief Executive Officer

Yes. So we've done both. We've done -- I can't remember, Chad, what the longest lateral we've done is.

Chad A. Griffith -- Chief Operating Officer

Yes. Close to 20,000 foot laterals. So we've done long ones. Like I said, it's facts and circumstances. It's the topography, like, where you can get pads and how the lease boundary sits and sort of where the right way to develop the area in connection with where the midstream systems are and for the topography that you have out here. So like I said, it's -- the average is around 12,000 we're at, and we've kind of have some that are longer. We have some that are a bit shorter. And like I said, it will be facts and circumstances to kind of optimize all the pieces we have to get these, call it, drilled in the most economical fashion.

Olayemi Akinkugbe -- Chief Excellence Officer

Yes. There is a point of diminishing returns. We'll start talking about long laterals. We always look at it to make sure we optimize and it's based on the available technologies to actually complete those things efficiently.

Nicholas J. DeIuliis -- President And Chief Executive Officer

Right, great thanks a lot.

Operator

[Operator Instructions] Our next question will come from David Heikkinen with Heikkinen Energy Advisors. Please go ahead.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Good morning guys, thanks for taking my questions. One of your Appalachian peers highlighted that they are drilling new wells from over 250 existing pads, and that's taking their well cost below like $600 a foot. I was curious, as you think about your inventory and being able to utilize, like you said, your existing midstream infrastructure as you try to continue to drive down costs below your $650 a foot, can you just give us some thoughts of how you'd react being able to use existing pads and existing infrastructure and really continue to drive down your lateral cost per foot?

Nicholas J. DeIuliis -- President And Chief Executive Officer

Yes, yes. And some of that, we do as well. Clearly, we don't have that in any pads where the availability to do that would be there. And part of the Southwest PA Utica strategy, however it plays out in the future, will -- a lot of that be going back to existing pads and kind of using that same phenomenon. But yes, the Marcellus we have pads that will do two trips on, and we've kind of done that same phenomenon. And a pad build, not having to build a pad, again, it obviously saves you money and the overall D&C per foot of the well, and that's something that we will optimize on. We just don't have as many legacy pads to do that as others.

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

Got you. So really, as you think about the 25% of the Utica in the future or if you ever come back to adding Utica, that would be -- that would drive down some of your cost per foot on those wells. That's helpful.

Chad A. Griffith -- Chief Operating Officer

Yes, yes. And then up in the CPA area, the CPA Utica is more economic. And then the CPA Marcellus, but the CPA Marcellus is good and CPA South Marcellus. I mean, there's some third parties drilling up there currently, and the new well results are really phenomenal actually with the new completion designs that we've talked. So that opportunity exists for us, both in the Southwest PA area and in the CPA area.

Nicholas J. DeIuliis -- President And Chief Executive Officer

Yes. David, I think the way to think of our footprint in that context is annuitizing that type of behavior dynamic over years and decades. So for us, in Southwest Pennsylvania, it's the Utica, right, taking advantage of all that shared infrastructure, pad water and midstream of the Marcellus. And then in CPA, for us, it's the Marcellus that would be doing the same, taking advantage of the existing infrastructure that's been capitalized because of the Utica. So those are really the drivers of the rate of return and the math behind two of our four horizons in a big way.

Operator

And this will conclude the question-and-answer session. I'd like to turn the conference back over to Tyler Lewis for any closing remarks.

Tyler Lewis -- Vice President Of Investor Relations

Thanks, operator, and thank you, everyone, for joining us today. We look forward to speaking with everyone throughout the quarter. Thank you.

Operator

[Operator Closing Remarks]

Duration: 51 minutes

Call participants:

Tyler Lewis -- Vice President Of Investor Relations

Nicholas J. DeIuliis -- President And Chief Executive Officer

Chad A. Griffith -- Chief Operating Officer

Donald W. Rush -- Chief Financial Officer

Olayemi Akinkugbe -- Chief Excellence Officer

Zach Parham -- JPMorgan -- Analyst

Leo Mariani -- KeyBanc -- Analyst

Neal Dingmann -- Truist -- Analyst

Michael Scialla -- Stifel -- Analyst

John Abbott -- Bank of America -- Analyst

Noel Parks -- Tuohy Brothers -- Analyst

David Heikkinen -- Heikkinen Energy Advisors -- Analyst

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