Good day. Welcome to the CNX Resources first quarter 2021 earnings conference call. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. I would now like to turn the conference over to Tyler Lewis, Vice President of Investor Relations. Please go ahead.
Thank you. Good morning to everybody. Welcome to CNX's first quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; 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.
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 Q1 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 in our press release today, as well as in 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.
Thanks, Tyler, and good morning, everybody. I'm gonna focus my comments on the first two slides of the deck that we posted this morning before turning it over to Chad , our Chief Operating Officer, to discuss our hedging strategy in gas markets. We're gonna go over to Don Rush, our Chief Financial Officer, to talk about the financials. Yemi will wrap things up to talk about some thoughts on ESG that we've got. Starting out 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 used some of the free cash flow to buy back our shares in the open market at attractive pricing. 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 - $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 we'll 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 de-risked through our hedging program that supports a simpler operational program that consists of one rig and one frac crew. We've worked hard to get the company to where we are today, and our focus is gonna remain on successfully executing that plan. I wanna jump over now to slide three. This is a slide that we have showed 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.
As you can see by three of the main financial metrics that we track, CNX screens 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. 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 a 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. 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 are 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 gonna turn things over to Chad.
Thanks, Nick. 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 exchange it 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. 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 with 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. Fewer wells 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 CapEx. That is how we generate, on average, $500 million per year of free cash flow over the next six years of 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 costs to continue to improve, primarily driven by a reduction in the other expense buckets, 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. With these changes, and assuming all future free cash flow goes towards debt repayments, we would expect fully burdened costs to decrease to around $0.90 per Mcfe and then lower in the 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 had an average all-in cost of less than $650 per foot, per lateral foot. During the quarter, we brought online two SWPA Utica wells, the Majorsville 12 wells.
Deep Utica costs 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. We're very encouraged by the data we're seeing. As we've regularly discussed, we only have four additional SWPA Utica wells in our long-term plan through 2026. Based on what we're seeing so far at Majorsville 12, we're excited about the Deep Utica's potential as e ither a growth driver if gas prices improve or as a continuation of our business plan for years 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 of the near-term NYMEX and weakening to the curve of the basin markets. As a gas producer, we're always rooting for stronger prices. 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. Despite our optimism and others' dire need, 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. The forward curve surged.
A mild winter, lack of strong winter storage draw, and growing drilling 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 bold commodity cases to make projections or investment decisions. Instead, our free cash flow projections and investment decisions are based on the forward strip.
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% for liquids. That 94% includes both NYMEX and basis hedges for fully covered volumes, which are hedged at $2.48 per Mcf. That is the 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 on locking in significant economics, which are supported by our best-in-class cost advantage. With that, I'm going to turn it over to Don to review our financials and guidance.
Thanks, Chad, and good morning, everyone. I'm gonna 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 this 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 Mcf of gas and per dollar of capital spending. Also, this low reinvestment rate demonstrates the company's commitment to generating cash to use towards 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 semi-annual 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%-5% range. Now let's touch on guidance. That is highlighted on slide nine. There are a couple 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 7th, compared to our last update, which was as of January 7th, 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. 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.
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 entails. The short answer is I oversee and manage all operational and corporate support functions within 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 benefits for generations.
This isn't a fact or a means we only talk about to pander to certain interests for short-term ends. 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're heading on this front. Our philosophy 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 few, if any, of any public company can claim. Two, we were the early adopters and innovators of commercial-scale coalbed methane capture in the 1980s. This resulted in historical mitigation of cumulatively over 700 Bcf of methane emissions 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 birthed this company you 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 recycle 98% of produced fluid in our core operations. This prevents unnecessary water withdrawal and eliminates the need for disposal. Our unique pipeline network decreases the need for water trucking, which has 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 tangible, impactful, and local accomplishments.
Committing to targets 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 the intrinsic per value share of the company.
These are the strategies that have allowed CNX to thrive for over 150 years, and they 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 for 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.
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 the SASB standards for both our E&P and midstream operations. 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 our 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 would have otherwise been emitted 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, and 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 our employees, our communities, and our shareholders. With that, I'll turn it over to Chad, Tyler for Q&A.
Thanks, Yemi. Operator, if you can please open the line up for questions at this time.
Certainly. We will now begin the question- and- answer session. Our first question today will come from Zach Parham with JP Morgan. Please go ahead.
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. 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?
Yeah, sure. Thanks for the question. You're right. 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. In fact, if you go back to 2019 was a year in which Q1, I think our NGL barrels was somewhere in the upper 20s, $27, $28 a barrel. The full year ended up averaging right just under $20 a barrel.
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, more what we're focused on is being able to react as spot prices change. We sort of demonstrated that by moving up our two Shirley fracs and being able to bring those two pads online in order to take advantage of the strong NGL prices that we're seeing in 2021.
Similarly, the flexibility that the midstream system that we own in SWPA provides us to be able to move wet volumes between dry outlets and processing plants depending upon the spread between gas and NGLs. 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. What happened is NGL prices generally stayed where they were, but gas prices improved relatively in Q1. We moved some of those called marginal volumes back to dry outlets to take advantage of the BTU uplift.
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 strong NGL prices.
Got it. Thanks for that color. 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? Maybe just a little color on how you're able to continue deferring taxes.
Yeah. This is Don. 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's 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 sort of the IDCs and the other attributes that you have on the tax side. The color awe've given to date is no material cash taxes through 2026 is the current plan.
Great. Thank you. That's it for me.
Our next question will come from Leo Mariani with KeyBanc. Please go ahead.
Hey, guys. Wanted to follow up on a few of your prepared comments here. You guys 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's dipping a little bit here. I guess the follow-up to that would be, would you expect production to start to rise again as we get into the third quarter?
Yeah. Not materially, is the way I would say it. The rest of the year is fairly consistent. Obviously, we had a big 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. Again, production should be mostly similar throughout the year. Sorry if I gave the impression that Q2 is going to be a big difference. It'd be very slight, if any.
Okay. 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 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.
Yeah, I'd say probably just slight is another way to describe it. Part of that is, as Chad mentioned, we pulled up some activity to take advantage of the higher NGL prices. 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. The best thing we can do is we're working on is call it quickly react instead of perfectly predict, because it's very difficult to perfectly predict. 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, is the easiest way to think about it.
Okay. Obviously, you guys were nice enough to talk a little about 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?
Yeah, no, I think, like I said, predominantly our acreage footprint is dry. We do still have some wet areas. Yeah, as 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, the sequencing and order you do them, you would obviously try to change them and get some of the wetter ones moved up and have some of the drier ones move back a little bit. Again, it's not going to materially change the production mix that CNX has.
Making margins and moving things on the margin, it's real dollars. It's meaningful dollars that we're able to increase our cash flows by managing it that way.
Thank you.
Our next question will come from Neal Dingmann with Truist. Please go ahead.
Morning, guys. 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, I 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 other folks out there doing more allocation towards variable dividends and all. Nick , for you or Don Rush, I was just wondering how you guys think about that.
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. We've talked about having the wherewithal to go ahead and return capital to shareholders along the way, pending on how free cash flow yield is moving or not moving, balancing with patience and prudence, just because as we talked with NGLs, the same with equity or gas prices.
Volatility is just 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. Second, I think you'd 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 dividends is a smarter investment.
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, reduce debt. At some point quickly here, we get to a leverage ratio liquidity debt profile that we're more than happy with. 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 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.
Yeah, I would agree. A great color add there, Nick. Just one second here or follow on. Want to add a little bit, maybe different spin on cadence a little bit. You guys, you continue to see 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's, what, 37 or so TILs this year, or even on a go-forward basis. You guys are pretty highly hedged, so I'm just wondering, maybe or maybe not, this matters.
Because of the seasonality that we continue to have with natural gas prices, does that impact how you think about the cadence throughout a typical year like this year? I don't know, maybe you could just talk cadence a little bit this year, and that'll give me an idea of how you all think about it through, just the typical seasonality.
Sure. This is Chad. I'll start, maybe Don fill in a sort of gloss over anything. Certainly, we're generally one rig, one frac crew, that's generally pretty consistent throughout the year. As far as timing drilling or completions activity, it's just sort of march along through the year. I think your question more comes along the lines of 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.
We curtailed some volumes, we shaped some volumes, cashed in some hedges, layered in additional winter hedges, and took advantage of that strong summer-wintertime price arbitrage by timing the production surge to sync up with those strong winter prices. We're not seeing that big of a summer-winter arb going into this coming winter yet. That is certainly something that we obviously keep an eye on every day. If we see that arbitrage begin to widen to the point that it makes sense to time production, then we will absolutely do that just like we did last year.
Right now, we don't have any active plans to do that based upon the way the forward strip currently looks. Like I said, we're always looking to maximize the value of our molecules. If that arbitrage comes back into the money, then we'll absolutely be open to timing volumes just like we did last year.
Yeah. I'd only add, I think similarly, I 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 balances that you have and all the factors that go into this stuff. Chad talked a lot about the whole, we'll delay production and delay some timing to kind of catch a contango when prices are weak and then prices are better. We've done the opposite too, similar to what 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. I think they're going to continue to be really volatile both directions, up and down, and shaping it quickly is something that we've got the ability to do, and I think that'll be a pretty good tool to use for the next several years as things move pretty volatility.
No. Great insights. Thanks for the time, guys.
Our next question will come from Michael Scialla with Stifel. Please go ahead.
Hi, good morning, everybody. I wanted to follow up on a previous question. Don, you said you don't expect to pay cash taxes before 2026. Does that change at all if the Biden administration is successful in eliminating the intangible drilling costs, or is that completely shielded with NOLs at this point?
Yeah, I think, just to make sure I clarify, no material cash tax payments through 2026. There'll be some, but not material. Yeah. The way we think, 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 some of the characteristics on the IDC changes that they might be utilizing could change when we would get into the cash tax paying mode by a year or so, I'd say, is the easiest way to think through it. Because of the profitability we do have as a business.
Clearly, we have the $1 billion worth of NOLs to help offset any kind of change to tax provisions. The easiest way to think about it is a year or so change in when we would be a cash taxpayer if steady state business plan through 2026, as we've laid out, we continue on.
Okay, good. Thanks. Chad, you mentioned the costs on the most recent Marcellus and Utica wells. Pretty significant difference there. I just want to see how their returns compare between those and any other factors you look at when you're deciding to allocate capital between the two.
Yeah. Certainly, we believe that all of those areas generate returns, attractive returns. It just becomes to us to prioritize our investment into the highest risk-adjusted rate of return first. A lot of that has to do with taking advantage of the existing infrastructure. We 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, those make the best returns in our portfolio. That will sustain us predominantly through the six-year plan through 2026, 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 up to CPA, those are tremendous producers up in CPA Deep Utica. The Bell Point 6 well that we've talked about, I think the latest public numbers we put out there are around 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 the SWPA Deep Utica, the returns will be, again, very attractive. I think CPA, the plans, like I said, will probably be about a pad a year, sort of through the long-term plan until 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.
SWPA Utica is sitting there, again, by all intents and purposes, with the costs we've seen and the production levels we're seeing off the most recent pad, we believe that those returns will be in the money as well. 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 infrastructure assets we have in SWPA, or it'll be there to tackle into the tail end and sustain our business plan for years to come.
Yeah. Just to finish off what Chad said. 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 what can fit in the pipeline systems that are up there. That mix is, that's the 25% that is Utica. It's predominantly the CPA Utica. As Chad mentioned, we only have four Southwest PA Uticas in the plan just for blending purposes. Although the economics can work, we're focusing on our best two areas for definitely the near term and through the plan.
Sounds good. Thanks for the color, guys.
Our next question will come from John Abbott with Bank of America. Please go ahead.
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 towards potential buybacks over the next three years if you continue to perceive a future free cash flow yield as 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 potential $500 million target versus paying down debt?
Yeah. Just so we're 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. 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. 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, call it, balance sheet targets.
How much and the pace of those will be to be determined based on the facts and circumstances as they change over time.
Yeah. Also, obviously, the effectiveness and impactfulness of growing per share value of buybacks really comes down to, in a large part, on timing, right? The price that obviously you acquire at and how it's discounted relative to fair value. As Don said, that volatility really lends itself to many twists 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 stored capacity.
It's a bit different in our minds from drilling the next pad or doing an acquisition, where those are sunk capital decisions. This is not necessarily a sunk capital decision. It's building liquidity and storing capacity to deploy it, if and so when circumstances dictate.
Understood. My second question 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. 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?
Yeah. This is Don. 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 is sort of over there, the risk profile, what it is you're buying, the payback periods, the risk-adjusted returns. Yeah, we do look at all the components together when we're making these assessments. If one piece of the components aren't good, but the other ones are really good, then you can kind of overweight and make the decision on this.
Yeah, 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. 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.
Yeah. I think, too, that the term we often use to describe our approach on M&A is just ruthlessly clinical. 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 of two positions. One, where we acquire 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.
Two, something that is largely or hugely speculative on a gas price view. Versus where the forward scripts are. If you follow the math and you're 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 okay, but oftentimes it doesn't and doesn't end well for shareholders. We want to avoid those two types of scenarios.
Thank you very much, guys. Appreciate it.
Our next question will come from Noel Parks with Tuohy Brothers. Please go ahead.
Hi. Good morning.
Morning.
Just noticing that, in the release, you sort of repeated the detail on your planned lateral lengths, where just about everything is 12,000 feet or better. I was wondering, as far as the inventory you have that might only allow shorter laterals, with gas as strong as it is, we're at $2.60 or better through 2023. I'm just curious, what would the economics be like on some of the shorter laterals? Just wondering if those would have any appeal, cleaning up some of those during a time that you have a supportive price tick out there.
Yeah. No, we've obviously looked at all the components of the rate of return math whenever you're looking at dispatching wells and optimizing lateral lengths and via leasing or swapping or any other of these pieces. It's just something that we're always sort of looking at and focusing on and what's the optimal lateral kind of changes depending on lots of facts and circumstances.
Yeah, 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 2 or Tier 3 areas or, heck, if gas prices go a little bit more, our CBM wells start being economic and developable at that point in time. We look at all these things and some of the assets that kind of dispatch at higher gas prices and if that's doable and that's something we just look at like we would anything else.
Okay. 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 there's some geographic or lease constraint that keeps you from going longer?
Yeah. Most of the way we handle the development of our pads and inventory and well profiles well into the future, we're always kind of building and getting to where the pad's optimized and efficient starting many, many years in advance. Net from 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.
Just to follow up, are you considering pushing your lateral length even longer, where the lease allows?
We've done both. We've done, I can't remember, Chad, what the longest lateral we've done is. Close to a 20,000 ft lateral. We've done longer 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. Like I said, the average is around 12,000 where we're at, and we kind of have some that are longer.
We have some that are a bit shorter, and like I said, it'll be facts and circumstances that kind of optimize all the pieces we have to get these, call it, drilled in the most economical fashion.
Yeah. There is a point of diminishing returns when we start talking about long laterals. We always look at it to make sure we optimize in it based off of the available technology to actually complete those things efficiently.
Right. Great. Thanks a lot.
Once again, if you'd like to ask a question, please press star then one. Our next question will come from David Heikkinen with Heikkinen Energy Advisors. Please go ahead.
Good morning, guys, and thanks for taking the question. 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 $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 to being able to use existing pads and existing infrastructure and really continue to drive down your lateral costs per foot?
Yeah. Some of that we do as well. Clearly, we don't have that many pads where the availability to do that would be there. Part of the SWPA Utica strategy, however it plays out in the future, a lot of that be going back to existing pads and kind of using that same phenomenon. Yeah, the Marcellus, we have pads that we'll do two trips on, and we've kind of done that same phenomenon. A pad build, not having to build a pad again, obviously saves you money in the overall D&C per foot of the well, and that's something that we'll optimize on. We just don't have as many legacy pads to do that as others.
Got you. 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 how to drive down some of your cost per foot on those wells, if that's helpful. Thanks, guys.
Yeah. Up in the CPA area, the CPA Utica is more economic than the CPA Marcellus. The CPA Marcellus is good, and CPA South Marcellus. There's some third parties drilling up there currently, and the new well results are really phenomenal, actually, with the new completion designs and stuff. That opportunity exists for us both in the Southwest PA area and in the CPA area.
Yeah, David, I think the way to think of our footprint in that context is annuitizing that type of a behavior dynamic over years and decades. For us, in Southwest Pennsylvania, it's the Utica, right? Taking advantage of all that shared infrastructure of pad water and midstream of the Marcellus. 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. Those are really the drivers of the rate of return and the math behind two of our four horizons in a big way.
Yep. Thanks, guys.
This will conclude the question- and- answer session. I'd like to turn the conference back over to Tyler Lewis for any closing remarks.
Yeah. Thanks, operator, and thank you everyone for joining us today. We look forward to speaking with everyone throughout the quarter. Thank you.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.