Earnings Call: Q1 2021

Apr 29, 2021

Good day, and 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, and good morning to everybody. Welcome to CNX's Q1 conference call. We have in the room today Nick Deulius, our President and CEO Don Rush, our Chief Financial Officer Chad Griffith, our Chief Operating Officer and Yemi Akinkube, our Chief Excellence Officer. Today, we will be discussing our Q1 results. This morning, we posted an updated slide presentation to our website. Also, detailed Q1 earnings release data such as quarterly E and P data, financial statements and non GAAP reconciliations are posted to our web site in a document titled 1Q2021 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 and A. With that, let me turn the call over to you, Nick. 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, COO, to discuss our hedging strategy in gas markets. Then we're going to go over to Don Rush, our CFO, 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 out on Slide 2, there's one main theme that I think is important to highlight and the theme there is steady execution. 1st quarter was another example of steady execution and it's illustrated by us generating $101,000,000 in free cash flow. This is the 5th 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. So for the quarter, we repurchased 1.5 1,000,000 shares at an average price of $12.26 per share at a total cost of $18,000,000 We still have ample capacity of around $240,000,000 under our existing stock repurchase program, which is a reminder that's not subject to an expiration date. Also in the quarter, we upped our free cash flow guidance by $25,000,000 to $450,000,000 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 7 year free cash flow plan and we continue to expect we'll generate over $3,000,000,000 over those 7 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 a simpler operational program that consists of 1 rig and 1 frac crew. 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 3. 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. And as you can see by 3 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 mode 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. So last, in that regard, with respect to the often asked about potential M and A activity, our view remains consistent from last time we spoke. Our 2 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 and A missteps that too often permanently can destroy shareholder value. With that now, I'm going to turn things over to Chad. Thanks, Nick, and good morning, everyone. I'm going to start on Slide 4, 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 quarter where we illustrate our peer leading production cash costs. While our Q1 result $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 Feet book, which allowed us to eliminate some unused Feet and exchange it for some Feet 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 NCFE 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 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. So 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 capital expenditures. That is how we generate on average $500,000,000 per year of free cash flow over the next 6 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 5 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 Feet rolling off. We are expecting around $10,000,000 of unused firm transportation to roll off in 2021, a modest amount next year in 2022 and then another $20,000,000 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 towards debt repayments, We would expect fully burdened costs to decrease to around $0.90 per Mcfe and 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 5 Marcellus wells and we're in the process of drilling out another 13 that will be turned in line within the next 2 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 $6.50 per foot per lateral foot. Also during the quarter, we brought online 2 Southwest PA Utica wells, the Majorsville 12 wells. Deep Utica costs have continued to come down with the all in capital cost for these 2 wells averaging $14.20 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 regularly discussed, we only have 4 additional Suipa Utica wells in our long term plan through 2026. But based on what we're seeing so far in Majidil 12, we're excited about the Deep Utica's potential as either a growth driver as 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 and weakening through 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 4 fundamental drivers of gas price that need to be in our favor to actually see higher gas prices. 1, moderate production levels 2, lower storage levels 3, higher weather related demand and 4, sustained levels of LNG export. If all 4 hit, expect gas prices to surge. But 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 and the forward curve surged. But 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. It's why we do not rely on bull 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. And that 94% includes both NYMEX and basis hedges for fully covered volumes, which are hedged at $2.48 per Mcf. It 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, 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. Thanks, Chad, and good morning, everyone. I'm going to start on Slide 6, which highlights our steady execution that Nick touched on in his opening remarks. Q1 was the 5th consecutive quarter of generating significant free cash flow and consistent execution of our plan. Our confidence in future execution supports a $25,000,000 increase in our 2021 free cash flow guidance and our continued expectation to generate over $3,000,000,000 across our long term plan. Slide 7 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 $500,000,000 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 towards investor friendly purposes, which include balance sheet enhancement and returning capital to shareholders. Slide 8 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 $70,000,000 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 9. 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 7 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 $25,000,000 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 2nd 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. But as we have said previously, quarterly CapEx cutoffs are difficult to predict since the 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 Akinkadevay, Chief Excellence Officer here at CNF. 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 benefit for Generation. This isn't a fact or a means we only talk about to pander to certain interests 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. Our philosophy when it comes to ESG is simple and can really be summed up in 3 words tangible, impactful, local. We've been the 1st mover across the board and I just want to highlight a few of our significant accomplishments over the years. First, we proactively reduced scope 1 and 2 CO2 emissions over 90% since 2011, something that few if any of any public company can claim. 2, we were the early adopters and innovators of commercial scale cobalt methane capture in the 1980s. This resulted in historical mitigation of cumulatively over 700 Bcf of methane emission that would have otherwise been embedded 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. 3, we were the 1st 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 coal operation. This prevents unnecessary water withdrawals 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 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, IESG goals and results are directly linked to driving efficiencies, safeguarding our license to operate, reducing our risk and growing intrinsic per barrel 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 multiyear community investment of $30,000,000 over the next 6 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 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 tristate area. We adopted a task force on climate related financial disclosure or TCFE framework and the SACI standards for both our E and P and midstream operation. In addition, the transparency and the financial sustainability of our business is second to none. 1 year into our 7 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 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 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 Chuck Tyler for Q and A. Thanks, Yemi. And operator, if you can please open the line up for questions at this time. Certainly. And we will now begin the question and answer session. And our first question today will come from Zach Parham with JPMorgan. 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. 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? 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 average just about $13 a barrel. 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, dollars 27, dollars 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, more what we're focused on is being able to react as spot prices change. And we sort of demonstrated that by moving up our 2 Shirley fracs and being able to bring those 2 pads online in order to take advantage of the strong NGL that we're seeing in 'twenty one. And similarly, the flexibility that 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, although that's because we are optimizing that frac spread. And what happened is NGL prices generally stayed where they were, but gas prices improved relatively in Q1. So we moved some of those, call it, marginal volumes back to dry outlets to 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. 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? And maybe just a little color on how you're able to continue deferring taxes? Yes. So this is Don. So thanks for the question. As we've stated before, our plan through 'twenty six were 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. So the color we've given to date is no material cash taxes through 20.6 is the current plan. All right. Thank you guys. That's it for me. Our next question will come from Leo Mariani with KeyBanc. Please go ahead. I guess wanted to follow-up on a few of your prepared comments here. You guys talked about production dipping a little bit in 2nd quarter, but 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, would you expect production to start to rise again as we got into Q3? Yes. Not materially. This is the way I would sort of say it. So the rest of the year is fairly consistent. Obviously, you had 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. So again, nothing sort of the production should be mostly similar throughout the year, but I'm sorry if I gave the impression that Q2 is going to be a big difference. It would be very slight if any. 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. 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 up 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. So the easiest way to think about it. 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? Yes. No, I think like I said, predominantly our acreage footprint is dry. We do still have some wet areas. And yes, they will 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 6 or 7 years are fairly static, but the sequencing in 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. 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. Thank you. And our next question will come from Neal Dingmann with Truist. Please go ahead. Good 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. So Nick, for any you or Don, I just wondered how you guys think about that. 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, depending 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 Hinge, with sort of patience and prudence just because as we talked with NGLs, the same with equity or gas prices, 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. Then 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 dividend is a smarter investment. I think, Neil, Don summed it up really well there. You got right now first focus was free cash flow allocation to strengthen the balance sheet, reduce debt. 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 and P and a manufacturer, so to speak, of methane is to be able to have a component of your free 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. Yes. It would be great. Great color to add there, Dick. And then just one second here to follow on. I 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 were done, when you guys think about Kayn's, I think there's what, 37 or so tills this year or even on a go forward basis. Do 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 could just talk cadence a little bit this year and that will give me an idea of how you all think about it through just the typical seasonality. Sure. This is Chad. I'll start and maybe Don fill in a sort of gloss over anything. Certainly, we're generally 1 rig, 1 frac crew. So that's generally pretty consistent throughout the year. So as far as timing drilling or completions activity, it's sort of it's 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 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, 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 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 into the money, then we'll absolutely be open to timing volumes just like we did last year. Yes. And I'd only add, I mean, I think similarly, I'd 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. And Chad talked a lot about the whole will delay production and delay some timing to kind of catch a 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 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, pretty volatility. No. Great details. Thanks for the time, guys. And our next question will come from Michael Ciudad with Stifel. Please go ahead. Yes. Hi, good morning everybody. I want 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 credits? Or is that completely shielded with NOLs at this point? No, I think, yes, just to make sure to clarify, no material cash tax payments through 'twenty six. So, they'll be selling, 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 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 sort of think through it because of the profitability we do have as a business. I mean, clearly, we have the $1,000,000,000 worth of NOLs to help offset any kind of change to the tax provisions. But 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 'twenty six as we've laid out, we continue on. Okay, good. Thanks. And Chad, you mentioned the costs on the most recent Marcellus and UCA wells, pretty significant difference there. I just want to see how the returns compare between those and any other factors you look at when you're deciding to allocate capital between the 2? 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 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 SWIPA Marcellus assets that we have in that area. Leveraging those existing infrastructure assets, those make the best returns in our portfolio. And that will sustain us predominantly through the 6 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 and 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 talked about, I think the latest public numbers we put out there around the 4,450 Bcf per 1,000 foot type production levels. When you combine that with the recent capital efficiency that we've seen in the SWIPA Deep Utica, the returns will be again very attractive. I think CPA, the plans, like I said, will probably be about a pat a year sort of through the long term plan until we build some we need some capital investment into administering systems 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 Suipa Utica is sitting there. Again, by all intents and purposes, with cost 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 infrastructure assets we have in SWPA, or it will be there to tackle under the tailwinds and sustain our business plan for years to come. 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 a year in the CPA Utica. That's kind of what can fit in the pipeline systems that are up there and that mix is that's the 25% that is Utica, it's predominantly the CPA Utica. As Chad mentioned, we only have 4 Southwest PA Utica's in the plan just for blending purposes. And although the economics can work, we're focusing on our best two areas for definitely the near term and through the plan. And our next question will come from Jon Abbott with Bank of America. Please go ahead. 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 $500,000,000 of free cash flow towards potential buybacks over the next 3 years. If you continue to perceive a future free cash flow yield is 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 $500,000,000 target versus repurchasing paying down debt? Yes. And just so it's just so we're clear, I mean, we didn't lay out a $500,000,000 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 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. And 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. And 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. So it's a bit different in our minds from drilling the next pad or doing an acquisition where those are some capital decisions. This is not a necessarily a some capital decision. It's building liquidity and storing capacity to deploy it if and so when circumstances dictate. Understood. And then my second question on is on M and 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 and 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? 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 is sort of over there, the risk profile, what it is that you're buying, the payback periods, the risk adjusted returns. So, yes, 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 over overweigh to make the decision on this. So, 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. 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. Yes. And I think too that the term we often use to describe our approach on M and 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 1 or 2 positions. 1 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 2, something that is largely or hugely speculative on a gas price view versus where the forward scripts are. So 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. So we want to avoid those two types of scenarios. And our next question will come from Noel Parks with Tuohy Brothers. Please go ahead. Hi, good morning. Good 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. 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 260 or better through 2023. I'm just curious, what are the or what would the economics be like on some of the shorter laterals? And just wondering if those would have any appeal cleaning up some of those during a time that you have the supportive price tag out there? Yes. No, we obviously look 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 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 lots 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 2 or Tier 3 areas or I mean, heck, if 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 at higher gas prices and if that's doable and that's something we just look at like we would anything else. 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 kind of some places where the there's some geographic or lease risk constraint keeps you from going longer? No. Like I mean, like there's most of the way we handle the development of our patents and inventory and well profiles well into the future. We're always kind of building and getting to where the pads optimize and efficient starting many, many years in advance. So net net 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. And just to follow-up, are you considering pushing your lateral length even longer where the lease allows? Yes. So we've done both. We've done I can't remember, Chad, what the longest lateral we've done is. Yes, close to 20,000 foot lateral. So 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 boundaries sit 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 where 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'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. Yes. There is a point of diminishing returns. When we start talking about long laterals, we always look at it to make sure we optimize and based off of the available technology actually complete those things efficiently. Right. Great. Thanks a lot. Our next question will come from David Heineken with Heineken 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 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 to being able to use existing pads and existing infrastructure and really continue to drive down your lateral cost per foot? Yes. And some of that we do as well. Clearly, we don't have that many 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, it 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, it will do 2 trips on and we've done that same phenomenon and a pad build not having to build a pad again is obviously saves you money in the overall D and 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. 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 drive down some of your cost per foot on those wells? That's helpful. Thanks guys. Yes. And then up in the CPA area, the CPA Utica is more economic than 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 and stuff. So that opportunity exists for us both in the Southwest GA area and in the CPA area. Yes, David, I think the way to think of our footprint in that context is annuitizing that type of behavior dynamic over years decades. So 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. 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 2 of our 4 horizons in a big way. Yes. 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. Yes. Thanks, operator, and thank you everyone for joining us today. We look forward to speaking with everyone throughout the quarter. Thank you. And the conference has now concluded. Thank you for attending today's presentation. You may now disconnect.