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spk05: Good day and welcome to the CNX Resources first quarter 2021 earnings conference call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one. 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.
spk03: Thank you and good morning to everybody. Welcome to CNX's first quarter 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 Akincibe, our Chief Excellence Officer. Today we will be discussing our first quarter results. This morning we posted an updated slide presentation to our website, also detailed first quarter earnings release data, such as quarterly E&P data, financial statements, and non-GAAP reconciliations are posted to our website in a document titled 1Q-2021 Earnings Results and Supplemental Information of CNX Resources. As a reminder, any forward-looking statements we make or comments about future expectations are subject to business risks, which we have laid out for you 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. Good morning, everybody.
spk08: I'm going to focus my comments on the first two slides of the deck that we posted this morning before turning it over to Chad Griffith, our 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 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. So for the quarter, we repurchased 1.5 million shares at an average price of $12.26 per share at a total cost of $18 million. We still have ample capacity of around $240 million under our existing stock repurchase program, which is a reminder that's not subject to an expiration date. Also in the quarter, we upped our free cash flow guidance by $25 million to $450 million. That's $2.04 per share compared to the previous guidance of $1.93 per share. Our steady performance drives our confidence in continuing to execute upon our seven-year free cash flow plan, and we continue to expect 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 frack 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 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 is For investor capital is not so much among just our Appalachian peers, but more so across the broader market. And as you can see by three of the main financial metrics that we track, CNX 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. 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&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 going to turn things over to Chad.
spk09: Thanks, Nick, and good morning, everyone. I'm going to start on slide four, which highlights some of the key metrics that make CNX an incredibly attractive investment today, particularly relative to our peers. For us, it begins in the upper right quadrant, where we illustrate our peer-leading production cash costs. While our Q1 result of $0.66 is up roughly $0.05 quarter over quarter, we're still more than $0.11 better than our next closest competitor. It's also worth noting that that 5 cent 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. 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 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 a 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 bucket, which consists primarily of interest coming down and additional unused FT rolling off. We are expecting around $10 million of unused firm transportation to roll off in 2021, a modest amount next year in 2022, and then another $20 million rolling off across through 2023 through 2025. These are simply contractual agreements that are expiring. So with these changes, and assuming all future free cash flow goes towards debt repayments, we would expect fully burdened costs to decrease to around $0.90 per MCFP and lower in years beyond 2021. Before handing it over to Don, I wanted to spend a couple of minutes on our operations, the gas markets, and provide a hedge book update. During the quarter, we turned in line five Marsalis 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. Also during the quarter, we brought online two Southwest PA Utica wells, the Magesville 12 wells. Deep Utica costs have continued to come down, with the all-wing capital cost for these two wells averaging $1,420 per lateral foot. Production from these wells are being managed as part of our blending program, but we're very encouraged by the data we're seeing. As we've regularly discussed, we only have four additional SWPA Utica wells in our long-term plan through 2026, But based on what we're seeing so far in Major Hill 12, we're excited about the deep Utica's potential as either a growth driver if gas prices improve or as a continuation of our business plan for years into the future. As for our CPA Utica region, as a reminder, we continue to expect about a pat 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 through the curve of invasive markets. As a gas producer, we're always rooting for stronger prices. But fortunately, our cost structure and hedge book make higher prices a luxury for CNX instead of a necessity as it is for many of our peers. The way we see it, there are four fundamental drivers of gas price that need to be in our favor to actually see higher gas prices. One, moderate production levels. Two, lower storage levels. Three, higher weather-related demand. And four, sustained levels of LNG export. If all four hit, expect gas prices to surge. But despite our optimism and others' dire needs, it's becoming less likely each year that all four of those factors line up in favor of strong gas prices. As an example, just last year, everyone was expecting all four factors to line up in 2021, and the forward curve surged. But a mild winter, lack of strong winter storage straw, and growing drilling and depletion 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 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 NIMEX and basis hedges or fully covered volumes, which are hedged at 248 per MCF. And it's 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.
spk10: Thanks, Chad, and good morning, everyone. I'm going to start on slide six, which highlights our steady execution that Nick touched on in his opening remarks. Q1 was the fifth consecutive quarter of generating significant free cash flow and consistent execution of our plan. Our confidence in future execution supports a $25 million increase in our 2021 free cash flow guidance and our continued expectation to generate over $3 billion across our long-term plan. Slide 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 million across our long-term plan. Our profitability profile allows us to generate an outsized free cash flow per MCF fee 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 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 million. And after the close of the quarter, we completed our semiannual bank redetermination process to reaffirm our existing borrowing base. Lastly, as you can see on the slide, our public debt continues to trade in the 4 to 5 percent 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. 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 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.
spk00: Thanks, Don. Good morning, everyone. I'm Yamia Kinkabe, the Chief Excellent Officer here at CNN. 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 a 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'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. 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 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 landfills. 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 frack spread in the Appalachian Basin. This improved our emission footprint, increased our efficiency, and supported 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 cooperation. 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 proving 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 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 EMP and midstream operations. In addition, the transparency and the financial sustainability of our business is second to none. One year into our seven-year free cash flow generation plan, we have a low-risk balance sheet driven by the most efficient, lowest-cost operation in the basis. 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 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, 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 community, and our shareholders. With that, I'll turn it over to Chuck Tyler for Q&A.
spk03: Thanks, Jimmy. And operator, if you can please open the line up for questions at this time.
spk05: Certainly. And we will now begin the question and answer session. To ask a question, you may press star then 1 on your touch-tone phone. If you're using a speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. And at this time, we'll pause momentarily to assemble the roster. And our first question today will come from Zach Parham with JP Morgan. Please go ahead.
spk04: 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 one queue, 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?
spk09: Yeah, 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're, you know, 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, you know, 2019 was a year in which Q1, I think our NGL barrels was somewhere in the upper 20s, $27, $28 a barrel. But then the full year ended up averaging right just under $20 a barrel. So based upon the volatility we've seen historically, really the difficulty in hedging those NGL markets and the NGL sales that we have, I feel like $20 for the full year is still a pretty good estimate of what we think the full year could come in at. I think on the NGL side, more what we're focused on is being able to react as spot prices change. You know, we sort of demonstrated that by moving up our two Shirley fracks and being able to bring those two pads online in order to take advantage of the strong NGL prices that we're seeing in 21. 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. Well, that's because we are optimizing that frack 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 called 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.
spk04: 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?
spk10: Yeah, so this is Don. So thanks for the question. As we've stated before, our plan through 26, 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, you know, 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 26 is the current plan.
spk04: Thanks, guys. That's it for me.
spk05: Our next question will come from Leo Mariani with KeyBank. Please go ahead.
spk01: Hey, guys. I wanted to follow up on a few of your prepared comments here. You guys talked about production dipping a little bit in second quarter, but at the same time, I guess it sounded like you had 13 new wells and the Marcellas 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 to third quarter?
spk10: Yeah, not materially. This is the way I would sort of say it. So 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. So, again, 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.
spk01: 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 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.
spk10: Yeah, I'd say just... I'd say, yeah, probably just slight is another way to sort of describe it. And part of that is, as just Chad mentioned, we pulled up some activity to take advantage of the higher NGL prices. So, you know, 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. It's the easiest way to think about it.
spk01: 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 – you know, changing up the plans over the next couple years to maybe focus a little bit more on some of the wetter areas as you look at your ops?
spk10: Yeah, no, I think, like I said, we, you know, predominantly our acreage footprint is dry. We do still have some wet areas. And, yeah, as we get pads ready and, you know, we're reacting to NGL prices staying good, I mean, the sequencing, you know, like we've talked about, The pads that we're going to do over the next six or seven 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.
spk05: Thank you. And our next question will come from Neil Dingman with Truist. Please go ahead.
spk11: Morning, guys. My question really just on capital allocation. You guys, you know, more recently have really done a good job on the buybacks, I would say. Thoughts, you know, it's always a nice option to have is, you know, pre-cash will continue to ramp like this. You know, I know you've got, I forget the exact amount, but still a bit left on that current buyback plan, just your thoughts on, you know, buybacks versus dividends. There's a lot of other folks out there doing more allocation towards variable dividends and all. So, Nick, for any of you or Donna, just wondering how you guys think about that.
spk10: Yeah, 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 the 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 NGL, it's 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 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 by backs or dividends is a smarter investment.
spk08: I think Neil, Don summed it up really well there. You got, right now, first focus with free cash flow allocations 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, you know, a good sustainable business model for an EMP 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.
spk11: Yeah, I would agree. My great caller there, Nick. And then just one second here, a follow-on. I want to add a little bit, maybe a different spin on cadence a little bit. You guys, you know, you continue to see just out there, natural gas prices are obviously always a bit seasonal. And I'm just wondering, you know, I guess, Chad, for maybe you or Donne, When you guys think about cans, I think there's, what, 37 or so tills 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 sort of think about the cadence throughout a typical year like this year or, you know, so I don't know, maybe you could just talk cadence a little bit this year and that will give me an idea of, you know, how you all think about it through just the typical seasonality.
spk09: Sure. This is Chad. I'll start and maybe Don fill in a sort of gloss over anything. The, you know, certainly we're generally one rig, one crack crew. So that's, that's generally pretty consistent throughout the year. So as far as timing drilling or completions activity, it's sort of, you know, 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, you know, 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 there. 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 the way the Ford 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.
spk10: Yeah, and I'd only add – I mean 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. And, you know, Chad talked a lot about, you know, 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. 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, you know, 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 volatilely. No, great to you, Stiles. Thanks for the time, guys.
spk05: And our next question will come from Michael Celia with Stifel. Please go ahead.
spk12: 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?
spk10: No, I think, yeah, just to make sure to clarify, no material cash tax payments through 26. So, you know, there'll be some, but not material. Yeah, 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, you know, 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 um we do we do have as a business i mean clearly we have the billion dollars where the nol is to help um offset any kind of uh change to the tax provisions but the easiest way to think about it is a year or so change and when we would be a cash taxpayer if you know steady state business plan through 26 as we've laid out we continue on okay good thanks and um
spk12: Chad, you mentioned the costs on the most recent Marcellus and Utica 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 two.
spk09: Yeah, so certainly, you know, 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. And so a lot of that has to do with taking advantage of existing infrastructure. We've made a huge investment into midstream and water infrastructure in Southwest PA, really 2018, early 19, and now really going into cash harvest mode, utilizing that infrastructure in Southwest PA and developing, you know, the SWPA Marsala 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, you know, predominantly through the six-year plan, you know, 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% Marsalis and about maybe 25% Utica sort of sprinkled in. Moving out of that area, you know, obviously going up to CPA, those are tremendous producers up in CPA, Deep Utica. You know, the Bell Point 6 well that we've talked about, you know, I think the latest public numbers we've put out there around the four and a half 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 pat a year. sort of through the long-term plan until we build some, we need some capital investment into a midstream system to truly unlock that area. And right now, I think we're just trying to assess what the proper timing of that is. It's sitting there ready to go in the event gas prices would, you know, justify increasing production or trying to grow. And Swipa Utica is sitting there, again, by all intents and purposes, with costs we've seen and the production levels we're seeing on the most recent pad, 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 assets, infrastructure assets we have in SWPA, or it will be there to tack on to the tail ends and sustain our business plan for years to come.
spk10: Yeah, 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. You know, that mix is, you know, 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. And, you know, although, you know, the economics can work, we're focusing on our best two areas for definitely the near term and, you know, through the plan.
spk05: Sounds good. Thanks for the color, guys. And our next question will come from John Abbott with Bank of America. Please go ahead.
spk06: Good morning. Thank you for taking my questions. The first question is on buybacks. You previously indicated that you could potentially allocate as much as $500 million of free cash flow 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 repaying down debt?
spk10: Yeah, just so it's just so clear. I mean, we didn't lay out a 500 million dollar target. We just said we had we had the wherewithal and the cash flow that we are generating. There's there's extra money that we'll have to utilize for other other things that are not debt pay down. And, you know, it's hard to have a complete exact science with the volatility that we've talked about on equity markets, debt markets, the political markets. environment everything else that's out there um with it so you know what we'll try to do is balance you know patience and being prudent with you know being opportunistic with um share buybacks and returning capital to shareholders along the way to or or call it balance sheet targets and you know how much and you know the pace of those will be to be determined based on you know the facts and circumstances as they change over time yeah also the um obviously the effectiveness
spk08: an impactfulness of growing for sure value of buybacks really comes down to 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 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.
spk06: Understood. And then 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. I mean, M&A is such a high hurdle for you just given your low cost structure. Is there a scenario where some dilution would be acceptable to you?
spk10: Yeah, I mean, this is Don. So, I mean, obviously, we look at these things holistically, right? When you look at, you know, 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 return. So, yeah, we do look at all the components, you know, together when we're making these assessments. So, if one piece of the components, you know, aren't good, but the other – other ones are really good, then, you know, you can kind of overweigh to make the decision on this. So, yeah, we do look at it on all the factors and, you know, with the ultimate goal of just increasing the intrinsic per share value for our shareholders. So I think, you know, we continue to assess all the pieces. We're just going to be, you know, making sure that it advances the value for CNX's shareholders.
spk08: Yeah, and I think, too, that, you know, the term we often use to describe our approach on M&A is just ruthlessly clinical. We just, it's just a simple matter of math. We follow math, and we're looking at both, you know, 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 acquired something and we sort of fall back on that classic descriptor of a strategic acquisition, which is typically code for something that's destroyed value, or two, you know, 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 it doesn't end well for shareholders. So we want to avoid those two types of scenarios.
spk06: Thank you very much, guys.
spk05: Appreciate it. And our next question will come from Noel Parks with TUI Brothers. Please go ahead.
spk07: Hi, good morning.
spk10: Morning.
spk07: I'm just noticing that in the release you sort of repeated the detail on your plan, 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 only allow shorter laterals, with gas as strong as it is, we're at 260 or better through 2023. I'm just curious, what would the economics be like on some of the shorter laterals? And just wondering if those would have any appeal, you know, cleaning up some of those during a time that you have a supportive economy. to put a price tag out there.
spk10: Yeah, no, we obviously, you know, look at all the components of the rate of return math whenever you're looking at dispatching wells and optimizing lateral lengths and, you know, 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, you know, what's the optimal lateral kind of changes depending on lots of facts and circumstances. But yeah, I mean, as you say, as gas prices, you know, rise, just more things become in the money period, whether it's you know, shorter, longer laterals, or whether it's, you know, call it tier two or tier three areas, or, I mean, heck, if gas prices go a little bit more, our CBM wells, you know, start being, you know, economic and, and, and developable at that point in time. So we, we look at all these, these things and, you know, some of the assets that kind of dispatch it in higher gas prices. And, you know, if that's a doable and, you know, that's something we just look at or like we would anything else.
spk07: Okay. And I was just wondering, um, 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 at least risk constraint keeps you from going longer?
spk10: No, like, I mean, like there's most of the way we handle the, you know, development of our patterns and inventory and well profiles, you know, well into the future, we're always kind of building and getting to where the pads optimize and efficient, you know, starting many, many years in advance. So, you know, net net from like geological constraints or something like that, there's really not a lot of restriction on being able to continue to call it managed pad builds to efficient levels going forward.
spk07: And just to follow up, are you considering pushing your lateral length even longer where the lease allows?
spk10: Yeah, so we've done both. We've done – I can't remember, Chad, what the longest lateral we've done is. Yeah, close to 20,000 foot lateral. So we've done longer ones. Like I said, it's facts and circumstances. It's, you know, the topography, like where you can get pads and how the lease boundaries sit and sort of where, you know, the right way to develop the area in connection with where the midstream systems are and, you know, for the topography that you have out here. So like I said, it's You know, the average is around 12,000 where we're at. 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 to kind of optimize, you know, all the pieces we have to get these caught and drilled in the most economical fashion.
spk00: Yeah, there is a point of diminishing returns. We'll start talking about long laggles. We always look at it to make sure we're optimizing it based off of the available technology to actually complete those things efficiently.
spk07: Right. Great. Thanks a lot.
spk05: And once again, if you'd like to ask a question, please press star then one. Our next question will come from David Heineken with Heineken Energy Advisors. Please go ahead.
spk02: 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 costs 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, you know, 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?
spk10: Yeah, and some of that we do do as well. Clearly, we don't have that many pads where the availability to do that would be there. And, you know, 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, yeah, the more sellers we have pads that we'll do, you know, two trips on, and we've kind of done that same phenomenon. And, you know, a pad build – not not having to build a pad again is obviously saves you money and the overall you know dnc per foot of of the well and you know that's something that we'll optimize on we just don't have as many legacy pads to do that as others gotcha so really as you think about the 25 percent of the utica in the future or if you ever come back to adding utica that would be
spk02: drive down some of your cost per foot on those wells. That's helpful. Thanks guys.
spk10: Yeah. Yeah. And then, you know, up in the CPA area, you know, the CPA Utica is more economic and then the CPA Marcellus, but the CPA Marcellus is good and CPA South Marcellus. I mean, there's some, you know, 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 PA area and in the CPA area.
spk08: Yeah, David, I think the way to think of our footprint in that context is annuitizing that type of behavior dynamic over years and decades. So for us in Southwest Pennsylvania, it's the Utica, right, taking advantage of all that shared infrastructure, pad water and midstream of the Marcellus. And then in CPA, for us, it's the Marcellus that would be doing the same, taking advantage of the existing infrastructure that's been capitalized because of the Utica. So those are really, you know, the drivers of the rate of return and the map behind two of our four horizons in a big way.
spk02: Thanks, guys.
spk05: 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.
spk03: Yeah, thanks, operator, and thank you, everyone, for joining us today. We look forward to speaking with everyone throughout the quarter. Thank you.
spk05: And the conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
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