Good day, and welcome to the CNX Resources' First Quarter 2021 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] 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 first-quarter conference call. We have in the room today Nick DeIuliis, our President and CEO; Don Rush, our Chief Financial Officer; Chad Griffith, our Chief Operating Officer; and Yemi Akinkugbe, our Chief Excellence Officer. Today, we will be discussing our first-quarter results. This morning, we posted an updated slide presentation to our website, 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, forward 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. 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, 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 is 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. And 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 7-year free cash flow plan, and we continue to expect will generate over $3 billion over those 7-years. Again, this is done by steady execution each and every day. Our long-term plan is largely…

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 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 are 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 FTE book, which allowed us to eliminate some unused FTE and exchanges for some FTE 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…

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 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 in the free cash flow. The top chart highlights that CNX is able to convert production volumes and 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 outsize 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 million and after the close of the quarter, we completed our semi-annual bank redetermination process to reaffirm our existing borrowing base. Lastly, as you can see on the slide, our public debt continues to trade in the 4% to 5%…

Thanks, Don. Good morning, everyone. I'm Yemi Akinkugbe, the Chief Excellence Officer here at CNX. A few of you may be wondering what exactly this role entails. The short answer is, I oversee and manage all operational and corporate support functions within the company. The longer answer is what I want to speak about in more detail today. As Nick briefly mentioned in his opening remarks last quarter, we are the leader in intangible, impactful ESG performance in our space. We've been focused on the underlying tenant of ESG and its benefit for generations. This has been a fact or a means we only talk about pandemic to certain interest for short-term in. That's not leadership, instead, the concept was part of our fabric long before the current management team joined the company, and 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 1 and Scope 2, CO2 emissions over 90% since 2011, something that few, if any of any public company can claim. Two, we were the early adopters and innovators of commercial-scale coal bed methane capture in the 1980s. This resulted in historical mitigation of cumulatively over 700 Bcfe - Bcf of methane emission that would have otherwise been vented into the atmosphere. Annually, we captured nearly as much methane from this operation than the nation's largest waste management company does on its landfill. That ingenuity and leadership on…

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

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

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 is still conservative, 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 powerful, they really are over the place where less than a quarter removed from 2020 were NGLs averaged 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, $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 of what we're focused on is being able to react as spot prices change. We sort of demonstrated that by moving up our two Shirley fracs, and being able to bring those two pads online in order to take advantage of the strong NGL prices that we're seeing in '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, but depending upon the spread between gas and NGLs. And I think if you look at the volumes, you'll see that our relative NGL yield came down during Q1. Well, that's because we are optimizing that frac spread. And what happened to NGL prices generally stayed where they were, but gas prices improved relatively in Q1. So, we move some of those called marginal volumes back to dry outlets, take advantage of the BTU uplift. And now that we've gotten through that strength of Q1 gas, I mean 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 pricing.

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, - 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 the cash taxes that we would 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 2026 is the current plan.

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

Wanted to follow up on a few of your prepared comments here. You talked about production dipping a little bit in the second 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 third quarter?

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 now. So, again nothing sort of - the production should be mostly similar throughout the year, but, sorry if I gave the impression that Q2 is going to be a big difference. It's - will 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. This materially higher? Or 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, probably just slight is another way to sort of describe. But 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, it's the easiest way to think about it.

Okay. And obviously, you guys were nice enough to talk a lot 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, we - predominantly our acreage footprint is dry. We do still have some wet areas. And yes, they - we'll get pads ready and we're reacting to NGL prices staying good. I mean the sequencing like we've talked, the pads that we're going to do over the next six or seven years are fairly static, but the sequencing and the order you do them, you would obviously try to change them and get some of the wetter ones moved up and have that 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.

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

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, pre-cash will continue 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 is a lot of other folks out there doing more allocation towards variable dividends and all. So Nick, or – you or Don, just wondering 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 year 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 was 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, where it wants to be first before we would entertain that. And second, I think you'd have to just look at the other factors that are there at the time, what our free cash flow yield is doing to determine if returning capital to shareholders via share buybacks or dividends is a smarter investment.

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

Yes. It would be great. Greater color add there Nick. And then just one, second here, a follow-on. Want to add a little bit, maybe a different spin on cadence, a little bit. You guys, you continue to see just out there natural gas price are obviously always a bit seasonal. And I'm just wondering, I guess, Chad for maybe you to Don. When you guys think about cadence, I think there is, what 37 or so TILs this year. Or even on a go-forward basis, do you - you guys are pretty highly hedged, so I'm just wondering maybe or maybe not this matters when - 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 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 sort of loss or anything. The - we certainly, we're generally one rig, one frac crew. So that's generally pretty consistent throughout the year. So as far as timing drilling or completions activity, it 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 lightest that I think I can ever remember seeing it. And so we curtailed some volumes, we shaped some volumes, cashed in some hedges, layered in additional winter hedges, and take it - and took advantage of that strong summer-winter time 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 begins to widen to the point that it makes sense to time production, then we will absolutely do that like we did last year. But right now, we don't have any active plan to do that based upon what - the way the forward strip currently looks. But like I said, we are 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 like we did last year.

Yes. 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 we have and all the factors that go into this stuff. And Chad talked a lot about the whole well delay production and delay some timing to kind of catch up contango when prices are weak and then prices are better. But we've done the opposite too similar with NGLs. We've done it with dry gas prices. If there is a bit of a spike in dry gas prices, we'll go ahead and get things online quicker. We have a bit of slack in the system to kind of do either one sort of delay it a little bit or pull it up a little bit depending on what those gas prices do, because I think they're going to continue to be really volatile both directions up and down, and shaping it quickly is something that, we've got the ability to do. And I think that will be a pretty good tool to use for the next several years as these things move pretty, pretty volatile.

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

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

Yes, I think, yes, just to make sure I clarify. No material cash tax payments through '26. So there'll be some, but not material. Yes, so the way we think, I mean obviously the Biden plan, there's a lot of moving pieces and where that actually settles and what gets approved is kind of to be determined. We're following it closely and sort of some of the characteristics on the IDC changes that they might be utilizing could change when we would get into the cash tax-paying mode by a year so. I'd say it's the easiest way to sort of think through it because of the profitability we do have as a business. I mean clearly, we have the $1 billion worth of NOLs to help offset any kind of change to tax provisions. But the easiest way to think about it is a year so change, and when we would be a cash taxpayer, if steady-state business plan through '26 as we've laid out, we continue on.

And, Chad, you mentioned the costs on the most recent Marcellus and Utica wells, pretty significant different surge. I want to see how the returns compare between those and any other factors you look at on your design to allocate capital between the two?

Yes. So, certainly, we believe that all of those areas generate returns - attractive returns. It's just become 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, that - we made a huge investment into midstream and water infrastructure in Southwest PA in really 2018, early '19. And now really going into cash harvest mode utilizing that infrastructure in Southwest PA and developing the [indiscernible] 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, with about maybe 25% Utica sort of sprinkled in. Moving out of that area, obviously, going into CPA, those are tremendous producers up in CPA deep Utica, the Bell Point 6 well that we've talked about. I think the latest public numbers we put out there around the 4.5 Bcf per 1,000-foot type production levels. And when you combine that with the recent capital efficiency that we've seen in the CPA deep Utica, the returns will be again very attractive. I think CPA, the plans, like I said, where will probably be about a pad a year, sort of through the long-term plan until we build some - we need some capital investment into a midstream system to truly unlock that area. And right now, I think we're just trying to assess what the proper timing of that is. It's sitting there ready to go in the event gas prices would justify increasing production or trying to grow. And CPA Utica is sitting there again by all intents and purposes with cost we've seen and the production levels we're seeing on the most recent pad where we believe that those returns will be in the money as well. And like I said in my prepared remarks, that's sitting there ready to quickly take advantage of in a strong gas price environment utilizing those existing asset - infrastructure assets we have in CPA. Or it will be there to tack on to the tailings and sustain our business plan for years to come.

Yes. So just to finish off what Chad said. So, our best return areas is right now, 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 four Southwest PA Uticas in the plan, just for blending purposes. And although the economics to work - our work focusing on our best two areas for definitely the near term and through the plan.

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

The first question is on buybacks. You've 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 that's under-appreciated. However, a number of times on this call you've mentioned commodity volatility. When you think about that, how do you think about buybacks at this point in time, that 500 - that potential $500 million target versus repurchase - paying down debt?

Yes. And just so - I was just sort of clear - I mean, we didn't lay out a $500 million target. We just said we had the wherewithal in the cash flow that we're generating. There is extra money that will 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, and everything else that's out there with it. So, what we will 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 the obviously the effectiveness and impactfulness of growing per-share 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 is power in that optionality. The second thought is, that is we deploy free cash flow toward debt reduction and building liquidity that is storage capacity. So it's a bit different in our minds from drilling the next pad or doing an acquisition and where - those are some capital decisions, this is not 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&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?

Yes. I mean this is Don. So, I mean obviously, we look at these things holistically, right. When you look at accretion, dilution math on per share, on per enterprise value cost structure, how much inventory sort of over there, the risk profile, what it is you're buying, the payback periods, the risk-adjusted return. 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 overweight to make the decision on this. So yes, we do look at it on all the factors and with the ultimate goal of just increasing the intrinsic per-share value for our shareholders. So, I think we continue to assess all the pieces. We're just going to be making sure that it advances the value for CNX's shareholders.

Yes. And I think to that, the term we often use to describe our approach on M&A is just ruthlessly clinical. We just - it's just a simple matter of math. We follow the 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. And what we don't ever want to do is get into one or two positions. One, where we acquired something and we sort of fall back on that, a classic descriptor of a strategic acquisition, which is typically code for something that's destroyed value, or to something that is largely or hugely speculative on a gas price view versus where the forward strips are. So, if you follow the math and your clinical about it, you'd typically more often than not the vast majority of times you'll 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.

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

I'm 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 $2.60 or better through 2023. I'm just curious, what are the economics or - what are 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 the time that we have the support of price deck out there?

Yes. No, we'd obviously look at all the components of the rate of return math whenever you're looking to dispatching and 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 kinds of changes depending on a lot 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. I mean, heck is, 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 kinds of dispatch it in 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 some places where the - there is some geographic or at least risk constraints keeps you from going longer?

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

And just a follow-up, are you considering pushing your lateral length even longer where the least allowance?

Yes. So we've done both. We've done - I can't remember Chad with 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 around 12,000 where we're at. We've kind of have some that are longer. We have some that are a bit shorter. And like I said, it will be facts and circumstances that kind of optimize all the pieces we have to get these call it drilled in the most economical fashion.

Yes. And there is a point of diminishing returns. I will start talking about long laterals. We always look at it to make sure we optimize any based off of the available technology to actually complete those things efficiently.

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

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

Yes. Yes, in some of that we - yes, 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 that we'll do two trips on and we've kind of done that same phenomenon on a pad build. Not having to build a pad again is obviously saves you money in the overall D&C per foot of the well and that's something that we'll optimize on. We just don't have as many legacy pads to do that as others.

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 sort of 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, CPA South Marcellus. I mean there is 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.

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

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.

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.