CNX Resources Corporation Aktie

Good day, and welcome to the CNX Resources First Quarter 2026 Q&A Conference Call.

[Operator Instructions]

Please note this event is being recorded. I would now like to hand the call to Tyler Lewis, Senior Vice President of Finance and Treasurer. Please go ahead.

Thank you, and good morning, everybody. Welcome to CNX's first quarter Q&A conference call. Today, we will be answering questions related to our first quarter results. This morning, we posted to our Investor Relations website an updated slide presentation and detailed first quarter earnings release data such as quarterly E&P data, financial statements and non-GAAP reconciliations, which can be found in a document titled 1Q 2026 Earnings Results and Supplemental Information of CNX Resources.

Also, we posted to our Investor Relations website our prepared remarks for the quarter, which we hope everyone had a chance to read before the call as the call today will be used exclusively for Q&A. With me today for Q&A are Alan Shepard, our President and Chief Executive Officer; Everett Good, our Chief Financial Officer; and Navneet Behl, our Chief Operating Officer. Please note that the company's remarks made during this call, including answers to questions, include forward-looking statements, which are subject to various risks and uncertainties.

These statements are not guarantees of future performance, and our actual results may differ materially as a result of many factors. A discussion of risks and uncertainties related to those factors in CNX's business is contained in its filings with the Securities and Exchange Commission and in the release issued today. With that, thank you for joining us this morning. And operator, can you please open the call for Q&A at this time.

[Operator Instructions]

Our first question will come from Leo Mariani of ROTH.

I was hoping to hear a little bit more about the Utica. I see you guys brought 3 wells on here in the first quarter. Any comments on, kind of, well performance or costs? I know you've been working hard to kind of continue to improve the play over time. So I just wanted to see if there was kind of an update there.

Leo, no, good question. We are continuing to develop the Utica program there. The most recent pad was a recent TIL towards the last part of the quarter. So we're a little ways off from providing any sort of production results from that. Everything we've seen so far, as we've mentioned on previous calls, very consistent with what our expectation of the reservoir is, and we're continuing to sort of, make progress on the cost side. But nothing new to update at this time. The way to think about it is probably towards the end of this year, we'll be in a position to provide more fulsome and we'll have a nice data set to provide to the market towards the end of '26, early '27 once these wells have had enough duration on.

Okay. And would you envision that as you guys develop a more robust data set, if the play continues to progress nicely, could we see a little bit more allocation to the Utica versus the Marcellus in the next handful of years? Or do you guys think that the Marcellus still is probably going to be a little bit economically superior based on kind of the current rate?

Yes. I think the Marcellus has the advantage of having the infrastructure already there, right? So we optimize for kind of the best economics per well, right? And right now, the Swift of Marcellus, you don't need to build new infrastructure for the most part because of all the legacy investment there. So you will see us kind of blend in more Utica over time as that's sort of the longer-term position for the company. But definitely, the Swift of Marcellus, we're in harvest mode there, and you're going to continue to see those for the next few years.

Okay. That's helpful for sure. And I just wanted to ask on your new tech business here. Any kind of updates there on any of the other business lines other than the kind of environment and credit monetization, which you guys have been consistently doing, specifically anything on AutoSep or anything on like CNG or LNG business you guys have mentioned in the past?

No, I think everything is consistent with where we thought it'd be at this point in '26. We're still waiting for, sort of, the final guidance on 45Z, but we don't think that's going to impact any of the projections we've made so far. So nothing new to update there, Leo.

The next question comes from Jacob Roberts of TPH.

On hedging, you guys are typically transacting on a longer-term basis than a lot of your peers. And so given what seems to be the prevailing theory of an improving gas base in that, sort of, 2028 plus time frame, can you give some context on what you're seeing in that 2028 market? I think you added another 13 Bcf to the book with this update. Just curious what you're seeing on that longer-dated market at the moment.

Yes. Yes. Again, on our longer-term hedges, we're certainly in a position to be more opportunistic maybe than we have in the past and patient. So as we see that price move up, and we've seen basis differentials tighten as well, and that's really helped us get to a better all-in realized price in kind of the Cal 28 market. So we're targeting to bring that up over time as we approach that year.

Okay. Perfect. I appreciate that. And then just kind of -- I know you made some changes to the balance sheet. Just curious what the next steps are from here on that front.

Yes. We did a very positive refinancing of our 2029 notes at new 8-year notes at 5 and 7/8s in the quarter. I mean, generally, we've been very consistent in that we try to push out the maturities to make sure that we're at least 2, 3 years out before our next maturity. So the next one up for us is a 2030 maturity that we'll handle well ahead of time. And it's all about keeping the maturity profile extended and making sure that we don't have particular periods where we have large maturity towers in front of us.

[Operator Instructions]

And our next question will come from Michael Scialla of Stephens.

I want to ask on in-basin demand. Some of your competitors are becoming a lot more confident on that, talking about that growing by more than 10 Bcf per day by the end of the decade. I want to see if you share that enthusiasm and anything you can share with us that the company may be doing to capture some of that demand?

Yes. No, I would agree that we certainly see the same sort of long-term optimism on the demand side. Some of the announcements that come out are sort of mind-boggling when you think about a 9-gigawatt sort of power center plant, there have been multiple of those proposed. So we're like everyone else, right? We see the announcements, and we're watching, monitoring as RFPs come out for gas supply, we're participating in those.

The magnitude of gas that's going to be demanded in-basin in Appalachia is going to need to be sourced by multiple producers. And if you think about the folks like ourselves that have the resource depth and sort of the creditworthiness to enter into long-term arrangements with these new demand sources, we're certainly going to benefit from that. So yes, we would share that optimism. The only question in my mind is timing, right? Is it 3 years? Is it 5 years? Is it 7 years?

Alan, do you see that developing more on the Ohio side? It looks like it's maybe ahead of Pennsylvania, and can you participate as much over there if that is the case?

Yes. I think for an Appalachian producer, just given the interconnectedness of the pipes, we're pretty agnostic to where it develops. You can wheel gas around here between the states pretty easily. Just as a sort of macro observation, Ohio has shown itself to be a little easier to do business with in terms of speed. It's a little bit flatter over there, too, for some of the data centers, and they have some of the intersection points with the long-haul pipelines like Clarington that make it very attractive.

Pennsylvania is also being competitive though. I mean you've got the Homer City plant here and the NextEra projects that they're still working on site selection, but have indicated they're going to be in the Mon Valley area. Those will certainly be in our footprint. But bigger picture, like I said, we're agnostic. We're just excited about the growth in demand. And as Everett mentioned, you're starting to see differentials tighten up in the out years, and we hope that trend continues.

Yes. Got it. I wanted to ask on your convertible notes. Can you say when during the quarter you expect that remaining, I think it's 209 million to convert? I'm just trying to estimate the diluted share count for the second quarter.

Yes. That maturity is on May 1 of this week. So the shares will be issued about approximately 12 million shares net issuance later this week.

Yes. And when we say net, that's included the effect of the capped call that we structured when we entered into the converts. So the 12 million is the net out the door.

This concludes our question-and-answer session. I'd like to turn the call over to Tyler Lewis for any closing remarks.

Great. Thank you again for joining us this morning. Please feel free to reach out if anyone has any additional questions. Otherwise, we look forward to speaking with everyone again next quarter. Thank you.

The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.

Good day, and welcome to the CNX Resources 2025 Fourth Quarter Q&A Conference Call. [Operator Instructions] Please note that this event is being recorded.

I would now like to turn the conference over to Tyler Lewis, Senior Vice President of Finance and Treasurer. Please go ahead.

Thank you, and good morning, everybody. Welcome to CNX's Fourth Quarter Q&A Conference Call. Today, we will be answering questions related to our fourth quarter results. This morning, we posted to our Investor Relations website an updated slide presentation and detailed fourth quarter earnings release data such as quarterly E&P data, financial statements and non-GAAP reconciliations, which can be found in the document titled 4Q 2025 Earnings Results and Supplemental Information of CNX Resources.

Also, we posted to our Investor Relations website our prepared remarks for the quarter, which we hope everyone had a chance to read before the call as the call today will be used for Q&A. With me today for Q&A are Alan Shepard, our President and Chief Executive Officer; Everett Good, our Chief Financial Officer; and Navneet Behl, our Chief Operating Officer.

Please note that the company's remarks made during this call, including answers to questions, include forward-looking statements, which are subject to various risks and uncertainties. These statements are not guarantees of future performance, and our actual results may differ materially as a result of many factors. A discussion of risks and uncertainties related to those factors and CNX's business is contained in its filings with the Securities and Exchange Commission and in the release issued today. Before we get into Q&A, I'm going to turn it over to Alan for a couple of comments related to the recent cold weather events. Alan?

Thanks, Tyler, and good morning, everyone. We normally don't provide opening remarks on these calls, but I'd be remiss today if I didn't take a moment to acknowledge the hard work and incredible efforts of not just our CNX team, but of all the men and women of the natural gas industry who are working to keep the heat and lights on across America during this extraordinary cold weather event we are experiencing.

Speaking on behalf of myself, everyone in the room with me and all of our fellow citizens who are staying warm today. Thank you for everything you've done, everything you will continue to do in the days, weeks and years ahead.

With that being said, operator, can you please now open the line for questions?

[Operator Instructions] The first question today comes from Jacob Roberts with TPH.

We wanted to ask about the commentary on the front half weighted capital and TIL program and how we should be thinking about that translating to a flat production profile across the year. Just wondering if you can provide any more granularity on how you're thinking about the TIL schedule quarter-to-quarter.

Yes. Thanks, Jacob. This is Everett. You can generally think about the first half CapEx being about 60% of the year's total. And then from a production basis, it's pretty flat throughout the year. But the weighting of that capital to the first half gives us some flexibility in the second half of the year to potentially accelerate frac activity if conditions warrant.

Okay. Great. That's helpful. And turning to the RMG business line, we're curious to how you view the outlook on the AEC pricing. And is there a pathway to getting that back to the $65 million or $75 million annual run rate? And in terms of the 45Z outlook, is it fair to assume that the $20 million or kind of grossed up $30 million, is that also firmly tied to the methane stream in terms of the volume being relatively steady going forward?

Yes. So thanks for the questions there. Let's start with the PA Tier 1 rec market. So that market has been pretty stable since, call it, spring of last year. With the Trump administration coming in, it softened a little bit. I think longer-term outlook for that market, the prices you're seeing now are basically what you need to underwrite sort of new solar and wind activity in the PJM markets. So for -- for value per megawatt hour to increase there, you're going to need to see some of the step-ups in the required percent of contribution to the grid from renewables. So that's sort of the long-term bull case as those standards tighten, you should see pricing move up. But in the near term, it's sort of settled into the marginal cost of bringing on new renewable supply.

On 45Z, yes, I think the way to think about that is at current production levels, we're able to generate on a run rate basis, about $30 million a year with the initial proposed guidance. And we'll see what the final guidance looks like when it comes out if there's any adjustments to that.

The next question comes from Leo Mariani with ROTH.

I was hoping you could talk about the Utica program here in 2026. I'm only seeing kind of 3 turn-in lines, probably a little bit lower than I expected. It seems like the company has been very excited about the Utica and made some good progress. So it just seemed like maybe it was a little smaller program this year. So just trying to reconcile that, but maybe some of this is just timing where maybe some of the 26 wells are coming on next year.

Yes. I think it's the latter, Leo. I appreciate the question. I mean it's really nothing to indicate the underlying kind of belief in the Utica or anything like that. It's just we have a lot of TILs from last year coming online. We have some Southwest PA inventory that we want to harvest that's really economic. And then we're going to continue in the last half of the year back at it reps at the wellhead on the Utica. So I don't know, Nav has got anything to add, but nothing to read into on sort of the TIL timing there.

Yes. Leo, I can add, we are really confident of our deep Utica program right now. And as Alan mentioned, this is just a timing issue, nothing else. In fact, we'll be teething about 5 Utica laterals this year. So it's just a function of timing on when we complete it.

Okay. That's very helpful for sure. And then, Alan, you kind of went up the call talking about weather here. Just wanted to get a sense, are you guys expecting some disruptions to the operations or the volumes here in the first quarter? Obviously, it sounds like your team is doing a great job, but I just wanted to get a sense if you think there's some impact here.

No, we're not. So our team has been preparing for the last weeks heading into this event. They've done a tremendous job keeping the field running. The numbers that we put out today include any expected disruptions. So nothing on that front.

Okay. That's helpful for sure. And then just lastly, on your new tech business. I wanted to get a sense if there's any update in terms of how some of the other businesses are progressing like AutoSep on the service side. And I know you guys have also discussed kind of some CNG, LNG ambitions over time.

Yes. On the AutoSep, I think as we mentioned before, we fully internalized, adopted that technology. We use it on our flowbacks, provide tremendous cost savings, environmental and safety benefits. We are the sort of non-op on that. We've outsourced that to an OFS company who's continuing to roll that out across the Appalachia here. Everything we're seeing is it's starting to be adopted, and we think '26 might be an uptick year for that, but nothing contributing yet materially to the financial bottom line. When it does, we'll provide guidance on that. As far as the other businesses, the tech still exists for those businesses, but just nothing material to update on those right now.

The next question comes from Michael Scialla with Stephens.

You guys said in your prepared remarks, you expect to be responsive to any material changes in gas prices this year. Everett, you mentioned you'd consider adding a frac crew in the second half of '26. I wanted to see, is that built into the CapEx guidance range, that $20 million variance for this year? Or any more detail you can provide there would suggest what CapEx could do in the -- for the full year?

Yes. Michael, yes, any uptick in activity is not included in our base ranges. What we're seeing right now in terms of pricing after you get beyond the February contract where falls off pretty significantly in terms of the strip. So we're not seeing the price activity yet, though kind of incentivize us to add frac activity in the second half of '26.

Yes. Just to add on, we're not going to chase sort of spot activity. When we talk about adding, it would be some sort of long-term call associated with new infrastructure, new power plants, something like that, that would really get the '27, '28, '29 strip moving. We're not going to try to jump around to catch a month of pricing.

And then I just want to see if you could add any color on the 3 deep Utica wells you turned in line for the quarter. I realize it's early days, but anything you can say there in terms of cost or production?

I think everything is generally aligned Nav, I don't know anything to add?

Yes. On -- like our team has been like really working on the drilling cost. And like we had guided, like our average Utica cost is about $1,700 per foot. So that's on the cost. And second, on the performance, these wells are in line with our expected performance. And we are pretty confident. And now we are into the spacing evaluation. So we have like 2 spacing tests going on now. One is 1,300-foot spacing and then second is 1,500-foot spacing. And as we get more results from these tests, we'll be getting that information out.

Next question comes from Kalei Akamine with Bank of America.

For my first question, I want to ask about coal mine methane volumes, kind of a modest downtick year-over-year, maybe 0.5 B off 17.5 from last year. Can you kind of help us understand the activity set behind the volumes, how that may compare to last year? And how many years of visibility you have looking forward?

Yes. The way to think about it, those volumes are really the primary driver is the underlying mining activity at that particular mine. Our expectation is that we're sort of in that range moving forward, assuming that mine continues to operate. That life of mine is 20-plus years, it's a metallurgical mine in Virginia, if you're familiar with it. So really, any sort of wiggle you see in volumes is just a sort of function of the pace of their longwall and what needs to be gas.

For my second question, can you just remind us on the hedging strategy? When do you guys expect to be done with 2027?

Yes. Yes, Kalei, I can take that. So for '27, I mean, we're -- as we approach that year, we look to be approximately 80% hedged. '27 is a really good year for us. Right now, we have kind of a weighted average NYMEX price of about $4. So we target that level around there based on what we can get in the basis markets as well. So at $4 kind of swaps, the business performs really, really well at that level.

And we're 60% hedged already on that.

Yes, we're a little over 60% hedged on that.

Yes. So we'll dig into the rest of that book throughout the year. Given we're already 60% hedged, we can be a little more opportunistic on putting those on. But as Everett mentioned, we'll be at our 80% sort of number heading into that year.

The next question comes from Jeff Bellman with Daniel Energy Partners.

I had 2 questions. First one, I appreciate the comments around not chasing a front-month gas price or a near price. But maybe just to expand on it, can you frame maybe a little bit more of kind of what you want to see? You mentioned a '27 strip, '28 strip. Is this something where you want to get through the winter, kind of see where storage levels end in terms of kind of timing on any kind of increase in activity? Just maybe a little bit more on kind of how you're thinking about level setting from maintenance to maybe something higher?

Yes. So maybe break it into 2 parts. I think if you think long term, right, we've been in maintenance of production, give or take, for the last 6 years, and that's really a function of just the constraints up here in Appalachia, the unwillingness for regulators to allow additional pipelines to get gas to where it could go. And then some of the projects you are seeing for potential in-basin demand, they're sort of longer lead projects with the new power and AI demand. We're hopeful on those, but they're still a few years out. So there's no reason to build those volumes just yet.

In terms of jumping up or down 5% in any given year, to make that decision as part of your planning cycle, you want to be able to have pretty good visibility that the prices aren't going to slip away from you by the time to bring the volumes on. So you'd want to hedge off that if you were going to increase production. And then you're just always trying to manage your TIL count and your DUC count to give you a little bit of flexibility. But that's all just sort of short-term tactics as opposed to sort of the longer-term strategy, which we'd like to see, which is actual increasing on the demand side.

Great. Yes. So a follow-up question on that. Can you just speak more broadly on incremental takeaway? I get it on the greenfield difficulties, but I'm hearing more and more, there's smaller projects, brownfield expansions, moving gas west out of Pennsylvania into Ohio, kind of some of the bigger data center growth. Just any thoughts on how everybody is doing in terms of kind of pushing a little bit more gas west and south?

Yes. A lot of the low-hanging fruit on those Western bound projects was taken up last decade. I mean there are some proposed on the table that gets you back sort of to the Midwest area, right, the Leb kind of area. But those haven't been greenlit yet. I mean, the cost of some of those projects is just a little bit challenging just yet. I think everyone is sort of waiting to see sort of what the final outlook is here on AI demand, right? You need kind of those guys to make their decisions and then we'll be right behind them with the fuel supply to support all that. But yes, there's some cats and dogs out there, but nothing material to kind of move anybody off maintenance production in my view.

The next question comes from Betty Jiang with Barclays.

I have a question on the 2026 activity of going to do the 3 wells in Marcellus in CPA and 3 wells in Utica. Bit surprised just with the Marcellus activity. What's your expectation for the Marcellus productivity in that region?

Yes. So the way to think about that, that's kind of our stacked pay development, right? So we're going first with the Utica and then you're just thinking about putting incremental laterals above that on the Marcellus. I think you're in the sort of just shy of 2.0 range, right, with the high 1s on those wells.

And back to your core Southwest PA Marcellus, where you're focusing most of your activity. Could you just remind us what is your like latest inventory runway in that area if you maintain at the 2026 level?

Yes. So I think we'll put out the updated acreage counts at the end of Q1. But generally, we're in the, call it, 40,000 to 50,000 acres sort of remaining. So we'll get you towards the end of the decade.

This concludes our question-and-answer session. I would like to turn the conference back over to Tyler Lewis for any closing remarks.

Great. Thank you for joining us, everyone, this morning. Please feel free to reach out if anyone has any additional questions. Otherwise, we look forward to speaking with everyone again next quarter. Thank you.

Thanks, everybody.

Thank you.

Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Good morning, and welcome to the CNX Resources Third Quarter 2025 Q&A Conference Call.

[Operator Instructions]

Please note, this event is being recorded. I would now like to turn the conference over to Tyler Lewis. Please go ahead.

Thanks, and good morning, everybody. Welcome to CNX's Third Quarter Q&A Conference Call.

Today, we will be answering questions related to our third quarter results. This morning, we posted to our Investor Relations website an updated slide presentation and detailed third quarter earnings release data, such as quarterly E&P data, financial statements and non-GAAP reconciliations, which can be found in a document titled 3Q 2025 Earnings Results and Supplemental Information of CNX Resources.

Also, we posted to our Investor Relations website our prepared remarks for the quarter, which we hope everyone had a chance to read before the call as the call today will be used exclusively for Q&A.

With me today for Q&A are Nick DeIuliis, our Chief Executive Officer; Alan Shepard, our President and Chief Financial Officer; and Navneet Behl, our Chief Operating Officer.

Please note that the company's remarks made during this call, including answers to questions, include forward-looking statements, which are subject to various risks and uncertainties. These statements are not guarantees of future performance, and our actual results may differ materially as a result of many factors. A discussion of risks and uncertainties related to those factors and CNX's business is contained in its filings with the Securities and Exchange Commission and in the release issued today.

With that, thank you for joining us this morning. And operator, can you please open the call up for Q&A at this time?

[Operator Instructions]

Our first question comes from Zach Parham from JPMorgan.

First, Nick, congrats and good luck in your retirement. And Alan, congrats on your new role.

First off, I just wanted to ask on the buyback. You had a sizable buyback during 3Q. It was the highest since, I think, 4Q '22. Can you talk about what drove that uptick in buybacks and how you think about the pace of the buyback going forward?

Yes. I think the primary driver was a significant free cash flow generator in terms of what we were able to do for the quarter. Our underlying process for evaluating whether or not we're doing buybacks versus other capital allocation opportunities hasn't changed. We continue to view the business valuation very attractive relative to its intrinsic value.

And then my follow-up, just wanted to ask on the Utica acquisition that you made on the Apex acreage. Could you give us a little more color there? Do you now have Utica rights across the position? If not, are there -- are you looking to make other acquisitions where you could get more Utica rights on that acreage?

Yes. If you recall, when we did that acquisition, there was about 30,000 Marcellus acres kind of the footprint for the whole asset, and it came with about 8,000 Utica rights. So what that transaction represents is we really went out there and got the remaining unleased Utica rights that underlies that footprint for Apex. And now we're able to go back in and leverage all that infrastructure kind of like we envisioned when we did the acquisition.

The next question comes from Leo Mariani from ROTH.

I wanted to see if there's any type of update on new tech here. Specifically, I was just curious if there's any update on kind of the oilfield service auto business, perhaps the CNG kind of LNG business and/or just status of 45Z as you guys see it?

Yes. So let's start with 45Z. So we're still in the period where we're waiting for the notice of final rule-making on 45Z, and we expect that before the end of the year. And then there'll be a comment period and a finalization of that rule, hopefully in the early first half of 2026. All that's subject to the government reopening and things like that. But once we have that, the expectation is that the guidance we provided last quarter on 45Z, that $30 million a year run rate will be sort of confirmed with that guidance. In terms of oilfield services, we have outsourced sort of the operational part of that to our partner on that, and they're continuing to make progress in rolling out those different technologies, but nothing material in sort of the current quarter for '26 as of yet.

Okay. And just in terms of the plans as we roll into next year, just at a high level, it sounds like the company still wants to stay in maintenance mode. Should we expect production is not a whole lot different in '26? And would that be similar for spending as well? How are you guys thinking about that?

Yes. I mean we'll give you the full detail on the guidance when we get to January. But generally, I would expect to see maintenance mode, right? We're still going into winter full storage, and we'll see what kind of weather we get this winter. And we need to see some of these longer-term calls on gas develop before you'd be thinking about doing anything other than that.

Okay. That makes sense. And just on M&A, obviously, you guys sold a little asset, bought another asset, seems kind of longer-term neutral on cash. But just what's the company's appetite in general for deals? Do you see other things that you'd like to pick up in Appalachia and perhaps there's other Utica deals out there that you guys would like to consider?

Yes. We look at everything that comes to market, but our threshold is acquiring ourselves, right? So unless there's an opportunity that outcompetes that opportunity, you won't see us do anything, right? So that's sort of how we think about it, but we're certainly open to anything if the math works.

The next question comes from Noah Hungness from Bank of America.

Just for my first question here, I was just hoping you could kind of unpack some of the moving pieces on your free cash flow guidance. Even when you take out the asset -- the additional asset sales, it looks like free cash flow guide is roughly flat to where it was before, even though the adjusted EBITDAX guide moved down and CapEx moved up. I was just hoping to unpack some of the moving parts there.

Yes. So the way to think about that is our free cash flow guidance includes all working capital adjustments, right? So if you try to take just EBITDA and CapEx, you got to account for sort of fluctuations in AR and AP. I mean we give you a sort of rough number to target for, and we try not to move that number around a bunch. But you're going to see movements like you see here where we're refining guidance throughout the year. But we're still confident we'll be at kind of the range we guided to, $575 million pre-asset sale number.

Great. That makes sense. And then on the Utica acquisition here in Pennsylvania, could you maybe talk about -- are there any requirements for drilling on that acreage next year? Or is there any acreage that may be expiring near term that you'll want to drill on to hold it?

Yes. So I mean, we plan to develop the field. Obviously, that's part of the underwriting case for making the investment. The exact timing of that development, I'm not going to get into at this point, but you'll see that fold into our development plan in the years ahead.

The next question comes from Michael Scialla from Stephens.

I had a couple of questions on the Utica. I guess as you think about next year's plan, is there any thought about trying to delineate the play any more with wells maybe further north or further south? Or do you plan to stay kind of in that area that you've been developing so far?

Yes. I think the plan for next year is really just focused on sort of the operational side of it, right? Nav and team have done a great job sort of driving down costs, and we want to give them a couple more opportunities to do that. We're pretty confident that we have a view on where the fairway is. So I don't think there's a burning desire to do much exploration either north or south.

Yes, I think we are pretty confident in our geological model. So our plan is to just step up the development of the play.

Makes sense. I wanted to see on -- in terms of well costs, where do you see the opportunities there? And does the Utica require a different rig? And if so, you've been just running one rig most of the year. Are there further efficiencies that could be had by keeping a rig running continuously in that play?

Yes. So if you think about -- I'll let Nav get into the details on rigs and things like that, but just at a real high level, the efficiencies are all on the drilling side, right? The completions is sort of pretty well known at this point. So what they're focused on is getting drilling days down. So maybe Nav, talk about that a little bit.

Yes. Like the rigs that we have right now are fully capable of drilling the deep Utica. We don't have any issues with that. And over the last 12 months or so, we have made really huge strides on the drilling side. We've been able to increase the efficiency of drilling the whole well and have cut down the days on the pad pretty much. And basically, on the drilling side, like our drilling operations are pretty steady. They're very repeatable. And best of all, we are improving and making up big efficiency gains to get the well down faster and reduce our cost. So...

Yes. And in terms of guidance on the cost per foot, we're still at that sort of $1,750 range for right now.

And then just to kind of add to that, like last year, our drilling costs on Utica were like about $2,200 a foot. So we are down almost 20% to $1,750 per foot.

The next question comes from Jacob Roberts from TPH.

I wanted to start on the well outperformance that we've seen over the past several quarters. I'm curious if you could provide some color on if this is a function of better-than-expected declines on older vintages? Is this better new well performance? And how durable do you think these results are and how that translates to your longer-term capital efficiency plans?

Yes. I think for this year, you're seeing 2 things, right? There's some outperformance on the Apex assets that we acquired, in particular, some of the big pad that we brought in right when we acquired it. And then you're seeing outperformance on some of the new products that got converted this year. In terms of long-term performance and capital efficiency ratios and things like that, that remains to be seen. But we're -- our focus is not on that, right? We're still in the sort of flat production mode and focused on generating as much free cash flow as possible.

Great. And then maybe if I could just ask your opinion on current in-basin demand and power generation and all that topic you hear and your thoughts there and ability to participate perhaps?

Yes. No, we're still long term, extremely bullish on the prospect for AI generated new demand come in the basin. Obviously, we sit on an enormous resource base here that can be developed. Still in the early innings, still a lot of talk with folks about developing some of these projects, but I can't say exactly when it's going to occur, but it definitely -- all the math suggests that Appalachia and all the gas up here needs to be part of that mix moving forward.

And Jacob, just to add to what Alan said, the other issue underneath all of this that sometimes gets lost with the excitement of AI demand and in-basin demand is the increasingly obvious need for additional pipeline infrastructure to get these low-cost BTUs and molecules from this basin, not just within the basin, but to wherever else the demand centers may be. So until that happens, AI sort of demand gets fulfilled in basin from our perspective. And then if that infrastructure gets built, other regions across the nation can start to participate more wholesomely in this AI revolution.

The next question comes from David Deckelbaum from TD Cowen.

I just wanted to echo the sentiments, congratulations to Nick and Alan. Just also wanted to ask on -- welcome. The activity for the fourth quarter, you have the frac crew coming back to work. I still wanted to get some color on the timing of the TILs. It seemed like the guidance have been more of a December time frame. I think last quarter, when we checked in, the macro perhaps seemed a little bit more precarious. And perhaps now things are tightening up a little bit. So how do you guys think about that in terms of turning on new volumes into the winter season here?

Yes. So we started the frac crews. I think we mentioned in the prepared remarks, kind of in that October time frame. So the expectation on those TILs would be sometime in December, right? So it'll be later in the quarter. In terms of the macro for '26, things have kind of settled into a trading range, but we're still not to the part of winter yet where you can have a good kind of read on where we're going to exit winter. So we'll see. But I think activity is going to look sort of like it did last year, right? We have a concentration of completion activities in Q4 and Q1, and then you set up yourself to be able to be flexible in '26 to respond to whatever sort of pricing environment develops.

Appreciate that. And my follow-up is just, obviously, you guys closed a couple of deals this quarter. It seems like the basin in general that there's been a lot more land spend through all your peers right now. I guess, is there -- can you just generally speak to that environment right now? Are we just seeing a lot more horse trading or folks kind of willing to transact on single zone areas? It seems like we should be underwriting perhaps a larger land spend in the '26 time frame and perhaps beyond as maybe these opportunities are increasing.

Yes. So maybe I'm not going to speak to the activities of some of the peers that happened down in West Virginia and Ohio. But definitely in Central PA, where we're focused on sort of the deep Utica development in the long term, you see more interest as folks start to understand the sort of potential of the reservoir, some of the transactions we've seen up there. You kind of have a moment in time here where there's an opportunity to pick up some of the acreage that still may be open or held by folks that are looking to deal with it to some of the more consolidated players in the area.

Appreciate that. And just to confirm real quick, the acres that you sold out of the Marcellus rights, are those areas where you've already developed Utica or those are areas that you intend to develop Utica in the future?

Those would be the Ohio areas where we've already developed the Utica.

[Operator Instructions]

And our next question comes from Betty Jiang from Barclays.

I want to ask about the -- pretty small, but in the guidance, the increase in the non-D&C capital, what's driving that? And as I'm hearing just more focus on deep Utica development going forward, is there a need for facility infrastructure spend going forward for you to optimize development there?

Yes. So maybe for your first question in terms of just the $7 million bump to the midpoint there, that's really just timing. I mean we build all of our midstream and water infrastructure. So sometimes you're just talking about a project sliding around 3 months or so, something like that. So it's really just noise on that front. Longer term, the way we think about infrastructure development as we move to Central PA, because our decline rates are so low, there will be -- need to be additional infrastructure, but it's not going to be anywhere near the scale that you saw last decade, sort of midstream build-out cycles that occurred. We're talking about adding a handful of pads a year. So you're able to really just sort of meter out that spend at a different pace from what we've seen historically.

Yes. And I can add to that comment, too, is, as I told earlier, that we are pretty confident of the model. So we will just be moving from pad, which are contiguous to each other. And so our infrastructure spend just will be like a little bit of additional infrastructure rather than in a delineation model where you have to like delineate the wells and build a whole fairway model. So we are getting into a more efficient infrastructure spend, so which won't change from year-to-year. It will be like pretty steady, just like we have in our drilling program.

Got it. So the non-D&C CapEx as a percent of total, probably going to be fairly steady.

I mean it will be -- it won't be anything like last decade. There will be periods where you maybe need to add a station or something like that, but it's nothing on the scale of last year. And as Nat pointed out, the goal is to be as efficient as possible with that spend given that we're able to kind of do return trips and have a focused development plan that just kind of steps out as opposed to needing to go to the extreme end of a field and build infrastructure to that part of it.

Great. And my follow-up is on the back to the deep Utica development. I know there's been many questions asked around that. But what I'm hearing is the focus is really trying to get the per foot cost down. And as we have seen in the past with play development, it's just about steady-state development and park a rig there and optimize and reduce drill time. And with one rig running, it just seems that's not moving between the Southwest and Central that's just not the most efficient way. Is there a possibility for us to start seeing like one dedicated rig being allocated to the Utica to maximize that efficiency?

Yes. I think you nailed it, like this industry is incredible. The engineers in the industry are incredible when it comes to optimizing development once you given up reps at any particular project, we do try to align our development plans so that we go back-to-back sort of on those types of pads. But we will have Southwest PA wells developed next year as well. So it all gets taken into consideration. But your broader point is the right one that we're at $1,750 per foot right now is what we're guiding to. And my expectation would be that we're able to drive that down as the engineers do what they do.

And then to add to that, like most of our pad development, we have like 3 to 4 wells that we are testing right now, especially with the spacing of 1,300 and 1,500 feet. So us being on a 3- and a 4-well pad leads to a lot more efficiency than it would otherwise appear in other place. So our team is actually making progress almost like section by section, and that's why you see the 20% reduction in costs. So -- and that will continue to be there, right? So we will focus on increasing drilling efficiency and reducing the cost no matter what. So -- and that's the advantage that we have in CNX with the acreage position we have right now.

There are no more questions in the queue. I would like to turn the conference back over to Tyler Lewis for any closing remarks.

Great. Thank you. Thank you again for joining us this morning. Please feel free to reach out if anyone has any additional questions. Otherwise, we look forward to speaking with everyone again next quarter. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

Good day, and welcome to the CNX Resources Second Quarter 2025 Q&A Conference Call. [Operator Instructions] After today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note 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, everybody. Welcome to CNX's second quarter Q&A conference call. Today, we will be answering questions related to our second quarter results. This morning, we posted to our Investor Relations website an updated slide presentation and detailed second quarter earnings release data such as quarterly E&P data, financial statements and non-GAAP reconciliations, which can be found in a document titled 2Q 2025 and Earnings Results and Supplemental Information of CNX Resources.

Also, we posted to our Investor Relations website, our prepared remarks for the quarter, which we hope everyone had a chance to read before the call. as the call today will be used exclusively for Q&A.

With me today for Q&A are Nick DeIuliis, our Chief Executive Officer; Alan Shepard, President and Chief Financial Officer; and Navneet Behl, our Chief Operating Officer.

Please note that the company's remarks made during this call, including answers to questions, include forward-looking statements, which are subject to various risks and uncertainties. These statements are not guarantees of future performance and our actual results may differ materially as a result of many factors. A discussion of risks and uncertainties related to those factors in CNX's business is contained in its filings with the Securities and Exchange Commission and in the release issued today.

With that, thank you for joining us this morning. And operator, can you please open the call for Q&A at this time.

[Operator Instructions] And your first question comes from Zach Parham with JPMorgan.

I wanted to ask on the 45 lease tax credit. Could you just give us a little detail on the timing and ability to claim those credits. And as the rules are laid out today, would those credits just run through 2029?

Yes. Zach, good question. So the way the program is set up currently, right, as the initial rule guidance, as you point out, there needs to be final rule making. As long as everything comes in, in line with the initial guidance, the first year eligibility to claim credits would be in 2025. So you saw in our materials, we were talking about 2026, would be the first potential opportunity to get some of that $30 million a year run rate.

And then yes, the program got extended under the OB through '29. It would be the first time that it would be up for re-extension.

And also just wanted to ask on activity levels at the E&P business. Any plans to grow volumes here? I know at one point, you all talked about having optionality to ad some activity back in the second half of the year? And if not, can you talk about what a maintenance program might look like in 2026? Would that be flattish CapEx year-over-year? Just trying to get a sense of what activity levels may look like.

Yes. So maybe on the first one, we were positioned with some optionality Had we seen sort of the end of year storage levels stay low. I mean at this point, it's pretty clear that we're going to creep towards kind of 4 TCF and storage. And under that scenario, we're just going to maintain the initial set of activity that we planned for the beginning of the year. So no changes expected at the current time.

When we think about the sort of capital efficiency levels, think in way to do that is to sort of tie back to what we guided to a few years back or a few quarters back. The 2 numbers that stand out are sort of the $580 million of production or 580 Bs of production over the $500 million CapEx, so that ratio is about $0.85 per million in terms of capital efficiency.

I think moving forward, if you set aside the actual production well target, which we always talk about as being a function of optimizing free cash flow per share, that's the right ratio to kind of think about the business' capital efficiency moving forward kind of that mid-80s range and middle wiggle plus or minus a little bit in any given quarter, just with the lumpiness of the 1 rig program, but that's the right way to think about it moving forward.

And your next question comes from Leo Mariani with ROTH.

I wanted to see if you could get a little bit more color on drilling and completion activity levels in the second half. I know you all have said that CapEx was pretty front half weighted in '25. But just looking at your turn-in-line schedule, the vast majority of turn in lines late happen here in 1Q. So if you could kind of maybe speak to whether or not there's a bit of a lull in activity here in the second half and maybe that activity kind of picks up a little bit in the winter. And then could you also kind of relate that to CapEx trends? I mean it looks like CapEx is down a little bit in 2Q versus 1Q, but maybe just kind of help a little bit with the trajectory on CapEx in the second half.

Yes, sure. Sort of similar what we talked about last time, LEO. Basically, the bulk of the tills were weighted towards the front half of the year. Our next batch of tiles would be towards the latter part of Q4. So what you'll see on the production front is kind of sequential decline, so it will be lower in Q3 and then lower in Q4 until that next batch tilt comes on. And then CapEx will track that, right? So CapEx will be lighter in Q3 and then pick back up in Q4 when we get back to it on the activity front.

Okay. So it sounds like there's a bit of a hiatus in activity then it kind of picks off late this year to get you all ready for kind of the winter in '26. Is that kind of the way to think about it?

Yes, that's the right way to think about it. We're going to continue to run the 1 rig program on the drilling side and the completion activities will hit a bit of a lull, and then those will pick back up in the fall as we get ready for the TILs that I talked about in the December time frame.

Okay. That's helpful. And then just on the Utica, obviously, you'll seem excited about that. It sounds like the costs are already below your target here on the wells. It's nice to see. At this point, given you've beaten the target, do you think there's more room to go on the cost side or maybe that can kind of come down? And apart from the cost, could you kind of speak to the actual well results, production performance? How are the results trending versus your expectations? And maybe just overall, how do you see this kind of competing with the Marcellus?

This is Navneet. So I just wanted to kind of outline on the Utica. We've done a really -- team has done a really great job over on optimizing our drilling and completion operation over the last couple of years. We're really pleased with the performance so far, but we're not satisfied yet. So -- and we are aggressively trying to improve the performance over the next few quarters. So stay tuned on where we can get down -- increase our operational efficiency and reduce our costs. So that's one.

Second, on the performance, all our Utica wells, our performance are within our expectations and our latest TILs that we got in Q2 are slightly above our expectation. So we are really excited about the deep Utica play, and we look forward to kind of continuing to kind of get more wells in there.

And then, Leo, maybe I'll address the last part of your question on how we think about the Utica and the Marcellus sort of mix. So we've been very intentional in giving Navin operating team a nice runway here to really demonstrate their prowess in being able to drive these costs down.

Moving ahead, obviously, we're going to continue to develop our core Southwest PA field over the next few years. But we also, as Nav pointed out, we want to keep getting him reps at the Utica well head there, so you can continue to work on cost efficiencies.

Okay. I appreciate all the detail.

Thank you.

And your next question comes from Noah Hungness with Bank of America.

I was hoping to ask on 45Z again.

Yes.

When do you think you'd be able to reach that $30 million a year run rate? And when you do realize the full $30 million of additional free cash flow from 45Z, should we think that all of your RMG gas would be sort of shifted to qualify for this 45Z opportunity? Or will some of it still be used to qualify for the PA AEC Tier 1 credit?

Yes. So the way to think about timing, like I said, so '25 is the first year of eligibility for the program, but the cash associated with that wouldn't occur until you file your tax return for '25 and '26, right? That's when you create the tax credit that would be fungible and you can convert that to cash in the market.

In terms of volumes that qualify, I mean, bigger picture, our initial read on the guidance is that it's stackable. So you're able to take advantage of both programs in terms of 45Z and the PA Tier 1 rec. But the volumes don't qualify 1 for one. So some volumes might qualify under Tier 1 rec and some volumes might qualify under 45Z. So it's a -- it's a blend of which ones do and which ones don't. And at this time, it's all still subject to that final rule. We're optimistic as long as things follow the initial guidance, but there's still a bit of wait and see on that.

Got you. That's helpful color. And then for my second question, could you maybe talk about what credit price is underwriting the revised mental attribute free cash flow guide of $65 million.

Yes. It's sort of where the market is at now. We treat it very similar to how we report kind of the open prices for the rest of the year just kind of look at the PAT strip. That's in the mid-20s right now for the megawatt hour?

And your next question comes from Jacob Roberts with TPH.

Maybe a bit of a follow-on to that last question. Should we be thinking about the $30 million as a function of the RMG input or the result of some sort of downstream output?

The tax credit is for the incentivizing the collection of waste gas off the backside of coal mines and creating a saleable product into the pipeline, if that makes sense. So that's why it's thought about more is remediated or abating emission source.

Okay. That's helpful. And then I just wanted to give you guys the opportunity to talk a little bit about the AI and Energy Summit. I know you mentioned it in the release. And specifically, we're wondering how much the RMG product is factoring into those conversations with any counterparties, maybe in particular, the tech guys. And ultimately, do you think there is a pathway for RMG to get better economics on some of the potential deals there relative to the current pathways you've laid out?

Yes, great question. No, we're super excited. Our mantra around here is Appalachia first. All of this AI stuff is going to be great for -- great for the region, great for the industry. And in particular, you nail kind of our lane that we're super focused on right now, which is offering the RNG product to the market as a true sustainable kind of energy solution to get folks that are using that gas down to a 0 carbon sort of profile on these new data centers.

Obviously, we've been having discussions with folks. We have third-party marketers having discussions with folks and we're excited to see that develop and not just on the existing volumes, but enough incentive from the voluntary markets to go out and kind of some additional volumes, hopefully.

And Jacob, this is Nick. Just to sort of follow on with Alan the way we look holistically at the AI opportunity and remediated mine gas RMG. It's another industry pathway, whatever you want to call it, to get the value of it recognized and utilized. So we started with manufacturing and arm's length transactions that recognized it for manufacturing downstream products. We've got it recognized, of course, in the power grid under the Pennsylvania PUC. We then were able to get it recognized in the hydrogen economy with 45V new transportation of alternative fuels with 45Z, and this would be another critical pathway that I think makes a whole bunch of sense and has a certain level of inevitability to it, but the timing and the magnitude of it is still in TBD.

Great. Appreciate the time, guys.

Yes, Rob.

And your next question comes from Michael Scialla with Stephens.

Just to follow-on the AI topic there. Obviously, a lot of news recently on gas providing power for data centers in the region. I just want to get your updated thoughts on in-basin demand? And does that have any impact on your long-term view of natural gas prices and your hedging strategy?

Yes. I don't think it has the impact on our hedging strategy. In the short term, our hedging strategy is a function of how we manage the balance sheet and how we manage our overall capital allocation program. I think long-term, it's absolutely going to be bullish, anything that creates in-basin demand given our kind of interstate pipe restrictions that we experienced over the last decade. It's going to help everyone in basin. So we're more of a wait-and-see mode. From our position is we have the depth of inventory, we have the ability to deliver gas. It's just not wait and see, which projects come online and how we can benefit of that.

Yes, Michael, I think the prior experiences that we've had and similar types of opportunities for the industry and for the region when you're looking at potentially new demand being created that journey to where we end up actually versus what we're hearing and what people are projecting today. It's obviously going to be very different. There's going to be all kinds of factors and changes in twists and turns. So as to which plants get built and when they're online and what the timing of all that is, there's just a lot of things to be figured out between today and then in the future.

And that's why -- and I think you saw that too since the summit with what's going on the volatility on pricing. That's why we basically love the opportunity and the developments it would mean for demand for natural gas and what it could mean for the region in terms of sort of a reindustrialization or revitalization of a lot of these communities.

But in terms of taking positions today and speculation of what that's specifically going to mean when it comes to things like hedge book and capital allocation, our playbook, our philosophy, our approach remains exactly the same.

Yes. It makes sense. I want to get your thoughts on the second quarter production surprised a little bit. I just wanted to see if you can pinpoint where that came from? Was it new wells outperforming expectations, base decline anything else?

So our production outperformance was basically like 4 things coming together for us. The first one is our new till performance, the Apex Marcellus wells and our Utica wells. They've done really well. So -- and the second part is our operational execution, which has given us opportunity to kind of move some of this forward. The third part is our production efficiency gains on our base production. So we are doing really well there. And the last part is like our uptime on base production. So all 4 combined, we kind of led.

And your next question comes from Betty Jiang with Barclays.

I want to go back and ask about the deep Utica results again. In your view, how much do you think cost will have to come down for the deep Utica to compete with Marcellus returns? And then broadly speaking, from what we can tell, the Utica wells are fairly concentrated right now. So would love to get your thought about the consistency of Utica performance IR acreage.

Yes. I would say on the first question, where we're at right now on sort of the cost structure, we think that makes those wells competitive with kind of best in-basin opportunities even on the Southwest PA sort of Marcellus stuff. The longer term, we're going to step out from where we're at now, but our expectation is that there's a pretty long runway across our field up there to make these results repeatable.

Okay. A follow-up on the Newtek. Just as related to the gas power for AI, when you think about your value recognition for the gas. Is it fair to think about it from a voluntary and current credit perspective where you're selling the attributes to tech companies looking to reduce their carbon footprint? Or is it through compliance market or other channels?

Yes. On the RNG front, we're going to sell to whichever market recognizes the highest value, right? I mean, currently, that is the latter of the one that you pointed out, kind of the renewable energy credit markets for the existing RPS programs. But there is a finite amount of this resource that's available, and we think the environmental attributes should result in some voluntary pricing that rivals the regulatory pathways in the long-term.

Betty, you also bring up another good point with the question, which is the focus currently, right, has really shifted with the opportunity of AI in places like Appalachia to nat gas demand and the construction of the data centers and power plants to power them, et cetera. But there's also another issue that's been there from the get-go that will remain. It just maybe has perhaps fallen a bit below the radar, which is the sustainability solution or the sustainability path to making all this growth occur.

And the ultimate sort of clients and drivers of that, the tech industry hasn't sort of backed up with regard to sustainability or carbon goals 1 step since they originally set them. And now this new growth option for them is going to make that even more of a heightened challenge.

So I think RMG playing a role in how this ultimately plays out has never been in more demand. And to your point, I think the tech industry will play a key role in that.

And sorry, if I could just follow-up on that answer. The on -- in the voluntary cover market perspective, would that be incremental to PA rec market or 45Z?

At some point, you can only sell into one market. So traditionally, in the voluntaries depending on which pathway you're using they might not be stackable. So it's all very facts and circumstances dependent. So I hesitate to give a general answer. But -- the way to think about it is you can generally get maybe 1 to 2 stacking, but you're not going to get beyond that.

Yes. I think of it as another pathway that we compete with your other alternatives, so not stack of [indiscernible].

[Operator Instructions] Your next question comes from David Deckelbaum with TD Cowen.

I just wanted to follow-up on just the Utica mix. You talked about just given more at bats next year. As we just think about the general activity level that you guys have laid out, should we think about the Utica taking more share of the program over the next couple of years? Or is there still some more headway to make on the cost side before it becomes a larger contribution?

No. Let me go back to what I said on one of your other questions. I think at this point in the cost structure, these wells are in the mix in terms of IRR competitiveness. So you're going to see them in the program moving forward. And what we're really trying to do is balance the harvesting of the Southwest PA sort of field that's fully developed with the any potential kind of step out in the new CPA area.

So we look at every project on a kind of full cycle IRR basis, and that's how we determine the mix. You said we've been very intentional recently and just given NAV lots of that bats to demonstrate repeatability, but moving forward, I think we're comfortable that we can be super focused on just the best projects at the right time.

Appreciate that. And then just a follow-up on conversations just around marketing and obviously, in-basin demand. As you said today, we go until winter you guys talked about before kind of hitting tank tops or so as we get into full and then sort of setting up for 26 million .

There's been a lot of contracts that seem like they're in the early days of being signed right now. From where you sit, do you think it's sort of best to see this market get appreciably tight over the next few years and see in-basin demand increase before signing long-term agreements? Or is that something that you think is going to be in your relative near future? .

Yes. I think the first signal you want to see is an actual data center connected to some of the nat gas projects. I think once you see the first sort of data center sign up for electricity offtake here in Appalachia, that will give folks a real sense of how the value is going to get distributed across the chain until you see that, you're a little bit hesitant to lock in your kind of respective ownership of that economics. So the Nick pointed out, there's still a lot of innings here. We're still very early, but there's some definite value and to wait and see how this plays out before locking up anything long term. SP1 This concludes our question-and-answer session. I would like to turn the conference back over to Tyler Lewis for any closing remarks. .

Thank you again for joining us this morning. Please feel free to reach out if anyone has any additional questions. Otherwise, we look forward to speaking with everyone again next quarter. Thank you. SP1 The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.