Greetings and welcome to the NOG's Second Quarter 2025 Earnings Conference Call. At this time, all participants are in a listen-only mode. The question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Evelyn Inferna, Vice President of Investor Relations. Thank you. You may begin.

Good morning. Welcome to NOG's third quarter 2025 earnings conference call. Yesterday, after the close, we released our financial results. You can access our earnings release and presentation in the Investors Relations section of our website at NOGinc.com. We'll be filing our September 30th 10Q with the SEC within the next few days. I'm joined this morning by our Chief Executive Officer, Nick O'Grady, our President, Adam Derlem, our Chief Financial Officer, Chad Allen, and our Chief Technical Officer, Jim Our agenda for today's call is as follows. Nick will provide introductory remarks, followed by Adam, who will share an overview of NOG's operations and business development activities. And Chad will review our financial results. After our prepared remarks, the team will be available to answer any questions. Before we begin, let me remind you of our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that have been described in our earnings release, as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income, and free cash flow. Reconciliation of these matters to the closest GAAP measures can be found in our earnings release. With that, I'll turn the call over to Nick.

Thanks, Evelyn. Welcome and good morning, everyone, and thank you for your interest in our company. I will, as usual, provide you with some highlights on our outlook and five quick points. Number one, the business remains very solid. Our activity remains stable. Our D&C list has continued to march on with high-quality, low-break-even activity, and we remain on target for the year and expect a strong exit into 2026. Number two, we and many of our operators have been cautious and disciplined with our drilling capital. We have explained that being return-driven versus growth-driven means we will react accordingly and be judicious with how we allocate our capital. So far, given the commodity complex, this strategy has proven to be sensible. It allows us to preserve our growth inventory and capital for periods where we can maximize value for our investors and ramp aggressively when it's appropriate in the cycle. Yet we've also grown our gas volumes into a stronger backdrop as we allocate capital accordingly. Number three, it also means we can focus some of our capital for long-term value creation. We have never been busier on the BD front, ever. We have been clear that our priorities are focused on creating long-term value, and we believe that disciplined, long-term strategic opportunities are best suited in this environment to create value. Our recent minerals and royalty deal typifies this strategy, adding long-term growth, low-risk assets into the portfolio that will prove highly resilient to short-term gyrations in the commodity market.

Number four, we've been purposely tactical in regards to our capital stack.

The balance sheet management we have undertaken may not be fully appreciated yet, but it is critical to how we navigate the current marketplace. With a tack-on to our convert earlier this year, our recent bond and tender transaction, and the recent extension of our bank facility, we will see some substantive benefits to the corporation. At the current pace, we will exit 2025 with potentially more than $300 million of additional liquidity as compared to the beginning of 2025. We will also see a further reduction in interest rates with our new RBL terms. We've entered into interest rate swaps to further reduce those rates and can increase this amount if warranted. The extra cash flow, this substantial increase in liquidity, and the longer tenure of our debt maturities continues to set us up to pounce on counter-cyclical investments as we intend to. Number five, we continue to actively manage other risks, such as commodity exposure. You'd be hard-pressed to find a better hedge company than ours. This actively managed hedge program allows us to better navigate the typical commodity cycle, This practice is another factor that protects our business and allows us to continue to take the offensive through trough periods. In summary, the business remains solid as a rock, inorganic opportunities are more robust than ever, and we've taken substantial steps on the risk and capital management front to ensure our ability to take advantage of any cycle. We firmly believe that energy has more growth in value-creating prospects than the bulk of the upstream sector, and we look forward in the coming quarters and years to proving this thesis to our investors. Thank you for your interest in our company, and with that, I'll turn it over to Adam.

Thank you, Nick. I'll touch briefly on the operational results for the quarter and then turn to our ongoing business development efforts. Operationally, our assets continue to outperform internal expectations, and we saw this across all of our respective basins. As a result, we've increased annual production guidance while tightening CAPEX for the year. While expected turn-in lines came in slightly under forecast as certain wells were deferred to the fourth quarter, production outperformance was driven by a number of different factors. Notably in the UINTA, upsized completion designs have increased overall productivity relative to internal estimates, While in the Williston, we've seen outperformance on recent tills and much better execution on refracts as operators continue to refine designs. As it pertains to activity levels, the Permian accounted for about two-thirds of our organic activity, while the Williston and Appalachia evenly made up the remainder of wells that were brought online. Drilling and development activity was also consistent, slightly building our wells in process, adding additional low-breakeven backlog and setting up for a strong finish into year-end. Relative to prior quarters, we are seeing a more balanced C&C list as the Permian now makes up 40% of our wells in process, while the Appalachia, Williston, and Uinta each make up roughly 20% of the total. New well proposals and election activity have also remained consistent as we received over 200 well proposals and consented to over 95% of AFBs balloted in the quarter. Year-to-date, we have seen 160 more proposals than what was balloted through the same period during 2024. Expected returns remain well above our hurdle rate, further bolstered by a 10% increase in lateral lengths, driving down normalized AFB costs by nearly 5%. In addition to the longer laterals, NOG's operators continue to see downward pressure on service costs for both drilling and completing, which has been encouraging. We should see those operational efficiencies materialize through Q4 and into 2026. Turning to our business development efforts, Q3 was one of the busiest periods in company history as we screened more than 14 large asset transactions and over 200 ground game opportunities, up over 20% relative to the second quarter. While our scaled business model provides more acquisition opportunities than any other in the E&P space, we remain focused on only the highest quality assets and will strictly adhere to our stringent underwriting requirements. As we previously announced, in August, NOG closed on a royalty and mineral interest acquisition in UINSA that included 1,000 net royalty acres across 400-plus gross locations, excluding the additional inventory that is not currently in our development plan. This is a prime example of how NOG leverages its proprietary database and asymmetric knowledge to capitalize on opportunities in an inefficient market. This acquisition increased NOG's average effective NRI from 80% to 87%, covering the entirety of our UNSA position and further lowering our break-evens in one of the fastest-growing basins in the lower 48. Our ground game remains as active as ever, closing 22 transactions, executing on three trades that high-graded our acreage position, and signing a joint development agreement that covers seven additional extended lateral spacing units. As a result, we added over 2,500 net acres and an additional 5.8 net wells during the quarter, bringing year-to-date ground game additions to over 6,000 net acres and 11.6 net wells across 50-plus transactions in all of our respective basins. These diverse holdings across both oil and gas has provided ample opportunity to deploy capital in both near-term drilling opportunities as well as longer-dated inventory. This has given us the ability to navigate the dynamic competitive pressures that have changed throughout the year. While the broader M&A market has been relatively stagnant across the sector in a lower commodity environment, our unique position counters that thesis, and we do not see things slowing down for NOG. However, the landscape has changed from historical trends. In the past, the large majority of opportunities were concentrated in the Permian, and while we continue to see those prospects, we are seeing a myriad of high-quality potential deals spread across a greater number of basins. Currently, we are screening eight transactions with a combined value of over $8 billion across operated, non-operated, and joint development structures. Additionally, we've been able to approach a number of these assets with various structures, providing optionality to the seller. That also works for us. Regardless of the environment, we will remain steadfast in our approach to underwriting and focused on high-quality assets that will generate superior returns for our investors and stakeholders. With that, I'll turn it over to Chad.

Thanks, Adam. Nog's diverse and scaled platform continues to deliver in the face of a challenging macro environment, and well-performance continues to exceed internal expectations across all of our basins. Third quarter total average daily production was approximately 131,000 BOE per day, up 8% versus Q3 of 2024, and down 2% from Q2 2025, as expected, reflecting the low point for net well additions in 2025 at 16.5. It is important to note that a third of those net wells came online late in the quarter, providing momentum into the fourth quarter. Oil production was approximately 72,000 barrels of oil per day, up 2% from Q3 2024, and down 6% sequentially. Gas production continues to ramp as our gas joint drilling program is on a consistent monthly till pace. Once again, we had record gas volumes of approximately 352 MMCF per day, up 15% from Q3 2024, and up 3% from Q2 2025. With the expectations of adding between 23 and 25 net wells in the fourth quarter, heavy late net well additions, and well-out performance in Q3, we have increased our annual production guidance to a range of 132,500 to 134,000 BOE per day. Moving on to our financial results, adjusted EBITDA in the quarter was $387.1 million, and free cash flow was $118.9 million, marking our 23rd consecutive quarter of positive free cash flow, exceeding $1.9 billion over that time period. We reported a net loss of $129 million in the quarter, which reflects the previously disclosed non-cash impairment charge of $319 million. Our adjusted net income was $102 million, but $1.03 per diluted share in the quarter. Oil differentials averaged $3.89 per barrel, as we saw improved differentials across all of our oily basins. Natural gas realizations were 82% of benchmark prices, consistent with Q2 2025, through the ongoing Waha market weakness, and was also impacted by lower NIMAC's natural gas prices. Race operating costs per BOE were down marginally from Q2 2025, despite lower oil volumes. We did see some relief on saltwater disposal costs, but we are still seeing steady expense pressure from workovers. Given the higher run rate year-to-date and the expectation of continued workovers, we have increased annual guidance on LOE. We have also revised guidance on production taxes to a lower run rate given year-to-date actuals and anticipated production mix in the fourth quarter. CapEx in the quarter, excluding non-budget acquisitions and other, was $272 million, reflecting an active quarter on the ground game, as discussed by Adam earlier. Overall, the $272 million was allocated with 49% to the Permian, 25% to the Williston, 5% to the Uinta, and 21% in the Appalachian Basin. Approximately $212 million of the total spend in the quarter was allocated to organic development CapEx. The history of three quarters behind us, we have tightened our full year CapEx guidance to a range of $950 million to $1.025 At the end of the quarter, we maintained approximately $1.2 billion in liquidity, consistent of $32 million in cash and over $1.1 billion available on a revolving credit facility. We have been actively managing our balance sheet throughout 2025, including since quarter end. In October, we raised $725 million of notice maturing in 2033 with a coupon of 7 7.8%. We used those proceeds to retire nearly all of our notes maturing in 2028 that have a coupon of 8% and 8%. We amended and restated our revolving credit facility, which extended the tenor to 2030 and markedly improved our pricing grid by 60 basis points, significantly reducing future interest costs. The credit facility's elective commitment amount and borrowing base remained unchanged. changed. These transactions together extended the weighted average maturity on our debt from approximately three years to six years. Importantly, we have no major maturities until 2029. That concludes our prepared remarks. Operator, please open up the line for Q&A.

At this time, I would like to remind everyone in order to ask a question, press star, then the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Charles Mead with Johnson Rise. Your line is now open. Please go ahead.

Yes, good morning, Nick and Adam and Chad, and to the rest of the NOG team there. Nick, you, I guess, approached, you know, the outlook for 2026 in your prepared comments, but I wondered if you could, you know, just elaborate a little bit more on what you're seeing, and I suppose if you'd wanted to give 26 guidance, we would have given it, but I'm really curious to hear what you're seeing because you sample so many different operators across many or most of the important producing areas in the lower 48. So maybe you could offer what you think the industry baseline is going to be, and then perhaps a delta for what NOG might be versus that industry baseline.

Yeah, I mean, I think what you see in the industry is probably what you'll see for us at this point. I mean, I think we haven't seen much change in activity since the prior quarter, which has been relatively flat. And I think change that, and I think that's why I think things certainly can change as we head into next year.

By break-evens, if we're looking at kind of what our backlog looks like here, we've got a healthy, you know, Permian backlog. I think the interesting thing that we've seen in the quarter, especially with the AFEs, is on the Williston side, you're seeing kind of weighted average AFE lateral lengths 15,000 feet, and that's spread across a multitude of different operators. And so I think that's obviously helping bolster some of the expected rate to return that we're seeing there, are lowering normalized well costs and helping, again, to bolster the expected rate of returns in the basin.

And I guess the only other thing I would add to it is that, you know, as I mentioned, the commodity outlook could change, I think, you know, depending on what happens to it we are today, I think we're going to.

If I could just focus in on 4Q, 4Q25, your annual guide suggests that you guys are going to be, sequential growth in 4Q. And Chad, I think I heard you say on your prepare comments that you've got 23 to 25 net wells that are supposed to be online in 4Q. So I wonder if you could just give us an update. We're here in whatever, the first week of November. How many of those wells have already come online and are those wells, are those tills going to front end loaded, evenly loaded, back end loaded? Just talk about where you are in that process This is, you know, to give you confidence on that implied 4Q volume bump.

Right on track. I'd also add that, you know, a good portion of the machines that a well takes an IP doesn't really mean very much. It takes 30 days usually for a well to clean up and be fully produced. It's important, but it's not.

Great detail.

Your next question comes from the line of Scott, handled with RBC. Please go ahead.

Yeah, CJ. Good morning. You know, Nick, I'd say that you had a pretty strong view on what you're seeing on M&A and ground game and, you know, obviously very encouraging. And, you know, frankly, I think it's one of the most robust, you know, comments to that effect I've heard from you for a while. And can you kind of compare and contrast what you're seeing in the market for that view today relative to, say, a few years ago when you did a number of large acquisitions? And, you know, how do you think about funding, you know, both, you know, ground game and larger transactions if it does meet your hurdle rates?

Your next question comes from the line of Neil Dingman.

My question, Nick, is centered on your continued activity. Specifically, you all have talked about, I'm just wondering, given the notable changes we've seen and, you know, oil prices now still sub-60 and natural gas now, you know, nearly $4.50. are you all getting a sense of things beginning to change into 26, meaning, you know, are you seeing some oily activity continue to slow down, and are you seeing maybe potentially some gas activity picking up? Or, you know, have you all noticed anything different with prices now in these ranges for, I guess, now a few weeks?

I mean, nothing imminent, you know, nothing different than we've seen all year. And I'd say what I said in my previous – I'm sorry. I'm not really sure – our phone dropped, so I'm not really sure where our last comments got cut off. But the answer to your question is we haven't really seen much of a change in activity overall since last quarter. We've seen oil activity roughly flat and stable. We have seen gas activity stable to growing, but that's a trend that we've been seeing all year. Adam, I'll get one there.

Yeah, that's right. I think the Williston and the Uinta has kind of been humming along. And then, you know, from more of an inorganic standpoint, we've been focused on, you know, deploying capital within Appalachia and then, you know, looking at more near-term drilling opportunities. That's largely been focused in the Permian based on break-evens.

Well, thanks, Adam. And then just, Nick, for you, Adam, just to follow up on M&A, two questions on M&A. First, it seems like, you know, you have a fair amount of assets that I don't know if you're getting full credit for. You know, are you always considering it as part of the M&A strategy? Is monetizing anything? Is that, you know, in the game plan? I haven't asked you that in a long time. And then secondly, with the opportunities you're seeing out there, you talk about, hey, you know, ground game or deal flow looks as good as ever. Is it a mix? You know, are you seeing the potential for large deals, you know, like whatever, the SM vital deals that you've done in the past for all these more, mostly small deals? What are, you know, what are the types of opportunities you're seeing?

So I think on the latter, it's all of the above. I think we're, you know, obviously, you know, you saw our recent royalties deal was, you know, relatively modest in size, around $100 million. You know, we've seen everything from $100 million to $1 billion. dollars. Obviously, the billion-dollar transaction has a much higher standard than, you know, in terms of the bar is extremely high for something like that from a financeability perspective. And I think, in general, you know, we're seeing transactions all across the board. I don't know exactly. I don't know how you want to answer that.

Yeah, I think the bell curve is relatively wide. To Nick's point, right, we signed up the mineral deal at $100 million. There's deals out there that are, you know, $4 billion, and you've got everything kind of in between. I think the other tool in our toolbox is that we can approach a handful of these transactions with different structures, right? You can buy down an undivided interest and make a non-op interest out of And so if we're thinking about, you know, co-purchases, could you also approach that, you know, from a joint development agreement perspective? So I think there's a handful of different ways that we can kind of shape these assets that, you know, others might not otherwise be able to.

Well said. Thanks, guys.

Your next question comes from the line of Scott Handled with RBC. Please go ahead.

Yeah, thanks for getting me back in the queue. And, you know, Nick, I guess to my first M&A question, I think we're cut off is, you know, when you were differentiating between now and, you know, say a few years ago, you were mentioning it was broader. And I guess just to, you know, finish off that question, I guess, would be the funding, how you think about funding for that, and then I'll have my follow-up after that.

Yeah, I mean, I think, you know, I guess I think my rant got cut off, but I would just say this. Look, in terms of funding, Scott, you know, we've answered this question publicly many times before. We will fund it no differently than we ever have. You know, if you believe that we have a relatively sophisticated understanding both at the board and the managerial level of corporate finance, one would assume we'll finance any transaction if and only if it's beneficial to our stakeholders and only in a way that would be beneficial to them for the long term and in a risk-positive way. But suffice it to say, as I mentioned in my prepared comments, we have an incredible amount of liquidity at advantage cost called sub-6 percent and multiple other avenues should we need to adopt those sources, but we'll only do it if it makes sense to you.

Okay, understood. Thanks for that. And then my follow-up question is, you know, Adam, you were talking about lateral lengths, you know, how they're increasing. And can you all just give some kind of context for us on, you know, how broadly you're seeing that lateral length increase and, you know, how does that impact your capital efficiency and decline rates moving forward?

Yeah, I can kick it off and then hand it over to Jim in terms of decline. rate commentary there, but it's across the board with our respective basins. As I mentioned earlier, the Williston and Q3 with AFEs, we're seeing 14,000, 15,000 foot lateral lengths, and that was spread across five-plus operators with 80-plus AFEs that we received during the quarter. We're seeing the same thing in Appalachia, and even in the Uinta, the partnership with SM. We're starting to lengthen lateral lengths there as well. And even with the Permian, I think we're seeing some of the longest average lateral lengths that we've seen to date. That obviously puts downward pressure on weighted average AFE, normalized AFE costs there, and then further bolsters expected returns. I think the biggest takeaway that we've seen after observing this over, you know, an extended period of time has really been, you know, how they've accessed the reservoir, and that's probably where I'll give it to the engineer.

Yeah, thanks, Sam. Yeah, you know, like we said, we're seeing operators continue to refine their completion designs, you know, more effectively stimulate the toll of the well and be able to draw down the pressure. What you'll see is, you know, they're not going to over-design the facilities, so you're not going to see a straight ratio going from a two-mile to a three-mile where the IP is going to go up by 50%. It's going to go up a little bit. What you're going to find is you're going to find that the well is going to take flat for much longer and then have shallower declines. Now, we typically are a little bit more conservative, and so what we'll see is when we see that IP rate, we'll continue to maintain our prior decline rates until we have more information. You know, that might take six, nine months. And so what we're seeing now is that these wells are holding and then they're a little bit flatter for a little bit longer. So they're starting to exceed our expectations from what we initially expected. So as we continue to get more information, we'll continue to refine our expectations and our decline curves moving forward.

Your next question comes from the line of John Freeman with Raymond James. Please go ahead.

Thank you. Good morning.

Just following up on the nice progress on the AFE, He's dropping to 8.06 a foot this quarter versus the 8.41 last quarter. Can you give us, kind of like you did last quarter, where the well cost stands on your current DNC list on a preferred basis?

Yeah, I think it's going to largely be similar. I mean, if you're looking at the AFD list from last quarter, that's going to largely translate to, you know, what we're seeing on the DNC list now. I also, you know, the expectation, I don't have the information in front of me so I can follow up with you, John, but would expect that it's, you know, slightly higher. Jim was able to pull it up and it looks like it's coming in kind of average at 821, give or take.

Okay, perfect. And then my thought question, you know, you all mentioned in the slide deck, you still got obviously the significant shedding and deferred volumes. And I'm just curious, like, where that number stands right now and if it's been continuing to grow.

Two to four is kind of what we're seeing. And, you know, operators, particularly the private ones, tend to cycle that, right, from a lease maintenance standpoint. And so I don't think we necessarily see that appreciably changing at this point. Got it.

Thanks, Adam. You bet.

But your next question comes from the line of Paul Diamond with Citi. Please take your head.

Thanks. Good morning, all. Thanks for taking the call. Just let me quickly touch on AFVs. You talked about a 5% sequential well-cost reduction, noting lateral lengths. But is there anything else in those numbers? I guess any other contributions and any opportunity sets you see for kind of continuing that trend?

Yeah, I mean, Paul, our observation has been that the bulk of cost savings of late have been through that lateral length and efficiencies. We haven't seen a huge step down in service costs. In fact, you know, as we've talked about in LOE, I think in general as a trend, you know, inflation is real, right? And so, you know, you're combating that with, you know, drilling, you know, shaving days and drilling longer laterals as a way to try to cut costs. I think in order to see material savings at the well level and to see huge cuts, my personal opinion is you're going to have to have another step down in overall activity. So if, you know, God forbid, oil prices take another, you know, material step down in prices and we see another drop in the rate count, I would think you're going to see big concessions. The one thing I will tell you is we've had conversations with some of our really large operators, and a lot of them are talking about, for lack of a better term, vendor management. And what they're doing is, you know, generally they have allowed their field teams, you know, at the individual base and level to manage their – to manage, you know, which vendors they use. and they're now looking to sort of centralize that and go to, you know, say, nine vendors instead of the 50 or 60 that they have as a way to try to get bargaining power. As that filters through, that may be another source of cost reductions over time, but time will tell.

Yeah, and you're going to see that on a rolling basis, right, and it's going to be spread across the operators. You know, they've obviously got to see these contracts through, and then once they roll off, then that's going to be your window.

Yeah, and this is, you know, we are going into budgeting season. We are going into a new year in which, theoretically, contracts would be turning, and so it may be a period in which we start to see some cost relief, but, again, time will tell.

It makes sense. Just a quick follow-up more holistically. You talked a bit about refrax. You talked about any shift in activity here you've seen over the last several quarters with this on the horizon, and it's been pretty topical, hasn't it?

Yeah, I mean, as far as the refrax go, That's primarily been concentrated within the Williston, and, you know, I think historically operators have, you know, deployed those refracts, and it's been a bit of a learn-as-you-go. And so I think, you know, this quarter we saw some appreciable uplift, and so I think it's, you know, maybe still early days as far as, you know, what we would look to change our kind of underwriting and expectations there, but it seems like operators are moving up and to the right.

Got it. Appreciate the clarity. I'll leave it there.

Your next question and final question comes from the line of Noah Hongness with Bank of America. Please go ahead.

Morning. For my first question, I was wondering if you could talk about what's driving the continued build and wells in progress and when you think that number will start to decline and if the higher kill count for 4Q versus 3Q would ultimately result in a drawdown in the wells in progress?

I think it's going to – I mean, that's a difficult question to answer, Noah. I mean, I think in the sense that, you know, as it stands now, we've seen very, very steady AAP activity, and so if activity continues as it is, we would expect it to be relatively stable. I think to the extent that we see, you know, a material change in commodity prices, we could see it potentially dip down, I think.

Yeah, I think the other variable that you've got to think about, right, is you've got growth activity levels, but then you need to think about, you know, average working interest on those AFEs, and that can certainly be variable. So, you know, from a growth perspective, you know, everything's been kind of humming along, But, you know, from a net level, that can vary from quarter to quarter. And so if you're looking at just activity quarter over quarter, that can fluctuate.

But, I mean, if the question is do we see that imminently changing, the answer is no. Of course. I think really it's going to be dictated by the environment. And so I think if, you know, certainly our view would be that if prices have a material change from here, we would expect activity to change probably one way or the other.

Yeah, the only other thing I guess I'd add is, you know, stack pay, co-development, you know, are you drilling two wells on a pad or are you drilling 12? And this budget sales timing is going to be wildly different between kind of those two scenarios.

No, that's helpful, caller. And for my second question, based on three key results in the updated 25 guide, Going back to kind of thinking about an implied 4Q oil production, the range is pretty wide. So could you help us think about maybe some of the moving parts there that could put you at the midpoint or below or above cement range?

Yeah, it's just really timing of completions. And I think, you know, look, we as a non-operator, we're always going to give ourselves some grace in terms of that timing. And so it is obviously timing. I would think we certainly, you know, will likely tighten that up as, you know, the year goes on. But what I would say is regardless, we would expect to see, you know, a material step up as we exit the year. And what I would say as well is that we have seen, you know, and I think, you know, we did talk about this in our prepared comments, but, you know, So as base production has improved and overall the clients have moderated, it has really set us up for a really nice start to the first half of next year. And I think, you know, to your prior point, I think the question will really come down to, you know, how much capital both do our operators deploy and how much capital do we want to discretionary, on a discretionary basis want to deploy next year in terms of what types of activity are we targeting. And that's really going to drive the results for next year as we go into it. And I think that's really a return-based decision.

Good stuff. Yep, you bet.

That concludes our Q&A session. I will now turn the call back over to Mr. Grady, CEO, for closing remarks.

Thanks, everyone. Energy is well-positioned to navigate through the current market volatility. Our assets are performing very well. Our liquidity is abundant, and our investment opportunity grows every single day. We're really grateful for being aligned with strong and capable partners, and we look forward to keeping you informed on all our activities and achievements in the coming weeks. Thanks again for your interest in our company. This is the way.

Ladies and gentlemen, that concludes today's call. Thank you all for joining. Everyone, have a great day.