NOG - NYSE

Greeting, and welcome to the NOG's Second Quarter 2025 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It's my pleasure to introduce your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Good morning. Welcome to NOG's Second Quarter 2025 Earnings Conference Call. Yesterday, after the close, we released our financial results. You can access our earnings release and presentation in the Investor Relations section of our website at noginc.com, who will be filing our June 30 10-Q with the SEC within the next few days. I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President; Adam Dirlam; our Chief Financial Officer, Chad Allen; and our Chief Technical Officer, Jim Evans. 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, including Jim 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. Reconciliations of these measures 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. As usual, I'll give some highlights on our outlook in 5 key points. Number one, resiliency. NOG's business model is proving its resiliency every day. We've built a solid business that embodies a number of tenets, diversity, scale and risk optimization that consistently drives results. Our Uinta and Appalachian Basins are and will continue to be strong contributors as the Williston moderates during a period of lower prices. Our commodity mix of oil and gas positions us to benefit or offset weakness in either or strength in both, and our conservative and disciplined approach to investing as well as downside protection supports our cash flow in the near term through hedging. And as we look through oil price cycles and take a longer-term risk-managed view as to how and where to deploy our capital. Our business activity continues to be solid with the D&C list building substantially this quarter as we have seen overall stable drilling activity on our lands. As I have said before and we'll reiterate now, our goal is to make money for investors, and we believe that our diverse portfolio of holdings will be a relative outperformer given the number of levers we have at our disposal. Number two, drilling versus acquiring organic, versus inorganic, the how and the why. In a period of flux for oil prices, it is a unique time for our model and the decisions we make. Many companies continue to modestly grow their volumes and continue to march forward even as price is signaling to do something else. I want to be clear that our tactics will likely differ depending on the commodity outlook. We always tell investors that growth is the output of return-based decisions, not a front-end decision for our company. As prices have retracted, our view is that growth capital is better preserved for higher returns in the future at better prices or if spent today on acquisitions. Upwards of 80% of a well's return is delivered in the first year of its life. And acquisition, on the other hand, typically delivers its return over 4 to 7 years. Drilling, while generally higher return in the short term is inherently riskier in this volatile price environment. With acquisitions, we benefit in multiple ways, long-term upside convexity and the resiliency to the long-term return profile. This is the driving logic to our reduced near-term spending. To the extent we do spend additional capital, it will be through discretionary capital outlays through acquiring stable production and inventory. That inventory and production will have the aforementioned convexity of future prices. So we retain the option of ramping activity if the environment changes. Remember, the oil is still there on the ground and will adapt quickly. Number three, whatever the price of oil cash flow continues. We generated over $126 million in free cash flow this quarter, plus we have another nearly $50 million pending from a recent legal settlement. Our debt balance has changed little since last quarter, mostly a function of the closing of our recent Midland acquisition, changes to working capital and the mechanics of our convert tack-on and simultaneous stock buyback. But the business itself through a very weak period of oil prices continues to shine while production has remained resilient and our careful risk management shines through. This is in spite of a significant amount of price-related shut-ins from price-sensitive operators and other deferments that are typical in a lower price environment. While not always the most popular, these decisions by our operators have proven time and time again to be value enhancing through patiently waiting out the cycles. With that said, the ground game is providing compelling offset opportunities, which brings me to my next point. Number four, ground game success. As I've mentioned in the past several quarters, the term ground game means many things from raw, unbound acreage to drill-ready projects and our competitiveness in all of these categories ebbs and flows at times. Our discipline means we evaluate across basins, structures and commodity type, depending on the returns and opportunity. In the past year, we focused particularly on acreage as it's become a lost art to take longer-dated positions on undeveloped acreage, and the results have been stellar. We've seen large portions of our acreage in the Uinta become unitized rapidly. And in short order, we're seeing our concentrated working interest getting well proposals on those lands. And in the second quarter with the weakness in oil all portions of the ground game saw more success across each of our active basins. If we see further weakness in the oil markets in the later innings of 2025, expect to see even further success for us in this arena as that's when we tend to have the most traction. Number five, with great power comes great responsibility. As the largest and best capitalized nonoperator, we have found ourselves uniquely situated by being involved in most major M&A processes that are going on in the marketplace today. This is being driven by the breadth of our capabilities, our reputation in the marketplace and the increasing need for our capital. I mentioned the difference between drilling for returns versus acquiring and our view that ultimately, from a long-term perspective, acquiring today has the best future potential. I'm pleased to note that our backlog of potential acquisitions from bolt-ons to truly transform -- transformational transactions is at an all-time peak both in value and in many cases, impacting quality. These potential transactions cover almost every structure, basin of operation and variance of scale. Should we be successful on our terms, these opportunities could be highly beneficial to our stakeholders on almost every measure. As I'll remind you, every transaction goes through incredible rigor and scrutiny here at NOG, not to mention our low level of actual conversion success rate. That being said, we are working hard to find value-accretive ways to continue to drive our business forward, and I'm highly confident that we'll find meaningful ways to do so this year and beyond. NOG's Q2 results highlight the flexibility of the business model and our returns-based philosophy. These factors have translated into significant cash flow generation and excellent capital efficiency over time. While overall growth dynamics have slowed in U.S. shale, we are hard at work to find accretive opportunities for our stakeholders and believe we can deliver over the long term. Let me be absolutely clear. As it pertains to 2026 and beyond, our goal is to maximize returns for our investors and find the optimal path to differentiated growth in value. And we have incredible opportunities to do so beyond just our drilling capital but we will allocate our capital in the way that creates the most value for our investors. We remain focused on the same simple tenets, which is to grow our profits on a per share basis and build scale for our investors, all the while focusing on strong returns on capital and keeping a strong balance sheet. I often mention that NOG is different. We are different in so many ways. But I think we're most different in that we do things almost exclusively focused on long-term thinking, on long-term value creation through cycle, sometimes these measures may differ from our peers but seizing on market opportunities will ultimately drive more value in the end. Thank you again for listening and your continued interest in our company. Adam?

Thank you, Nick. Operationally, the second quarter finished as expected, even in the face of continued commodity price volatility. Our operating partners have, for the most part, maintain their development cadence with the exception of a few operators in the Williston who have pulled back. As a result, we saw 1 net well deferred in approximately 3,800 barrels per day shut-in due to pricing pressure from a single operator. Notwithstanding the deferrals and shut-ins, current Williston results continue to outperform internal estimates and well productivity is appreciably higher compared to 2024 TILs. While we've seen some expected IP dates pushed out as operators take a more cautious stance on bringing wells online, overall activity levels across our core basins remain robust. The Permian held steady, while both the Uinta and Appalachia saw the anticipated uptick in drilling activity. In the Uinta, we spud 4.8 net wells during the quarter, up from 1.4 net wells in Q1. Meanwhile, our joint development program in Appalachia is now in full swing. Wells were spud on time and on budget and with both programs, wells are performing consistent with internal expectations. We're encouraged by the execution we're seeing across the board. Despite modest deferrals on the TILs front, drilling and AFE activity remained strong. The Permian, Uinta and Appalachia now account for 80% of our wells in process, which totaled 53.2 net wells at quarter end. That represents a 70% increase in drilling activity quarter-over-quarter with 27.1 net wells added to the D&C list in Q2. This drove a net build of 14.3 net wells, with the Permian contributing roughly half of the total wells in process and 60% of the oil-weighted wells in process. We also see a continued push for improvement in capital efficiency. Normalized well costs on our D&C list are now averaging approximately $800 per lateral foot and our oil-weighted basins saw cost decline 6% sequentially on a normalized basis. This reflects both longer laterals and exposure to some of the most efficient operators in our basins. Turning to well elections. We've seen a retreat to the core with estimated EURs up quarter-over-quarter, and as a result, our election percentage has remained elevated at 95-plus percent. Quarterly net AFE elections also increased sequentially along with over a 50% increase in activity relative to 2024's quarterly average. As always, we remain highly selective and continue to stress test all elections against conservative price decks to ensure resilience in a lower-for-longer environment. Looking ahead, we expect to see more of the same from our operating partners as we move into the back half of the year. Relative to Q2, we see a slight increase to TILs in Q3 before ramping through Q4 as the Permian and Appalachia increased completions compared to the first half of the year. Similar to anticipated TILs, we expect the Permian and Appalachia to drive the bulk of our drilling in the back half of the year while seeing the Williston slowdown absent a change in commodity pricing. On the business development front, we are seeing an accelerating number of opportunities and have been able to take advantage of the downward pressure on commodities to capitalize on ground game opportunities across all of our basins. In the second quarter alone, we reviewed over 170 transactions, over a 40% increase relative to the first quarter. In addition to closing our previously announced Upton County acquisition, we closed 22 transactions, up from 7 deals in the first quarter for a total of 4.8 net wells and over 2,600 net acres across all of our respective basins. Our approach remains the same, targeting both near-term drilling opportunities as well as long-dated inventory. We're finding creative ways to put things together, whether through smaller joint development agreements in the Permian, acreage trades and farm-outs as well as old-fashioned leasing efforts. Regarding larger scale M&A, there has been an increase in gas-related opportunities entering the market alongside assets that have become available as commodity volatility has decreased. Currently, more than 10 ongoing processes are being assessed with a combined value exceeding $8 billion and additional opportunities are anticipated. As the largest non-operator of scale, we are having more strategic bilateral conversations, and we're optimistic that our flexible model and strong balance sheet position us well to capitalize in this environment. As always, we remain focused on total returns, disciplined capital allocation and leveraging the advantages of our non-operated model to navigate the current environment. With that, I'll turn it over to Chad.

Thanks, Adam. NOG delivered another solid quarter against the noisy macro backdrop. Second quarter total average daily production was approximately 134,000 BOE per day, up 9% versus Q2 of 2024 and in line on a sequential quarter basis. Oil production was approximately 77,000 barrels of oil per day, up 10.5% from Q2 of 2024 and down 2% sequentially, largely due to lower activity in the Williston. The Uinta turned in another strong contribution with volumes up 18.5% sequentially. Gas production continues to ramp. The first batch of wells from our Appalachian JV are online and started to contribute to volumes in the back half of the quarter. Overall, we had record gas volumes of approximately 343 mmcf per day. Adjusted EBITDA in the quarter was $440.4 million including the impact of a legal settlement of approximately $48.6 million. Free cash flow, excluding the legal settlement, was approximately $126 million, marking our 22nd consecutive quarter of positive free cash flow, exceeding $1.8 billion over that time period. Total differentials averaged $5.31 per barrel, excluding certain noncash revenue adjustments. Year-to-date, differentials were $5.50, leading us to adjust our guidance range. Natural gas realizations were 82% of benchmark prices, down from 100% last quarter due to ongoing Waha market weakness, lower NGL prices and weaker seasonal Appalachian pricing. Lease operating costs per BOE rose 6% to $9.95 and due to higher expenses in the Williston due to lower volumes and greater fixed cost absorption and in the Permian doing increased saltwater disposal costs. To account for higher cost year-to-date, we revised guidance on LOE. We also revised guidance on production taxes to a lower run rate. CapEx in the quarter, excluding non-budgeted acquisitions and others was $210 million, 16% lower sequentially. Overall, the $210 million was allocated with 34% to the Permian, 25% of the Williston, 15% for Uinta and 26% in the Appalachian Basin, respectively. Approximately $185 million of total spend in the quarter was allocated to development CapEx. For the remainder of 2025, we are still anticipating a 50-50 split in terms of spend for the third and fourth quarters. Given our outlook on commodity pricing, in our anticipation of deceleration in organic growth, we are reducing our 2025 CapEx guidance to a range of $925 million to $1.05 billion, which is a reduction of about $137.5 million at the midpoint. With the acceleration of potential investment opportunities Adam's team is evaluating, we anticipate the growth wedge initially built into our CapEx guidance will be pivoted into discretionary acquisitions from ground game to bolt-ons. At the end of the quarter, we maintained over $1.1 billion in liquidity, consisting of $26 million in cash on hand and $1.1 billion available on our revolving credit facility. Our asset base continues to generate solid cash flow. We expect to grow this over time. As a testament to the confidence of our asset base and credit profile, we were recently upgraded to BB- by Fitch. In mid-June, we successfully completed a reopening of our 2029 convertible notes, issuing an additional $200 million under the same terms as the original 2022 offering, including a cap call with an effective conversion price exceeding $50 per share. The proceeds were used to partially repay our revolver and in conjunction with the offering, we repurchased 1.1 million shares. This opportunistic transaction enabled us to generate incremental annual interest and dividend savings of approximately $5 million. During my prepared remarks, I mentioned changes in guidance on differentials, LOE, production taxes and CapEx. We also have made changes to our guidance for total annual production and annual oil production that align with our outlook on activity for the remainder of the year. Before moving to Q&A, I'd like to briefly address impairment and cash taxes. Due to lower oil prices in the second quarter. NOG recorded a $115.6 million noncash impairment charge, leading us to reduce our DD&A guidance per BOE. Regarding cash taxes, based on our current analysis of the One Big Beautiful Bill Act. NOG will not be subject to federal cash taxes in 2025, and we do not anticipate having a federal cash tax liability through 2028 based on our current forecast. With that, I'll turn it back to the operator for Q&A.

[Operator Instructions] Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Yes. I was wondering if you could help me think about the cadence into 2026. And it sounds like most of your operators have been drilling more core wells, results have been good. We did take down oil production guidance, is that really solely related to just lower activity in the Williston? And what should we expect into '26 there? And as you think about the setup for '26, and you did mention, obviously, having a very similar TIL level could do maintenance production. But is that view in organic view? Or would that be a combination of organic and inorganic activity?

I'll try to get all those questions, if I forget one of them, just remind me, Scott. As it pertains to the cadence for '25, as you noticed, our Q2 spending was materially lower, right? So as we've seen a bit lower spending, that will translate into modestly lower volumes in Q3. But as our D&C list is building, we should see levels in Q4 similar to where we were in Q2. So we should exit the year pretty similar to where we are today. And as we mentioned in our prepared documents that we could certainly spend a level lower than this year in a lower TIL count, so -- and keep roughly the same as '25 volumes. If we spend a similar level, that would translate into certain growth. Look, it's July, I think it's a little bit premature. Look, we are a return-driven the #1 factor in which we are compensated on is return on capital employed, and that's what drives our decisions. And so growth is the output of those. And so our spending will be dictated by the price environment and all those things. And so whether we spend less money or more money next year and whether that translates into growth or more of a maintenance activity level will be driven by the commodity price environment as we get to the end of the year.

I appreciate that. And as my follow-up...

In terms of the organic or inorganic, we're talking our normal course spending, which would be a combination of what we would -- acreage replacement and which we embed our ground game capital in there and a typical organic spend.

Okay. And as a quick follow-up, it sounds like your comments alluded to the fact that you like some of the return profiles on the inorganic type of activity is being a little bit more -- I won't say predictable but more controllable, is that right? I mean, is there a sort of a strategy to look at some of the inorganic piece a little bit more? And could that become a higher blend going forward?

Yes. I mean I think, Scott, like I think, look, what I think you should take away from this is, number one, look, our operators are doing what they should be doing, which is we are going to be governed by not just the price of oil that you see on the screen today but by the future strip and by a risk factor on that future strip, right? And if you look at the fundamentals of oil today, they are in question, right? You have significant volumes coming online. And so the risk profile to that strip, of course, it could be better, but it could be worse, and it is simultaneous. And so we're seeing many of our operators pull back on activity and defer that activity until the environment is more clear, and they want to make money on that inventory. And there's -- as I said, the oil is still in the ground, so they'd rather preserve that until there's a better day. And so while everybody wants to see linear growth, the real key is to drill those wells when it's most profitable. When we look at an acquisition, on the other hand, if you think about long-dated inventory and stable long-term production that isn't really just a singular well that's being drilled in that singular period where that return is dependent on that short-dated period. We can allocate that same amount of capital to something that is much more resilient to a longer period of time and provides convexity because we do believe, regardless of what happens in the next 12 months, that the long-term profile for oil for natural gas and all those things is very, very strong. And so I think as we look at the risk profile for additional capital next year, to the extent that we do spend, as you saw as we came into this year, where we were going to spend up to $1.2 billion, and that would have been almost a similar level next year, whereas at a maintenance level, you're talking about $500 million to nearly $600 million difference, that $500 million to $600 million allocated towards acquisitions. Ultimately, if you were to spend that same amount of capital has a much more resilient growth profile should oil prices or natural gas prices collapse in the short term.

Your next question comes from the line of Charles Meade with Johnson Rice.

Nick, I'm going to try to go a little bit the same direction as Scott but perhaps from ask it a different way. Can you -- earlier in the year, you gave us an estimate for how much of your total capital budget? How much of it was growth CapEx? Can you give us an update on that now? How much growth CapEx for '26 is in your updated '25 capital budget?

I'm not sure. Well, look, if you look at -- we've cut from peak to trough about $275 million, right? We said about $250 million to $300 million of growth capital. So to the extent that we spent the bottom end of our guidance, we would effectively not be spending that. Charles, does that make sense?

That makes sense. And that's what I was looking for. That's the way I looked to me but I just wanted to know if it looked kind of the same to you. And then, Nick, I want to ask a question about how the -- how you're reducing your CapEx. Is this -- I can think of at least 3 possibilities. There's one, which is maybe you're nonconsenting some wells? Or number two, you just -- your fewer wells are being proposed and your agreeing with that decision? Or maybe from your more recent JVs where you guys have these -- you have those provisions for input. I mean, how does it -- how does the reduction spending kind of break down on the mechanism, how you're pulling back?

I'll let Adam discuss this a little bit further but it's really a combination. One, the beautiful thing about our business is that the rationale, especially, I'd say, from our private operators that are under the pressure of meeting public estimates and things like that and are more focused on profitability. Our private operators are doing their thing, and we're seeing a reduction in activity. And that's one of the reasons like, for example, we have seen such stellar Williston results is because you're not seeing the marginal wells being drilled. So our consent rate is still very high. And that's important because ultimately, the nonconsent tool is not something you want to be using because, obviously, we're not foregoing any inventory instead that inventory is being preserved for a better day. So that makes up roughly half of the capital -- potential capital reduction. The other half is really our discretionary spending. And those are projects and other ad hoc spending, things that we would otherwise have been spending. And we just frankly don't see -- from a risk-adjusted perspective, we don't see the returns in the forward price environment, right? As we came into 2025 in a 70-plus environment world, that growth is predicated on the fact that, that's the right thing to do for your investors, and you're generating a strong return. So growth for the -- we certainly could do that and spend that money but ultimately, it's about doing the right thing for your investors. So you want to grow, you can grow. But the question is, are you actually adding value by doing so. And I think our -- the answer that we've come to the conclusion is that capital is better preserved for a better day and it can be spent at any point in time. Adam?

Yes. I mean the short answer is we're aligned with our operators. It's activity based, and it's generally driven by the Williston. Everything that we've elected to 95% to 98%, effectively in the second quarter is well above our hurdle rates even in down price environment. And so going back to Nick's comments, then it's a matter of what's the discretionary spending and what we're seeing on the ground game front. We're certainly seeing an acceleration and the conversion rate is going higher, booking 22 deals over 7 in Q1. That being said, there's certain areas where people are looking to shed capital and when you start running expected full cycle rates of return, that's stuff that you're effectively just not going to pursue because the full cycle return isn't there. And so it's laser-focused on the assets in the near-term drilling opportunities as well as the long-dated inventory that's going to generate an acceptable rate of return on a full cycle basis.

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

I'm kind of approaching, I guess, a little bit different when I look at the cadence. So I guess if we're seeing operators start to maybe sell activity some, maybe the privates, especially as you pointed out, I guess what's interesting is it's -- I look over the last 4 or 5 quarters, the AFEs have been really steady right around kind of 2021 for 4 or 5 quarters, your wells in process is basically either at or near like a record level of 53%. I go back and look at the last couple of years, and there's obviously, as you would imagine, a pretty tight correlation with your wells in process and then what you all TIL the next quarter. I mean every time you have been around 50 wells in process, the following quarter, you're always 26 to 30 TILs. So I guess I'm trying to understand kind of the -- I don't want to call it a disconnect but what's sort of different where activity wells in process still looks really good but the second half guide of kind of, call it, 18 TILs on average in the second half relative to this really robust work in process number, like, I guess, try to help me reconcile that?

Yes. I mean I think what we're seeing from operators here is a conversation that we had in Q1, and it was we're going to maintain the schedule, right? We're going to keep our rigs for the most part, right? Every operator is a different philosophy. But by and large, they don't want to necessarily laid down a rig so that they have the optionality to the extent that oil extends the upside, right, because it's a lot harder getting that back. And so you're seeing a relatively steady cadence of drilling what we're seeing now are deferrals of some of these TILs that were in process, wells that were TIL prior to liberation day, and then just more of an elongation of the spud to sales timing. So I think that's starting to come into play, especially when you think about cube development, leave no location behind. You've got to come in drill 6, 8 wells, whatever it might be. Now they've got to come back and complete those wells effectively all at the same time. And so I think that's a piece of it as well. So I think it's a combination of all 3 of those different variables.

But I'd also point out, John, that the TIL count tends to follow the previous quarter, right? So if we put on a ton of wells in the third quarter, it oftentimes has more of an impact on our fourth quarter volume. So we should see an increase in our Q2, the lower spend in Q2 has more of an impact on 3Q than it does on 2Q, right? Because of the time cost averaging. It's all about the time of when those wells come online. And so as our spending has been decelerating in the first half of the year, that's going to have an impact sort of in the third quarter but that building and the till count will obviously -- actually, our production should increase as we head to the end of the year. So you're not wrong. It's just a matter of time. And so the difference -- as you look at our previous guidance, we had a much larger acceleration of that D&C list embedded as was our spend in the back half of the year.

Yes. And I guess what Adam touched on, I guess, kind of getting at, it seems like it would imply that you would end the year at a more elevated DUC level than I think what you all traditionally have, which is, I guess, what I'm kind of looking at. So that makes sense.

Yes. That's right. You don't see the same type of pull forward that you would have -- ironically, everyone gets mad at us when we see a huge pull forwards in the capital acceleration and they don't -- they don't care about the production benefit you get. And then here, it's the opposite, right? You can't win.

Right. And then just my other question, this quarter, pretty nice over 60% of the free cash flow that went to dividends and buybacks. How will you treat that nearly $50 million settlement you're getting in 3Q, does that kind of get put in a different bucket? Or does that get kind of considered part of the free cash flow in 3Q when you're kind of thinking about the allocation of shareholder returns?

I believe it's just working capital. So it goes into a receivable now, it will not be in the free cash flow. But, Chad...

No, it won't. But as far as what to do with it, John, I think we'll just -- we'll roll it into our normal kind of capital allocation process.

Your next question comes from the line of Noah Hungness with Bank of America.

I wanted to start off here. You guys mentioned that '25 and '26 free cash flow should be higher under the revised plan. Can you maybe talk about the use of those funds? And just where you use it would be buybacks? Would it be debt reduction?

Yes, I mean, the default -- no, the default uses, obviously, we sweep the revolver with every extra fund we get. To the extent we find inorganic opportunities, that is always. Generally, I don't ever want to think people to think that we think our stock is inexpensive but generally, from a value creation perspective and organic opportunities tend to have the highest return. So that would sort of rank as the first other use of proceeds and then followed by a stock buyback. I think we always want to be mindful of our overall leverage but I do think, as we look forward, depending on the price environment, commodity mix, et cetera. We, as I mentioned -- I mean, as Adam mentioned, the backlog is at record levels. So we would hope to be able to find the inorganic opportunities throughout this year and next year. If the cycle -- and I'd like to use 20 until 21, as examples, if the cycle does get nasty, one of the -- part of the logic of our recent convert offering is our liquidity is extremely high, and that's purposeful because we are in a situation where in almost virtually any price environment while our leverage multiple could possibly go up just because cash flows will go down, our absolute debt levels will keep falling. And so that means our liquidity will keep growing, and that means we will be able to find acquisitions and be able to continue to allocate through the cycle. And so I think our hope would be we can find true long-term value-added things to do because ultimately, that's how you create the most value in oil and gas.

Yes. No, it sounds like you guys have positioned yourself for countercyclical investment, which seems like a good setup. Then I guess, could you just give any color on the M&A market? I know you touched on it a bit. But I mean, how does it compare to a few months ago? And why do you think you are seeing such a robust list of assets on the market today?

Yes. So I mean, it's an interesting dynamic. I color -- I don't want to speak for Adam or Chad or Jim but it's color me a little bit surprised that within oil assets, it's still been fairly robust. And I think some of that is a combination of fund life. And frankly, even though prices are weaker, they are not that weak and people are still, in many cases, well in the money on their assets. And we've seen everything from royalties on our book that overlay our own properties to just diversified non-op properties to some of the more partnership and drilling style things that you've seen us do. The natural gas market is obviously very robust just because you have a very strong forward strip, and we've frankly seen activity in almost every active basin that we have evaluated. I don't know if you want to add to it?

The only other thing I would add, I think, is just overall seller expectations coming into the year, you're getting ready to launch a process in Q4 and Q1, and oil and commodities are at one price when you launch it and then you get the bid date and it's completely reset itself. And so the bid-ask spread there is inherently wide given the volatility. Now that we've seen things settle down a bit more. I think people coming into these processes and being at relatively similar levels in terms of the commodity prices come bid, you can manage those seller expectations a bit as well. And so hopefully, that means that there's something to get done. But Obviously, we're going to continue to stick to our hurdle rates and the underwriting that we typically do.

Your next question comes from the line of Phillips Johnston with Capital One.

Sorry to ask another question on quarterly cadence. But I just wanted to clarify Nick's earlier comments on production cadence for the remainder of the year. It sounds like you're expecting fourth quarter volumes will look something like what you just printed for Q2. If that's the case, it seems like that would imply that Q3 volumes will be down fairly significantly from 2Q levels. I think you alluded to a slight decline in Q3 from Q2. So I just wanted to reconcile that.

Yes. I mean I think, Phill, it really depends. When I say similar, it really is going to depend, as you know, for us, the TIL cadence can vary widely, right? So it could be a situation where Q3 is modest and Q4's increase is more modest or it could be where Q3 is a little bit deeper and Q4 is more significant. So it really just depends on the timing of those completions. So the earlier the completions come online, it's just going to be -- and frankly, if we can -- so prices remain stronger. We may then see Q1 activity pull forward and Q4 may stay more robust, and that would ultimately drive upward pressure to our overall guidance. So I think it's not necessarily all bad. I think, as always, there's a little bit of fog of war in terms of how ours goes. But what I will tell you is that just a function of the lower overall completion count in Q2, we will see a modest dip in Q3. The question is how -- I mean, I don't think it will be -- I would say, we look at it mid-single digits is something that looks more realistic than something -- if that makes sense.

And then throw in curtailments, right, that we're seeing from some of our private operators, and that's effectively getting managed on a month-to-month basis. So it would be the other variable to consider.

So if prices are stronger, we could see those come off but we've made the assumption that those will continue.

Okay. That makes sense. And then just some clarification on some of your comments on '26. If you guys did determine that it's prudent to sort of operate in a maintenance mode, would you look to kind of maintain oil volumes pretty flat with the 25% average of around 75,000 a day or sort of second half levels that are closer to 72,000 a day?

Well, I mean, I think the answer is when we talk about maintenance, we mean maintenance, so we mean versus our annual guidance. However, what I would say is that from a capital allocation perspective, if oil prices are $50 and gas prices are $450, we might allocate more money to gas, right? So I mean I think we'll do what's right for the business. But when we talk about a spend level today on a generic basis, and we're talking about that, it would be versus the annual '25 guide not versus where -- versus that lower level.

Your next question comes from the line of Paul Diamond with Citi.

I just want to touch quickly on kind of the cost structure. You mentioned that absolute AFE costs were down 5% sequentially, somewhat split between oil and gas. But I guess how much -- do you guys see any further runway with that downward pressure? Or is pretty much everything baked at this point?

Yes. So I mean, Paul, I'd rather let Jim or Adam talk about this. But the one thing I'd say is that -- we are -- we've obviously seen a pretty material reduction in the rig count. I got asked last question about the last quarter about steel costs and tariffs and stuff like that. And I said, I've never seen an environment where oil costs went down and well cost didn't and so far have been proven right. And I think that where we are now as we were starting to see, for the first time, frac spreads usage come down materially. And we've seen a lot of consolidation in that sector. And so prices -- that's the biggest cost, right? Rig rates are not the biggest driver of that anymore. I think to see material cost reductions now, you'd have to see the frac spread count contract materially. And I think if that happened, you might see margins there really collapsed and then you could see material relief. Otherwise, I think most of it has been small and incremental, either through modest efficiencies or through slight costs here and there. I don't know, Adam or Jim, if you want to add?

The conversations that we've been having with a handful of our JV partners, they're certainly seeing downward pressure. That being said, we're a relatively conservative shop, right? So it's going to be a show me and it's going to come through the actuals when we start truing up our accruals. So we'll continue to accrue based on the AFEs that we get in the door. But anecdotally, I think we could potentially see something like that. That's probably something more of a 26% kind of realization to the extent that we see it continue in the direction that operators are guiding us.

Got it. Makes perfect sense. And then just one kind of quick one on the M&A market again. You all mentioned that there were 10 ongoing processes worth $8 billion give or take. Is there any concentration in the structure of those larger deals? Are they more non- op, are they more joint development, co-bids, et cetera?

Honestly, it's across the board. We're seeing a number of different non-op packages. We're also seeing a number of different kind of co-buying and minority interest buy down. So I don't think it's necessarily concentrated to any given basin or any given structure at this point. So we've got a buffet of options.

Yes. I mean I think the one thing I would highlight and we really -- whether we're successful at all or on one or any of these processes is always a total crap shoot for us. But what I would say is that I get feedback from investors just because we've had more success on the co-bid over the last few years like, well, where are the traditional non-op assets. Actually, we've seen and we even have had several that are coming to market, some of the largest just standard non-op assets we've seen in maybe ever. So some of the biggest just regular weight non-op assets we've ever seen come to market. And so whether or not the efficacy of those transactions still needs to be tested. But it does tell you that as the natural consolidator, some of these assets we view ourselves as uniquely situated that if there was to be a buyer, which could be potentially one of a handful of people who could do it.

Your final question comes from the line of Noel Parks with Tuohy Brothers.

So just a lot of interesting topics and questions have come up. I guess, would you say that you're at a juncture where sort of specific post-deal related divestments are sort of receding as a driver of assets coming to market. We certainly have some very large acquisitions, I think, especially in the Permian that have now been digested and could conceivably be at the point where they're now looking at non-op stuff they could spin off. But I just wonder, it's been such an unusual first half of the year if that's figuring in at all or whether those dynamics are not really affecting.

I don't think so. You might have seen that there was just a big ConocoPhillips Mid-Con package. That's a perfect example of a kind of post-merger that was sort of their marathon post-merger.

Yes. I mean I think the way that we think about it is you've got to merge, right? Then you've got to wrap your head around the assets and then -- only then can you bring a lot of these assets to market. And so yes, you've seen to Nick's point, some of these packages come out and fully marketed. A lot of other operators are taking a different tack, whether it's through the non-op market where 20% of these portfolios are all made up of non-operated properties. They're also doing it in a way where they're selling down a minority interest on a unit-by-unit basis but still retaining operatorship. And so I think operators are getting creative and not necessarily just throwing a massive asset package into the market. And so we're seeing all of the above in terms of kind of the different structures as to how a lot of these operators are socializing their assets post-merger.

Got it. And I've been thinking about a lot of scrutiny, I hear from the gas side, the pure-play gas producers of associated gas in the Permian and what weaker oil might do there as far as activity. And I know you guys have talked about being pretty mindful of what gas takeaway looks like when you're looking at Permian assets. Is that correlating at all with what might be happening in Appalachia with in-basin power and so forth? Just wondering if those sort of concern about the -- ongoing concern about Permian gas and pricing versus maybe new opportunities that we're seeing in Appalachia. Is that playing out in the deals you see coming to market or in price expectations?

I don't think that people ultimately, Noel, I think they can only price based on where the differentials. If it was priced into the forward differential strip in some form or fashion, I think then they can make an economic hit on it or if they had a direct contract. So perhaps there are certain scenarios where people can buy an asset because they might have some directly. That's more of an operator game than it would be for us, ultimately, unless we see something that's actually impacting those future prices directly. I don't think we're going to be able to see that. I don't know if you have any -- I mean I do think, look, as you have what you would call like stranded gas and from a regional basis that can't really get hub related prices or may not have access to LNG, I think given the AI and data center boom, it does not surprise me that people are going to try to take advantage of that cheap source. And so it would not surprise me if you start to see a lot of this building, next thing you know, Midland might be the center of a huge data center boom because they'll want to use that gas. And you're seeing that, obviously, there's been a lot of hullabaloo going on in Appalachia about just that. And so I do think that over time, that can narrow those bands but it has not been enough to have some -- and remember the time to build these things super long and things like that, I mean. And so it has not been enough to actually impact those markets of any significance at this point.

I will now turn the call back over to Nick for closing remarks.

Thank you all for joining us today. We look forward to talking to you in the coming weeks. And again, thanks for your interest in our company.