Earnings Call Transcript - NOG Q2 2025

Operator, Operator

Greeting, and welcome to the NOG's Second Quarter 2025 Earnings Conference Call. 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.

Evelyn Infurna, Vice President, Investor Relations

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.

Nicholas L. O'Grady, CEO

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 five 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 will 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 prices signal 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 four to seven 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, regardless of 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 convertible 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, unbounded 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 non-operator, 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 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 the 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?

Adam Dirlam, President

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, maintained their development cadence with the exception of a few operators in the Williston who have pulled back. As a result, we saw one net well deferred and 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 costs 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 over 95%. 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 expect a slight increase in TILs in Q3 before ramping through Q4 as the Permian and Appalachia increase 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 seven 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, farm-outs, or 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.

Chad Allen, CFO

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, largely due to higher expenses in the Williston caused by lower volumes and greater fixed cost absorption, as well as in the Permian due to increased saltwater disposal costs. To account for higher costs 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 spending between the third and fourth quarters. Given our outlook on commodity pricing and 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 in 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 have also 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, Operator

Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold, Analyst

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?

Nicholas L. O'Grady, CEO

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, we could certainly spend a level lower than this year with a lower TIL count and keep roughly the same volumes as '25. If we spend a similar level, that would translate into certain growth. Look, it's July; I think it's a little premature. Look, we are return-driven. The #1 factor in which we are compensated 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.

Scott Hanold, Analyst

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

Nicholas L. O'Grady, CEO

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

Scott Hanold, Analyst

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 being a little 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?

Nicholas L. O'Grady, CEO

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, 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 towards something that is much more resilient over 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.

Operator, Operator

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

Charles Meade, Analyst

Nick, I'm going to try to follow the same line of questioning as Scott but frame it differently. Earlier this year, you provided us with an estimate of your total capital budget. Can you give us an update on how much of that was allocated for growth CapEx? Specifically, how much growth CapEx for 2026 is included in your revised 2025 capital budget?

Nicholas L. O'Grady, CEO

I'm not sure. However, if you examine the situation, we've reduced our expenses by about $275 million from the highest point to the lowest point. We mentioned a range of $250 million to $300 million for growth capital. Therefore, if we allocate funds at the lower end of our guidance, it effectively means we wouldn't be spending that amount. Charles, does that make sense?

Charles Meade, Analyst

That makes sense, and that's what I was looking for. It seemed that way to me, but I wanted to know if it looked the same to you. Nick, I would like to ask about how you are reducing your capital expenditure. I can think of a few possibilities: maybe you are not consenting to some wells, or perhaps fewer wells are being proposed and you are agreeing with that decision. It could also be related to your recent joint ventures where you have provisions for input. How does the reduction in spending break down in terms of the mechanisms you are using to pull back?

Nicholas L. O'Grady, CEO

I'll let Adam elaborate on this, but it's really a mix of factors. One of the great aspects of our business is that our private operators, under pressure to meet public estimates, are more focused on profitability. This has led to a decrease in activity. For instance, the outstanding results in the Williston area can be attributed to fewer marginal wells being drilled. Our consent rate remains high, which is important because we don’t want to rely on the non-consent tool; instead, we aim to preserve our inventory for better opportunities in the future. This accounts for about half of the potential capital reduction. The other half comes from our discretionary spending, which includes various projects and expenses that we would typically invest in. However, from a risk-adjusted viewpoint, we don’t see satisfactory returns in the current price environment. As we approach 2025 with prices above 70, any growth would need to be justified for our investors, ensuring strong returns. While we could allocate funds for growth, the key question is whether this growth actually adds value. Our conclusion is that it’s wiser to conserve capital for more favorable conditions, which we can deploy at any time. Adam?

Adam Dirlam, President

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 a 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 seven 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.

Operator, Operator

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

John Freeman, Analyst

I am approaching the situation a bit differently when considering the cadence. If we are seeing operators potentially reducing their activities, particularly among private firms, it’s intriguing to note that over the last four or five quarters, the AFEs have remained consistent at around 2021. Your wells in process are currently at or near a record level of 53%. Over the past years, I've noticed a strong correlation between the number of wells in process and your TIL count in the subsequent quarter. Each time you have around 50 wells in process, you consistently report 26 to 30 TILs in the following quarter. I’m trying to understand the differences here because the activity and wells in process look quite promising, yet the guidance for the second half indicates an average of only 18 TILs, which seems at odds with such a strong work in process figure. Please help me make sense of this.

Adam Dirlam, President

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 has a different philosophy. But by and large, they don't want to necessarily lay down a rig so that they have the optionality to the extent that oil extends the upside, right, because it's a lot harder to get 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 six, eight 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 three of those different variables.

Nicholas L. O'Grady, CEO

I want to highlight, John, that the TIL count often reflects what happened in the previous quarter. If we drill a lot of wells in the third quarter, it usually affects our fourth quarter volume more significantly. Therefore, we can expect an increase in our second quarter, as the lower spending in that quarter impacts the third quarter more than it does the second. This is due to the time cost averaging, which depends on when those wells start production. As we reduce our spending in the first half of the year, it will influence our third quarter, but we should see an increase in production by the end of the year. You're correct; it's just a timing issue. Moreover, the difference from our prior guidance includes a significantly higher acceleration of the D&C list, which was based on our spending plans for the latter half of the year.

John Freeman, Analyst

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.

Nicholas L. O'Grady, CEO

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 care about the production benefit you get. And then here, it's the opposite, right? You can't win.

John Freeman, Analyst

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 Q3? Does that kind of get put in a different bucket? Or does that get kind of considered part of the free cash flow in Q3 when you're kind of thinking about the allocation of shareholder returns?

Nicholas L. O'Grady, CEO

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...

Chad Allen, CFO

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

Operator, Operator

Your next question comes from the line of Noah Hungness with Bank of America. I believe it's just working capital. So it goes into a receivable now; it will not be in the free cash flow. But as far as what to do with it, I think we'll just roll it into our normal capital allocation process.

Noah Hungness, Analyst

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?

Nicholas L. O'Grady, CEO

Yes, we typically use any extra funds we receive to pay down the revolver. When we find inorganic opportunities, we always consider them. I want to clarify that we don't necessarily believe our stock is undervalued, but from a perspective of value creation, organic opportunities usually offer the highest returns. Therefore, that would be our primary way to use proceeds, followed by stock buybacks. We remain cautious about our overall leverage, but as we look ahead, depending on market conditions and commodity mix, we hope to identify inorganic opportunities this year and next. If the market becomes challenging, as seen in 2020 to 2021, our recent convertible offering was designed to ensure we maintain high liquidity. This is intentional, as in almost any price environment, while our leverage ratio might increase due to declining cash flows, our total debt levels will continue to decrease. Consequently, our liquidity will grow, enabling us to pursue acquisitions and allocate resources effectively throughout market cycles. Ultimately, our goal is to identify long-term value-adding opportunities because that is how we maximize value in the oil and gas sector.

Noah Hungness, Analyst

Yes. No, it sounds like you guys have positioned yourself for counter-cyclical 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?

Nicholas L. O'Grady, CEO

Yes, it's an interesting situation. I'm a bit surprised that despite the challenges, oil assets remain quite strong. This stability could be attributed to aspects like fund lifespan. Even though prices have dipped, they aren't excessively low, and many are still making good returns on their investments. We're seeing various activities, from royalties linked to our own properties to diverse non-operated properties and various partnerships and drilling projects we've undertaken. The natural gas market is also thriving, supported by a strong forward price outlook, and we've noted active operations in nearly every basin we’ve assessed. Would you like to add anything?

Adam Dirlam, President

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.

Operator, Operator

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

John Phillips Johnston, Analyst

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 levels. So I just wanted to reconcile that.

Nicholas L. O'Grady, CEO

Yes, it really depends. When I say similar, it depends on our TIL cadence, which can vary widely. We might see a modest Q3 with a small increase in Q4, or Q3 could be more significant and Q4 could be even stronger. It really hinges on the timing of the completions. The earlier they come online, the better it could be for our prices. If prices stay strong, we might see some activity in Q1 pulled forward, and Q4 could remain robust, which would positively impact our overall guidance. It's not all negative. There is always some uncertainty in predicting these outcomes. However, due to the lower overall completion count in Q2, we expect a modest dip in Q3. Realistically, we would look at a mid-single digit decline.

Adam Dirlam, President

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.

Nicholas L. O'Grady, CEO

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

Operator, Operator

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

Paul Diamond, Analyst

I just want to quickly discuss the cost structure. You mentioned that absolute AFE costs decreased by 5% sequentially, somewhat divided between oil and gas. But do you see any potential for further downward pressure, or is everything pretty much set at this point?

Nicholas L. O'Grady, CEO

Yes. I would prefer Jim or Adam to elaborate on this, but I want to note that we have seen a significant decrease in the rig count. In the previous quarter, I discussed steel costs and tariffs, and mentioned that I've never observed a situation where oil costs decreased while well costs remained high, which has proven to be true so far. Currently, we're witnessing a substantial drop in frac spread usage for the first time, alongside considerable consolidation in that sector. Consequently, prices are the main concern; rig rates are no longer the biggest factor. For us to see significant cost reductions, there would need to be a substantial decrease in the frac spread count. If that occurs, margin pressures could lead to meaningful relief. Otherwise, most of the changes have been minor and gradual, primarily driven by slight efficiencies or small cost adjustments. Adam or Jim, would you like to add anything?

Adam Dirlam, President

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.

Operator, Operator

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

Noel Parks, Analyst

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.

Nicholas L. O'Grady, CEO

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.

Adam Dirlam, President

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 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.

Nicholas L. O'Grady, CEO

Yes, I would like to emphasize that our chances of success in any of these processes are always uncertain. However, I've received feedback from investors highlighting our recent success with co-bids, prompting questions about the absence of traditional non-operated assets. We're actually seeing several significant non-operated assets coming to market, some of the largest we've encountered. The effectiveness of these transactions still needs to be assessed, but it indicates that as a natural consolidator, we believe we are in a unique position to be a potential buyer, limited to a few possible candidates.

Operator, Operator

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

Nicholas L. O'Grady, CEO

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.

Operator, Operator

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.