Northern Oil and Gas (NOG) Second Quarter 2025 Earnings Conference Call

Date

Aug. 1, 2025 at 9 a.m. ET

Call participants

Chief Executive Officer — Nick O’GradyPresident — Adam DirlamChief Financial Officer — Chad Allen

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Risks

Noncash impairment charge: Chad Allen stated, due to lower oil prices in Q2 2025, the company recorded a $115.6 million noncash impairment charge.Lease operating expenses (LOE): Lease operating costs per BOE increased 6% to $9.95 in Q2 2025, primarily due to lower volumes, higher fixed cost absorption in the Williston, and increased saltwater disposal costs in the Permian.Natural gas realizations: Natural gas realizations decreased to 82% of benchmark prices from 100% in the previous quarter, attributed to Waha market weakness, lower NGL prices, and weaker Appalachian seasonal pricing.Production deferrals/shut-ins: Adam Dirlam reported one net well was deferred and approximately 3,800 barrels per day were shut in due to pricing pressure from a single operator in Q2 2025.

Takeaways

Free cash flow: Free cash flow (non-GAAP) was approximately $126 million for Q2 2025, excluding a $48.6 million legal settlement; representing the 22nd consecutive quarter of positive free cash flow (non-GAAP), totaling over $1.8 billion in free cash flow (non-GAAP) over the past 22 quarters.Total average daily production: 134,000 BOE per day, up 9% from 2024 and flat sequentially.Oil production: 77,000 barrels per day, up 10.5% from 2024, but down 2% sequentially, mainly due to reduced Williston activity.Record gas volumes: 343 MMcf per day; driven in part by Appalachian JV wells contributing in the latter half of Q2.Drilling and completion (DNC) activity: 53.2 net wells in process at quarter end, with a 70% quarter-over-quarter increase in drilling activity; 27.1 net wells added, and the Permian making up roughly half of total wells in process.Normalized well costs: Averaged approximately $800 per lateral foot; oil-weighted basin costs declined 6% quarter over quarter on a normalized basis.Capital expenditures (CapEx): $210 million allocated (excluding non-budgeted acquisitions), 16% lower sequentially; new guidance for 2025 CapEx at $925 million-$1.05 billion, marking an approximate $137.5 million reduction at the midpoint of 2025 CapEx guidance.Net wells and ground game: 4.8 net wells and over 2,600 net acres added from 22 closed transactions (vs. 7 deals in Q1 2025); over 170 transactions reviewed, a 40% increase quarter over quarter.Liquidity: Over $1.1 billion available on a revolving credit facility, consisting of $26 million in cash and full availability on the $1.1 billion revolver.AFEs and elections: Estimated 95%+ core election rate; AFE activity up over 50% versus 2024’s quarterly average.Convertible notes offering: Issued $200 million of additional 2029 convertible notes in June 2025, with a conversion price exceeding $50 per share; used proceeds in mid-June 2025 to partially repay the revolving credit facility and repurchase 1.1 million shares, generating approximately $5 million in annual interest and dividend savings as a result of the 2029 convertible notes reopening.Credit upgrade: Fitch upgraded Northern Oil and Gas to BB- (Double B minus).Impairment and tax position: A $115.6 million noncash impairment charge (GAAP) was recorded due to lower oil prices; no federal cash tax liability is expected in 2025 or through 2028, under current forecasts.CapEx allocation: $210 million in capital expenditures, with 34% to the Permian, 25% to Williston, 15% to Uinta, and 26% to Appalachia; $185 million of the spend designated for development CapEx.Guidance updates: Revised 2025 guidance for oil differentials, LOE, production taxes, CapEx, total annual production, and oil production, based on updated activity outlooks and costs.

Summary

Northern Oil and Gas(NYSE:NOG) signaled a deliberate shift in capital allocation away from near-term organic growth, favoring increased discretionary acquisitions and inventory building as oil prices and operating conditions remain volatile. Management emphasized the company’s flexibility to quickly adapt spending and activity to the commodity environment, leveraging deferred completions and a growing backlog of drilling opportunities. The M&A pipeline was described as being at an “all-time peak,” with ongoing evaluation of more than ten transactions exceeding $8 billion in combined value, broadening the company’s strategic options. Guidance revisions targeted both cost management and production estimates for 2025, with explicit plans to preserve capital for high-return deployment as risk and price signals warrant. While realizing continued strength in cash generation and liquidity, the company is prepared for countercyclical moves in both acquisition and return of capital in the coming periods.

CEO O’Grady noted, “our backlog of potential acquisitions, from bolt-ons to truly transformational transactions, is at an all-time peak.”President Dirlam reported 80% of wells in process are now located in the Permian, Uinta, and Appalachia.The company is structuring spending to allow reallocation between organic development and inorganic deals, underscored by, “we anticipate the growth wedge initially built into our CapEx guidance will be pivoted into discretionary acquisitions from ground game to bolt-ons.”O’Grady stated, “If we spend a similar level [in 2026], that would translate into certain growth … our spending will be dictated by the environment,” highlighting a returns-based, flexible operational model.Cash proceeds from the approximately $50 million legal settlement will be treated as working capital and excluded from non-GAAP free cash flow metrics when received.

Industry glossary

Ground game: Opportunistic acquisition of acreage, undeveloped inventory, or small working interests frequently outside of formal marketed processes.DNC (drilled, not completed): Wells that have been drilled but not yet completed and brought online, representing production inventory for future periods.AFE (authorization for expenditure): A formal agreement to participate in a specific well or drilling project, outlining projected costs and partners’ commitments.TIL (turned in line): Wells that have been completed and brought into production (“on line”) during a given time frame.

Full Conference Call Transcript

Nick will provide introductory remarks, followed by Adam, who will share an overview of Northern Oil and Gas, Inc.’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-Ks 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.

Nick O’Grady: 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. Northern Oil and Gas, Inc.’s business model is proving its resiliency every day. We built a solid business that embodies a number of tenets: diversity, scale, and risk optimization that consistently drives results. Our units in the 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 strengthen both, and our conservative and disciplined approach to investing, as well as downside protection, supports our cash flow in the near term through hedging. 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 a DNC 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.

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. An 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 in the ground, and we 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 Utica become unitized rapidly.

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. In our view, 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, impact and quality. These potential transactions cover almost every structure, basin of operation, and variants 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 Northern Oil and Gas, Inc., 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. Northern Oil and Gas, Inc.’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 US 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 and 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 Northern Oil and Gas, Inc. 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 cycles. 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: 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 TIL 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 DNC 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 DNC 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 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 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 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 nonoperator 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 nonoperated model to navigate the current environment. With that, I’ll turn it over to Chad.

Chad Allen: Thanks, Adam. Northern Oil and Gas, Inc. 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 2024 and in line on a sequential quarter basis. Oil production was approximately 77,000 barrels of oil per day, up 10.5% from 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 twenty-second consecutive quarter of positive free cash flow, exceeding $1.8 billion over that time period. Oil 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 due to higher expenses in the Williston due to lower volumes and greater fixed cost absorption and 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 other, was $210 million, 16% lower sequentially. Overall, $210 million was allocated with 34% to the Permian, 25% to the Williston, 15% to the 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 fifty-fifty split in terms of spend for 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 a revolving credit facility. Our asset base continues to generate solid cash flow, and 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 double B minus 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 a 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 to 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, Northern Oil and Gas, Inc. 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, Northern Oil and Gas, Inc. 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: 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. Your first question comes from the line of Scott Hanold with RBC Capital Markets.

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

Nick O’Grady: Try to get all those questions. If I forget one of them, just remind me, Scott. As it pertains to the cadence for 2025, 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 DNC 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 and a lower TIL count and keep roughly the same as 2025 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 company. The number one factor in which we are compensated on is return on capital employed, and that’s what drives our decisions. So growth is the output of those, and so our spending will be dictated by the environment and all those things. And so whether we spend growth or less money or more money next year and whether that translates into 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: Appreciate that. And as my follow-up, in terms of the organic or inorganic work, we’re talking, you know, our normal course spending, which would be a combination of what we would, you know, acreage replacement in which we embed our ground game capital in there and a typical organic spend.

Nick O’Grady: Okay. Thanks. And as a quick follow-up, it sounds like your comments allude to the fact that you like some of the return profiles that’s on the inorganic type of activity is, you know, being a little bit more, and 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 pieces a little bit more, and could that become a higher blend, you know, going forward?

Nick O’Grady: Yeah. 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, you know, 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, you know, they are in question, right? You have significant volumes coming online. And so the risk profile to that strip, you know, of course, it could be better, but it could be worse. And it is somewhat tenuous.

And so we’re seeing many of our operators pull back on activity and defer that activity until the environment’s 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, you know, 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 twelve months, that the long-term profile for oil, for natural gas, and all of 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, you know, as you saw as we entered 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, you know, a $500 to nearly $600 million difference. That $500 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: Your next question comes from the line of Charles Meade with Johnson Rice.

Charles Meade: Good morning, Nick, to you and your whole team there. Nick, I’m going to try to go a little bit the same direction as Scott, but perhaps ask it a different way. Can you know, earlier in the year, you gave us an estimate for how much of your total capital budget was growth CapEx. Can you give us an update on that now? Like, how much growth CapEx for ’26 is in your updated ’25 capital budget?

Nick O’Grady: I’m not sure. Well, look. If you looked at it, we’ve cut from peak to trough about $175 million. Right? We’d set about $150 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 Meade: That makes sense, and that’s what I was looking for. I just wanted to know if it looked kind of the same to you. And then, Nick, I want to ask you a question about how you’re reducing your CapEx. Is this, yeah, I can think of at least three possibilities. You know, there’s one, which is maybe you’re nonconsenting some wells. Or number two, you’re just fewer wells are being proposed, and you’re agreeing with that decision, or maybe from your more recent JVs where you guys have these, you know, you have those provisions for input. I mean, how does the reduction in spending break down on how you’re pulling back?

Nick O’Grady: Yeah. The mechanisms why you put 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, you know, the rational, especially, I’d say, from our private operators that aren’t under the pressure of, you know, 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 drilled.

So our consent rate is still very high, and that’s important because ultimately the non-consent 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, you know, roughly half of the 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?

You know, as we came into 2025 in a $70 environment world, that growth is predicated on the fact 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 the answer that we’ve come to the conclusion is that capital is better preserved for a better day, it can be spent at any point in time.

Adam Dirlam: Yeah. 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, 98% effectively in the second quarter, is well above our hurdle rates even in a down price environment. And so, you know, going back to Nick’s comment, 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 in the conversion rate is going higher, you know, booking 22 deals over seven in Q1. That being said, there’s certain areas where, you know, people are looking to shed capital.

And when you start running, you know, 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, you know, the assets and 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: Your next question comes from the line of John Freeman with Raymond James.

John Freeman: Thanks. Good morning, guys. I was going to, I’m kind of approaching, I guess, a little bit different when I look at the cadence. So I guess if, you know, we’re seeing operators start to maybe slow activity some, maybe the privates especially as you pointed out, I guess what’s interesting is it’s, you know, I look over the last, you know, four or five quarters, the AFEs have been really steady right around kind of 2021 for four or five 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 y’all till the next quarter. I mean, time y’all 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, disconnect, but what sort of different where activity, wells, and 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.

Adam Dirlam: Yeah. I mean, I think if what we’re seeing from operators here, this conversation that we had in Q1, 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, you know, oil extends to 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, you know, TILed 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 that, you know, 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, you know, 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, you know, all three of those, you know, 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 3Q than it does on 2Q. You know, Q2, the lower spend in Q2 has more of an impact on, right? Because of the, you know, 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, going to have an impact sort of in the third quarter, but that building in the TIL 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 is as we look at our previous guidance, we had a much larger acceleration of that DNC list. Embedded as was our spend in the back half of the year.

John Freeman: Yeah. And I guess what Adam touched on is I guess, kind of what I’m getting at. It seems like it would imply that you would end the year at a more elevated DUC level than I think what y’all traditionally have, which is, I guess, what I was kind of, you know, looking at. So that makes sense.

Nick O’Grady: That’s right. Yeah. You don’t see the same type of pull forwards that you would’ve that, you know, ironically, wrong, you know, gets mad at us when we see the huge pull forwards in the capital acceleration. And they don’t love, you know, they don’t care about that the production they benefit you get. Then here, it’s the opposite. Right? You know? Can’t win. Right.

John Freeman: Right. And then just my other question, you know, this quarter, you know, 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 March when you’re kind of thinking about the allocation of shareholder returns?

Nick O’Grady: Believe it’s just working capital. Yep. So it goes into a receivable. Now it will not be in the free cash flow with a check. No. It won’t. But as far as what to do with John, I think, you know, I think we’ll just roll it into our…

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

Noah Hungness: Morning. I wanted to start off here. You guys mentioned that 2025 and 2026 free cash flow should be higher under the revised plan. Can you maybe talk about the use of those funds, and just, where would you use it? Would it be buybacks? Would it be debt reduction?

Nick O’Grady: Yeah. I mean, I think the default, no, the default use is 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 thank people to think that, you know, we think our stock is inexpensive, but generally, from a value creation perspective, inorganic opportunities tend to have the highest returns, 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, etcetera, we, as I mentioned, I mean, and as Adam mentioned, the backlog is at record levels, so we would hope to be able to find inorganic opportunities throughout this year and next year. If the cycle, and I like to use 2020 until 2021 as examples. If the cycle does get nasty, you know, one of the part of the logic of our recent convert offering is, you know, 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 could go down. Our absolute level debt levels will keep falling. And so that means our liquidity will keep growing, and that means we will be able to, our hope would be we can find true long-term value-added things to do to find acquisitions and be able to continue to allocate through cycle. And so I think because ultimately that’s how you create the most value in oil and gas.

Noah Hungness: Yeah. No. It sounds like you guys are positioning yourself for your countercyclical investment. Which, yeah, seems like a good setup. And 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 real robust list of assets on the market today?

Nick O’Grady: Yeah. So, I mean, it’s an interesting dynamic. I don’t want to speak for Adam or Chad or Jim, but it’s coloring me a little bit surprised that, you know, within oil assets, it’s still been fairly robust. And I think some of that is a combination of fund life and, you know, frankly, even though prices are weaker, they are not that weak, and people are still, you know, in many cases, well in the money on their assets. And we’ve seen everything from royalties on our that overlay our own properties to just diversified non-op properties that, you know, that to some of the more partnership and drilling style 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.

Adam Dirlam: The only other thing I would add, I think, is just overall seller expectations. Coming into the year, you’re, you know, getting ready to launch a process in Q4 and Q1. You don’t hit 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, you know, 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 day, you know, you can manage those seller expectations a bit as well. And so, you know, 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: Your next question comes from the line of Phillips Johnston with Capital One.

Phillips Johnston: Hey. Thanks for the time. 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. You know, if that’s the case, it seems like that would imply that Q3 volumes will be down fairly significantly from Q2 levels. And I think you alluded to a slight decline in Q3 from Q2. So just wanted to reconcile that.

Nick O’Grady: Yeah. I mean, I think, Phillips, it really depends when, you know, 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, the, you know, it’s just going to be, and frankly, if we can, you know, so if prices remain stronger, we may then see Q1 activity pull forward in 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, you know, how, I mean, I don’t think it will be, you know, I would say, you know, we look at it, you know, mid-single digits is something that looks more realistic than something, but 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 that 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.

Phillips Johnston: Okay. That makes sense. Then just some clarification on some of your comments on 2026. 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 2025 average of, you know, around 75,000 a day? Or sort of second-half levels that are closer to, you know, 72,000 a day?

Nick O’Grady: We mean maintenance, and we mean versus our annual guidance. However, what I would say is that from a capital allocation perspective, 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, we’re talking about that, it would mean versus the annual 2025 guide, not versus that lower low.

Phillips Johnston: Okay. Sounds good, Nick. Thank you.

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

Paul Diamond: Thank you. Good morning all. Thanks for taking the call. Just wanted to touch quickly on kind of the cost structure. You mentioned an absolute AFD cost. Were down 5% sequentially. Somewhat split between oil and gas. But I guess, how much do you guys see any further runway with that, you know, downward pressure? Is much everything baked at this point?

Nick O’Grady: Yeah. So, I mean, Paul, I’d rather let Jim or Adam talk about this, but the one thing I’d say is that, you know, we’ve obviously seen a pretty material reduction in the rig count. You know, I got asked last question about, you know, 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, you know, 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 seen a lot of consolidation in that sector, and so prices, that’s the biggest cost, 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 collapse, 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, if you want to add.

Adam Dirlam: Yeah. The conversations that we’ve been having with, you know, a handful of our JV partners, they’re certainly seeing that downward pressure. That being said, you know, 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 chewing up our accruals. So we’ll continue to accrue based on the AFEs that we get in the door. But anecdotally, I think, you know, we could potentially see some something like that. That’s probably something more of a 2026 kind of realization to the extent that we see it. You know? Continue in the direction that operators are guiding us.

Paul Diamond: 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, you know, 10 ongoing processes worth $8 billion give or take. Is there any concentration of the structure of those larger deals? Are they more normal? More joint development, COVID, etcetera?

Adam Dirlam: 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-downs. 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.

Nick O’Grady: Yeah. I mean, I think the one thing I would highlight and if we really, whether we’re successful at all or on one or any of these processes, it’s a crapshoot for us. But what I would say is that, you know, I get feedback from investors just because we’ve had more success on the COVID over the last few years like that, you know, and we even have several that are coming to market, some of the largest, you know, just standard non-op assets we’ve seen in maybe ever. So some of the biggest just regular way non-op assets we’ve ever seen come to market.

And so whether or not, well, you know, the efficacy of those transactions still needs to be tested, but it does tell you that, you know, as the natural consolidator, you know, some of these assets, we view ourselves as uniquely situated that, you know, if there was to be a buyer, potentially one of a handful of people who could do it.

Operator: Your final question comes from the line of Noel Parks with Tony Brothers.

Noel Parks: Morning, Noel.

Noel Parks: Hi. Good morning. How are you doing?

Adam Dirlam: Doing good.

Noel Parks: So just a lot of interesting topics and questions have come up. I guess you’re at a juncture where sort of specific, you know, 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, you know, non-op stuff they could spin off. But I just wonder if it’s been such an unusual first half of the year, if that’s figuring in at all or whether those dynamics aren’t really affecting what you’re seeing?

Nick O’Grady: I don’t think so. You might have seen that there was just a big ConocoPhillips MidCon package. That’s a perfect example of a kind of post-merger that was sort of their marathon post-merger.

Adam Dirlam: I mean, I think so. 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, you know, through, you know, the non-op market where 20% of these portfolios are all made up of nonoperated properties. They’re also, you know, 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 out into the market. And so we’re seeing that, you know, 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.

Noel Parks: 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, you know, weaker oil might do there as far as activity. And I know in the past 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, you know, in-basin power and so forth? Just wondering if those sort of concern about the ongoing concern about Permian gas and pricing. Versus, you know, the 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?

Nick O’Grady: I don’t think that people, you know, ultimately, no. I think they can only price based on, you know, where the differentials, you know, if it was priced into the four differentials strip in some form or fashion, I think then they can make an economic fit 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 direct link. That’s more of an operator game than it would be for us ultimately. You know, 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.

Adam Dirlam: No. That’s right. I mean, I do think, look. As you have what you would, given that AI and data center boom, it does not surprise me that 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. You know? 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 that the time to build these things is 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.

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

Nick O’Grady: Thank you all for joining us today. We look forward to talking to you in the coming weeks. Again, thanks for your interest in our company.

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

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