Northern Oil and Gas Q2 2025 Earnings Call - Cash Generation and a Clear Pivot from Drilling to Acquisitions

Evelyn, Moderator/Investor Relations, Northern Oil and Gas: Good morning. Welcome to Northern Oil and Gas 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 nog.com. We’ll be filing our June 30th 10-Q with the SEC within the next few days. I’m joined this morning by our Chief Executive Officer Nicholas O’Grady, our President Adam Dirlam, our Chief Financial Officer Chad Allen, and our Chief Technology Officer Jim Evans. Our agenda for today’s call is as follows. Nicholas will provide introductory remarks followed by Adam who will share an overview of Northern Oil and Gas’ 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 Nicholas.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: 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 built a solid business that embodies a number of 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 strengthen both. 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 the DNC list building substantially this quarter as we have seen overall stable drilling.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Activity on our lands.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: 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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Inorganic, the how and the why in.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: 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 the 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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: First year of its life.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: 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. We gain the option of ramping activity if the environment changes. Remember, the oil is still there in.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: The ground and will adapt quickly.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: 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. 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, and in short order we’re seeing our concentrated working interest getting well proposals on those lands.

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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: In the marketplace today.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: 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 impact and 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 in 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 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 NOG is different. We are different in so many ways, but I think we’re most different in that we do things almost exclusively focused on long-term thinking, on long-term value creation through cycle. Sometimes these measures may differ from our peers, but seizing on market opportunities will.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Ultimately, drive more value in the end.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Thank you again for listening and your continued interest in our company.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Adam.

Adam Dirlam, President, Northern Oil and Gas: 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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: In the Williston who have pulled back.

Adam Dirlam, President, Northern Oil and Gas: As a result, we saw one net well deferred, and approximately 3,800 bbl/d shut in due to pricing pressure.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: From a single operator.

Adam Dirlam, President, Northern Oil and Gas: Notwithstanding the deferrals and shut-ins, current Williston results continue to outperform internal estimates, and well productivity is appreciably higher compared to 2024 tills. 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 remained robust. The Permian held steady, while both the Uinta and Appalachian basin saw the anticipated uptick.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: In drilling activity in the Uinta.

Adam Dirlam, President, Northern Oil and Gas: 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 spot 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 till front, drilling and AFE activity remain 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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Weighted wells in process.

Adam Dirlam, President, Northern Oil and Gas: 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 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 95+%. Quarterly net AFV 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 tills in Q3 before ramping through Q4 as the Permian and Appalachian basin increased completions compared to the first half of the year. Similar to anticipated tills, we expect the Permian and Appalachian basin to drive the bulk of our drilling in the back half of the year while seeing the Williston basin slowdown. Absent a change in commodity pricing on the business development front, we are seeing an accelerating number of opportunities and have been able to take advantage of the downward pressure on commodities to capitalize on ground game opportunities across all of our basins. In the second quarter alone, we reviewed over 170 transactions, over a 40% increase relative to the first quarter.

In addition to closing our previously announced Upton County acquisition, we closed 22 transactions, up from 7 deals in the first quarter, for a total of 4.8 net wells and over 2,600 net acres across all of our respective basins. Our approach remains the same, targeting both near-term drilling opportunities as well as long-dated inventory. We’re finding creative ways to put things together, whether through smaller joint development agreements in the Permian, acreage trades and farm outs, as well as old-fashioned leasing efforts. Regarding larger scale M&A, there has been an increase in gas-related opportunities entering the market alongside assets that have become available as commodity volatility has decreased. Currently, more than 10 ongoing processes are being assessed with a combined value exceeding $8 billion, and additional opportunities are anticipated.

As the largest non-operator of scale, we are having more strategic bilateral conversations, and we’re optimistic that our flexible model and strong balance sheet position us well to capitalize in this environment. As always, we remain focused on total returns, disciplined capital allocation, and leveraging the advantages of our non-operated model to navigate the current environment. With that, I’ll turn it over to Chad.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: Northern Oil and Gas 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 bbl/d, 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 joint venture are online. It started to contribute to volumes in.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: The back half of the quarter.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: 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. Oil differentials averaged $5.31 per barrel excluding certain non-cash 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, the $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 50/50 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 Dirlam’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. We expect to grow this over time. As a testament to the confidence of our asset base and credit profile, we were recently upgraded to BB- by Fitch. In mid June, we successfully completed a reopening of our 2029 convertible notes, issuing an additional $200 million under the same terms as the original 2022 offering, including a cap call with an effective conversion price exceeding $50 per share.

The proceeds were used to partially repay 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, NOG recorded a $115.6 million non-cash impairment charge, leading us to reduce our DDA 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: 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’ll pause for just a moment to compile the Q and A roster. Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah, thanks.

Speaker 1: I was wondering if you could help me think about the cadence into 2026, and it sounds like most of your operators have been, you know, drilling more core wells. Results have been good. I know we did take down oil production guidances. Is that really solely related to, you know, just lower activity in the Williston, and what should we expect in 2026 there? As you think about the setup for 2026, you know, and you did, you know, mention obviously having a very similar till level could do maintenance production. Is that view an organic view, or would that be a combination of organic and inorganic activity?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Okay, I’ll try to get all those questions. If I forget one of them, just let me know.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Remind me, Scott, as it pertains to.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: The cadence for 2025, as you noticed, our Q2 spending was materially lower. Right. As we’ve seen a bit lower spending, that will translate into, you know, modestly lower volumes in Q3. As our DNC list is building, we should see levels in Q4 similar to where we were in Q2. We should exit the year pretty similar to where we are today. As we mentioned in our, you know, prepared documents, we could certainly spend a level lower than this year and a lower total 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 returns-driven business model. The number one factor in which we are compensated on is return on capital employed. That’s what drives our decisions. Growth is the output of those.

Our spending will be dictated by the price environment and all those things. Whether we spend less money or more money next year and whether that translates into, you know, 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.

Speaker 1: Appreciate that.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: In terms of the organic or.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Inorganic, we’re talking our normal core spending, which would be a combination of what we would acreage replacement in which we embed our ground game capital in there in a typical organic spend.

Speaker 1: Okay, thanks. As a quick follow up, it sounds like your comments allude to the fact that you like some of the return profiles of some of the inorganic type of activity as being a little bit more, I won’t say predictable, but more controllable. Is that right? I mean, is there 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?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah, I think, Scott, I think, look.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: What I think you.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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? If you look at the fundamentals of oil today, you know they are in question, right? You have significant volumes coming online. The risk profile to that strip, you know, of course it could be better, but it could be worse and it is somewhat tenuous. 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.

As I said, the oil is still on the ground, so they’d rather preserve that until there’s a better day. While everybody wants to see linear growth, the real key is to drill those wells when it’s most profitable. When we look at an acquisition, on the other hand, if you think about long-dated inventory and stable long-term production, that isn’t really just a singular well that’s being drilled in that singular period where that return is dependent on that short-dated period. We can allocate that same amount of capital to something that is much more resilient to a longer period of time and provides convexity because we do believe regardless of what happens in the next 12 months, that the long-term profile for oil, for natural gas and all those things is very, very strong.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: I think as we look.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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 a $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.

Operator: Your next question comes from the line of Charles Mead with Johnson Rice.

Speaker 1: 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. Earlier in the year you gave us an estimate for how much of your total capital budget, how much of it was growth CapEx. Can you give us an update on that now? How much growth CapEx for 2026 is in your updated 2025 capital budget?

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: I’m not sure.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: If you looked at it, we’ve cut from peak to trough about $275 million. Right, right. We said about $250 to $300 million with growth capital. To the extent that we spent the bottom end of our guidance, we would effectively not be spending that. Charles, does that make sense?

Speaker 1: That makes sense and that’s what I was looking for. That’s the way it looked to me. I just wanted to know if it looked kind of the same to you. Nick, I want to ask a question about how you’re reducing your CapEx. I can think of at least three possibilities. There’s one which is maybe you’re non-consenting some wells, or number two, fewer wells are being proposed and you’re agreeing with that decision. Or maybe from your more recent joint ventures where you guys have those provisions for input. How does the reduction in spending break down?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah.

Speaker 1: The mechanisms, why you’re, how you’re pulling back.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I’ll let Adam discuss this a little bit further. It’s really a combination, one that, you know, the beautiful thing about our business is that, you know, the rational.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Especially, I’d say, from our private operators.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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. That’s one of the reasons, like for example, we have seen such stellar Williston results is because you’re not seeing the marginal wells being drilled. Our consent rate is still very high. 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. That makes up 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.

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 plus environment world, that growth is predicated on the fact that that’s the right thing to do for your investors and you’re generating a strong return. Growth for the, we certainly could do that and spend that money, but ultimately it’s about doing the right thing for your investors. You want to grow, you can grow. The question is, are you actually adding value by doing so? I think the answer that we’ve come to, to the conclusion is that capital is better preserved for a better day and it can be spent at any point in time. Adam?

Adam Dirlam, President, Northern Oil and Gas: Yeah, I mean the short answer is.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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. Going back to Nick’s comment, 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 are 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.

It’s laser focused on 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.

Evelyn, Moderator/Investor Relations, Northern Oil and Gas: Thanks.

Speaker 7: Good morning, guys. I was going to, I’m kind of approaching, I guess, a little bit different when I look at the cadence. 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 20, 21 for four or five quarters. Your wells in process are basically 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. Then what you all till the next quarter.

I mean every time you open around 50 wells in process, the following quarter you’re always 26 to 30 tills. I guess I’m trying to understand kind of the, I don’t, I don’t call it a disconnect, but what’s sort of different where activity, wells in process still looks really good, but the second half guide of kind of call it 18 tills on average in the second half relative to this really robust work in process number. I guess try to help me reconcile that.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah, I mean, I think what we are seeing from operators here is a 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.

Speaker 1: Right.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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. You’re seeing a relatively steady cadence of drilling. What we’re seeing now are deferrals of some of these tills that were in process, wells that were, you know, tilled prior to liberation day, and then just more of an elongation of the spud to sales timing. I think that’s starting to come into play, especially when you think about cube development. 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.

I think that’s a piece of it as well. I think it’s a combination of, you know, all three of those, you know, different variables.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I’d also point out, John, that the till count tends to follow the previous quarter. Right. If we put on a ton of wells in the third quarter, it oftentimes has more of an impact on our fourth quarter volume. We should see an increase in our Q2. The lower spend in Q2 has more of an impact on 3Q than it does on 2Q. Right. Because of the time cost averaging, it’s all about the time of when those wells come online. As our spending has been decelerating in the first half of the year, that’s going to have an impact sort of in the third quarter. That building in the till count will obviously actually our production should increase as we head to the end of the year. You’re not wrong. It’s just a matter of time.

The difference, as we looked 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.

Evelyn, Moderator/Investor Relations, Northern Oil and Gas: Yeah.

Speaker 7: What Adam touched on is kind of what I was getting at. It seems like it would imply that you would end the year at a more elevated DNC level than what you traditionally have, which is what I was kind of looking at. That makes sense. That’s right.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah, you don’t see the same type of pull forwards that you would have. You know, ironically, everyone gets mad at us when we see these huge pull forwards and the capital acceleration, and they don’t love, you know, they don’t care about that, the production, the benefit you get. Here it’s the opposite. Right. You know, can’t win.

Speaker 7: Right. Just my other question, this quarter, pretty nice, over 60% of the free cash flow that went to dividends and buybacks. How will you treat that nearly $50 million settlement you’re getting in 3Q? Does that kind of get put in a different bucket, or does that get considered part of the free cash flow in 3Q when you’re kind of thinking about the allocation of shareholder returns?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I believe it’s just working capital.

Speaker 1: Yep.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: It goes into a receivable. Now it will not be in the free cash flow.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: No, it won’t. As far as what to do with the.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I think we’ll just roll it into our normal kind of capital allocation process.

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

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: I wanted to start off here. You guys mentioned that 2025 and 2026 free cash flow should be higher under the revised plan. Could you maybe talk about the use of those funds and just where would you, where use it would be buybacks? Would it be debt reduction? Yeah, I mean, I think the default.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: No, the default uses. Obviously, we sweep the revolver with every extra fund we get. To the extent we find inorganic opportunities, that is always, generally. I don’t ever want 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 return. That would sort of rank as the first, 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. I do think as we look forward, depending on the price environment, commodity mix, et cetera, as I mentioned, I mean, as Adam Dirlam mentioned, the backlog is at record levels.

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. One of the parts of the logic of our recent convertible note 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 would go down, our absolute debt levels will keep falling. That means our liquidity will keep growing and that means we will be able to find acquisitions and be able to continue to allocate through cycle. I think our hope would be we can find true long term value added things to do because ultimately that’s how you create the most value in oil and gas.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Yeah, no, it sounds like you guys are positioning yourself for countercyclical investment, which seems like a good setup. 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? Why do you think you are seeing such a robust list of assets on the market today? Yeah, it’s an interesting dynamic.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I don’t want to speak for Adam or Chad or Jim, but it’s coloring me a little bit surprised that within oil assets it’s still been fairly robust. 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. We’ve seen everything from royalties that overlay our own properties to just diversified non-operated properties to some of the more partnership and drilling style things that you’ve seen us do. The natural gas market is obviously very robust just because you have a very strong forward strip. We frankly have seen activity in almost every active basin that we have evaluated. I don’t know if you want to add to it.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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. Oil and commodities are at one price when you launch it, and then you get the bid date and it’s completely reset itself. 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 date, you can manage those seller expectations a bit as well. Hopefully that means that there’s something to get done. 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.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: Hey, thanks for the time. Sorry to ask another question on quarterly.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Cadence, but I just wanted to clarify Nick O’Grady’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.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: From two Q levels.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I think you alluded to a slight decline in Q3 from Q2.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: I just wanted to reconcile that.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Yeah, I mean, I think, Phillips, it.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: really depends when, you know, when I say similar, it really is going to depend, as you know, for us, that the till cadence can vary widely. 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. It really just depends on the timing of those completions. The earlier the completions come online, you know, it’s just going to be. Frankly, if we can, you know, if prices remain stronger, we may then see Q1 activity pulled forward and Q4 may stay more robust. That would ultimately drive upward pressure to our overall guidance. 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.

What I will tell you is that just as 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, mid single digits is something that looks more realistic than something.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: If that makes sense, then throw in curtailments that we’re seeing from some of our private operators, and that’s effectively getting managed on a month-to-month basis. That would be the other variable to consider.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Prices are stronger. We could see those come off, but we’ve made the assumption that those will continue.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: Okay, that makes sense.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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 around 75,000 a day or sort of second half levels that are closer to, you know, 72,000 a day?

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: I think the answer.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: When we talked about maintenance, we mean maintenance and we mean versus our annual guidance. However, what I would say is that from a capital allocation perspective, if oil prices are $50 and gas prices are $4.50, we might allocate more money to gas. I think we’ll do what’s right for the business. When we talk about a spend level today on a generic basis and we’re talking about that, it would mean versus the annual 2025 guide, not versus that lower level.

Chad Allen, Chief Financial Officer, Northern Oil and Gas: Okay, sounds good, Nick.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Thank you.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah.

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

Adam Dirlam, President, Northern Oil and Gas: Thank you.

Speaker 1: Good morning, all.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Thanks for taking the call.

Speaker 1: I just want to touch quickly on kind of the cost structure. You mentioned that absolute ASV costs were.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Down 5% sequentially, somewhat split between oil and gas.

Speaker 1: I guess how much.

Adam Dirlam, President, Northern Oil and Gas: Do you see any further runway with.

Speaker 1: that downward pressure or is pretty much everything baked in at this point?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: I mean, Paul, I’d rather let Jim or Adam talk about this.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: The one thing I’d say is that we’ve obviously seen a pretty material reduction in the rig count. I got asked last question about the last quarter about steel costs and tariffs and stuff like that. I said I’ve never seen an environment where oil costs went down and, you know, well costs didn’t, and so far have been proven right. I think that where we are now, as we are starting to see for the first time, frac spreads usage come down materially, we’ve seen a lot of consolidation in that sector. Prices, that’s the biggest cost. Rig rates are not the biggest driver of that anymore.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: I think to see material cost reductions.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Now, you’d have to see the frac spread count contract materially. 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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah.

Adam Dirlam, President, Northern Oil and Gas: The conversations that we’ve been having with.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: A handful of our JV partners are certainly seeing that downward pressure. That being said, we’re a relatively conservative shop. Right. It’s going to be a show me and it’s going to come through the actuals when we start truing up our accrual. We’ll continue to accrue based on AFVs that we get in the door. Anecdotally, I think we could potentially see something like that. That’s probably something more of a 2026 kind of realization to the extent that we see it continue in the direction that operators are guiding us.

Speaker 1: Got it. Makes perfect sense. Just one kind of quick one on the M&A market.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Again, you all mentioned that there were.

Speaker 1: 10 ongoing processes worth $8 billion, give or take. Is there any concentration of the structure of those larger deals? Are they more nano, are they more joint development co bids, et cetera?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Honestly, it’s across the board. We’re seeing a number of different non-operated packages. We’re also seeing a number of different kind of co-buying and minority interest buy-down. I don’t think it’s necessarily concentrated to any given basin or any given structure at this point. We’ve got a buffet of options.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah, I mean I think the one thing I would highlight, and we really, whether we’re successful at all or on one or any of these processes, is always a total crapshoot for us. What I would say is that I get feedback from investors just because we’ve had more success on the COVID over the last few years, like that, you know, oh well, you know, where are the traditional non-op assets? Actually, we’ve seen, and we even have several that are coming to market, some of the largest just standard non-op assets we’ve seen in maybe ever. Some of the biggest just regular way non-op assets we’ve ever seen come to market.

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

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

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Morning Noel.

Speaker 9: Hi, good morning, how you doing? A lot of interesting topics and questions have come up, I guess. Would you say that you’re at a juncture where specific post-deal related divestments are 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-operated stuff they could spin off. 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 see.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I don’t think so.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: You might have seen that there was.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Yeah, I mean I think the way that we think about it is you’ve got to merge, right, then you’ve got to wrap your head around the assets, and then only then can you bring a lot of these assets to market. 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. I think operators are getting creative and not necessarily just throwing a massive asset package out into the market. We’re seeing, you know, all.

Adam Dirlam, President, Northern Oil and Gas: Of the above in terms of kind.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: Of the different structures as to how a lot of these operators are socializing their assets post M&A.

Speaker 9: I’ve been thinking about it.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: A lot.

Speaker 9: Of scrutiny I hear from the gas side, the pure play gas producers of associated gas in the Permian and what weaker oil might do there as far as activity. 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?

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I don’t think that people, you know, ultimately, no, I think they can only price based on where the differentials, if it was priced into the forward differential strip in some form or fashion, I think then they can make an economic bet on it or if they had a direct contract. 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, 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, President, Northern Oil and Gas: That’s right.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: I mean, I do think as you have what you would call like stranded gas and from a regional basis that can’t really get hub-related prices or may not have access to LNG, I think given the AI and data center boom, it does not surprise me that people are going to try to take advantage of that cheap, that cheap source. It would not surprise me if you start to see a lot of this building. Next thing you know, Midland might be the center of a huge data center boom because they’ll want to use that gas. You’re seeing that obviously there’s been a lot of hullabaloo going on in the Appalachian basin about just that. I do think that over time that can narrow those bands.

It has not been enough to have some, and remember that the time to build these things is super long and things like that. 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.

Nicholas O’Grady, Chief Executive Officer, Northern Oil and Gas: Thank you all for joining us today.

Unspecified Voice, Supporting Speaker, Northern Oil and Gas: 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.