Northern Oil Gas Aktie

Greetings, and welcome to NOG's Second Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.

It's now my pleasure to introduce your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Good morning. Welcome to NOG's Second Quarter 2026 Earnings Conference Call. Yesterday after the close, we released our financial results. You can access our earnings release and presentation in the Investor Relations section of our website at noginc.com. We will be filing our June 30, 2026 10-Q with the SEC within the next few days.

I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; and our Chief Financial Officer, Chad Allen; as well as our Chief Technical Officer, Jim Evans. Our agenda for today's call will be as follows: Chad will provide an overview of our financial performance, followed by Adam, who will share an overview of NOG's operations and business development activities. Nick will close with a remark about NOG's positioning and value proposition. After our prepared remarks, the team will be available to answer any questions.

Before we begin, let me remind you of our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements.

Those risks include, among others, matters that we've 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 those 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 will turn the call over to Chad.

Thanks, Evelyn. Q2 was a clear demonstration of our diversified portfolio business model. When one region hits turbulence, other aspects of our platform pick up the slack. And this quarter, that showed up directly in the numbers. Adjusted EBITDA was up 17% sequentially and free cash flow is up over 400% from the first quarter. That's the model working as designed.

Total production was up 9% year-over-year with record natural gas volumes up 35% year-over-year and 5% sequentially. As previously disclosed, we saw significant curtailments in the second quarter as a result of challenging Waha economics. In a volatile environment, our operating partners in the Permian made prudent decisions to generate excess cash flows. And with improving economic conditions, we've seen volumes come back online including 3 net turn in lines that will contribute to the third quarter.

Outside of that Waha-driven curtailment, the underlying assets performed well. The Williston and Uinta both topped our internal expectations and our Appalachian volumes set another record with a full quarter of contribution of our Utica joint development, where early well results have been strong. On pricing, our unhedged net realized oil price improved 36% from the first quarter. Gas realizations were 90% of Henry Hub and with our hedges, Waha base included reached 123%. Strong NGL prices contributed as well.

Waha pressures has receded, and we're seeing that trend continue thus far into Q3. On costs, production expenses per BOE were down 4% year-over-year. Budgeted capital expenditures were $196 million, comprised of $151 million of organic D&C and $45 million of ground game activity. Normalized well costs were $761 per lateral foot, essentially in line with the first quarter. Spending this quarter skewed more towards oil weighted.

Permian at 37%, Williston at 33%. Appalachia and Uinta to each at 14% and our newly acquired Duvernay position beginning to contribute at 2%. We ended the quarter with over $1 billion of total liquidity. Our balance sheet remains well positioned to fund our development program and continue executing on inorganic opportunities as they arise.

Turning to capital allocation and shareholder returns. This is where the free cash flow generation translates directly into returns. We repurchased 2.95 million shares, roughly 3% of shares outstanding at an average price of $20.37 with about 81% of that activity completed before the dividend record date in late June. That repurchase largely offset the shares issued to the Duvernay seller, so we effectively funded a scaled acquisition, while holding share count roughly flat.

Subsequent to quarter end, the Board increased our stock repurchase authorization, bringing total capacity to approximately $243 million, a clear signal of how we view the value in our stock at current levels. On the dividend, our Board declared $0.45 per share for the quarter or approximately $48 million paid on July 31. Against the $159 million of free cash flow this quarter alone, the dividend is covered several times over. We view the dividend as a floor, not a ceiling on the capital we return to shareholders.

With that, I'll turn the call over to Adam.

Thank you, Chad. We remain as confident as ever in the strength of our assets confirmed through recent results and leading indicators. Looking ahead, we are seeing multiple positive catalysts as drilling activity materially outperformed internal expectations and the D&C list built to almost 52 net wells as operators modestly pull forward activity in the Permian and Williston. Additionally, we elected to do approximately 17 net wells, which is up almost 20% relative to the trailing 12-month run rate 90% of those elections were weighted towards our oily basins with normalized AFE costs down 5% from our 2025 average.

Moving to business development. Our M&A engine has been firing on all cylinders. We continue to build on our track record of finding premier assets, including our latest with the Duvernay joint development deal that we closed in early June. The Parallax acquisition is a self-funding asset with 20 years' worth of inventory at an average breakeven below $50 and with a price tag of less than $600,000 per location highly competitive with the basins in the Lower 48. With it, we have strategically and meaningfully expanded our addressable market into Canada, and we will continue to screen for other complementary assets.

Our ground game has maintained strong momentum and the barbell approach of sourcing near-term drilling opportunities as well as long-dated inventory continues to be underappreciated. Since we have made a concerted effort to build out our inventory in Appalachia, we've amassed roughly 80 locations through our leasing efforts excluding the acreage that has already converted to development. We believe that NOG is one of the few companies, if not the only that budgets for the acquisition of new locations on an annual basis, which allows us to build duration and optionality for the future with core locations that would compete in any portfolio.

This overstates the reinvestment rate that is needed and also means NOG is one of the few who is actively replacing its inventory year after year. That said, we can and will adjust how capital is deployed based on dislocations in the market. Capital can be shifted to buybacks or other near-term drilling opportunities or both, as you saw us do in Q2. In the second quarter, we pivoted to more drilling opportunities acquiring over 6 net wells weighted to the Permian and Bakken that are currently in process.

To further put this into perspective, through the first half of '26, our ground game has already capitalized on the same number of drilling opportunities than we did in all of 2025. NOG's opportunity set continues to expand and will remain dynamic capital allocators. Directing capital to wherever it creates the most value as the market presents it. Nick?

Thanks, Adam. Thanks for joining us this morning and your continued interest in our company. I'll cover 3 pillars that reinforce the strength of our business and build on Chad and Adam's comments.

Number one, unrecognized value. We have created an incredible business, and this has fostered a fantastic industry reputation as a partner, acquirer and asset manager and owner. We've built state-of-the-art custom AI-powered management and evaluation tools that are light years ahead of the competition. Most importantly, we have built a high-quality platform with tremendous value that is not being recognized by the public market today.

By our conservative internal estimate, the assets we own are worth $7 billion plus, trapped in $4.6 billion enterprise value. Fortunately, we have multiple avenues for this value to be recognized. In the meantime, we'll continue to generate significant free cash flow, pay our dividend and allocate capital to strong forward returns. We will make decisions that allocate capital in a way that will maximize value for our investors long term, whether that's acquiring assets, selling assets or returning cash to shareholders in the form of dividends or share repurchases or a combination of these actions.

Number two, cash flow strength. Based on current strip pricing, our assets should generate $1.4 billion to over $1.5 billion of adjusted EBITDA this year. We believe $850 million to $900 million of D&C capital will sustain these production volumes, generating approximately $375 million to over $500 million of free cash flow. Across that range, our dividend remains multiple times covered, leaving free cash flow available to reduce debt, acquire inventory and assets or repurchase shares. A modest spending increase could also grow oil or total volumes, generating more cash flow while ultimately producing a similar free cash flow profile.

Number three, acquisition track record. We are a proven disciplined acquirer. Using our advanced tracking systems, we consistently analyze successful acquisitions, opportunities we passed on and bids we did not win. Our acquisitions have performed exceptionally well with our systematic approach generating north of 20% annualized returns on a standard 1x levered basis net of hedging.

Monetizing selected assets could accelerate these returns further by bringing value forward. As we remind investors quarter after quarter, our value creation is grounded in long-term strategic thinking. That will never change but a long-term focus does not prevent us from adapting or capitalizing on short-term opportunities, including the fundamental disconnect in our equity today.

Our largest quarterly open market repurchase ever demonstrates that approach. Our dividend is solidly covered. Our assets are materially undervalued, and we are capital allocators. When the market presents opportunities, we will act. Over the past 7 years, we identified irreplaceable assets at compelling values and the returns have validated that strategy, whether the market recognizes it today or not. Our job is to ensure those successes are recognized and we will work around the clock and analyze every avenue to do so. That's what a company run by investors for investors does.

With that, we can turn it over to questions.

[Operator Instructions] Our first question comes from Neal Dingmann from William Blair.

Nick, my first question is on your capital efficiency. Specifically, it seems like most E&Ps now that we're towards the end of the second quarter reporting. The trend I seem to see out there is most -- many E&Ps, I should say, talked about higher expected '26 CapEx yet you all were able to reiterate your capital spend and your production, which we view should ramp up nicely going forward.

So my question is could you discuss a bit your confidence in to be able to reiterate the CapEx and remind us what some of the primary drivers are there?

Yes. Thanks, Neal. I'll talk about a couple of things. One, recall that our guidance all along has sort of made the assumption that we would see a steady pickup in activity throughout the year. Obviously, it's probably happening a little bit faster, but the total quantum isn't changing.

The second thing I'd point out is that if you look when we revised guidance when we announced the Duvernay acquisition, we implicitly cut our capital by about $50 million. That's a combination of production efficiency and just the fact that, we talked about this in the past, but when costs came down last year, you noticed that we said, look, we're an accrual shop, which means we accrue for the cost of those wells, and it takes 180 to 365 days for those reduction in costs to be realized.

So if a well cost $10 million, we accrue the full amount at the AFE. If the actual comes in at $9 million, it can take 6 to 12 months before that money is credited back to us. We are seeing the benefits of that really starting this past quarter. And even if costs do increase some, you'll probably see the tailwinds from that for us for some time.

Great point. And Nick, one more, I don't think I've ever asked you this on the call, but I want to ask, I'd just love to hear your thoughts on what I would call your value disconnect? I mean, it's certainly evident that, again, I think we all see Northern stock being relatively flat year-to-date versus some of the others have followed oil and now are up 40% to 50%. I'd just love to hear you or any of the team's thoughts on what do you think the cost behind this?

Yes. Now, you're going to get me monologuing I mean I think, look, at the end of the day, our cash flows and profits are up several hundred million dollars since the beginning of the year, and the stock obviously is not. But I'll be candid about the perception challenge we face we are a non-op, which means at the end of the day, we buy and invest in oil and gas properties. In the public markets, we are rightfully or wrongfully compared against E&P operators. Their job is to manage production and spending and are judged accordingly.

We ultimately should be managed by the investments we make and their value over time. That's tough admittedly when we typically buy and hold assets to life, but managing guidance is not the same thing as creating value. And I think there's a fundamental disconnect in the analyst community today. As many of you know, I spent 15 years on the buy side, and most of that time, the idea was to look at the company's asset value as a driver for ultimate equity value.

This did get out of control during the pre-2014 kind of oil armageddon period when companies were valued for acreage without regard to the capital required to keep it, not to mention the fact that much of it wasn't worth what was assumed at the time. And look, I have a ton of respect for the analyst community and the market is at any moment what it is.

But today, people rightfully or wrongfully are focused almost solely on quarterly guidance and free cash flow yields as they see them. 8 years ago, on my first call as the CFO, I literally discussed as one of the first people in the space openly to move the company to a self-generating cash position and to pay shareholders a fair and reasonable return. Don't get me wrong, free cash flow is really important. But the definition of it is very tricky and often misrepresented in a depleting business.

I'll add that even those that do still attempt at NAV may not understand the differences between how we book reserves and inventory as a non-op compared to an operator, which are inherently different in the sense that we can't simply book inventory that we don't control the timing of, and we can't count locations before operators ultimately decide where they're spacing it. As Adam mentioned, we're one of the only E&P companies that actually budget for acquisitions in our regular budget every year. Most public E&Ps are not replacing their inventory. So what you call free cash flow is actually in reality of depleting annuity. And I don't think that's a fair comparison, which is why NAV should be an important part of the equation, what is in the end, effectively a depleting real estate business.

So if you look at our reinvestment rate, of course, it's less immediately productive by design, but we continue to stack on assets. That's not capital efficiency as the market views it for the record. Over the last year, we spent over $100 million acquiring potentially north of 80 locations in the Utica. This does nothing but make us screen worse in the "capital efficiency" and "free cash flow metric", yet definitively adding asset value to the enterprise, albeit nonproductive at the moment.

You can tell the -- and I can tell you the bonuses paid for that land are up, in some cases, 50-plus percent since we began that campaign. So no cash flow, just CapEx, but did we add value likely the answer is a resounding yes. As I stated in my prepared comments, screening leverage is another example. If we borrow money and buy an asset, the market has focused on the leverage as a negative when comping, but they don't recognize that now we have an asset that's worth a heck of a lot of money.

And I can say with a lot of certainty that the current future values of our Uinta and Utica assets, which were funded with leverage are greater today than when we purchased them and likely grow further over time as the operators improve and delineate. Again, this is a business model viewpoint, we struggle to reconcile at times. We could be unlevered and screen better. We could only spend money on D&C capital and look better by these metrics. But at the end of the day, now we have these assets. And in virtually all the cases scarcity and quality has proven that the assets that we purchased are now appreciably more valuable.

If we need to monetize them to prove to the market as a mechanism that the value since only cash yields are being used, we're fine with that. At the end of the day, our job is to maximize value. But it's a shame they're not analyzed for what they would be in virtually any private setting. Put it to you this way, if our assets were at the lowest end of our expectations, and we sold half, we'd take in roughly half our float and have 0 debt.

That implies a stock value more than triple the current levels. So if the market wants to be singularly focused on production volume cadence versus expectations, a leverage multiple and a free cash flow yield, where 75% of the competing stocks are not replacing any inventory, but just depleting away. That's incredibly shortsighted when in reality, we're about owning and harvesting assets at good values.

At the same time, we need to ensure the market understands how valuable all the assets we purchased have become. You have an insane dichotomy going on at the moment where people are paying north of $330,000 per acre and assets have never been so sought after at significant premiums to even a few years ago, and yet a public market that wants to give it away. But to be fair, when that happens, the [ onus ] is on us to prove it and make no mistake, we will. Back to you.

Thanks for the quick comment.

I told you. You got me monologuing.

Our next question comes from Charles Meade from Johnson Rice.

Nick that was a wonderful monologue. In all candor, I appreciate you sharing that point of view. And it's I like the -- it's a fashion in the market right now to be lower leverage and maybe you guys aren't there. But the question I want to ask actually touches on this leverage point. And when you talk about -- you and Adam also talked about allocating capital and putting it in the best -- at the best places, whether it's the ground game or D&C or things like that, it's easy for me to imagine how you stack up, say, a ground game acquisition versus buying back your own shares.

It's a little harder for me to imagine how you consider paying down debt kind of there seem to be more intangibles, benefits or maybe cost related to paying down debt versus looking at an acquisition or buying your own shares. So can you talk about how you view the desirability or the framework for debt reduction or debt additions?

Sure. I mean, I think -- look, I would say that, number one, there are a couple of ways to delever, right? So obviously, highly efficient capital, which grows your cash flow can lower your leverage metrics, and that's important. And that's a big part of the capital allocation. But to be candid, what I'd tell you about our shares, as an example, is that that's a clear and present opportunity, right, that may or may not be there tomorrow, and we're extremely focused on that as you see. Leverage is the easy part because ultimately,

I'd tell you that, as I mentioned just before, in my long-winded monologue, which is that we have incredibly desirable assets. So if we want to solve for leverage, we can do that almost immediately, right?

I don't know, Chad, do you want to add to that?

No, I think you're right. I mean, obviously, our stock right now where it's trading at close yesterday, it's up 9% yield. So I mean it's certainly massively accretive for us to continue to attack that. And we'll kind of be -- we'll be prudent about it, and it's a fluid and dynamic situation for us.

Yes. But I mean I think you have to weigh in the fact that your asset value, your leverage is a function of the fact that we've acquired all these assets, right? So we didn't have to do it the way we did it, but we did it because we knew that they would be more valuable. They are today. And so to the extent that the market wants to discount the value because the leverage you used to acquire them, that's an easy answer.

Okay. Okay. And then, Adam, I want to go back to something you said in your prepared comments. I believe I heard you say that you've -- you have a lot of recent wells that are outperforming your internal expectations, your type curves. And I wonder if you could just give a little bit more detail on where that's happening across your asset base?

Yes, absolutely. I mean I think we look to Appalachia, we just finished up our West Virginia joint development agreement. We've seen significant outperformance relative to internal expectations there. That was a driver in the gas volumes that you saw this quarter.

And we're also seeing it in the Uinta notably both on kind of the legacy production from the XCL assets as well as the 2026 campaign. Jim, I don't know if there's anything else that is notable that...

Yes, I think you kind of -- we're really seeing it across all of our basins, right? Even in the Williston, we continue to see outperformance across operators, as they drill longer laterals getting more efficient. We're not seeing the decline rates that you might expect as you go from a 2- to a 3- to 4-mile lateral. So really, it's across all of our basins that we're kind of outperforming internal expectations.

Yes. And I'd say it's early, but even on our new Ohio program where we really started to just put on our first pads, we've seen really, really strong performance. So kudos to the Infinity guys.

Our next question comes from Phillips Johnston from Capital One.

I have to say that I'm also a fan of the monologue. And I'm actually going to be the guy that asked about the short-term production trends. So my apologies in advance.

Your implied oil production guidance for the second half of the year is around $74,000 a day on average, I guess. If we adjust your second quarter volumes upward to account for the shut-ins. It sort of implies your second half production is going to grow by a couple of thousand barrels a day relative to Q2.

Obviously, there's a lot of positive momentum given your strong wells in process figure at the end of June, and you talked about the accelerated AFE and election activity. I realize it's still a pretty uncertain operating environment, but it seems like the guidance could be a little conservative with some upside potential. So I just wanted to get your take on that.

Yes, it's definitely possible. I mean, I think, look, to your point, it's very fluid. Oil prices are all over the place. And so it's too early to declare victory, but obviously, you have really just the base assets returning to trend. You also have the addition of the Duvernay assets on top of that.

And I'd say, as we stand today, one of the things that has been difficult for both you and investors in general, which is that you -- we got a lot of questions when oil prices spiked, why weren't you seeing the reaction? And the answer was really that one of our biggest growth engines is the Permian, and it's really been hampered by the logistical problems. And we tried to be really forthright about that, that it was going to take a little bit of time.

Obviously, I think what I would tell you is, as it stands today, some of those challenges have resolved themselves faster than I would have thought. And we had really pushed and we had frankly had those conversations with the operators so there was a good reason for it. We had really pushed a lot of that development that had been delayed, really starting in the end of the fourth quarter of last year. And even in the third quarter, we started seeing things being moved towards the end of this year. We're actually seeing that trend invert, and we're seeing a lot of that stuff being brought forward. So it really bodes well for the remainder of this year. Again, I think it's too early to declare total victory and we want to make sure we see it before we really come out and brag about it, but I'd say your thoughts in general are correct.

Yes. I mean I think, Phillips, we've seen some operators jockeying kind of figuring out kind of 2027 plans as well, maybe picking up a rig sooner than otherwise kind of expected, seeing some drilling efficiencies there. And so depending on how that all kind of shakes out next to Northern that would be another thing to kind of keep an eye on.

Okay. Sounds good. On the LOE guidance, you did reduce the full year guidance a little bit. As we look at Slide 4, which is really great disclosure, by the way, there's a pretty wide range of operating costs across your basins. So my question is how you're evolving production mix and the addition of the Duvernay volumes, which obviously have the lowest LOE on the slide, influence, I guess, your LOE trajectory over the next 4 to 6 quarters or so?

Yes, yes. So number one, like I want to -- I'm not trying to be pithy or make a pithy comment, but our LOE is not LOE, as you would say. It includes LOE, but it also -- we don't have a separate GP&T line. So it carries a bunch of gathering transportation costs, some other portion of the GP&T is in our differential, which we really look at as from wellhead to sales. So we report a little bit different than other people.

But what I would tell you is that if your production remains flat and this is not this is for any company, your LOE will rise over time, right? And so to your point, our goal in general is as we add growth areas such as the Duvernay and I think potentially the Uinta over time those areas should offset the fact that LOE, I mean, if you look at our Williston total production costs, those -- and our Williston volumes have stayed relatively flat for the last 4 or 5 years. Those used to be $10, right? Now some of that is just inflation of -- and workover costs have increased over time. but some of it is just the aging of the wells, right, which is that you've got, call it, in your LOE, I think about 60% of the costs generally are fixed.

And so as the wells decline over time, that LOE naturally goes up. But obviously, the maintenance capital associated with it goes down as well. So your cash flow stay here. While you're operating cost go up, your capital costs go down. So a long-winded way of saying, I think our goal is to try to keep LOE flat to down. Obviously, as our gas volumes grow, that also helps lower that because they're advantaged. And I'd say our joint development program, which was extremely liquids which as that declines, and you see an increase in and you see an increase in our Ohio volumes over time, that should actually offset that trend a little bit and get LOE to go down some over time.

And so in general, I think we feel very good that we can kind of maintain the current levels for some time. I do think you have to keep in mind fuel prices and other things that can flow through LOE right, and workover expenses, which we really saw a huge increase on as the wells have aged in both the Permian and the Williston over the last few years, but that's generally stabilized at this point.

Our next question comes from Noel Parks from Tuohy Brothers.

I was wondering, I did appreciate your comments on valuation and in particular, I sort of keyed on your mention that what -- I think it's what others call free cash flow is actually on -- is actually a depleting annuity.

And so it sort of got me thinking as you've expanded into different basins and with sort of the realities of valuation what you do and don't get credit for. I'm just wondering, I think of the story as being one largely a basin arbitrage, you're recognizing opportunities and from that perspective, being able to get them at a good price that other people would overlook.

So I mean doesn't basin arbitrage alone, if you continue on that path, doesn't that sort of naturally kind of help you build value more or less regardless of kind of what the public markets are saying?

Yes. I mean I think there's a public and a private view, but I think we recognize our job is to make sure that, that value is recognized, right? So that is part of our job, [indiscernible] and that's one of the hardest things to do to be candid, Noel, Slide 4 in our earnings deck, we really one of the comments we got was people wanted more visibility and we're happy to provide it.

And we really show a basin-by-basin look at the company. And what I'd tell you about that is when we acquired the Uinta assets, we had spent a significant sum of time, a year plus prior evaluating and reviewing the Uinta, and we understood that this was a basin that had economics that could compete or even exceed the Permian. When we evaluated Canada, which we've been doing for several years, and we found the light oil part of the Duvernay, we were incredibly encouraged by both the length of inventory on it. I mean you're talking about a 20-plus year asset as well as the incredible margins it generates.

And Slide 4 really underscores that you can, when I say those things, I sometimes get blank stares, but when your margin in Uinta is $20 higher than in the Permian and people ask you about differentials, you can sit there and say, I don't care like the proof is in the pudding. In the case of the Duvernay, similar, which is that we talked about it when we acquired it, which is it had very unique properties and we really found.

So we are -- we are truly seeking the best assets, and we'll allocate our capital accordingly. We're not someone who just does 1 thing and does it well. And I think sometimes that does have value in a public market that wants surety and clarity, but I think we're trying to provide that here and people should recognize it.

I don't know, Adam or Chad if you don't want to add to that.

Okay. Great. And I was just wondering, thinking about the gas side of the equation, the move towards some of the larger players towards sort of an integrated gas model, bringing back in-house infrastructure or acquiring infrastructure that they had at one time spun out. I'm just wondering what your thoughts are? Does it have an effect on your model?

Or is it compatible that trend sort of with your own model? And I guess it just makes you think about those sorts of players as opposed to for gas exposure in the Permian, for example, there's a ton of associated gas. So you have plenty there. So I just wondered what that sort of change in the landscape is telling you.

Yes. So we own significant infrastructure in the Uinta in the Permian and in the -- both the Duvernay and the Uinta -- sorry, the Utica, excuse me. And what I would say about that is that, obviously, the most notable thing is that when we acquired the Utica, it implies a higher upfront multiple. But you're talking about something that with the fully integrated model drops your breakeven costs $1.20 versus the prior operator.

And so you make a more resilient asset, importantly as well, you also have control. And control is really important, which is look no further than the Permian, where the bulk of it is through third-party gathering and processing systems. And you run through periods of time in which quite frankly, you just can't get your gas out, right? And some of that stuff is not stuff that E&Ps would own like long-haul pipes. But at the end of the day, controlling the infrastructure is really critical.

It also builds a moat in which once that system is built, you will ultimately become -- the acreage and the surrounding acreage becomes by de facto, really only valuable to you. That being said, and we would never -- we would consider anything. People are knocking on our door every day trying to buy that infrastructure at significant value. And so it's always an option, but I would tell you that there's extreme value to having that infrastructure and being integrated.

I think you've seen one of our top operators is EQT. You've seen them do that in Appalachia. It's a great success. And I think at first when people saw it, they might not have fully understood it, but a couple of years later, it proves its value.

Our last question comes from Paul Diamond from Citi.

Just a quick one for you. So last quarter, we obviously saw some Appalachia curtailments some reactivity to invasive pricing. U.S. diversification. I guess, as you see the winter approaching or any other operational efficiencies, do you see that occurring anywhere else across your basins? Or is it any warning lights for you?

Not at the moment. I mean, I think one of the interesting things about the gas market right now is there's been a lot of discussion and research around potential super El Nino and the strip really reflects that. My experience over time has been most people are wrong about the weather all the time. And so I think that the fact that, that sort of baked into the gas market today is pretty interesting to me, right? So usually, they bake in a normal winter. They think it's going to be a cold winter, and then things wind up disappointing. I think frankly, the situation today is probably the opposite.

Several years ago, as you remember, we had some significant storms in both the South and around the country, and it caused huge disruptions in areas because of extreme weather. Over that time, you've seen a lot of investment in infrastructure to make it more resilient. So I expect operational disruptions. Similar to what you saw in the Gulf of Mexico years ago where there were huge disruptions from Katrina and Rita and then people built the system stronger as it came back. And so I see the same scenario here. Quite frankly, as it pertains to winter and gas, we generally become a huge beneficiary should something happen.

So I think in general, even if it lasts as much as 1.5 months or whatever. And using last winter as an example, that incredible strength happened right after we acquired our Ohio assets, and we were able to actually take really advantage hedges, which are on the book today and take advantage of that scenario. And so I would hope we see similar volatility can be bad, but it can also be very good.

Got it. Makes perfect sense. And then one more, last larger strategic one quickly. You guys have worked pretty strongly to diversify across basins about 30, 30, 30 across Williston, Permian, Appalachia and the [ Nada ] and Uinta and Duvernay. I guess how do you see that on a long-term basis?

Is the idea to be like split evenly amongst those 5? Or do you see, I guess, more opportunity sets in one versus the other? I guess how should we think about those knobs turning over time?

Yes. I think it's hard to say in some cases and easier in others. I mean I think the Williston is very mature and I think episodically, we may see opportunities to come up in the Williston. But in general, it is a very, very mature basin. The Permian comes and goes. So obviously several years ago that were enormous numbers of assets coming to market.

We took advantage of that. The last year or so, it's probably been less exciting to us, but that can invert on itself over time. I think -- what I would tell you is we are a management company at the end of the day, and we're really focused on economics. So the diversity is certainly part of the business model, but it's also going where the opportunities are, and those can change and are very dynamic over time.

I don't think there's a desire to be more diversified or less diversified but similarly, when assets are sought after, it could be a scenario in which we take advantage of that and monetize a portion of it over time. I think we're we -- everything is for sale every day, everything is both for us to buy and for us to sell. And I think we'll do whatever makes the most economic sense. I don't know if you want to add to that.

Yes. I think that's the competitive advantage of the business model, right? We can expand in basins in a relatively cost-efficient way. You saw that with the entry into Canada. We've been looking at Canada for the last 2 years, both in the Montney as well as the Duvernay. And this quarter, we're fortunate to find an asset that checks the box.

And so even looking at our ground game, we had activity in every single basin and the competition ebbs and flows depending on what you're looking at in what period of time and our ability to move quickly and leverage the proprietary information that we have with the evergreen models that we have enables us to make those decisions on a real-time basis. And so we'll continue to look at the opportunities that are within the basins in our own backyard in Sandbox now. But that's not to say that we're not looking at a number of other different basins at any given moment in time. I think we've got 15 different large asset transactions that we're looking at right now. A lot of the stuff that was in market was formal auctions, but a lot of the stuff that we're having conversations around in the third quarter has really been bilateral conversations. So we'll continue to stay dynamic in terms of how we're sourcing and looking at opportunities.

Yes. I mean I use the example, obviously, we've grown our Utica position probably in excess of what we would have thought the opportunity was when we entered the basin. We've made a significant investment in acreage and our phone is ringing off the hook now of things to do with it, right? And so from operators all over the map. But I do think it's a really important distinction about our business model versus, say, an operator, right?

And I think the market spoke long ago, which is that too much diversity as an operator can be challenging. And there are some specific reasons for that, which is, one, do one thing, do it well. Can you be really good at lots of different things? Secondly, allocation of capital for operators in which they have to maintain a team and rig activity and all these things can get a little bit squirrely. For nonoperator, it's very, very different, right, which is that for us, it's truly just capital allocation, so it's just dollars in and dollars out.

And so the diversity, while it might be a little bit harder to model and annoying for you at times, at the end of the day, it doesn't have the same inherent challenges that it can be when you're trying to maintain multiple business lines for an operated business.

And we have no further questions. I would like to turn the call back to Nick O'Grady for closing remarks.

Thanks, everyone, for joining the call today. We'd like to remind investors to view our new earnings presentation slide supplement, which contains new enhanced disclosures, which highlights our asset value. and the incredible investment opportunity. As always, reach out to Investor Relations with questions, and we look forward to continuing the mission. Thanks again.

This concludes today's conference call. Thank you for your participation. You may now disconnect.

Greetings, and welcome to the NOG's First Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. It is now my pleasure to introduce your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Good morning. Welcome to NOG's First Quarter 2026 Earnings Conference Call. Yesterday after the close, we released our financial results. You can access our earnings release and presentation in the Investor Relations section of our website at noginc.com.

We will be filing our March 31, 2026, 10-Q with the SEC within the next few days.

I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; our Chief Financial Officer, Chad Allen; and our Chief Technical Officer, Jim Evans. Our agenda for today's call is as follows: Nick will provide introductory remarks followed by Adam, who will share an overview of NOG's operations and business development activities, and Chad will review our financial results. After our prepared remarks, the team 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 we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliations of these measures to the closest GAAP measures can be found in our earnings release.

With that, I'll turn the call over to Nick.

Thank you, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. I'll be very brief this quarter by highlighting 9 key points. Number 1, business activity remains stable with few observable changes since we last reported. Number 2, potential changes to activity in 2026 remain a TBD for us as the effect of the Iran war is only now going to be potentially seen in AFE activity. We will update our investors accordingly throughout the year. Number 3, the higher long-dated pricing stays, the more likely we see a sustained change in activity, especially as we head into 2027. Number 4, in the meantime, we've seen a reversal of curtailments in the Williston, and this will drive better capital efficiency throughout 2026. Number 5, it was a banner first quarter for our ground game with an incredible 41 deals done, while overall capital remains controlled. Number 6, the current geopolitical storm is showing some key benefits and a few negatives to the business.

We are seeing wide swings in oil differentials, which are likely benefiting our realizations materially, some in the Permian, but particularly in the Williston. On the gas front, Permian production remains hamstrung by limited takeaway for the time being, but we remain financially well insulated with significant basis hedges at less than $1 off Henry Hub. Number 7, our leasing program remains materially underappreciated as through this effort, we've added over 70 net locations in the last year. Free cash flow yields aren't free when comparing us to peers that are just depleting away their inventory. Number 8, while all eyes are on Iran and the wide swings in spot prices, it is the longer-dated strip that matters. The improvement in the 2027 and 2028 strip are what drive growth in undeveloped activity and in asset prices, and these improvements should help stabilize activity going forward, lubricate the M&A market, reduce bid-ask spreads and drive up our competitiveness.

We have several exciting large-sized package prospects in evaluation and more coming as the M&A market heats up. The backlog has improved in both size and quality, which is highly encouraging for our business model. Number 9, regardless of what happens in Iran, we believe things have been set in motion that will materially improve the long-term strip's outlook, absent significant economic turmoil. That bodes well for activity, acquisitions and for our investors. Given our hefty free cash flow generation despite adding inventory, our improved balance sheet and our reputation in the marketplace, there is a huge opportunity for our business to find meaningful growth paths.

Again, thank you for your interest in our company. We remain focused on growing our enterprise the right way, and as always, our company run by investors for investors. With that, I'll turn it over to Adam.

Thank you, Nick. As a whole, Q1 activity was in line with expectations. Production was strong, particularly in Appalachia, where we continue to see promising results from our growing asset base and with our Q1 program right on plan, showing strong IPs. The Williston also outperformed as multiple operators contributed meaningful return to sales volumes from prior curtailments, along with performance gains from recent IPs.

Uinta and Permian rounded out the quarter with performance in line with expectations. We ended the quarter with 43.7 net wells in process and 9.2 net AFEs, with the Permian representing roughly 1/3 of our wells in process and approximately 60% of AFE inventory. Well proposals have held steady at 216 consents, squarely in the 200 to 230 range we saw throughout 2025. And based on our conversations with operators, our forward activity view is unchanged from what we laid out on the fourth quarter call. However, the next few months will be instructive for activity changes as it pertains to the expectations for the remainder of the year and 2027.

On the ground game, we set a new quarterly record with 41 transactions in Q1, adding over 5,100 net acres and 6 net wells. Our Appalachian leasing program continues to perform well, but we were also able to close deals across all of our respective basins. Most transactions occurred early in the quarter ahead of rising commodity prices, and our pipeline continues to deliver as we diligently evaluate opportunities. Our ground game will stay central as we leverage NOG's proprietary infrastructure to grow our portfolio through smaller acquisitions and evaluate further joint development opportunities.

Larger M&A opportunities have also picked up, and we are evaluating over $10 billion in assets across 8 transactions that are currently in the market. As expected in this environment, there is a fair amount of variability in asset quality, but it has been encouraging to see higher quality assets coming to the forefront. Given the consistent number of opportunities afforded to us, we remain discerning and, as always, will prioritize packages that are resilient in any commodity environment and those that create long-term value.

With that, I'll turn it over to Chad.

Thanks, Adam. In the interest of time and to avoid repeating standard financial metrics available in our release and presentation, I will focus my comments on the overall performance drivers and outlayers encountered in the quarter.

Our first quarter financial results and production cadence were largely in line with internal expectations with no major disruptions. And despite the persistent macro volatility faced by the industry, NOG's diversified and scaled platform continued to deliver, outperforming internal estimates on production and EBITDA for the quarter.

First quarter total average daily production was over 148,000 BOE per day, up 6% sequentially, a record for our company. Our oil-to-gas ratio was an even 50-50 split as our Appalachian JV reached its peak in terms of well deliveries.

GAAP net income was impacted by 2 noncash items. The first was a noncash mark-to-market loss on derivatives of approximately $521 million, which was the result of a huge run-up in oil prices during the quarter due to the war in Iran. Hedges settled in the quarter was only $17.6 million loss, comprised of an $11 million gain in natural gas hedges, offset by a $28 million loss on our oil hedges. The second item impacting net income was a noncash impairment charge of $268 million.

As we have discussed on prior calls, NOG accounts for its assets under the full cost method as opposed to the successful efforts method, which does not perform historical price-based asset test. We are one of the only companies among our peers that utilize the full cost method. I should mention, given the recent change in oil prices, if they stay at current levels, this should be the last impairment charge for the year. We also continue to evaluate a potential shift to successful efforts longer term to avoid such optics.

Moving on to pricing. Natural gas realizations have continued to be weak in the first quarter, coming in at 72% of benchmark prices, reflecting ongoing Waha market weakness due to constraints in the Permian. We expect gas realizations, specifically in the Permian to remain weak for at least the next couple of quarters until planned infrastructure projects come online in the back half of 2026.

I do want to point out that inclusive of our Waha basis hedges, our gas realizations in the Permian were 53% or $1.86 per Mcf versus a negative 1% or negative $0.02 per Mcf that are included in our corporate gas realizations. So we are well insulated from a risk management perspective for the rest of the year.

CapEx in the quarter, excluding non-budgeted acquisitions and other was $270 million, which includes the success we had in our ground game. The $270 million of capital was very balanced with 31% to the Permian, 27% to Appalachia, 24% to the Williston and 17% in the Uinta Basin. Approximately $227 million of the total spend in the quarter was allocated to organic development capital. We still expect CapEx cadence to track at approximately 60-40 split between the first half and the second half of the year, subject to change with activity behavior from our operating partners.

After closing our joint Utica acquisition during the quarter, we exited the quarter with debt well within our comfort zone and our balance sheet remains in a healthy spot. Our leverage and liquidity were further enhanced by the nearly $230 million equity offering we completed late in the first quarter. We currently have over $1.2 billion of liquidity available to us with an additional $175 million of untapped liquidity. And given all the work we've done on the maturity wall last year, we have plenty of runway to execute for years to come.

With respect to our 2026 guidance, we have not made any updates given the significant level of volatility in commodity prices, our industry and in the macro generally. Directionally, we are currently trending towards the higher end of the low activity scenario we laid out last quarter, but we still got a wide range of potential outcomes for the year. I'd anticipate that we'll be able to start tightening those ranges and narrowing our 2026 guidance by our second quarter call.

That concludes our prepared remarks. Operator, please open up the line for Q&A.

[Operator Instructions] And your first question comes from the line of Neal Dingmann with William Blair.

Nick, my first question is just on incremental activity. Specifically, you all mentioned in your prepared remarks and release that you suggested operator activities remained flat. But I'm just wondering, based on your recent conversations and what you've seen sort of happened historically, both in this period and prior, what in addition to the 12 months now surpassing $80 do you think has to happen in order to see what I'd call more sustainable change in activity? And if -- when and if this happens, do you believe it occurs sort of equally in your Bakken, Permian and Uinta plays?

Yes. Thanks, Neal. Good morning. I'd say this, one, when you think about our original guidance, it didn't contemplate a war, right? And so it really -- it comes into the fact that we're seeing obviously a huge surge in short-term prices and a decent surge in the long-term strip. But because it's being driven by geopolitical things, I think you're seeing a little bit more caution than you normally would from operators.

One of the reasons we haven't made any substantive changes to guidance just yet is just that there is a lag factor, which is that I do think, and as I mentioned in my prepared comments, it's likely that we will see an increase in activity over time. And that's really going to be driven by the long-term strip. The average spud to sales time is -- it can be faster, but I'd say, on average, it's sometimes around 150, 160 days. And so when you're making that decision today to pick up a rig to drill an additional pad, you're not capturing $100 spot oil, right? You have to make those decisions based on the future. And I think nobody from our operators, they don't want to have egg on their face and commit to a bunch of new activity, sign up a bunch of stuff and then have some resolution in the Gulf and suddenly, they feel like they're falling on their face.

That being said, as we continue to draw oil out of storage, I think what's inevitable is that the long-term strip is going to have to reflect that, right? And so it's around $70 on a 2-year basis today. I think the reality is that's probably enough in order to certainly incentivize activity, M&A, all those sort of things. But I think you may see it creep higher just to really give people a buffer to ensure they can feel good about making those investments because that's really what drives that.

For us, I think, frankly, just right now, what happened in early March really only starts to affect us right now, and we're really just asking for some grace to really see over the next several months of how this plays out. I do -- but I do think -- look, I think we've talked about this from a guidance perspective. I think we're certainly confident in the high end of the low end. And then I think from there, I think we just want a little bit more time in order to narrow that band. But I think we'll certainly get it done by, call it, the second quarter.

That's more than fair. And then my second question, just on -- typical on capital allocation. Specifically, I know talking to some of the operators, they seem to simply look at oftentimes just sort of mid-cycle pricing assumptions as what I'd call a primary driver between deciding if you're just leaning into share buybacks or more, I guess, ground game and M&A. But again, you all seem unique because you seem to have more ground game opportunities than most. So again, I'm just thinking, when it comes to capital allocation, is it simply looking at a mid-cycle price and how cheap your shares are or versus a ground game return? Or what's involved in that?

Yes, that's right. I mean I think what I'd tell you is that we have to manage a bunch of things, right, which is that like, at the end of the day, a share buyback is a high return proposition, especially when prices were low, and we did do some buybacks at the end of last year. But I'd also tell you that one of our goals as a company, one of the long-term goals is you really have to -- you have to grow your business over time, and it's not what a share buyback does where you just now own more of the same thing. And so ultimately, the opportunity when prices are low countercyclically to acquire assets, which is why we were really so busy in January and February, ultimately can provide some of the best long-term value when you talk about that mid-cycle. I mean, I think oil was $57 in January or February, right? That's certainly below what we would view as a mid-cycle oil price. And so anything you're acquiring during that period of time is likely to deliver a really high return, as do buybacks. And I think it can all be part of the mix, but it's really about that balance.

And the next question comes from the line of John Davenport with Johnson Rice.

So from the previous quarter, you guys kind of beat on natural gas pricing, specifically in Appalachia. I was just curious if that's going to be an ongoing trend both for next quarter and the second half of the year? I know the strip for natural gas hasn't looked all too strong in the past couple of months. So just curious what your thoughts are on that.

Yes. Yes. Well, as a 2-stream reporter, it's a little bit different, right, because our NGL yield is in there. So what I would tell you is that, as it pertains specifically to Appalachia, certainly -- and some of our Appalachian gas is getting kind of on-water NGL prices, right? So we're certainly getting a huge benefit there. Appalachian differential is the bulk of our prices at M2 and M2 has certainly been better. I mean it's one of the few basis areas where we're actually losing money on our hedges. So M2 has been sort of tighter and it appears even it obviously tends to dip seasonally, but it's certainly been better than what the averages have been for the last several years. And so we're definitely seeing an improvement there.

In terms of our overall differentials, I think Chad talked a little bit about this in guidance, but I would tell you that we're seeing likely significantly better-than-expected oil differentials, which is really the biggest driver to our revenue given it's about 80% of our revenue. And then we're seeing, in aggregate, worse gas differentials, and that's 100% driven by Waha pricing. At the financial level, it's not having as much of an effect at the bottom line because of our hedge position. But at the end of the day, at the actual spot realizations, I think there's probably downward pressure in the short term. Obviously, I'm not -- I think there's something like 4 Bcf a day of expansions going on in the Permian. So I think it certainly will improve from some of the doldrums we've seen in April, but that's going to take some time this year.

Okay. Yes. Perfect. And I was also curious, you mentioned you are evaluating, call it, $10 billion in potential large M&A transactions. Curious where -- what the locations of those might be along with -- just give us some characteristics that you guys are looking for on those opportunities.

I'll set the table, I'll let Adam finish it, but I'd say this, one, it's been -- and consistent with the last several years, it's definitely more diversified. There's some stuff all over the place. And as our capabilities have expanded, obviously, we've seen more than we ever have from, call it, Canada to every single subbasin in the U.S. What I would tell you is that we are seeing -- typically, people are willing to sell PDP latent properties even in low price environments, especially in the days of ABS and things like that, where they view they're getting relatively good prices for them.

When the long-dated strip was $57 coming into this year, people -- that -- if you think about a DCF exercise, that's what drives the value of undeveloped inventory. And so assets with strong undeveloped inventory, which are the characteristics we're looking for, really, we're starting to dry up on the oil side. That has obviously inverted completely. We're seeing higher-quality Permian assets in particular, coming to market. And so I think, for us, you are right now at a little bit of a -- it might seem counterintuitive given how high spot prices are. But with the strip closer to what we would view as a mid-cycle price today, it really does help the long-dated M&A. And so my point would be, if oil prices went from $100 to $75 in the spot market today, it's not going to have as much of an impact on the value of those assets versus that long-dated stripping to here. Adam, I don't know if you want to add to that?

That's right. I mean I think the biggest difference that we're seeing between kind of 2025 and where we stand today has been kind of a pivot from the gas-weighted quality assets that we were looking at last year to more of the oil weighted, which is obviously expected. I think you've got a number of operators post consolidation now starting to kind of socialize their assets. You've got private equity groups that are obviously taking a look at the strip and coming to market. And so based on my prepared remarks, you're certainly seeing a fair amount of variability, but the quality is starting to improve, especially on the oil side.

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

I just wanted to quickly touch on you guys hedge book. Looking forward to the curve and the big -- I guess, big bug of swaps you guys hold, how should we think about any strategic shifts for the rest of the year given the volatility, and as you said before, the war that no one expected?

Yes. I don't think that you'll see much in terms of fireworks in terms of the swaptions. We don't really have that many swaptions remaining this year to be candid. And what few ones we have will either be exercised or roll forward. But I wouldn't expect any major shifts to our hedge book specifically for this year. And then for next year, we've started hedging, Paul, but not in a significant action at this point. And I think it's just -- we're just trying to be patient as we go through the -- we really want to see the conclusion of what happens in the Middle East before we really make a call on 2027.

Got it. Makes perfect sense. And then as you guys talked about the net wells in process, the current split is I guess third Permian, third Williston and then split even otherwise. Any reason to think with what you see in that range right now that, that shifts? Or is that kind of -- should we think about that as more locked in for the next year or so?

Being an expert, I'll leave it to you.

Yes. I mean, I guess what I would be looking towards is probably more like the election activity, right? And so if you look at that, you're seeing about 2/3 related to the Permian and you're starting to see a fair amount of Williston acceleration as well. And so I would expect kind of the Permian and the Williston to be the front runners. Obviously, we've got a fair amount of activity in Appalachia, and that will also be dependent on, obviously, the transaction that we just closed as well as the ground game leasing program that we've got in place. And then the Uinta is really just kind of steady as it goes. So Permian and Williston is probably where I'd be looking to.

Yes. And I'd say, I think my guess would be just given the gas situation in the Permian right now, that the acceleration you see there really is probably later in the year just as you get closer to a resolution there. And on the Uinta, I think there are some options for some acceleration, but we'll have to see [indiscernible].

And the next question comes from the line of Noel Parks with Tuohy Brothers.

I was wondering, and it's definitely interesting to hear about the different parties, the private side coming to the table and so forth and -- but I was wondering, for operators, where do you think things stand now around sort of basin rationalization in the wake of some of the big transactions of the last year or so now being fully digested? And I guess I'm just curious if you think overall across your basins, you're seeing operators more inclined to sort of expand their footprint or sort of core up and narrow them down right now?

Yes. No, I don't know if I want to speak for them completely. I would say this that we -- Adam had talked extensively last year about that he thought that post a lot of this consolidation, we would see rationalization. We are starting to see that. So we're seeing several large companies put packages of noncore assets sometimes in good basins to sell. And so I do think that we're seeing some rationalization. We're seeing that in the Permian, the Eagle Ford, I'm trying to think of where else. I think there's a large Williston package coming at some point this year. And so we're definitely seeing that to some degree. I think, look, consolidation is a trend that I think continues. It both benefits and hurts us sometimes. Obviously, it tends to hurt us in the sense that you probably have less aggregate activity, but it helps us from a cost efficiency and from a returns perspective. And so I don't know if you want to add to that, Adam?

Yes. I mean, going back to your initial question, I would just say that 2 things can be true at the same time. And ultimately, it's going to be dependent on the philosophical approach from the operator, right? And who did they consolidate with, where are those positions? And then ultimately, what does that integration difficulty look like? Because from our experience in talking with our operating partners who have gone through this, some can go very smoothly and others cannot. And so I think you're going to see some large asset packages, but then you're also going to see other operators that might take small pieces, non-op and kind of just kind of layer that out into the market kind of as they go. So I think you're going to see a little bit of everything.

Got it. And I'm just wondering, are you seeing anything happening kind of in the sort of off the beaten path gas plays? I'm thinking a little bit about Mid-Con, Rockies, just as people look ahead to longer-term supply and sort of thinking about underutilized infrastructure and so forth and maybe some capital finding its way there?

Yes. I mean, look, there have been some major consolidations on the private side in like Rockies gas and some of the legacy assets, and there have been some companies that have put together some really good assets. And in some cases, some of the wild swings in differentials out there over the last couple of years have made those really, really sound investments. I'm not sure that's necessarily something for us per se. And I say I'm not sure we really haven't evaluated a ton of it. So we don't -- things like the San Juan Basin or the Piceance, we just -- we've never really evaluated them at any extent. So I can't really speak to them.

I'd say this in general, though, if you think about the life cycle of shale, and this is consistent with my public comments everywhere, in general, there is more life in the core basins of gas in the U.S. than there is in the core basins in oil. And so I think the necessity to really step out isn't quite there. We have decades of gas inventory internally here alone. We don't really write in our core basins. I don't know if you'd want to add to that.

No. I think the only other thing I would add is, I mean, you obviously have seen kind of the ABS market come into play with maybe some more PDP-heavy type assets, Mid-Con, Eagle Ford, things like that. And typically not the sandbox that we play in, but we're always having conversations about how we could potentially be helpful there. So we'll continue to explore it. So...

Yes. I mean we've done a number of -- as you know, we don't have any assets in the Mid-Con. We've have done dozens of evaluations at this point. And it's just a more complex area. It's not really as uniform. And so it doesn't mean it's bad, but I think we'd have to be really highly selective if we ever enter that basin just -- with them, and most likely, we would do it with an operating partner.

And then what are we looking at relative to what's in our own backyard.

Correct. And so far, it has sort of lost in the tug of war from a return on capital perspective that is amenable forever. It's just we have yet to find an asset that really...

Compete.

Compete it, that's right.

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

Just wanted to follow up on the earlier question about the oil swaptions and just ask about some of the accounting nuances for those swaptions. I think most of us understand that the vast majority of those swaptions that expire at the end of this year are required to be listed for 2026, even though the majority of them would actually turn into swaps for '27 or even beyond rather than this year if they're ultimately exercised. So I guess I understand that nuance, but I just kind of wanted to square that with the makeup of the hedge liability on the balance sheet where it looks like close to 65% of the hedge liability is classified as current.

Yes. That's because of the expiry, right? Just as you stated, Phillips, right? We have to -- because of when that expiry is being, in some instances, or most instances 12/31/2026, it's got to sit into the current bucket there.

Okay. Okay. So that makes sense. It's basically the same...

Yes. For accounting purposes, it's got to be treated for the bank's counterparty election date.

But it's not really how it works.

That's not how it works. No. And you'll see in our 10-K -- or 10-Q, sorry, some updated disclosures with respect to kind of how the swaptions roll out. But again, like what we've mentioned before, Phillips, we certainly -- we actively manage this portfolio.

It's a nothing burger to be candid.

Yes, it is.

And I'm showing no further questions at this time. I would like to turn it back to Mr. Nick O'Grady for closing remarks.

Thanks very much for your time this morning. We look forward to talking to you in the coming weeks. Appreciate it.

Thank you. And ladies and gentlemen, this concludes today's call. You may now disconnect.

Greetings, and welcome to the NOG Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.

It's now my pleasure to introduce you to your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Good morning. Welcome to NOG's Fourth Quarter and Year-end 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 the website at noginc.com. We will be filing our 2025 10-K with the SEC within the next few days.

I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; our Chief Financial Officer, Chad Allen; and our Chief Technical Officer, Jim Evans. Our agenda for today's call is as follows: Nick will provide introductory remarks, followed by Adam, who will share an overview of NOG's operations and business development activities, and Chad will review our financial results. After our prepared remarks, the team, including Jim, will be available to answer any questions.

Before we begin, let me remind you of our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause the actual results to be materially different from expectations contemplated by our forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliations of these measures to the closest GAAP measures can be found in our earnings release.

With that, I'll turn the call over to Nick.

Thank you, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. I'd like to take the time to reflect upon 2025, discuss our plans for 2026 and also share my views in regard to the macro oil and gas environment and how it may affect our company and strategy.

While our equity total return was down in 2025, our adjusted EBITDA was actually up 1%, and this was with oil prices down some 14% on average. Our share count was 2% lower year-over-year, our net debt was down modestly year-over-year, all of this despite closing over $340 million of acquisitions, including Ground Game. Our financial results are a testament to our consistent hedging and the decisions we made regardless of market perceptions in the short term, which are manifested in multiple compressions. We were judicious and strategic on how we deployed and allocated capital in 2025.

Our natural gas spending increased dramatically and our oil spending declined. NOG is now seeing record natural gas volumes aligned with some of the highest seasonal prices seen in many years, and we and our operating partners have tried to deploy the bare minimum on the oil front to preserve our precious barrels for a better day.

Our 2025 ground game focused more on long-term development versus drill bit projects given the fluxing pricing environment. It is our intent to capitalize on attractive land pricing while still maximizing our long-term return on capital as we anticipate incredible return development opportunities on these lands over time.

As a result, we grew our footprint organically by over 12,000 acres last year, extremely cost effectively with advantageous and low-risk long-term leases. Our land assembly effort may have made us look less capital efficient in the short term, but it's the exact type of capital allocation tactics companies should take in times such as these, and we believe our decisions will pay dividends in the years to come as commodity pricing improves.

In the first quarter of this year, we've already grown that land position substantially once again. And while the market likely treated our equity based on a deceleration of growth estimates in the short term and the continued decline of forward prices, we also took great pains in extending our maturity wall and increasing our liquidity to bridge to the next cycle. In fact, even after closing our joint Utica acquisition with Infinity and using our revolver to finance that transaction in its entirety, we will still have more liquidity than we started with in 2025. These are all purposeful moves to allow us to navigate a cyclical business while also creating value during a downturn.

As oil declined into the 50s later in the fourth quarter and into this year, we saw a notable change in operator behavior with a significant slowdown in new activity and a deferral of existing activity. While in the short term, this can affect us, it helps solidify our belief that 2026 will mark the trough of the oil cycle. This also may lead to a slowdown in capital spending, offset in part or in whole from ground game opportunities as one would expect during weaker periods.

In our view, there are 2 potential outcomes for oil: one of continued middling prices for the bulk of the year, which ultimately leads to an increase of pricing within a year or 2, or conversely, a sharper short-term decrease in pricing, which leads in the end to the same outcome, higher prices. In either scenario, NOG will come out stronger. We are well hedged and our spending decisions over the last 12 months have proven wise as we have pushed and preserved high-value development for a higher price environment. Geopolitical noise in the short term has a lot of people guessing, but fundamentals are set to improve.

We've heard investor rumors that somehow our dividend could be in question. I'd like to address that directly as we think this chatter is totally unfounded. While nothing in life is ever completely certain, our dividend is built for an even significantly weaker environment than we face today, where we would ultimately be at a cash flow breakeven level during the trough of the cycle post dividend. And we believe that our dividend can be sustained for many years, even though we don't believe that oil cycles work in a way that we will be in a breakeven scenario for an extended period.

We built our dividend to last and ultimately to grow through cycles. So while we, of course, must manage risk, we are dedicated to sustaining and growing our dividend over the long term, and we believe the attractive yield it provides today is a great opportunity, particularly at the trough of the energy cycle. Our macro view and the belief oil's trough is coming will pivot the execution of our ground game in 2026 from leasing, in some cases, to drill-ready projects.

Organic activity, as always, will be dependent on short-term commodity prices, but our ground game capital deployment will be targeted on investments that will create the coiled spring growth effect our investors saw in 2021. What we're seeing in real time is that drill-ready projects, something we saw as mostly unattractive in 2025, are slowly becoming a much better place to be. While leasing remains active as we focus on the long term, the ground game will definitively evolve in 2026.

I'll let Chad and Adam cover this further, but our guidance is reflective of the marketplace. In our low activity scenario, we do see some reduction in oil volumes, but a much more dramatic reduction in spending. In that low activity scenario, we'll generate substantially larger amounts of free cash flow at today's strip while deferring and pushing our high-value development for a better environment.

In the higher case scenario, we'll see some acceleration of activity, a reduction in the curtailments we've carried for some time and a higher TIL count. While free cash flow would be lower at today's prices, it certainly would also drive higher future production. And of course, in this environment, it's quite possible that the overall pricing environment would wind up being much higher. Our ground game can play a major role in the in between of these scenarios regardless of the environment, where opportunities may arise for us to deploy ad hoc capital throughout the year, and we expect and hope to do so, especially in a tougher environment.

On the M&A front, we continue to evaluate assets as they come to market. With that said, however, we are satisfied with the portfolio strategic positioning, and moreover, we believe that quality assets that meet our criteria, particularly on the oil front, possibly will only come to market if we see a healthier market price point. So we'll focus our discretionary capital on the ground.

In the past several years, we've seen some aggressive new entrants to the smaller deal side of the market, and much of that capital has become sidelined as these parties' prior investments are proving to have been poor capital allocation decisions. This should now provide NOG with a clear competitive advantage in the current environment.

On the development side, it's important to understand the inherent alignment built into our business model. Our operators are rational and the activity we have seen curtailed and deferred will be activated into a healthier environment. Consequently, NOG should see disproportional benefits as the market improves. But what that means is that as the cycle recovers, we create far more convexity to the upside exactly when you're supposed to have it, when prices are stronger.

I recognize that our business model may make our journey a bit lumpier when comparing us to a typical operator, but it also has the potential to enhance long-term returns significantly versus a production targeting mindset. NOG has pioneered the large non-op at scale, moving to a broad-based multi-basin, multi-commodity platform over the last 8 years. We effectively created the large co-purchase partnership and reinvented to some degree the joint development agreement.

We're not done innovating and evolving. We are reevaluating how we operate, how we allocate capital and even how we source capital. Over time, the initiatives we are evaluating have the potential to enhance our value creation capabilities, our returns and our business model. So stay tuned for these developments. It's going to be a great year. NOG has a differentiated coil spring-like exposure to the cycle. It could take much of 2026 for the oil markets to fully recover. But as any good investor knows, the market will be well ahead of that.

I can't say in my investment career I have seen a period where energy equity saw multiple compression at the same time that oil prices were declining. Cyclical stocks should never be valued at peaks or troughs but at a mid-cycle marginal cost of production. This leads to multiple compression during high prices and expansion during low prices. We saw such a period during the trough of gas prices in 2024, but that has not happened for oil stocks and certainly not specifically in our case.

For our investors and prospective investors, this phenomenon presents a clear opportunity in NOG's shares, especially because NOG has true right way risk. Our volumes and activity from operators will rise with pricing. I'm extremely excited about how we're positioned and for what lies ahead.

Now I'll turn it over to Adam.

Thank you, Nick. I'll start by reviewing the operational details for Q4, what we're observing in the current environment and how we're thinking about 2026 activity levels, followed by our business development efforts and the broader M&A landscape. As a whole, Q4 came in line with expectations as we saw activity ramp exiting the year.

During the quarter, we added 24.2 net wells to production even as a number of our operators deferred completions due to commodity pricing. Deferrals notwithstanding, recent results have topped expectations with Appalachia, the top-performing basin relative to forecast, and the Uinta and Williston fast following. Given the accelerated completion activity in the fourth quarter, we saw our wells in process draw down 7.8 net wells, finishing the year with a total of 45.6 net wells.

The Permian currently makes up over 1/3 of the wells in process, while Appalachia makes up just less than 1/4 and the Williston and Uinta make up the rest. In addition to our wells in process, we have 13 net wells that have been elected to but not yet spud, with the Permian making up roughly 2/3 of the total. Lateral lengths remain elevated as operators continue to drive normalized cost down and bolster returns in an effort to counter current commodity prices.

As we exited the year, both our wells in process and our elected AFEs were averaging around 13,000 feet with normalized well costs down nearly 5% quarter-over-quarter. In addition, our operators have been high-grading locations, and we elected to over 95% of our well proposals during the quarter with expected returns significantly higher than our hurdle rate. 2025 marks the year where we've seen an acceleration in activity across Appalachia, and we are poised to significantly increase activity levels as we scale and further diversify our asset base after closing our Utica acquisition in late February.

Pro forma for the transaction, NOG will have increased its Appalachian footprint by 45%, now totaling approximately 90,000 net acres, including over 100 identified gross locations on the Antero asset alone. The scale and diversity of NOG's asset base will provide us with a unique optionality as we head into 2026 regardless of the price environment. We will adapt to market dynamics and deploy capital according to what we are seeing on a real-time basis. As such, we have provided guidance reflecting a range of outcomes.

As it stands right now, with our current wells in process and based on the conversations that we have had with our operators, we expect activity levels for 2026 to be roughly split with the Permian at 40%, 25% to Appalachia, 25% to the Williston and 10% to the Uinta. As far as timing is concerned, this year's well activity will be relatively evenly weighted between the front and the back half of the year, while we forecast spending to be a bit more front-end loaded with a 60-40 split.

And while we don't provide quarterly guidance, we expect the usual downtick in Q1 driven by elevated Q4 activity levels along with weather and commodity-related curtailments, and from there, moving higher in Q2 with a relatively flat cadence thereafter. The mix and pace of our activities could shift based on how commodities perform during the year. If organic activity slows in a particular basin, we'll consider reallocating capital to another more constructive area of the business. Additionally, we may focus more on the ground game to seize countercyclical opportunities that arise.

Turning to the M&A landscape and our business development efforts. NOG has remained more engaged than we ever have been. As mentioned earlier, our integrated upstream and midstream Utican transaction is now closed, and we are excited to get to work on our fifth major joint acquisition with our partners at Infinity. Our assets' resilient inventory with average breakevens below $2 will be a significant focus as we prosecute development plans and grow volumes beyond 2030. In addition to the 100-plus locations already identified, there is potential for incremental value creation from both the undeveloped upstream footprint as well as the midstream fee potential.

Looking ahead, there are several large assets in the market right now, something to the tune of $6 billion in total. That said, it pays to be patient as many of those assets are not the right fit for NOG. However, we are expecting a number of potential opportunities coming down the pike that could be of greater interest. All else being equal, we expect the ground game to continue to take center stage as we leverage our proprietary infrastructure and further enhance our portfolio through smaller acquisitions while screening a number of different joint development opportunities.

In this environment and, in particular, the fourth quarter, the team did a phenomenal job taking advantage of the disconnect in the market as operators and the competition exhausted their budgets for the year. In the fourth quarter alone, we were able to pick up over 6,000 net acres and 1.2 net wells across 33 transactions, a quarterly record. The acreage alone represented over 50% of the ground game acreage picked up in 2025, and we finished the year with 12.8 net wells and over 12,300 acres while evaluating over 700 opportunities.

We don't see our progress slowing down in the first quarter either as a number of committed transactions are slated to close in the first part of the year. However, most encouraging are the results from our recently acquired acreage that is already getting converted into development. From our acreage acquisitions in Ohio alone, we've seen 14 well proposals with some of the strongest economics across our portfolio. We'll continue to navigate this environment as we have every other down cycle by staying nimble, allocating resources to the most capital-efficient projects and creating long-dated and durable value for our stakeholders.

With that, I'll turn it over to Chad.

Thanks, Adam. Our fourth quarter financial results and production cadence were down the fairway with no major disruptions. And despite the persistent macro headwinds faced by the industry, NOG's diversified and scaled platform continues to deliver, outperforming internal estimates on production and EBITDA for both the quarter and the year.

Fourth quarter total average daily production was 140,000 BOE per day, up 7% from Q3 2025 and up 6% versus Q4 2024. For the year, total average daily production was 135,000 BOE per day, topping the high end of our guidance, up 9% as compared to the full year 2024. The outperformance was driven primarily by a continued ramp in our gas assets.

Fourth quarter oil production increased 3% to 75,000 barrels of oil per day sequentially, but was 5% lower year-over-year as some of our Q4 wells were deferred as price sensitivity among our operators became more acute. The ramping of our Appalachian JV drove gas production to record levels for the third consecutive quarter with 392 MMcf per day, up 11% sequentially and up 24% from Q4 2024. For the full year 2025, NOG's oil production was 75,646 barrels per day with gas production coming in at 356 MMcf per day.

Moving on to our financial results. Adjusted EBITDA in the quarter was $367 million and free cash flow was $43 million. For the year, adjusted EBITDA was $1.63 billion with free cash flow of $424 million. Adjusted net income in the fourth quarter was $82 million or $0.83 per diluted share, excluding the impact of the $270 million non-cash impairment charge we took in the fourth quarter. For the year, adjusted net income was $453 million or $4.57 per diluted share. GAAP net income was impacted by $703 million in non-cash impairment taken over the course of 2025.

As a reminder, NOG accounts for its assets under the full cost method as opposed to the successful efforts method, which does not perform historical price-based asset tests. Driven by lower average oil prices, we recorded a series of non-cash impairment charges beginning in Q2 under the ceiling test of our full cost pool of oil and gas assets. These impairment charges are not indicative of the quality of our assets. They are merely dictated by weaker oil prices year-over-year.

As the cycle recovers, we do not get to write up the same assets that we impaired on the way down. We are one of the only companies among our peers that utilize the full cost method. We are evaluating in making a change in our accounting method to successful efforts as it's more aligned with our peers, providing a better basis for comparability.

Moving on to pricing. Oil differentials in Q4 averaged $5.05 per barrel as compared to $3.89 in Q3 as we saw widening seasonal differentials in the Williston, offset by improvement in the Permian. For the year, oil differentials were $5.53 per barrel, in line with our expectations. Natural gas realizations in the fourth quarter were 58% of benchmark prices, reflecting ongoing Waha market weakness as well as lower absolute NGL prices and a lower NGL to natural gas ratio. For the year, natural gas realizations were 79% as compared to 93% in 2024.

Lease operating cost per BOE in Q4 were $9.30, improved by 5% as compared to the third quarter and by 3% as compared to the fourth quarter of 2024. For the year, LOE per BOE was $9.61, up 2% from 2024. Despite higher volumes, we continue to see higher workover and maintenance-related costs. CapEx in the quarter, excluding non-budgeted acquisitions and other, was $270 million, reflecting another record quarter for ground game, as discussed by Adam.

The $270 million of capital was allocated with 44% to the Permian, 26% to the Williston, 8% to the Uinta and 22% to the Appalachian Basin. Approximately $193 million of total spend in the quarter was allocated to organic development capital. Total CapEx for the year, excluding non-budgeted acquisitions and other, was $1 billion, inclusive of $174 million of ground game investment in 2025. The fourth quarter and, frankly -- and the first quarter of 2026 have been busy as we took a number of actions to enhance liquidity in our maturity wall.

Starting with our revolver. In November, we extended the maturity date from June 2027 to November 2030, keeping the borrowing base and the elected commitment the same. The revolver was further amended just this week. We upsized the borrowing base to $1.975 billion and increased the elected commitment by $200 million to $1.8 billion, reflecting the addition of our joint Utica acquisition to our asset base.

In October, we issued $725 million of notes with a 7.875% coupon and retired nearly all of our 2028 notes with an 8.125% coupon. Just last week, we gave notice to the holders of the remaining $20 million of our 2028 notes, and we will be redeeming those notes at par on March 4. After closing our joint Utica acquisition earlier this week, we have over $1 billion of liquidity available to us.

Moving on to guidance. As Nick discussed earlier, given the lack of visibility with commodity pricing in this environment, we are providing 2 ranges that capture potential production, operating expenses and CapEx in a low activity environment and a high activity environment. For details concerning each scenario, please refer to the 2026 guidance page in our earnings presentation on Page 15.

That concludes our prepared remarks. Operator, please open up the line for Q&A.

[Operator Instructions] Your first question comes from the line of Neal Dingmann of William Blair.

Nice details again today. Nick, my question, you -- I think it was last night you talked about and mentioned that you have notably more than the typical amount of wells that have been spud -- that have not been spud, but have been consented. I'm just wondering what -- maybe you or Adam, what's your guess as to when these wells are finally drilled and completed? Is it just a matter of when, not if? Or maybe talk about why we're seeing that today.

That's right, Neal. As Adam also noted in his comments, we have a large D&C with -- and about 13 net wells we've consented to that still haven't been spud. We sometimes have given kind of specific TIL timing guidance throughout the year, and we chose not to do that this year. The range is obviously anywhere from 70 to almost 90 wells this year, which is really wide. And we think it would be a disservice to try to predict the behavior, because it's been moving around substantially in real time.

As an example, a lot of these proposals were delivered to us in November and early December, and then we've seen significant changes as pricing weakened late in the year and early into this year. The recent geopolitical spike in oil thus far hasn't shown a reversal in that behavior. But I think particularly from our private operators, which is meaningful to us -- but what I can say is if you look at this in history, especially as an accrual accounting shop, we have seen periods of time where we have had to bring forward accruals. We've had -- ironically, we're talking about not spending enough money, but we've had periods where our CapEx has been accelerated, and we've seen those things move really quickly. So that can happen again. I think it's really going to just be dictated a little bit, as I talked about, by right way risk with commodity pricing and specifically oil.

And what I would tell you is that we look a little bit different. If you're a -- when you compare us to, say, an operator and you're comparing -- look, I recognize estimates and all these things and changes to estimates. I spend a lot of time on that side of the table. But our optical capital efficiency -- whereas an operator targets a maintenance level of production and then tries to spend as little as possible to achieve that, they may look more capital efficient as things go down. We actually may look the opposite in the sense that we have committed capital, we have accrued capital in many cases, but we're managing significant curtailments or significant deferments.

And so we -- and you don't have to believe what I'm saying. You can look back to 2020. If you look in 2020, we looked far less capital efficient on the way down than other companies. And in 2021, we looked far more capital efficient because all of that capital that's in the ground and it's been determined -- that's been committed comes to fruition. So I don't know if that's too much or too little. Or you want to add to that, Adam?

Yes. I guess the only other additional color that I'd add, I think we alluded to it in the prepared remarks, which you've got about 2/3 of those 13 wells in the Permian. And if you're looking at kind of half cycle expected returns, you're looking at something well north of 40%, 45%. You've got 235 gross wells in total as well. So you've got a handful of diversity. And so I think it's really going to boil down to just what the gross level activity levels look like.

Yes. And that's the point, is that I don't think this is a function of economics in the sense that -- all of the activity that we have seen deferred or pushed has been largely economic in this environment. Especially, when you get to our private operators, it's not a question of whether they can make money on it. It's a question of whether they should, right? They'd rather defer those to a better day. I recognize in the shorter term that can have an effect on numbers, but in the long run, you're going to make a -- this is an ROI game and you're going to make a lot more money. You can't eat IRR, as they say.

Yes, great details. And then, Nick, maybe take the M&A question in a different direction again. You guys certainly have been active in -- I just -- it doesn't seem like looking at the stock price that you're getting rewarded for just how much bigger inventory position you have today than, let's say, even a few years ago. And so my question is, on the other side, just given how great right now the seller's market is, especially given what ABS players are paid for mature, would you consider divesting maybe not a lot, but some to -- if the market continues to reward for this?

Yes. I mean, look, we are for sale every day. Our assets are for sale every day. We'll always look at what makes the most economic sense for the company. I alluded to this in my prepared remarks -- prepared comments, excuse me, that we have been evaluating a lot of different outcomes. And without being too forward, I would just say -- we're pretty creative people, right? And I think that's been demonstrated over time. And we've got some creative ideas that could effectively bridge some of the things you're discussing over time.

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

Nick, this is I guess maybe a basic question, but worth -- I want to take a shot at trying to illuminate how you're going to -- how are you going to know and how are we going to know whether you're tracking the low end -- or the low activity scenario or the high activity scenario? I mean there's an obvious -- yes, go ahead.

Yes. No, I recognize it's not a basic question and it's not one that is unexpected because it's obviously an extremely wide set of outcomes. And we are dealing with the fog of war. And like I said, people watch the price of oil and expect behavior to change accordingly. And it does, but it takes a little bit more time, right? You need duration. So when things go down, behavior changes. When things go back up, it takes a while before that behavior changes. And so what I would tell you is, one, the onus is on us. We will communicate throughout the year. And I think, two, there's a complicating factor between the low kind of activity and the high activity, which is that obviously we have an active ground game which can fill that gap.

The other thing I'd point out is we are carrying substantial amounts of volume shut in, which is very different than the average operator. A lot of our privates have curtailed volumes. Some of it has been due to pricing. Some of it has been due to Waha issues and just the inability. And some of the deferral of activity has actually been driven by some of the gas issues you're seeing in New Mexico. But what I'd tell you there is that we will continuously try to tighten that band throughout the year and we will try to communicate.

And I think -- again, we've tried to take a pretty -- one of the things that I would point out in the high case, which is that what we have done in that case is we've made the assumption, "Okay, a more normal activity," but we're not turning it on, say, today. We're really pushing a lot of that out till later in the year, which is why the oil volumes might optically look a little bit different. But obviously, it would change the actual -- and I don't want to say the exit trajectory because the timing could be very wonky depending on when that stuff comes on, but it could potentially mean that.

So -- but I will give some comfort, which is that either one of these scenarios aren't going to affect our maintenance capital levels for the level of volumes you're talking about. So my point being that to the extent we spend more through that ground and we bridge that gap, even if we do see the low scenario, those dollars right now are kind of in between where we're going to be at any -- so as you look towards the following year, stable to growing activity.

The only other piece that I'd add to the deferments is we had about 4 net DUCs get pushed in Q4, and that's something that can get turned on at any time as well. So it's the combination of not only the curtailments, but the DUCs that have near-term catalysts depending on what kind of near-term pricing we're seeing.

Yes. And the one -- I'll just leave one thing because I think optically, we have sort of indicated that we would front half weight some of the capital, even though the capital in total is -- or excuse me, the development in total in both scenarios is considered to be relatively evenly weighted. That front half is 100% driven by ground game activity because we've had atypical success early in the year.

Interesting. That's good detail. Second question, you've drill down on Appalachia. So that was a -- it was a strong 4Q for you. You guys have already closed this Utica deal here in 1Q. Can you give us a sense -- I mean, to the extent you were surprised, or I think, Adam, you said your -- Appalachia was the most ahead of plan of all your geographies in 4Q. Is that carrying over into 1Q? And is the -- and can you give us any -- I know it's early, but anything incremental what you're seeing with the joint Infinity assets?

Yes. So I'll give a brief overview and then let the smarter people in the room finish the conversation. But I just say this, that -- timing plays a role in that and performance, right? So performance has been really, really strong on both our legacy Appalachian assets and on our joint development agreement and obviously, as we perceive, on the forward case in Antero. In case of the Antero assets, I would say you can see it in the purchase price adjustment that we've obviously had a strong -- it performed strongly prior to us taking possession of it. So that's -- or that means we get a reduction in that purchase price. I think as it pertains to the legacy assets, they've continued to surprise us month after month, year after year. They just are incredible. It explains why gas has been depressed for so long because they're so good.

And on our joint development JV over the last year, we've seen both timing and performance improvements. But I will tell you that like, for example, it's not a totally linear in the sense that I believe most of the completions that we're expecting are actually in April. So in Q1, in general, it's not going to be some huge thing. However, performance relative to plan versus linear performance are different things. I don't know if you guys want to add to that.

No. I think you nailed it.

Yes. And Charles, I'll just finish with just saying that I think we -- when we look at these assets, right, we have historically always underwritten things based on the prior operator, right? But that doesn't mean that necessarily is what we think we can do with those assets when we take possession. So we have great hopes for the Antero asset that we'll be able to see performance and cost improvements over time.

Your next question comes from the line of Scott Hanold of RBC.

Nick, thinking about the -- I guess, the high case, low case on the budget, can you give us a sense of where some of the uncertainty is more? Is it more on the private operators versus the public? And has any of that started to show itself? Like are you getting a better read right now? So my question comes down to, is there a point in time where you're going to commit to, say, one case or the other? Or do you think that having kind of 2 cases is a reasonable sort of way to look at moving forward?

Yes. I mean I think at this point in time, it's definitely still reasonable, Scott. I think there's going to be a time where it has to meld into one, right? And I think that's what we'll try to do. And obviously, we want to do -- look, we -- we have incredible insight to what we do over a 12- and 24-month period. However, the timing of it, as you've always known in our business model, it's harder to do quarter-to-quarter, right? And so -- and sometimes in a period like this, it becomes -- I mean, if you go back to 2020, we just had to flat out withdraw guidance because we couldn't predict the timing of that.

But in the end, it actually wound up -- for example, those decisions -- we saw half of our -- I don't mean to get off topic. But we saw half of our Williston volumes shut in for the better half of 2020. Well, when we went backwards and tested that versus everyone else who tried to keep their production flat, we made an additional $100-plus million in profit by turning those wells back on later on. So what I say is we have good alignment with our operators, but it is going to take some time to get some clarity in terms of some of these things.

I can just tell you what -- so you asked about public versus private. On the private side, this is something -- a trend that we saw really in the beginning or really early, probably the middle of last year, where we've seen a slow slowdown, a deferral, curtailments, et cetera, et cetera, et cetera. And that has stayed on.

What I'd tell you from a public operator perspective is -- obviously, I'm not -- I am watching all the public companies report, and I would just say that what publicly stated guidance and activity levels look like versus what we are seeing don't necessarily foot, which tells us that that's part of the reason we have 2 sets of guidance in some ways because a lot of what they're saying versus what they would indicate would suggest there's going to be a change in behavior throughout the year.

Got it. And then when you take some of the enhanced governance you've put in place and some of these larger transactions you've done, when you think about 2026 -- I don't know, pick whichever case you want to do or just sort of give an average, like how much of your '26 activity do you think is underpinned by -- this guidance is underpinned by enhanced governance, where you've got some reasonably good predictability?

I'm not sure I have that number off the top of my head, Scott, but we can get back to you on that. Jim is saying he thinks it's around half.

Yes.

Okay. Okay.

Yes. But what I'd say is this, like, look, we have commodity price triggers in almost all of our large joint development agreements. We haven't hit those price triggers. So it wouldn't necessarily change an activity. But I'll use an example. In one of the cases, we went to the operator and said we would really prefer to defer this activity because there's a better time. So it's not just them. Sometimes we ourselves would rather push that activity to a future day where it makes more economic sense.

[Operator Instructions] Your next question comes from the line of Noah Hungness of Bank of America.

To start off here, Nick, I was hoping, could you help us quantify maybe what the EBITDA or free cash flow upside would be from the coiled spring that you've spoken about here. I'd assume, let's say, like $65 of WTI?

Yes, I mean, I -- look, I think there's probably -- it's a bit interesting because right -- I think every $5 a barrel is something like $100...

No, it's about $100 -- between the low and the high, is that what you asked?

Yes.

Yes, it's probably about $100 million to $150 million.

But if you factor in, call it, $5 a barrel, right, you're talking -- that's another $150 million. So that's why in my prepared comments I talked about that. Yes, sort of a low case maintenance capital, which obviously generates more cash at today's strip, and a high case, which actually would generate less, albeit that's an averaging effect because when you look at the annual numbers versus obviously where we're expecting sort of that stuff to come in gradually, you may kind of on a terminal basis look a lot different. But you make the assumption that in the $65 world, which is about $5 delta on the strip today, that's $130 million to $150 million a year of extra cash for us alone. And so where I would go with that is that -- that change means that your free cash flow may be the same or even superior in the high case just because you're -- that's happening in a slightly better environment.

That's helpful. And then for my second question is, in the low versus high activity scenarios, could you maybe talk about how much of the CapEx is related to ground game spend versus your just standard D&C?

Yes. Give me one second. So you're looking at about $150 million to $200 million between the 2.

[Operator Instructions] Mr. O'Grady, there are no more questions in the queue. Do you have any closing remarks?

Yes, please. Thanks. Thanks for joining us today. NOG is well positioned to navigate through the current market volatility. Our assets are performing well. Our liquidity is abundant, and our investment opportunity set remains strong. We're grateful for being aligned with strong and capable operators, and look forward to keeping you informed on our activities and achievements in the coming weeks. Thanks again.

This concludes today's conference call. You may now disconnect.

Welcome to the Northern Oil and Gas, Ohio Utica Joint Acquisition Call. I'll now turn the call over to our host, Evelyn Infurna, Vice President of Investor Relations at Northern Oil and Gas.

Thank you, operator, and good morning, everyone. Earlier today, we announced an Ohio Utica joint acquisition with Infinity Natural Resources for $1.2 billion of which NOG's interest is 49% or $588 million.

On the call today are Nick O'Grady, NOG's CEO, who will share his thoughts about the strategic value of the acquisition; Adam Dirlam, NOG's President; and Jim Evans, NOG's Chief Technical Officer, who will discuss the structure of the joint acquisition and the unique nature of the asset, respectively.

We will not be taking Q&A on this call but are available at any time today, December 8 and over the coming days to discuss details with you. Please feel free to reach out to me to schedule a meeting with the team.

I'll now hand the call over to Nick.

Thank you all for joining today's call. I'd like to begin by outlining the strategic rationale behind our latest transaction. NOG is focused on executing deals that add long-term value to our platform. Partnering with Infinity Natural Resources to acquire a significant stake in the Ohio Utica assets is a testament to our commitment to growth and resilience. This transaction is the largest in our history and further strengthens our Appalachian portfolio, providing vertical integration and a clear visible growth path well into the next decade.

Alignment with Infinity sets the stage for a successful partnership, enhancing shareholder value and positioning NOG as a leader in nonoperated working interest in premier hydrocarbon basins. This asset features 35,000 acres net to NOG over 100 dose identified undeveloped locations with significant running room for expansion and approximately 65 million cubic feet per day equivalent of first year expected production. This production base is extremely low decline, rich in liquids at high margin and with a single rig program is poised to grow at a 30-plus percent CAGR well past the end of the decade just on what is identified today.

With an estimated breakeven price below $2 per MMBtu, this asset immediately competes with this partnership's capital and will prove to be resilient throughout the cycle. We are equally excited about the midstream, comprised of over 140 miles of low- and high-pressure gathering pipelines. The system was built to handle a larger amount of volumes which will reduce the near-term capital needs of the asset. And importantly, it materially improves control and margins by owning both.

Time and time again, we talk to our investors about being focused on the long term about being strategic in nature about focusing on resiliency and returns. This asset checks all those boxes. It will grow. It is resilient to low price environments, and we see multiple avenues on the development side for better cost and performance and other synergies with our partner, INR.

And finally, as always, the key is not just short-term accretion or simple multiples, but multiyear high-return growth that will drive NOG's profits per share for the long run on a risk-managed basis and a focus on driving total return.

In terms of funding the transaction, as we discussed during our third quarter results, we have taken significant steps to prepare for this throughout 2025, building a war chest of liquidity, enhancing our maturity wall and extending our bank facility. With that bank extension, we were able to meaningfully lower our cost of borrowings. By executing on interest rate swaps, we will both lower as well as fix those rates. And as a result, we were able to use a very low mid-single-digit cost of capital to purchase these assets, which will accrete directly to the shareholder without adding undue risk.

While leverage will increase modestly in the short term, as the asset grows and converts to generating free cash flow, NOG will see a steady reduction in its leverage ratios in the coming years. A prudent hedging strategy has been undertaken and is ongoing to derisk the balance sheet and these assets further by adding basis hedges, swaps and 2-way collars as far out as 2029.

With the addition of this asset, NOG now owns over 90,000 acres in Appalachia with decades of inventory, positioning the company to participate in the growing demand for gas.

With that, I'll turn it over to Adam.

Thanks, Nick. The Utica transaction is another example in our track record of executing on large-scale accretive investments, marking our fifth major joint acquisition and our largest in company history. While we're getting milestones in terms of individual acquisitions, NOG continues to become even more diversified across commodity and resource plays. This is a testament to NOG's unrivaled and scaled nonoperated business model, with a total addressable market spread across the entirety of the upstream E&P industry and now making inroads into the midstream space.

Given the number of opportunities available to us, we have the unique ability to be selective, only targeting assets that will compete for capital in an organization with deep low breakeven inventory and peer-leading returns. The Utica asset checks those boxes, and we are eager to partner with another technically superior operator with Infinity as they drive operational synergies. This joint acquisition comes with the same alignment and governance that we're accustomed to, including our longest drilling commitment to date given the multiyear inventory on the asset.

In addition to the drilling commitment, we've established our customary area of mutual interest, providing an avenue to extend laterals, grows up our interest and further drive returns. Our enhanced informational rights will only bolster NOG's proprietary intelligence platform developed to maximize data and accelerate decision-making while ensuring scalability and precision.

As Nick mentioned earlier, our Utica acquisition brings NOG's Appalachian position to the forefront at over 90,000 net acres, representing a 60% increase and puts NOG squarely in the macro tailwinds of growing demand driven by data centers and LNG exports.

With that, I'll turn it over to Jim.

Thanks, Adam. The acquired assets are located in the core of the Utica play in Monroe, Noble, Guernsey and Belmont Counties in Eastern Ohio and include approximately 35,000 net acres. The acreage spans the condensate, rich gas and dry gas windows providing us with commodity optionality. There are currently 255 producing wells with a sub-15% first year decline rate. We have identified over 100 gross long-lateral undeveloped locations that breakeven below $2 per MMBtu, providing nearly a decade of high-quality development and growth at a 1-rig pace.

There's all significant opportunity to grow the footprint over time, adding potential locations along the development plan with an annual CapEx spend of around $100 million, inclusive of land capital, the asset is expected to average approximately 65 million cubic feet equivalent per day in 2026 and grow at a 30-plus percent CAGR through the end of the decade. As we mentioned, the acquired assets also include an integrated midstream system that consists of approximately 104 miles of low- and high-pressure gas gathering lines along with 6 compressor facilities with throughput capacity of 600 million cubic feet per day, the system is built to support multiyear growth on the asset as well as provide an opportunity to generate additional revenue from third-party gathering.

The system has direct access to REX Zone 3, providing enhanced gas realizations. The midstream system also includes approximately 90 miles of water lines and 12 water storage facilities. The system helps lower breakeven costs by $0.70-plus per Mcf to reduce operating expenses as well as development costs. In addition, these properties offset Infinity's nearby Guernsey assets, which should create additional synergies on the asset and lower breakeven costs even more.

I'll now turn the call back over to Evelyn.

Thanks again for joining this morning. We look forward to speaking with you. Please reach out to me at [email protected] to schedule a follow-up call. Thanks again.

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

Good morning. Welcome to NOG's Third Quarter 2025 Earnings Conference Call. Yesterday, after the close, we released our financial results. You can access our earnings release and presentation in the Investor Relations section of our website at noginc.com. We will be filing our September 30 10-Q with the SEC within the next few days.

I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; our Chief Financial Officer, Chad Allen; and our Chief Technical Officer, Jim Evans.

Our agenda for today's call is as follows: Nick will provide introductory remarks, followed by Adam, who will share an overview of NOG's operations and business development activities, and Chad will review our financial results. After our prepared remarks, the team will be available to answer any questions.

Before we begin, let me remind you of our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that have been described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliation of these matters to the closest GAAP measures can be found in our earnings release. With that, I'll turn the call over to Nick.

Thanks, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. I will, as usual, provide you with some highlights on our outlook and 5 quick points. Number one, the business remains very solid. Our activity remains stable. Our D&C list has continued to march on with high-quality, low breakeven activity, and we remain on target for the year and expect a strong exit into 2026.

Number two, we and many of our operators have been cautious and disciplined with our drilling capital. We have explained that being return-driven versus growth driven means we will react accordingly and be judicious with how we allocate our capital. So far, given the commodity complex, this strategy has proven to be sensible. This allows us to preserve our growth inventory and capital for periods where we can maximize value for our investors and ramp aggressively when it's appropriate in the cycle. Yet we've also grown our gas volumes into a stronger backdrop as we allocate capital accordingly.

Number three, it also means we can focus some of our capital for long-term value creation. We have never been busier on the BD front ever. We have been clear that our priorities are focused on creating long-term value, and we believe that disciplined long-term strategic opportunities are best suited in this environment to create value. Our recent minerals and royalty deal typifies this strategy, adding long-term growth, low-risk assets into the portfolio that will prove highly resilient to short-term gyrations in the commodity market.

Number four, we've been purposely tactical in regards to our capital stack. The balance sheet management we have undertaken may not be fully appreciated yet, but it is critical to how we navigate the current marketplace. With a tack-on to our convert earlier this year, our recent bond and tender transaction and the recent extension of our bank facility, we will see some substantive benefits to the corporation. In the current pace, we will exit 2025 with potentially more than $300 million of additional liquidity as compared to the beginning of 2025. We will also see a further reduction in interest rates with our new RBL terms. We've entered into interest rate swaps to further reduce those rates and can increase this amount if warranted. The extra cash flow, the substantial increase in liquidity and the longer tenure of our debt maturities continues to set us up to pounce on countercyclical investments as we intend to.

Number five, we continue to actively manage other risks such as commodity exposure. You'd be hard-pressed to find a better hedged company than ours. This actively managed hedge program allows us to better navigate the typical commodity cycle. This practice is another factor that protects our business and allows us to continue to take the offensive through trough periods.

In summary, the business remains solid as a rock. Inorganic opportunities are more robust than ever, and we've taken substantial steps on the risk and capital management front to ensure our ability to take advantage of any cycle. We firmly believe that NOG has more growth and value-creating prospects than the bulk of the upstream sector, and we look forward in the coming quarters and years to proving this thesis to our investors.

Thank you for your interest in our company. And with that, I'll turn it over to Adam.

Thank you, Nick. I'll touch briefly on the operational results for the quarter and then turn to our ongoing business development efforts. Operationally, our assets continue to outperform internal expectations, and we saw this across all of our respective basins. As a result, we've increased annual production guidance while tightening CapEx for the year. While expected turn-in-lines came in slightly under forecast as certain wells were deferred to the fourth quarter, production outperformance was driven by a number of different factors. Notably in Uinta, upsized completion designs have increased overall productivity relative to internal estimates. While in the Williston, we've seen outperformance on recent TILs and much better execution on refracs as operators continue to refine designs.

As it pertains to activity levels, the Permian accounted for about 2/3 of our organic activity, while the Williston and Appalachia evenly made up the remainder of wells that were brought online. Drilling and development activity was also consistent, slightly building our wells in process, adding additional low breakeven backlog and setting up for a strong finish into year-end.

Relative to prior quarters, we are seeing a more balanced C&C list as the Permian now makes up 40% of our wells in process, while the Appalachia, Williston and Uinta each make up roughly 20% of the total.

New well proposals and election activity have also remained consistent as we received over 200 well proposals and consented to over 95% of AFEs balloted in the quarter. Year-to-date, we have seen 160 more proposals than what was balloted through the same period during 2024. Expected returns remain well above our hurdle rate, further bolstered by a 10% increase in lateral lengths, driving down normalized AFE costs by nearly 5%.

In addition to the longer laterals, NOG's operators continue to see downward pressure on service costs for both drilling and completing, which has been encouraging. We should see those operational efficiencies materialize through Q4 and into 2026.

Turning to our business development efforts. Q3 was one of the busiest periods in company history as we screened more than 14 large asset transactions and over 200 ground game opportunities, up over 20% relative to the second quarter. While our scaled business model provides more acquisition opportunities than any other in the E&P space, we remain focused on only the highest quality assets and will strictly adhere to our stringent underwriting requirements.

As we previously announced, in August, NOG closed on a royalty and mineral interest acquisition in the Uinta that included 1,000 net royalty acres across 400-plus gross locations, excluding the additional inventory that is not currently in our development plan. This is a prime example of how NOG leverages its proprietary database and asymmetric knowledge to capitalize on opportunities in an inefficient market. This acquisition increased NOG's average effective NRI from 80% to 87%, covering the entirety of our Uinta position and further lowering our breakevens in one of the fastest-growing basins in the Lower 48.

Our ground game remains as active as ever, closing 22 transactions, executing on 3 trades that high-graded our acreage position and signing a joint development agreement that covers 7 additional extended lateral spacing units. As a result, we added over 2,500 net acres and an additional 5.8 net wells during the quarter, bringing year-to-date ground game additions to over 6,000 net acres and 11.6 net wells across 50-plus transactions in all of our respective basins.

NOG's diverse holdings across both oil and gas has provided ample opportunity to deploy capital in both near-term drilling opportunities as well as longer-dated inventory. This has given us the ability to navigate the dynamic competitive pressures that have changed throughout the year.

While the broader M&A market has been relatively stagnant across the sector and a lower commodity environment, our unique position counters that thesis, and we do not see things slowing down for NOG. However, the landscape has changed from historical trends. In the past, the large majority of opportunities were concentrated in the Permian. And while we continue to see those prospects, we are seeing a myriad of high-quality potential deals spread across a greater number of basins.

Currently, we are screening 8 transactions with a combined value of over $8 billion across operated, non-operated and joint development structures. Additionally, we've been able to approach a number of these assets with various structures, providing optionality to the seller that also works for us. Regardless of the environment, we will remain steadfast in our approach to underwriting and focused on high-quality assets that will generate superior returns for our investors and stakeholders.

With that, I'll turn it over to Chad.

Thanks, Adam. NOG's diverse and scaled platform continues to deliver in the face of a challenging macro environment and well performance continues to exceed internal expectations across all of our basins. Third quarter total average daily production was approximately 131,000 BOE per day, up 8% versus Q3 of 2024, and down 2% from Q2 2025 as expected, reflecting the low point for net well additions in 2025 at 16.5. It is important to note that 1/3 of those net wells came online late in the quarter, providing momentum into the fourth quarter.

Oil production was approximately 73,000 barrels of oil per day, up 2% from Q3 2024, and down 6% sequentially. Gas production continues to ramp as our gas joint drilling program is on a consistent monthly TIL phase. Once again, we had record gas volumes of approximately 352 MMcf per day, up 15% from Q3 2024, and up 3% from Q2 2025. With the expectations of adding between 23 and 25 net wells in the fourth quarter, heavy late net well additions and well outperformance in Q3, we have increased our annual production guidance to a range of 132,500 to 134,000 BOE per day.

Moving on to our financial results. Adjusted EBITDA in the quarter was $387.1 million, and free cash flow was $118.9 million, marking our 23rd consecutive quarter of positive free cash flow, exceeding $1.9 billion over that time period. We reported a net loss of $129 million in the quarter, which reflects the previously disclosed noncash impairment charge of $319 million. Our adjusted net income was $102 million or $1.03 per diluted share in the quarter. Oil differentials averaged $3.89 per barrel as we saw improved differentials across all of our oily basins. Natural gas realizations were 82% of benchmark prices, consistent with Q2 2025, due to ongoing Waha market weakness and was also impacted by lower NYMEX natural gas prices.

Lease operating costs per BOE were down marginally from Q2 2025, despite lower oil volumes. We did see some relief on saltwater disposal costs, but we are still seeing steady expense pressure from workovers. Given the higher run rate year-to-date and the expectation of continued workovers, we have increased annual guidance on LOE. We have also revised guidance on production taxes to a lower run rate given year-to-date actuals and anticipated production mix in the fourth quarter.

CapEx in the quarter, excluding non-budgeted acquisitions and other, was $272 million, reflecting an active quarter on the ground game as discussed by Adam earlier. Overall, the $272 million was allocated with 49% to the Permian, 25% to the Williston, 5% to the Uinta, and 21% in the Appalachian Basin. Approximately $212 million of the total spend in the quarter was allocated to organic development CapEx. With the history of 3 quarters behind us, we have tightened our full year CapEx guidance to a range of $950 million to $1.025 billion.

At the end of the quarter, we maintained approximately $1.2 billion in liquidity, consisting of $32 million in cash and over $1.1 billion available on our revolving credit facility. We have been actively managing our balance sheet throughout 2025, including since quarter end. In October, we raised $725 million of notes maturing in 2033 with a coupon of [ 7.875% ]. We used those proceeds to retire nearly all of our notes maturing in 2028 that have a coupon of [ 8.125% ]. Earlier this week, we amended and restated our revolving credit facility, which extended the tenure to 2030, and markedly improved our pricing grid by 60 basis points, significantly reducing future interest costs.

The credit facility's elected commitment amount and borrowing base remained unchanged. These transactions together extended the weighted average maturity on our debt from approximately 3 years to 6 years. Importantly, we have no major maturities until 2029.

That concludes our prepared remarks. Operator, please open up the line for Q&A.

[Operator Instructions] Your first question comes from the line of Charles Meade with Johnson Rice.

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

Yes. I mean I think what you see in the industry is probably what you'll see for us at this point. I mean I think we haven't seen much change in activity since the prior quarter, which has been relatively flat. And I think that's generally what we would expect as we head into next year. The activity has been very, very stable. I think the commodity outlook may change, and that may change that. And I think that that's why I think things certainly can change as we head into next year. And I think that's why we tend to wait later to guide because I think, frankly, the -- I think if oil prices were to change materially between now and next year, obviously, activity may change as well.

But I think as it stands today, I think what we've said and I'd say it would be consistently would be that to maintain an outlook, I think, on the oil side, similar to where we are this year for our annual guidance, it would require a budget lower. I think in any scenario, and I'm referring to oil volumes, I think we're going to see material gas growth next year. I think if we spend a budget similar to this year, we would see probably growth in both commodities.

And so I think the question will really be what's appropriate, right? And I think, obviously, we're watching the commodity outlook. And as I mentioned in my prepared comments, we're very much return-driven. And I think it's going to be a combination of operator behavior, project optionality and things that we see on the ground and where we want to allocate our capital accordingly. I don't know, Adam, if you want to add to that.

Yes. I mean, obviously, everything is going to be driven by breakevens. If we're looking at kind of what our backlog looks like here, we've got a healthy Permian backlog. I think the interesting thing that we've seen in the quarter, especially with the AFEs is on the Williston side, you're seeing kind of weighted average AFE lateral lengths, almost 14,000, 15,000 feet, and that's spread across a multitude of different operators. And so I think that's obviously helping bolster some of the expected rates of return that we're seeing there, lowering normalized well costs and helping again to bolster the expected rate of returns in the basin.

Yes. And I guess the only other thing I would add to it is that, as I mentioned, the commodity outlook could change. I think, depending on what happens with the gas environment next year as well, I think in any -- I mean, based on where we are today, I think we're going to see substantial growth in gas next year one way or the other. But that could grow even further, obviously, if the gas market explodes next year, we're going to see additional organic growth on our assets. And so that's another source of capital that could change, and we then proactively could obviously on the ground allocate additional capital there as well.

Got it. That is helpful color on your thinking. And then if I could just focus in on 4Q, your -- 4Q '25, your annual guide suggests that you guys are going to be -- we're going to see sequential growth in 4Q. And Chad, I think I heard you say on your prepared comments that you've got 23 to 25 net wells that are supposed to be online in 4Q. So I wonder if you could just give us an update. We're here in whatever, the first week of November, how many of those wells have already come online? And are those wells -- whether those TILs kind of front-end loaded, evenly loaded, back-end loaded? Just talk about where you are in that process to give you confidence on that implied 4Q volume bump.

I think, Charles, where we are right now, we're right on track. I'd also add that a good portion of -- remember, well completions, the well takes an IP doesn't really mean very much. It takes 30 days usually for a well to clean up and be fully producing. So if a well comes online in October, its contribution to the quarter is important, but it's not massive. A good portion of -- it's a lot of the late Q3 deals are going to have some of the biggest impact for Q4, and that's the driving confidence for us in this quarter. So the early Q4 and late Q3 wells, which we've -- many of which have already transpired are really what drove our guidance increase as well as the base production outlook, which is really the big driver of our production increase for the year and for the base volume increase as we said. And so we're going to have really strong production as we head into early next year.

Your next question comes from the line of Scott Hanold with RBC.

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

Well, let's see here. I mean in terms of the robustness of the backlog, I'd say -- the one comment I'd make is, it's a lot broader than it's been. I think if you go back a few years ago, it was very Permian-centric. Scott, it was very much driven by private equity firm life and you had a lot of assets being monetized after a long period. And so I think that now you're seeing what we see now is a really broad and robust backlog of multi-base stuff.

Your next question comes from the line of Neal Dingmann with William Blair.

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

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

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

Well said. And then just, Nick, for you, Adam, just a follow-up on M&A. Two questions on M&A. First, seems like you have a fair amount of assets that I don't know if you're getting full credit for. Are you always considering as part of the M&A strategy? Is monetizing anything? Is that in the game plan? I haven't asked you that in a long time.

And then secondly, with the opportunities you're seeing out there, you talked about ground game or deal flow looks as good as ever. Is it a mix? Are you seeing the potential for large deals like whatever, the SM Vital deals that you've done in the past for all these mostly small deals? What are the types of opportunities you're seeing?

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

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

Your next question comes from the line of Scott Hanold with RBC.

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

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

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

Yes, I can kick it off and then hand it over to Jim in terms of decline rate commentary there, but it's across the board with our respective basins. As I mentioned earlier, the Williston in Q3 with AFEs we're seeing 14,000, 15,000 foot lateral lengths, and that was spread across 5-plus operators with 80-plus AFEs that we received during the quarter. We're seeing the same thing in Appalachia and even in the Uinta with the partnership with SM, we're starting to lengthen lateral lengths there as well. And even with the Permian, I think we're seeing some of the longest average lateral lengths that we've seen to date. That obviously puts downward pressure on weighted average AFE -- normalized AFE costs there and then further bolsters expected returns. I think the biggest takeaway that we've seen after observing this over an extended period of time has really been how they've accessed the reservoir, and that's probably where I'll give it to the engineer.

Yes. Thanks, Adam. Yes, like we said, we're seeing operators continue to refine their completion designs, more effectively stimulate the toll of the well and be able to draw down the pressure. What you'll see is they're not going to overdesign the facilities. So you're not going to see a straight ratio going from a 2-mile to a 3-mile where the IP is going to go up by 50%. It's going to go up a little bit. What you're going to find is you're going to find that the well is going to stay flat for much longer and then have shallower declines. Now we typically are a little bit more conservative. And so what we'll see is when we see that IP rate, we'll continue to maintain our prior decline rates until we have more information. That might take 6 to 9 months. And so what we're seeing now is that these wells are holding in there a little bit flatter for a little bit longer. So they're starting to exceed our expectations from what we initially expected. So as we continue to get more information, we'll continue to refine our expectations and our decline curves moving forward.

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

Just following up on the nice progress on the AFE dropping to $806 a foot this quarter versus the $841 last quarter. Can you give us kind of like you did last quarter, where the well cost stands on your current D&C list on a per foot basis?

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

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

2 to 4 is kind of what we're seeing. And operators, particularly the private ones, tend to cycle that, right, from a lease maintenance standpoint. And so I don't think we necessarily see that appreciably changing at this point.

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

Just wanted to quickly touch on AFEs. You talked about a 5% sequential well cost reduction, noting lateral length, but was there anything else in those numbers? And I guess, any other contributions and any opportunity that you see for kind of continuing that trend?

Yes. I mean, Paul, our observation has been that the bulk of cost savings of late have been through that lateral length and efficiencies. We haven't seen a huge step down in service costs. In fact, as we've talked about in LOE, I think in general, as a trend, inflation is real, right? And so you're combating that with drilling -- shaving days and drilling longer laterals as a way to try to cut costs. I think in order to see material savings at the well level and to see huge cuts, my personal opinion is you're going to have another step down in overall activity. So if God forbid, oil prices take another material step down in prices and we see another drop in the rig count, I would think you're going to see big concessions.

The one thing I will tell you is we've had conversations with some of our really large operators, and a lot of them are talking about, for lack of a better term, vendor management. And what they're doing is generally, they have allowed their field teams at an individual basin level to manage their -- to manage which vendors they use, and they're now looking to sort of centralize that and go to, say, 9 vendors instead of the 50 or 60 that they have as a way to try to get bargaining power. As that filters through, that may be another source of cost reductions over time, but time will tell.

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

Yes. And this is -- we are going into budgeting season. We are going into a new year in which theoretically contracts would be turning. And so it may be a period in which we start to see some cost relief. But again, time will tell.

Got it. Makes sense. Just a quick follow-up more on the -- more holistically. You talked a bit about refracs. Can you talk about any shift in activity here you've seen over the last several quarters that's on the horizon? It's been pretty topical as of late.

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

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

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

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

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

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

Yes. The only other thing, I guess, I'd add is stacked pay co-development, are you drilling 2 wells on a pad? Or are you drilling 12? And the spud to sales timing is going to be wildly different between kind of those 2 scenarios.

No, that's helpful color. As for my second question, based on 3Q results and the updated '25 guide, going back to kind of thinking about an implied 4Q oil production, the range is pretty wide. So could you help us think about maybe some of the moving parts there that could put you at the midpoint or below or above in that range?

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

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

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

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