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April 29, 2026 at 9 a.m. ET
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Northern Oil and Gas (NYSE:NOG) reported sequential record production with a 6% increase in average daily volumes and closed the quarter with robust balance sheet liquidity exceeding $1.2 billion. The company closed a record 41 ground game deals, enhancing its leasehold footprint and future drilling opportunities across all operational basins. While exposure to volatile oil pricing drove a substantial $521 million noncash derivative loss, management emphasized effective risk mitigation through proactive hedging and a healthy capital allocation mix. NOG is currently evaluating over $10 billion in large M&A opportunities, reflecting an improved asset quality pipeline in a heating transaction market.
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.
Nicholas O’Grady: 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.
Adam Dirlam: 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.
Chad Allen: 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: [Operator Instructions] And your first question comes from the line of Neal Dingmann with William Blair.
Neal Dingmann: 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?
Nicholas O’Grady: 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.
Neal Dingmann: 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?
Nicholas O’Grady: 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.
Operator: And the next question comes from the line of John Davenport with Johnson Rice.
John Davenport: 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.
Nicholas O’Grady: 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.
John Davenport: 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.
Nicholas O’Grady: 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?
Adam Dirlam: 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.
Operator: And the next question comes from the line of Paul Diamond with Citi.
Paul Diamond: 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?
Nicholas O’Grady: 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.
Paul Diamond: 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?
Nicholas O’Grady: Being an expert, I’ll leave it to you.
Adam Dirlam: 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.
Nicholas O’Grady: 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].
Operator: And the next question comes from the line of Noel Parks with Tuohy Brothers.
Noel Parks: 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?
Nicholas O’Grady: 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?
Adam Dirlam: 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.
Noel Parks: 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?
Nicholas O’Grady: 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.
Adam Dirlam: 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…
Nicholas O’Grady: 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.
Adam Dirlam: And then what are we looking at relative to what’s in our own backyard.
Nicholas O’Grady: 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…
Adam Dirlam: Compete.
Nicholas O’Grady: Compete it, that’s right.
Operator: And the next question comes from the line of Phillips Johnston with Capital One.
Phillips Johnston: 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.
Chad Allen: 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.
Phillips Johnston: Okay. Okay. So that makes sense. It’s basically the same…
Chad Allen: Yes. For accounting purposes, it’s got to be treated for the bank’s counterparty election date.
Nicholas O’Grady: But it’s not really how it works.
Chad Allen: 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.
Nicholas O’Grady: It’s a nothing burger to be candid.
Chad Allen: Yes, it is.
Operator: 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.
Nicholas O’Grady: Thanks very much for your time this morning. We look forward to talking to you in the coming weeks. Appreciate it.
Operator: Thank you. And ladies and gentlemen, this concludes today’s call. You may now disconnect.
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