Northern Oil and Gas, Inc. (NYSE:NOG) Q4 2025 Earnings Call Transcript

Northern Oil and Gas, Inc. (NYSE:NOG) Q4 2025 Earnings Call Transcript February 26, 2026

Operator: 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.

Evelyn Infurna: 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.

Nicholas O’Grady: 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.

Adam Dirlam: 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.

Chad Allen: 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.

Q&A Session

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

Neal Dingmann: 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.

Nicholas O’Grady: 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?

Adam Dirlam: 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.

Nicholas O’Grady: 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.

Neal Dingmann: 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?

Nicholas O’Grady: 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.

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

Charles Meade: 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.

Nicholas O’Grady: 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.

Adam Dirlam: 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.

Nicholas O’Grady: 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.

Charles Meade: 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?

Adam Dirlam: 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.

Nicholas O’Grady: No. I think you nailed it.

Adam Dirlam: 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.

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

Scott Hanold: 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?

Nicholas O’Grady: 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.

Scott Hanold: 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?

Nicholas O’Grady: 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.

Jim Evans: Yes.

Scott Hanold: Okay. Okay.

Nicholas O’Grady: 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: [Operator Instructions] Your next question comes from the line of Noah Hungness of Bank of America.

Noah Hungness: 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?

Nicholas O’Grady: 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…

Adam Dirlam: No, it’s about $100 — between the low and the high, is that what you asked?

Nicholas O’Grady: Yes.

Adam Dirlam: Yes, it’s probably about $100 million to $150 million.

Nicholas O’Grady: 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.

Noah Hungness: 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?

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

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

Nicholas O’Grady: 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.

Operator: This concludes today’s conference call. You may now disconnect.