Greetings and welcome to the NLG fourth quarter 2025 earnings conference call. At this time, all participants are in a listen-only mode. The question and answer session will follow the formal presentation. If you would like to ask a question during this time, simply press star, followed by the number 1 on your telephone keypad. If you would like to withdraw your question, simply press star 1 again. As a reminder, this conference is being recorded. It's now my pleasure to introduce to your host, Evelyn Inferna, Vice President, Investor Thank you. You may begin.

Evelyn Inferna 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 Derlem, our Chief Financial Officer, Chad Allen, and our Chief Technical Officer, Jim 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 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 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. 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 I 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 a 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 defense, 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 two 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 two, 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 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 break-even 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 break-even scenario for an extended 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 draw will generate substantially pushing our high value development for a better. 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 kill 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 a portfolio of 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. 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 return 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 eight 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 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 drops, 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 share. 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. 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 a third of the wells in process, while Appalachia makes up just less than a quarter, 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 spun, with the Permian making up roughly two-thirds of the total. Lateral lengths remain elevated as operators continue to drive normalized costs down and full-screw 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 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 Entero 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 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 counter-cyclical 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 Utica 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 break evens below $2 will be a significant focus as we prosecute development plans and growth volumes beyond 2030. In addition to the 100 plus locations already identified, there's 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're 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 go 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 be delivered, outperforming internal estimates on production and EBITDA for both the quarter and the year. 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 EBIT in the quarter was $367 million and free cash flow was $43 million. For the year adjusted EBITO was $1.63 billion with free cash flow of $424 million. adjustment. 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. Gap 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're evaluating 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 average $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 costs 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 Uwenta, and 22% to the Appalachian Basin. Possibly $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, in the first quarter of 2026, have been busy as we took a number of actions to enhance liquidity and 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 Unica acquisition to our asset In October, we issued $725 million of notes with a 7 and 7 eighth coupon and we tied nearly all of our 2028 notes with an 8 and 8 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 4th. After closing our joint Utica acquisition earlier this week, we have over a billion dollars 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 two ranges that capture potential production, operating expenses and capex in a low activity environment and a high activity environment. For details considered in 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.

The floor is now open for questions. If you have dialed in and would like to ask a question, please press star 1 on your telephone keypad to raise your hand and join the queue. If you would like to withdraw your question, simply press star 1 again. If you are called upon to ask a question and are listening via loudspeaker on your device, please pick up your handset and ensure that your phone is not on mute when asking your question. And we do request for today's session that you please limit yourself to one question and one follow-up. Your first question comes from the line of Neil Dingman of William Blair. Your line is open.

Morning, Nick. Nice details for you in the game today. Nick, my question, you, I think it was last night, 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 is to when these wells are finally drilled and completed? Is it just a matter of, you know, when, not if, or maybe talk about why we're seeing that today?

That's right, Neil. As Adam also noted in his comments, we have a large CNC list and about 13 net wells we consented to that still haven't been spud. We sometimes have given kind of specific 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 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 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 job, We have seen periods of time where we have had to bring forward accruals. You know, we've had, ironically, we're talking about not spending enough money, but we've had periods where, you know, our CapEx has been accelerated, and we've seen those things move really quickly. So that 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, specifically oil. And, you know, what I would tell you is that we look a little bit different. You know, if you're a, you know, when you compare us to, say, an operator, and you're comparing, look, I recognize estimates and all these things and changes out of the Optical capital efficiency, you know, whereas an operator targets a maintenance level of production and then tries to spend, 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, you know, we're managing, you know, 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 – it's been committed comes to – I guess the only other additional color that I'd add, I think we alluded to it in the prepared remarks, but you've got about two-thirds of those 13 wells in the Permian.

And if you're looking at kind of half cycle expected returns, you're looking at 40, 45 percent, you've got 230, 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.

Yeah, and that's the point is that I don't think this is a fund for private operators. It's not a question of whether they can make money on it. It's a question of whether 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.

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

Yeah, 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 markets, prepared comments, excuse me, that we have been evaluating a lot of different outcomes. And without, you know, 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. Yeah, I'd love to hear that. Yep.

Your next question comes from the line of Charles Mead of Johnson Rice. Your line is open.

Yes, good morning, Nick, to you and the whole team there. 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 I mean, there's a obvious – yeah, go ahead.

Yeah, 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, you know, we are dealing with the fog of war, and like I said, you know, people, you know, 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, too, 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, you know, can fill that gap. You know, the other thing I'd point out is, you know, 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 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 would 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, you know, again, we've tried to take a pretty, you know, one of the things that I would point out in the high case, which is that, you know, 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 until later in the year, which is why the oil volumes might up. 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, you know, but I will give some comfort, which is that either one of these scenarios in effect are maintenance capital levels you're talking about. So my point being that to the extent we spend more in that gap, even if we do see the lows, and those dollars right now are kind of in between.

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

Yeah, and, you know, the one – I'll just leave one thing because I think optically, you know, 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 those scenarios is considered to be relatively evenly weighted. That front is driven by ground game, atypical success.

That's good detail. Thank you for that, Nick and Adam. Yeah, you bet. Second question to drill down on Appalachia. So that 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 assume 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 can you give us any, I know it's early, but anything incremental what you're seeing with the joint infinity assets?

Yeah, 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, you know, 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, you know, as we perceive on the Ford case and the Antero. In case of the Antero assets, you know, I would say you can see it in the purchase price adjustment that we've obviously had a strong, you know, it performed strongly prior to us taking possession So that's important. I think as pertains to the legacy assets, they continue to surprise, you know, they just earn. We've seen both timing and performance.

I think you nailed it.

The question comes from the line of Scott Handel of RBC. Your line is open.

Yeah, thanks. Hey, Nick, you know, thinking about the, I guess, the high-key flow fees, can you give us a sense of where some of the uncertainty is more on the private operating system?

Look, we've covered the timing of it, as you've always known in our business model, it's harder to do in some ways because you think some of the enhanced governance, you

know, when you think about 20, I have that number up.

We haven't hit those. We would really prefer to defer this activity because these, you know, and so it's not just them sometimes. Sometimes we ourselves today where it makes more economic sense.

Understood. Appreciate it. Yeah, you bet.

And again, if you have a question, please press star 1 on your telephone keypad to join the queue. Your next question comes from the line of Noah Hungness of Bank of America. Your line is open.

Morning. To start off here, Nick, I was hoping, could you help us quantify maybe what the EBITDA or pre-cash flow upside would be from the coiled spring that you've spoken about here? Let's say like 65 WTI.

Yeah, I mean, look, I think there's probably, it's a bit interesting because, right, you know, I think every $5 a barrel is something like, you know, a hundred.

No, it's about a hundred. Between the low and the high, is that what you're asking? Yeah, it's probably about $100 to $150 million.

But if you factor in, you know, call it, you know, $5 a barrel, right, you know, you're talking that's another $150 million. So that's why, you know, in my prepared comments I talked about that, you know, So you have 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, you know, when you look at the annual numbers versus obviously where we, you know, where we're expecting, terminal bases look a lot different, but you make the assumption that in a $65 world, which is about $5 delta on the strip today, you know, that's 130 to $150 million a year of extra cash for us alone. And so where I would go with that is, you know, that change means that, you know, your free cash flow may be the same or even superior in the high case just happening in SLA.

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

So you're looking at about $150 million to $200 million between the two. Thank you, guys.

And again, if you have a question, please press star 1 on your telephone keypad. 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 notice