Prepared remarks
Greetings, and welcome to the NOG Fourth Quarter 2025 Earnings Conference Call. As a reminder, this conference is being recorded. It's now my pleasure to introduce you to your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.
Good morning. Welcome to NOG's Fourth Quarter and Year-end 2025 Earnings Conference Call. Yesterday after the close, we released our financial results. You can access our earnings release and presentation in the Investor Relations section of the website at noginc.com. We will be filing our 2025 10-K with the SEC within the next few days. I'm joined this morning by our Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; our Chief Financial Officer, Chad Allen; and our Chief Technical Officer, Jim Evans. Our agenda for today's call is as follows: Nick will provide introductory remarks, followed by Adam, who will share an overview of NOG's operations and business development activities, and Chad will review our financial results. After our prepared remarks, the team, including Jim, will be available to answer any questions. Before we begin, let me remind you of our safe harbor language.
Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause the actual results to be materially different from expectations contemplated by our forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliations of these measures to the closest GAAP measures can be found in our earnings release. With that, I'll turn the call over to Nick.
Thank you, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. I'd like to take the time to reflect upon 2025, discuss our plans for 2026 and also share my views in regard to the macro oil and gas environment and how it may affect our company and strategy. While our equity total return was down in 2025, our adjusted EBITDA was actually up 1%, and this was with oil prices down some 14% on average. Our share count was 2% lower year-over-year, our net debt was down modestly year-over-year, all of this despite closing over $340 million of acquisitions, including Ground Game. Our financial results are a testament to our consistent hedging and the decisions we made regardless of market perceptions in the short term, which are manifested in multiple compressions. We were judicious and strategic on how we deployed and allocated capital in 2025. Our natural gas spending increased dramatically and our oil spending declined.
NOG is now seeing record natural gas volumes aligned with some of the highest seasonal prices seen in many years, and we and our operating partners have tried to deploy the bare minimum on the oil front to preserve our precious barrels for a better day. Our 2025 ground game focused more on long-term development versus drill bit projects given the fluctuating 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 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 pushed and preserved high-value development for a higher price environment. Geopolitical noise in the short term has a lot of people guessing, but fundamentals are set to improve. We've heard investor rumors that somehow our dividend could be in question. I'd like to address that directly as we think this chatter is totally unfounded.
While nothing in life is ever completely certain, our dividend is built for an even significantly weaker environment than we face today, where we would ultimately be at a cash flow breakeven level during the trough of the cycle post-dividend. And we believe that our dividend can be sustained for many years, even though we don't believe that oil cycles work in a way that we will be in a breakeven scenario for an extended period. We built our dividend to last and ultimately to grow through cycles. So while we, of course, must manage risk, we are dedicated to sustaining and growing our dividend over the long term, and we believe the attractive yield it provides today is a great opportunity, particularly at the trough of the energy cycle. Our macro view and the belief oil's trough is coming will pivot the execution of our ground game in 2026 from leasing, in some cases, to drill-ready projects.
Organic activity, as always, will be dependent on short-term commodity prices, but our ground game capital deployment will be targeted on investments that will create the coiled spring growth effect our investors saw in 2021. What we're seeing in real-time is that drill-ready projects, something we saw as mostly unattractive in 2025, are slowly becoming a much better place to be. While leasing remains active as we focus on the long term, the ground game will definitively evolve in 2026. I'll let Chad and Adam cover this further, but our guidance is reflective of the marketplace. In our low activity scenario, we do see some reduction in oil volumes, but a much more dramatic reduction in spending. In that low activity scenario, we'll generate substantially larger amounts of free cash flow at today's strip while deferring and pushing our high-value development for a better environment. In the higher case scenario, we'll see some acceleration of activity, a reduction in the curtailments we've carried for some time and a higher TIL count.
While free cash flow would be lower at today's prices, it certainly would also drive higher future production. And of course, in this environment, it's quite possible that the overall pricing environment would wind up being much higher. Our ground game can play a major role in the in between of these scenarios regardless of the environment, where opportunities may arise for us to deploy ad hoc capital throughout the year, and we expect and hope to do so, especially in a tougher environment. On the M&A front, we continue to evaluate assets as they come to market. With that said, however, we are satisfied with the portfolio strategic positioning, and moreover, we believe that quality assets that meet our criteria, particularly on the oil front, possibly will only come to market if we see a healthier market price point. So we'll focus our discretionary capital on the ground. In the past several years, we've seen some aggressive new entrants to the smaller deal side of the market, and much of that capital has become sidelined as these parties' prior investments are proving to have been poor capital allocation decisions.
This should now provide NOG with a clear competitive advantage in the current environment. On the development side, it's important to understand the inherent alignment built into our business model. Our operators are rational and the activity we have seen curtailed and deferred will be activated into a healthier environment. Consequently, NOG should see disproportional benefits as the market improves. But what that means is that as the cycle recovers, we create far more convexity to the upside exactly when you're supposed to have it, when prices are stronger. I recognize that our business model may make our journey a bit lumpier when comparing us to a typical operator, but it also has the potential to enhance long-term returns significantly versus a production targeting mindset. NOG has pioneered the large non-op at scale, moving to a broad-based multi-basin, multi-commodity platform over the last 8 years.
We effectively created the large co-purchase partnership and reinvented to some degree the joint development agreement. We're not done innovating and evolving. We are reevaluating how we operate, how we allocate capital and even how we source capital. Over time, the initiatives we are evaluating have the potential to enhance our value creation capabilities, our returns and our business model. So stay tuned for these developments. It's going to be a great year. NOG has a differentiated coil spring-like exposure to the cycle. It could take much of 2026 for the oil markets to fully recover. But as any good investor knows, the market will be well ahead of that. I can't say in my investment career I have seen a period where energy equity saw multiple compression at the same time that oil prices were declining. Cyclical stocks should never be valued at peaks or troughs but at a mid-cycle marginal cost of production.
This leads to multiple compression during high prices and expansion during low prices. We saw such a period during the trough of gas prices in 2024, but that has not happened for oil stocks and certainly not specifically in our case. For our investors and prospective investors, this phenomenon presents a clear opportunity in NOG's shares, especially because NOG has true right-way risk. Our volumes and activity from operators will rise with pricing. I'm extremely excited about how we're positioned and for what lies ahead. Now I'll turn it over to Adam.
Thank you, Nick. I'll start by reviewing the operational details for Q4, what we're observing in the current environment and how we're thinking about 2026 activity levels, followed by our business development efforts and the broader M&A landscape. As a whole, Q4 came in line with expectations as we saw activity ramp exiting the year. During the quarter, we added 24.2 net wells to production even as a number of our operators deferred completions due to commodity pricing. Deferrals notwithstanding, recent results have topped expectations with Appalachia, the top-performing basin relative to forecast, and the Uinta and Williston fast following. Given the accelerated completion activity in the fourth quarter, we saw our wells in process draw down 7.8 net wells, finishing the year with a total of 45.6 net wells. The Permian currently makes up over one-third of the wells in process, while Appalachia makes up just less than one-fourth 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 two-thirds of the total. Lateral lengths remain elevated as operators continue to drive normalized costs 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 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 breakevens below $2 will be a significant focus as we prosecute development plans and grow volumes beyond 2030. In addition to the 100-plus locations already identified, there is potential for incremental value creation from both the undeveloped upstream footprint as well as the midstream fee potential. Looking ahead, there are several large assets in the market right now, something to the tune of $6 billion in total. That said, it pays to be patient as many of those assets are not the right fit for NOG. However, we are expecting a number of potential opportunities coming down the pike that could be of greater interest. All else being equal, we expect the ground game to continue to take center stage as we leverage our proprietary infrastructure and further enhance our portfolio through smaller acquisitions while screening a number of different joint development opportunities.
In this environment and, in particular, the fourth quarter, the team did a phenomenal job taking advantage of the disconnect in the market as operators and the competition exhausted their budgets for the year. In the fourth quarter alone, we were able to pick up over 6,000 net acres and 1.2 net wells across 33 transactions, a quarterly record. The acreage alone represented over 50% of the ground game acreage picked up in 2025, and we finished the year with 12.8 net wells and over 12,300 acres while evaluating over 700 opportunities. We don't see our progress slowing down in the first quarter either as a number of committed transactions are slated to close in the first part of the year. However, most encouraging are the results from our recently acquired acreage that is already getting converted into development. From our acreage acquisitions in Ohio alone, we've seen 14 well proposals with some of the strongest economics across our portfolio.
We'll continue to navigate this environment as we have every other down cycle by staying nimble, allocating resources to the most capital-efficient projects and creating long-dated and durable value for our stakeholders. With that, I'll turn it over to Chad.
Thanks, Adam. Our fourth quarter financial results and production cadence were down the fairway with no major disruptions. And despite the persistent macro headwinds faced by the industry, NOG's diversified and scaled platform continues to deliver, outperforming internal estimates on production and EBITDA for both the quarter and the year. Fourth quarter total average daily production was 140,000 BOE per day, up 7% from Q3 2025 and up 6% versus Q4 2024. For the year, total average daily production was 135,000 BOE per day, topping the high end of our guidance, up 9% as compared to the full year 2024. The outperformance was driven primarily by a continued ramp in our gas assets. Fourth quarter oil production increased 3% to 75,000 barrels of oil per day sequentially, but was 5% lower year-over-year as some of our Q4 wells were deferred as price sensitivity among our operators became more acute.
The ramping of our Appalachian JV drove gas production to record levels for the third consecutive quarter with 392 MMcf per day, up 11% sequentially and up 24% from Q4 2024. For the full year 2025, NOG's oil production was 75,646 barrels per day with gas production coming in at 356 MMcf per day. Moving on to our financial results. Adjusted EBITDA in the quarter was $367 million and free cash flow was $43 million. For the year, adjusted EBITDA was $1.63 billion with free cash flow of $424 million. Adjusted net income in the fourth quarter was $82 million or $0.83 per diluted share, excluding the impact of the $270 million non-cash impairment charge we took in the fourth quarter. For the year, adjusted net income was $453 million or $4.57 per diluted share. GAAP net income was impacted by $703 million in non-cash impairment taken over the course of 2025. As a reminder, NOG accounts for its assets under the full cost method as opposed to the successful efforts method, which does not perform historical price-based asset tests.
Driven by lower average oil prices, we recorded a series of non-cash impairment charges beginning in Q2 under the ceiling test of our full cost pool of oil and gas assets. These impairment charges are not indicative of the quality of our assets. They are merely dictated by weaker oil prices year-over-year. As the cycle recovers, we do not get to write up the same assets that we impaired on the way down. We are one of the only companies among our peers that utilize the full cost method. We are evaluating 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 others, 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, 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 two 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.
Questions and answers
Your first question comes from Neal Dingmann of William Blair.
Nice details again today. Nick, my question is about what you mentioned last night regarding having a notably higher number of wells that have been consented but not drilled yet. I'm curious to know what you or Adam think about when these wells will finally be drilled and completed. Is it just a matter of timing, or could you elaborate on why we're seeing this situation today?
That's correct, Neal. As Adam mentioned in his comments, we have a large drilling and completion program and approximately 13 net wells that we have consented to but have not yet started drilling. In the past, we have provided specific timing guidance for well turn-in-line throughout the year, but we've opted not to do that this year. The estimate for this year ranges from 70 to nearly 90 wells, which is quite broad. We believe it would be unwise to try to predict the timeline, as the situation has been changing significantly in real-time. For instance, many proposals were submitted to us in November and early December, and we've observed notable shifts as pricing softened towards the end of last year and into this year. The recent geopolitical surge in oil prices has not changed this pattern. However, particularly from our private operators, which is important to us, we've historically seen periods where we needed to accelerate accruals.
Interestingly, we are currently discussing not spending enough, yet we have faced times when our capital expenditures have increased rapidly. That could happen again. The situation will largely depend on the risks associated with commodity pricing, specifically oil. What I would point out is that we operate differently. In comparisons to an operator, I understand there are varying estimates and adjustments, and I spend a lot of time focusing on that area. Our capital efficiency is distinct; while an operator aims for a maintenance level of production and seeks to minimize spending to achieve it, they may appear more efficient as prices decline. Conversely, we might seem less efficient because we have committed or accrued capital while dealing with substantial curtailments or deferments. To illustrate, in 2020, we appeared less capital efficient during the downturn compared to other companies. Yet in 2021, we looked much more efficient as all that previously committed capital finally came into play. I’m not sure if that provides enough detail or if you would like to add anything, Adam.
Yes. I guess the only other additional color that I'd add, I think we alluded to it in the prepared remarks, which you've got about 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 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 looks like.
Yes, I believe this isn't primarily about economic conditions. The postponement of activities we've observed is mostly driven by the current economic environment. Particularly for our private operators, the issue isn't whether they can profit, but rather whether they should take action now. They prefer to wait for a more favorable time. I understand that this might impact short-term numbers, but from a long-term perspective, this is about return on investment, and there is greater potential for profit down the line. As the saying goes, you can't consume internal rate of return.
Yes, great details. Nick, could you address the M&A question from a different angle? It seems like despite your significant increase in inventory compared to a few years ago, the stock price doesn’t reflect that growth. Given the current strong seller's market and the favorable prices that ABS players are receiving for mature assets, would you consider selling some assets, even if it’s a small amount, if the market continues to offer good returns?
Yes, we are always looking at potential sales of our assets. We consistently evaluate what is economically beneficial for the company. I mentioned earlier that we have been considering various possibilities, and I want to emphasize that we are quite innovative. That creativity has been evident over time, and we have some ideas that could help address the issues you've raised.
Your next question comes from the line of Charles Meade of Johnson Rice.
Nick, I have a basic question that I want to address. How will you and we know if you're monitoring the low activity scenario or the high activity scenario? There's an obvious point to consider.
Yes, I understand that this isn't a simple question and it is not unexpected, given the wide range of potential outcomes. We are navigating a complex situation. People monitor oil prices and anticipate changes in behavior accordingly. This does occur, but it requires some time; you need duration. When prices decline, behavior shifts. However, when prices rise again, it takes a while for that behavior to adjust. What I want to emphasize is that the responsibility lies with us to communicate regularly throughout the year. Additionally, there is a factor that complicates the distinction between low and high activity, which is our active ground strategy that can help bridge that gap. It's also important to note that we have significant amounts of shut-in volume, which sets us apart from the average operator. Many of our competitors have limited their volumes due to various issues, including pricing and specific regional challenges.
Some deferred activity is indeed influenced by gas issues in New Mexico. Going forward, we will strive to narrow that gap and keep communication open. In our optimistic scenario, we have assumed a return to more normal operations, but we are not activating that immediately; we are definitely pushing much of that to later in the year, which is why the oil volume might appear somewhat different. This could affect the overall outlook, but I want to reassure you that neither scenario will impact our maintenance capital levels relative to the volumes in question. Essentially, whether we spend more to close that gap, even in a lower scenario, those funds are positioned between our current and future levels. So, as you consider the next year, we are poised for stable to growing activity.
The only other piece that I'd add to the deferments is we had about 4 net DUCs get pushed in Q4, and that's something that can get turned on at any time as well. So it's the combination of not only the curtailments, but the DUCs that have near-term catalysts depending on what kind of near-term pricing we're seeing.
Yes. I want to mention that we have suggested that we will initially focus on some of the capital, even though the overall development in both scenarios is viewed as fairly balanced. The initial focus is entirely influenced by our ground game activities because we have experienced unusual success early in the year.
That's interesting detail. For my second question, you've focused on Appalachia, which had a strong fourth quarter. You've already completed the Utica deal in the first quarter. Can you share if you were surprised by that performance? Adam mentioned that Appalachia was the most ahead of plan compared to your other regions in the fourth quarter. Is that trend continuing into the first quarter? Also, can you provide any updates, although I know it's early, on what you're observing with the joint Infinity assets?
I'll provide a brief overview and then let the more knowledgeable colleagues continue the discussion. Timing and performance are significant factors here. Our legacy Appalachian assets and our joint development agreement have demonstrated exceptionally strong performance, and we anticipate this will continue with Antero. Regarding Antero assets, the strong performance prior to our acquisition is reflected in a favorable purchase price adjustment. Our legacy assets have consistently exceeded expectations month over month and year over year, which is surprising given the prolonged low gas prices. This is due to their exceptional productivity. Over the past year, we've also observed improvements in timing and performance for our joint development venture. However, it's worth noting that the expected completions will primarily occur in April, so the impact in the first quarter may not be substantial. That said, the actual performance versus our plans differs from linear expectations. I'm open to any additional comments you might have.
No. I think you nailed it.
Yes. Charles, I want to conclude by mentioning that when we evaluate these assets, we have traditionally based our assessments on the previous operator. However, this doesn't necessarily reflect our expectations for performance once we take over. We are optimistic about the Antero asset and believe we can achieve improvements in both performance and costs over time.
Your next question comes from the line of Scott Hanold of RBC.
Nick, in considering the optimistic and pessimistic scenarios for the budget, could you share where some of the uncertainties lie? Is it more related to private operators compared to public ones? Have you started to see any indications of this? Are you getting a clearer picture at this point? Ultimately, my question is whether there will come a time when you will choose one scenario over the other, or do you believe that maintaining both scenarios is a sensible approach for the future?
Yes, I think it's still reasonable at this time. There will come a moment when it needs to be unified, and that's our goal. We have great insights into our operations over a 12- and 24-month period, but as you know, it's more challenging to predict quarter-to-quarter in our business model. In uncertain times, like in 2020, we had to withdraw guidance because we couldn't anticipate timing. Looking back, that decision allowed us to generate an extra $100 million in profit by delaying the reopening of our wells. We have strong alignment with our operators, but it will take time to gain clarity on these matters. Regarding public versus private, we noticed a trend starting last year with private operators showing signs of slowdown and curtailments. On the public side, as I review the reports, I observe that there is a discrepancy between the public guidance and the actual activity levels, indicating there may be changes in behavior throughout the year.
Got it. When considering the enhanced governance you've implemented and the larger transactions you've completed, how much of your 2026 activity do you think is supported by this guidance based on enhanced governance, where you have a reasonable level of predictability?
I'm not sure I have that number off the top of my head, Scott, but we can get back to you on that. Jim is saying he thinks it's around half.
Yes.
Okay. Okay.
Yes. But what I'd say is this: 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 the 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.
Your next question comes from the line of Noah Hungness of Bank of America.
To start off here, Nick, I was hoping, could you help us quantify maybe what the EBITDA or free cash flow upside would be from the coiled spring that you've spoken about here. I'd assume, let's say, like $65 of WTI?
Yes, I think it's interesting because every $5 increase in the price per barrel could result in something like $100.
No, it's about $100 between the low and the high, is that what you asked?
Yes.
Yes, it's probably about $100 million to $150 million.
If you consider an additional $5 per barrel, that translates to roughly $150 million. This is why I mentioned it in my remarks. We have a low case maintenance capital scenario which generates more cash at today's pricing, and a high case that would generate less. However, this variance averages out when you compare annual numbers to where we expect production to gradually increase. Assuming a price of $65, which reflects a $5 difference from today's strip prices, it equates to an extra $130 million to $150 million a year in cash for us. Therefore, this shift could mean that our free cash flow remains the same or even improves in the high case due to the more favorable environment.
That's helpful. And then for my second question is, in the low versus high activity scenarios, could you maybe talk about how much of the CapEx is related to ground game spend versus your just standard D&C?
Yes. Give me one second. So you're looking at about $150 million to $200 million between the two.
Mr. O'Grady, there are no more questions in the queue. Do you have any closing remarks?
Yes, please. Thanks. Thanks for joining us today. NOG is well-positioned to navigate through the current market volatility. Our assets are performing well. Our liquidity is abundant, and our investment opportunity set remains strong. We're grateful for being aligned with strong and capable operators, and look forward to keeping you informed on our activities and achievements in the coming weeks. Thanks again.
This concludes today's conference call. You may now disconnect.