Northern Oil and Gas - Earnings Call - Q3 2025

Executive Summary

• Q3 2025 delivered mixed results: Adjusted EPS of $1.03 beat consensus $0.87 and Adjusted EBITDA of $387.1M was above consensus $356.8M, but revenue was below S&P Global consensus due to commodity mix and definitional differences; GAAP net loss of $129.1M was driven by a non-cash impairment of $318.7M. EPS/EBITDA estimates from S&P Global; see Estimates Context section for details.*
• Production was 131,054 Boe/d (55% oil), down 2% q/q on expected TIL timing and up 8% y/y; management raised full-year production guidance (132,500–134,000 Boe/d; oil 75,000–76,500 Bbl/d) and tightened capex ($950–$1,025M).
• Cost and pricing tailwinds: oil differentials improved to $3.89/bbl vs WTI and LOE/boe eased sequentially; hedges protected cash flows, with $55.4M realized hedge gains in Q3.
• Balance sheet actions are a catalyst: issued $725M 2033 notes at 7.875%, retired ~97% of 2028 notes, and extended/cheaper revolver (-60 bps), pushing weighted average maturity to ~6 years and preserving >$1.1B revolver availability.

What Went Well and What Went Wrong

What Went Well

• Raised FY2025 production guidance and tightened capex; Q3 production outperformed internal expectations across basins, with record Appalachia volumes and rising gas momentum.
• Improved realized pricing/differentials and operational efficiencies: oil differential improved to $3.89/bbl; normalized AFE costs fell to ~$806 per foot from $841 in Q2; LOE/boe down marginally q/q.
• Strategic capital and BD execution: $98.3M Uinta royalty/minerals bolt-on increasing effective NRI from ~80% to ~87%; robust ground game (22 transactions, +2,500 net acres, +5.8 net wells).
• Quote: “You’d be hard-pressed to find a better hedge company than ours… [hedging] protects our business and allows us to continue to take the offensive through trough periods.” — CEO Nick O’Grady.

What Went Wrong

• GAAP loss due to non-cash impairment: $318.7M full-cost “ceiling test” impairment tied to lower average oil prices; net loss of $129.1M (−$1.33 diluted EPS).
• Sequential oil volume decline and fewer net wells added: oil at 72,348 bbl/d (−6% q/q) and 16.5 net wells added (vs 20.8 in Q2), with Q3 the low point for TILs.
• Continued expense pressure in parts of the cost stack (workovers), prompting LOE guidance increase; production taxes guidance lowered reflecting mix.

Transcript

Operator (participant)

Greetings and welcome to the NOG's second 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. As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Evelyn Infurna, Vice President of Investor Relations. Thank you. You may begin.

Evelyn Infurna (VP of IR)

Good morning. Welcome to NOG's third quarter 2025 earnings conference call. Yesterday, after the close, we released our financial results. You can access our earnings release and presentation in the investor relations section of our website at noginc.com. We will be filing our September 30th 10-Q with the SEC within the next few days. I'm joined this morning by our Chief Executive Officer, Nick O'Grady, our President, Adam Dirlam, our Chief Financial Officer, Chad Allen, and our Chief Technical Officer, Jim Evans. Our agenda for today's call is as follows. Nick will provide introductory remarks, followed by Adam, who will share an overview of NOG's operations and business development activities, and Chad will review our financial results. After our prepared remarks, the team will be available to answer any questions. Before we begin, let me remind you of our safe harbor language.

Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that have been described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income, and free cash flow. Reconciliation of these matters to the closest GAAP measures can be found in our earnings release. With that, I'll turn the call over to Nick.

Nick O'Grady (CEO)

Thanks, Evelyn. Welcome and good morning, everyone, and thank you for your interest in our company. I will, as usual, provide you with some highlights on our outlook in five quick points. Number one, the business remains very solid. Our activity remains stable. Our D&C list has continued to march on with high-quality, low-break-even activity, and we remain on target for the year and expect a strong exit into 2026. Number two, we and many of our operators have been cautious and disciplined with our drilling capital. We have explained that being return-driven versus growth-driven means we will react accordingly and be judicious with how we allocate our capital. So far, given the commodity complex, this strategy has proven to be sensible.

This allows us to preserve our growth inventory and capital for periods where we can maximize value for our investors and ramp aggressively when it's appropriate in the cycle. Yet we've also grown our gas volumes into a stronger backdrop as we allocate capital accordingly. Number three, it also means we can focus some of our capital for long-term value creation. We have never been busier on the BD front, ever. We have been clear that our priorities are focused on creating long-term value, and we believe that disciplined, long-term strategic opportunities are best suited in this environment to create value. Our recent minerals and royalty deal typifies this strategy, adding long-term growth, low-risk assets into the portfolio that will prove highly resilient to short-term gyrations in the commodity market. Number four, we've been purposely tactical in regards to our capital stack.

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

Number five, we continue to actively manage other risks, such as commodity exposure. You'd be hard-pressed to find a better hedge company than ours. This actively managed hedge program allows us to better navigate the typical commodity cycle. This practice is another factor that protects our business and allows us to continue to take the offensive through trough periods. In summary, the business remains solid as a rock. Inorganic opportunities are more robust than ever, and we've taken substantial steps on the risk and capital management front to ensure our ability to take advantage of any cycle. We firmly believe that energy has more growth and value-creating prospects than the bulk of the upstream sector, and we look forward in the coming quarters and years to proving this thesis to our investors. Thank you for your interest in our company, and with that, I'll turn it over to Adam.

Adam Dirlam (President)

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

Drilling and development activity was also consistent, slightly building our wells in process, adding additional low-break-even backlog, and setting up for a strong finish into year-end. Relative to prior quarters, we are seeing a more balanced D&C list as the Permian now makes up 40% of our wells in process, while the Appalachia, Williston, and Uinta each make up roughly 20% of the total. New well proposals and election activity have also remained consistent as we received over 200 well proposals and consented to over 95% of the AFEs balloted in the quarter. Year to date, we have seen 160 more proposals than what was balloted through the same period during 2024. Expected returns remain well above our hurdle rate, further bolstered by a 10% increase in lateral lengths, driving down normalized AFE costs by nearly 5%.

In addition to the longer laterals, NOG's operators continue to see downward pressure on service costs for both drilling and completing, which has been encouraging. We should see those operational efficiencies materialize through Q4 and into 2026. Turning to our business development efforts, Q3 was one of the busiest periods in company history as we screened more than 14 large asset transactions and over 200 ground game opportunities, up over 20% relative to the second quarter. While our scaled business model provides more acquisition opportunities than any other in the E&P space, we remain focused on only the highest quality assets and will strictly adhere to our stringent underwriting requirements. As we previously announced, in August, NOG closed on a royalty and mineral interest acquisition in Uinta that included 1,000 net royalty acres across 400+ gross locations, excluding the additional inventory that is not currently in our development plan.

This is a prime example of how NOG leverages its proprietary database and asymmetric knowledge to capitalize on opportunities in an inefficient market. This acquisition increased NOG's average effective NRI from 80% to 87%, covering the entirety of our Uinta position and further lowering our break-evens in one of the fastest-growing basins in the Lower 48. Our ground game remains as active as ever, closing 22 transactions, executing on three trades that high-graded our acreage position, and signing a joint development agreement that covers seven additional extended lateral spacing units. As a result, we added over 2,500 net acres and an additional 5.8 net wells during the quarter, bringing year-to-date ground game additions to over 6,000 net acres and 11.6 net wells across 50+ transactions in all of our respective basins.

NOG's diverse holdings across both oil and gas have provided ample opportunity to deploy capital in both near-term drilling opportunities as well as longer-dated inventory. This has given us the ability to navigate the dynamic competitive pressures that have changed throughout the year. While the broader M&A market has been relatively stagnant across the sector in a lower commodity environment, our unique position counters that thesis, and we do not see things slowing down for NOG. However, the landscape has changed from historical trends. In the past, the large majority of opportunities were concentrated in the Permian, and while we continue to see those prospects, we are seeing a myriad of high-quality potential deals spread across a greater number of basins. Currently, we are screening eight transactions with a combined value of over $8 billion across operated, non-operated, and joint development structures.

Additionally, we've been able to approach a number of these assets with various structures, providing optionality to the seller that also works for us. Regardless of the environment, we will remain steadfast in our approach to underwriting and focused on high-quality assets that will generate superior returns for our investors and stakeholders. With that, I'll turn it over to Chad.

Chad Allen (CFO)

Thanks, Adam. NOG's diverse and scaled platform continues to deliver in the face of a challenging macro environment, and well performance continues to exceed internal expectations across all of our basins. Third quarter total average daily production was approximately 131,000 BOE per day, up 8% versus Q3 of 2024 and down 2% from Q2 2025, as expected, reflecting a low point for net well additions in 2025 at 16.5.

It is important to note that a third of those net wells came online late in the quarter, providing momentum into the fourth quarter. Oil production was approximately 72,000 bbl of oil per day, up 2% from Q3 2024 and down 6% sequentially. Gas production continues to ramp as our gas joint drilling program is on a consistent monthly TIL pace. Once again, we had record gas volumes of approximately 352 MMCF per day, up 15% from Q3 2024 and up 3% from Q2 2025. With the expectations of adding between 23 and 25 net wells in the fourth quarter, heavy late net well additions, and well-out performance in Q3, we have increased our annual production guidance to a range of 132,500 BOE-134,000 BOE per day.

Moving on to our financial results, adjusted EBITDA in the quarter was $387.1 million, and free cash flow was $118.9 million, marking our 23rd consecutive quarter of positive free cash flow, exceeding $1.9 billion over that time period. We reported a net loss of $129 million in the quarter, which reflects the previously disclosed non-cash impairment charge of $319 million. Our adjusted net income was $102 million or $1.03 per diluted share in the quarter. Oil differentials averaged $3.89 per barrel, as we saw improved differentials across all of our oily basins. Natural gas realizations were 82% of benchmark prices, consistent with Q2 2023 due to ongoing Waha market weakness and was also impacted by lower NYMEX natural gas prices. Lease operating costs per BOE were down marginally from Q2 2023 despite lower oil volumes.

We did see some relief on saltwater disposal costs, but we are still seeing steady expense pressure from workovers. Given the higher run rate year-to-date and the expectation of continued workovers, we have increased annual guidance on LOE. We have also revised guidance on production taxes to a lower run rate given year-to-date actuals and anticipated production mix in the fourth quarter. CapEx in the quarter, excluding non-budgeted acquisitions and other, was $272 million, reflecting an active quarter on the ground game, as discussed by Adam earlier. Overall, the $272 million was allocated with 49% to the Permian, 25% to the Williston, 5% to the Uinta, and 21% in the Appalachian Basin. Approximately $212 million of the total spend in the quarter was allocated to organic development CapEx.

With the history of three quarters behind us, we have tightened our full-year CapEx guidance to a range of $950 million-$1.025 billion. At the end of the quarter, we maintained approximately $1.2 billion in liquidity, consisting of $32 million in cash and over $1.1 billion available on a revolving credit facility. We have been actively managing our balance sheet throughout 2025, including since quarter end. In October, we raised $725 million of notes maturing in 2033 with a coupon of 7.78%. We used those proceeds to retire nearly all of our notes maturing in 2028 that have a coupon of 8.8%. Earlier this week, we amended and restated our revolving credit facility, which extended the tenor to 2030 and markedly improved our pricing grid by 60 basis points, significantly reducing future interest costs. The credit facility's electric commitment amount and borrowing base remained unchanged.

These transactions together extended the weighted average maturity on our debt from approximately three years to six years. Importantly, we have no major maturities until 2029. That concludes our prepared remarks. Operator, please open up the line for Q&A.

Operator (participant)

At this time, I would like to remind everyone in order to ask a question, press star, then the number one on your telephone keypad. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Charles Meade with Johnson Rice. Your line is now open. Please go ahead.

Charles Meade (Research Analyst)

Yes. Good morning, Nick and Adam and Chad and to the rest of the NOG team there.

Nick O'Grady (CEO)

Good morning.

Charles Meade (Research Analyst)

Nick, you, I guess, approached the outlook for 2026 in your prepared comments, but I wondered if you could just elaborate a little bit more on what you're seeing.

I suppose if you'd wanted to give 2026 guidance, you would have given it. I'm really curious to hear what you're seeing because you sample so many different operators across many or most of the important producing areas in the Lower 48. Maybe you could offer what you think the industry baseline is going to be and then perhaps a delta for what NOG might be versus that industry baseline.

Nick O'Grady (CEO)

Yeah. I think what you see in the industry is probably what you'll see for us at this point. I think we haven't seen much change in activity since the prior quarter, which has been relatively flat. I think that's generally what we would expect as we head into next year. The activity has been very, very stable. I think the commodity outlook may change, and that may change that.

I think that is why I think things certainly can change as we head into next year. I think that is why we tend to wait later to guide because I think, frankly, if oil prices were to change materially between now and next year, obviously, activity may change as well. I think as it stands today, what we have said, and I would say it would be consistently, would be that to maintain an outlook, I think on the oil side, similar to where we are this year for our annual guidance, it would require a budget lower. I think in any scenario, and I am referring to oil volumes, we are going to see material gas growth next year. I think if we spent a budget similar to this year, we would see probably growth in both commodities.

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

Adam Dirlam (President)

Yeah. I mean, obviously, everything is going to be driven by break-evens. If we're looking at kind of what our backlog looks like here, we've got a healthy Permian backlog. I think the interesting thing that we've seen in the quarter, especially with the AFEs, is on the Williston side, you're seeing kind of weighted average AFE lateral lengths, almost 14,000 ft-15,000 ft, and that's spread across a multitude of different operators.

I think that's obviously helping bolster some of the expected rates of return that we're seeing. They are lowering normalized well costs and helping, again, to bolster the expected rate of returns in the basin.

Nick O'Grady (CEO)

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

We then proactively could, obviously, on the ground, allocate additional capital there as well.

Charles Meade (Research Analyst)

Got it. That is helpful color on your thinking. If I could just focus in on 4Q, 4Q 2025, your annual guide suggests that you guys are going to be, we're going to see sequential growth in 4Q. Chad, I think I heard you say on your prepared comments that you've got 23-25 net wells that are supposed to be online in 4Q. I wonder if you could just give us an update. We're here in whatever the first week of November. How many of those wells have already come online? Are those wells or those TILs going to be front-end loaded, evenly loaded, back-end loaded? Just talk about where you are in that process to give you confidence on that implied 4Q volume bump.

Nick O'Grady (CEO)

I think, Charles, where we are right now, we're right on track. I'd also add that a good portion of, remember, well completions, a well takes an IP doesn't really mean very much. It takes 30 days usually for a well to clean up and be fully producing. If a well comes online in October, its contribution to the quarter is important, but it's not a massive. A good portion of a lot of the late Q3 tills are going to have some of the biggest impact for Q4. That's the driving confidence for us in this quarter.

The early Q4 and late Q3 wells, many of which have already transpired, are really what drove our guidance increase, as well as the base production outlook, which is really the big driver of our production increase for the year and for the base volume increase as we head. We are going to have really strong productions as we head into early next year.

Charles Meade (Research Analyst)

That is great detail. Thank you.

Nick O'Grady (CEO)

Yep.

Operator (participant)

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

Scott Hanold (Managing Director of Energy Research)

Yeah. Excuse me. Thanks. Good morning. Nick, I would say that you had a pretty strong view on what you are seeing on M&A and ground game, and obviously very encouraging. Frankly, I think it is one of the most robust comments to that effect I have heard from you for a while.

Can you kind of compare and contrast what you're seeing in the market for that view today relative to, say, a few years ago when you did a number of large acquisitions? How do you think about funding both ground game and larger transactions if it does meet your hurdle rates?

Nick O'Grady (CEO)

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

Scott Hanold (Managing Director of Energy Research)

Hey, I'm not sure if y'all can hear me, but the call cut out here.

Operator (participant)

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

John Freeman (Managing Director)

I don't know if that's me, but I can't hear anything on the line.

Operator (participant)

Hello, everyone. This is Bella. Due to technical difficulty, this meeting will be paused for a short moment. Please keep standing by. Thank you for your patience.

Your next question comes from the line of Neal Dingmann. Please go ahead.

Neal Dingmann (Energy Analyst)

Morning. Can y'all hear me fine?

Operator (participant)

Yes.

Neal Dingmann (Energy Analyst)

There you go.

Nick O'Grady (CEO)

Neal.

Neal Dingmann (Energy Analyst)

Neal, yeah.

Nick O'Grady (CEO)

Sorry.

Neal Dingmann (Energy Analyst)

Good.

Nick O'Grady (CEO)

I don't know.

Neal Dingmann (Energy Analyst)

Nice update, guys. My question, Nick, is centered on your continued activity.

Specifically, y'all have talked about—I am just wondering, given the notable changes we have seen in oil prices now still sub-$60 and natural gas now nearly $4.50, are y'all getting a sense of things beginning to change into 2026? Meaning, are you seeing some oil activity continue to slow down, and are you seeing maybe potentially some gas activity picking up? Or have y'all noticed anything different with prices now in these ranges for, I guess, now a few weeks?

Nick O'Grady (CEO)

I mean, nothing imminent, Neal. Nothing different than we have seen all year. I would say what I said in my previous—I am sorry, I am not really sure. Our phone dropped, so I am not really sure where our last comments got cut off. The answer to your question is we have not really seen much of a change in activity overall since last quarter. We have seen oil activity roughly flat and stable.

We have seen gas activity stable to growing, but that's a trend that we've been seeing all year, Adam and I are going to.

Adam Dirlam (President)

Yeah, that's right. I think the Williston and the Uinta has kind of been humming along. From more of an inorganic standpoint, we've been focused on deploying capital within Appalachia. Looking at more near-term drilling opportunities, that's largely been focused in the Permian based on break-evens.

Neal Dingmann (Energy Analyst)

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

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

Nick O'Grady (CEO)

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

Adam Dirlam (President)

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

Neal Dingmann (Energy Analyst)

Thanks, guys. Appreciate it.

Operator (participant)

Your next question comes from the line of Scott Hanold with RBC. Please go ahead. Yeah.

Scott Hanold (Managing Director of Energy Research)

Thanks for getting me back in the queue.

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

Nick O'Grady (CEO)

Yeah. I mean, I think, yeah, I guess I think my rant got cut off, but I would just say this. Look, in terms of funding, Scott, we've answered this question publicly many times before. We'll fund it no differently than we ever have.

If you believe that we have a relatively sophisticated understanding both at the board and the managerial level of corporate finance, one would assume we'll finance any transaction if and only if it's beneficial to our stakeholders and only in a way that would be beneficial to them for the long term and in a risk-positive way. Suffice it to say, as I mentioned in my prepared comments, we have an incredible amount of liquidity at advantage cost, called sub-6%, and multiple other avenues should we need to tap those sources, but we'll only do it if it makes sense to.

Scott Hanold (Managing Director of Energy Research)

Okay. Understood. Thanks for that. My follow-up question is, Adam, you were talking about lateral lengths, how they're increasing. Could you all just give some kind of context for us on how broadly you're seeing that lateral length increase?

How does that impact your capital efficiency and decline rates moving forward?

Adam Dirlam (President)

Yeah. I can kick it off and then hand it over to Jim in terms of decline rate commentary there. It is across the board with our respective basins. As I mentioned earlier, the Williston in Q3 with AFEs, we are seeing 14,000 ft-15,000 ft lateral lengths, and that was spread across 5+ operators with 80+ AFEs that we received during the quarter. We are seeing the same thing in Appalachia and even in the Uinta. The partnership with SM, we are starting to lengthen lateral lengths there as well. Even with the Permian, I think we are seeing some of the longest average lateral lengths that we have seen today. That obviously puts downward pressure on weighted average AFE, normalized AFE cost there, and then further bolsters expected returns.

I think the biggest takeaway that we've seen after observing this over an extended period of time has really been how they've accessed the reservoir. That's probably where I'll give it to the engineer.

Jim Evans (Chief Technical Officer)

Yeah. Thanks, Adam.

Yeah. Like we said, we're seeing operators continue to refine their completion design, more effectively stimulate the toe of the well, and be able to draw down the pressure. What you'll see is they're not going to over-design the facilities. You're not going to see a straight ratio going from a 2 mi to a 3 mi where the IP is going to go up by 50%. It's going to go up a little bit. What you're going to find is you're going to find that the well is going to stay flat for much longer and then have shallower declines. Now, we typically are a little bit more conservative.

What we will see is when we see that IP rate, we will continue to maintain our prior decline rates until we have more information. That might take six to nine months. What we are seeing now is that these wells are holding in there a little bit flatter for a little bit longer. They are starting to exceed our expectations from what we initially expected. As we continue to get more information, we will continue to refine our expectations and our decline curves moving forward.

Operator (participant)

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

John Freeman (Managing Director)

Thank you. Good morning. Just following up on the nice progress on the AFEs dropping to $806 a foot this quarter versus the $841 last quarter.

Can you give us, kind of like you did last quarter, where the well cost stands on your current D&C list on a per-foot basis?

Adam Dirlam (President)

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

John Freeman (Managing Director)

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

Adam Dirlam (President)

Two to four is kind of what we're seeing. Operators, particularly the private ones, tend to cycle that, right, from a lease maintenance standpoint. I do not think we necessarily see that appreciably changing at this point.

John Freeman (Managing Director)

Got it. Thanks, Adam.

Adam Dirlam (President)

You bet.

Operator (participant)

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

Paul Diamond (Equity Research Analyst)

Thank you. Good morning, all. Thanks for taking the call. Just wanted to quickly touch on AFEs. You talked about a 5% sequential well cost reduction, noting lateral lengths, but was there anything else in those numbers? I guess any other contributions and any opportunity sets you see for kind of continuing that trend?

Nick O'Grady (CEO)

Yeah. I mean, Paul, our observation has been that the bulk of cost savings of late have been through that lateral length and efficiencies. We have not seen a huge step down in service costs.

In fact, as we've talked about in LOE, I think in general as a trend, inflation is real, right? You are combating that with shaving days and drilling longer laterals as a way to try to cut costs. I think in order to see material savings at the well level and to see huge cuts, my personal opinion is you are going to have to have another step down in overall activity. If, God forbid, oil prices take another material step down in prices and we see another drop in the rig count, I would think you are going to see big concessions. The one thing I will tell you is we've had conversations with some of our really large operators, and a lot of them are talking about, for lack of a better term, vendor management.

What they are doing is generally they have allowed their field teams at an individual basin level to manage which vendors they use. They are now looking to sort of centralize that and go to, say, nine vendors instead of the 50 or 60 that they have as a way to try to get bargaining power. As that filters through, that may be another source of cost reductions over time, but time will tell.

Paul Diamond (Equity Research Analyst)

You are going to see that on a rolling basis, right? It is going to be spread across the operators because they obviously have to see these contracts through. Once they roll off, that is going to be your window.

Nick O'Grady (CEO)

This is, we are going into budgeting season. We are going into a new year in which theoretically contracts would be turning.

It may be a period in which we start to see some cost relief. Again, time will tell.

Paul Diamond (Equity Research Analyst)

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

Adam Dirlam (President)

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

Paul Diamond (Equity Research Analyst)

Got it. Appreciate the clarity. I'll leave it there.

Operator (participant)

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

Noah Hungness (Equity Research Associate)

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

Nick O'Grady (CEO)

I think it's going to—I mean, that's a difficult question to answer, Noah. I mean, I think in the sense that as it stands now, we've seen very, very steady AFE activity. And if activity continues as it is, we would expect it to be relatively stable.

I think to the extent that we see a material change in commodity prices, we could see it potentially dip down. I think, yeah, I think.

Adam Dirlam (President)

The other variable that you got to think about, right, because you have got gross activity levels, but then you need to think about average working interest on those AFEs. That can certainly be variable. From a gross perspective, everything has been kind of humming along. From a net level, that can vary from quarter to quarter. If you are looking at just activity quarter-over-quarter, that can fluctuate.

Nick O'Grady (CEO)

Yeah. I mean, if the question is, do we see that imminently changing, the answer is no. Could it? Of course. I think really it is going to be dictated by the environment.

I think if certainly our view would be that if prices have a material change from here, we would expect activity to change one way or the other.

Adam Dirlam (President)

The only other thing I guess I'd add is stack pay, co-development. Are you drilling two wells on a pad, or are you drilling 12? The budget sales timing is going to be wildly different between kind of those two scenarios.

Noah Hungness (Equity Research Associate)

No, that's helpful color. For my second question, based on 3Q results and the updated 2025 guide, going back to kind of thinking about an implied 4Q oil production, the range is pretty wide. Could you help us think about maybe some of the moving parts there that could put you at the midpoint or below or above in that range?

Nick O'Grady (CEO)

It's just really timing of completions.

I think, look, we as a non-operator, we're always going to give ourselves some grace in terms of that timing. It is obviously a timing. I would think we certainly will likely tighten that up as the year goes on. What I would say is regardless, we would expect to see a material step up as we exit the year. What I would say as well is that we have seen—and I think we did talk about this in our prepared comments—that as base production has improved and overall declines have moderated, it has really set us up for a really nice start to the first half of next year.

I think to your prior point, I think the question will really come down to how much capital both do our operators deploy and how much capital do we want to, on a discretionary basis, want to deploy next year in terms of what types of activity are we targeting. That is really going to drive the results for next year as we go into. I think that is really a return-based decision.

Noah Hungness (Equity Research Associate)

Good stuff. Thanks, guys.

Nick O'Grady (CEO)

Yep. You bet.

Operator (participant)

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

Nick O'Grady (CEO)

Thanks, everyone. Northern Oil and Gas is well-positioned to navigate through the current market volatility. Our assets are performing very well. Our liquidity is abundant, and our investment opportunity grows every single day.

We're really grateful for being aligned with strong and capable partners, and we look forward to keeping you informed on all our activities and achievements in the coming weeks. Thanks again for your interest in our company. This is the way.

Operator (participant)

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