Northern Oil and Gas - Earnings Call - Q4 2024

Executive Summary

• Q4 delivered solid volumes but mixed financials: oil & gas sales were $545.5M (+0.4% y/y), GAAP EPS was $0.71, and Adjusted EPS was $1.11, with Adjusted EBITDA of $406.6M; disruptions (wildfires, takeaway issues, and price-driven deferrals) weighed on realized prices and timing, while oil volumes rose 11% q/q to 78,939 bbl/d.
• 2025 outlook is back‑half weighted: guidance calls for 130–135 Mboe/d, 75–79 Mbbl/d oil, and $1.05–$1.20B capex, with 106–110 net spuds outpacing 87–91 net oil TILs, setting up a stronger 2026 growth inflection (+~10% total, +~14% oil) on similar/lower capex.
• Balance sheet/liquidity remain sound: year‑end liquidity was $818.9M; net debt/LQA EBITDA near the high end of the 1.0x–1.5x target now but expected to trend lower through 2025; 2024 shareholder returns totaled nearly $260M via buybacks/dividends.
• Capital returns stepped up: dividend raised to $0.45 for Q1’25 from $0.42 in Q4’24; NOG repurchased ~694k shares in Q4 and ~2.54M in 2024; operational cadence and JV/inorganic pipeline (~$8B of live processes) are key stock catalysts into H2’25/2026.

What Went Well and What Went Wrong

• What Went Well

  • Oil production rose 11% q/q to 78,939 bbl/d, a company record, driven by full-quarter Point contribution, Uinta closing, and higher TILs (25.8 net).
  • Adjusted EBITDA of $406.6M and FCF of $96.4M despite price/timing headwinds; 2024 Adjusted EBITDA reached a record $1.62B.
  • Management reaffirmed multi‑year growth path and strategic posture: “We’ve been hit with… extraordinary… events… [but] this is an issue about timing” and “we can double our business over the next several years,” with a heavier 2025 spud program to set up 2026.

• What Went Wrong

  • Disruptions (forest fires, refinery outages, freeze‑offs, third‑party takeaway issues) and price-sensitive operator deferrals in the Williston caused timing slippages and slightly higher fixed-cost absorption (LOE $9.62/boe).
  • Realized oil price fell to $65.40/bbl (–12% y/y), widening corporate differentials modestly with Uinta takeaway costs; gas realizations improved to 81% of Henry Hub but remain exposed to regional basis.
  • Non‑cash MTM derivative loss of ~$59.7M in Q4 reduced GAAP earnings; realized hedge gains of ~$25.5M partially offset.

Transcript

Operator (participant)

Greetings and welcome to the NOG's Fourth Quarter and Year-End 2024 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 one on your telephone keypad. We encourage participants to limit yourselves to one question and one follow-up. If you would like to withdraw your question, press star one again. As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Erik Romslo, Chief Legal Officer. Thank you. You may begin.

Erik Romslo (Chief Legal Officer)

Good morning. Welcome to NOG's Fourth Quarter and Year-End 2024 Earnings Conference Call. I'm standing in for Evelyn Infurna today, who could not be here but will be back soon. Yesterday, after the market close, we released our financial results for the fourth quarter. You can access our earnings release and presentation on our investor relations website at noginc.com. We will be filing our 2024 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. First, Nick will provide his introductory remarks. Then, Adam will give you an overview of operations and business development activities. And finally, Chad will review our financial results and walk through the details of our 2025 guidance.

After our prepared remarks, the team will be available to answer any questions. Before we begin, let me cover our safe harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income, and free cash flow.

Reconciliations of these measures to the closest GAAP measures can be found in our earnings release. With that, I will turn the call over to Nick.

Nick O'Grady (CEO)

Thanks, Erik. Welcome and good morning, everyone. I'm going to deviate from my typical rundown of points, and my comments will be fairly brief this quarter. One of the hallmarks of the non-operated strategy is in its diversification. Our broad footprint of operators, basins, and well exposures typically means that we're well insulated from more acute disruptions that happen from time to time in the fields. It's something we've purposely built here at NOG over the past seven years. In the past four months, we've been hit with forest fires, refinery outages, freeze-offs, shut-ins, delays of every kind, and material deferments, many of which have been a result of the aforementioned issues all at the same time. This confluence of events, while beyond anyone's control, is extraordinary in nature and very rare for our business.

With that said, it had a material effect not just on the fourth quarter, but started us out at a lower level of base oil volumes, primarily in the Williston, and to a lesser extent in the Uinta coming into 2025, and our capital program will spend a portion of 2025 catching back up. As a result, we'll exit 2025 much stronger than we would have otherwise, however. I think it's important that we put these events in perspective. Oftentimes, we have a tendency to compartmentalize results versus expectations and forgo looking at the actual trends at hand. The reality is that we grew volumes last year 25% year over year, and despite recent disruptions, oil volumes will grow again in the high single digits this year and will exit materially higher than that. These are huge numbers.

The oil that was deferred in Q4 is still there in the ground, and much of the capital for those wells has already been spent. The wells in production continue to perform as expected. And so ultimately, this is an issue about timing. We think and execute for the long term here. As a non-operator, we allocate capital and focus meticulously on the engineering well by well. But as we've discussed in the past, the timing for these wells can shift, leading to periodic lumpiness quarter to quarter. We don't and frankly cannot run our business in 90-day increments. Our budget this year is designed purposely in that fashion, with a hefty spud schedule to drive long-term growth, and that it will.

As an example of this thinking, our Uinta program is immediately going to a larger program of optimally spaced three-mile laterals, which will materially improve longer-term production, performance, returns, and capital efficiency. But it also has the added effect of pushing out turn-in-lines and thus volumes later into the year, given they also take longer to drill. So you who only look at the 2025 numbers might come to the opposite capital efficiency conclusion, but you'd be wrong. We're setting the stage not just to grow in 2025, but to position NOG for the future. We often have a choice. We can front-end load capital so we can grow more now at the expense of the future or vice versa.

Here at NOG, we'll always choose what's best for the long term, both from an organic growth perspective, which may involve recasting the cadence of the development plan, and in the way we underwrite and pursue bolt-ons and other inorganic opportunities. On the topic of inorganic opportunities, things are looking increasingly strong. As oil prices weaken, we find our competitive advantage grows, and the need for our capital and the request for partnerships from a variety of operators and other potential partners has never been greater. As gas prices strengthen, we find that this market is becoming healthier on the M&A front, that there is more activity, and that M&A activity becomes more realistic as the contango spread improves. Operators continue to seek our capital to accelerate development, and many assets remain stranded looking for permanent homes.

As Adam will discuss, we've had success in every one of our basins adding leasehold, but especially in Appalachia. We have stated that we can double our business over the next several years. We are looking at some of the largest transactions in our history, and the need for and call on our capital has never been greater. The inbound activity and backlog of evaluations we're underwriting on a daily basis is as high or higher than at any time during my tenure. And it gives me confidence that we can continue to find meaningful ways inorganically to create value for our investors over time. It will require discipline, but the right opportunities will present themselves. And that discipline has paid off over the years. Our corporate return on capital employed has remained above almost all our peers.

As we do multi-year lookbacks on our acquisitions, from our early Williston deals to the Marcellus to our series of Permian transactions, our underwriting has continued to deliver strong returns, which gives us confidence in our forward plan to grow further over time. As an example, our 2021 Marcellus transaction, we estimate has delivered well over double the internal return we originally projected, paid out in less than two years, and still has decades of life on it. Based on the current gas strip, it's positioned for multiple years of strong cash flow ahead. It's important to note that as we have scaled our platform, we have also been mindful to ensure that we have the internal infrastructure in place to support our growth.

During 2025, we'll be investing significantly in our financial, land, data science, and engineering teams and have already expanded our capabilities by building out an internal geology function that, when paired with our engineering prowess, can help identify additional value that can be extracted from the acreage we already own and find value where we do not. I'll conclude with a review of the highlights of our business model. As the dominant non-operator in the space, NOG is uniquely positioned as a growth story and a consolidator. Our opportunity set continues to grow as we scale. And as a non-operator, our diversification by region, commodity mix, and operator over time should give us a stable business profile. Our strong margins provide a durable cash profile that has provided steady, peer-leading growth and dividends over time. We will continue through thick and thin to manage risk properly and hedge where appropriate.

All of this combined with a disciplined approach to capital allocation should translate into superior shareholder return over time. This has been proven out in the marketplace over the past seven years, and we're going to continue with the same methodical approach to creating value for our investors going forward. I remain incredibly excited for what lies ahead for our company. That concludes my prepared remarks. Thanks to everyone for listening and again for your interest in our company. I'll turn it over to Adam.

Adam Dirlam (President)

Thank you, Nick. First, I'll expand on our operations and what we have observed in the fourth quarter and how that influences the business for 2025. From there, I'll touch on our acquisition efforts as of late and what we are seeing across the landscape. As Nick alluded to, we had a confluence of events hit in the fourth quarter from weather to logistics. But as we look forward, we see operations returning to normal and our asset base setting itself up for additional growth in 2025 and continuing to ramp through 2026. During the fourth quarter, we turned 25.8 net wells to sales. The Permian accounted for 60% of the additions as our joint ventures accelerated activity from what was previously underwritten.

Offsetting that acceleration were re-frac, startup delays, and deferrals in the Williston, where 5.5 completed wells were delayed primarily due to a downtick in commodity pricing from one of our more price-sensitive operators. We expect almost all will be turned in line by the end of the first quarter. The Uinta also experienced some delays in expected completions in connection with third-party takeaway issues that have since been resolved. As of January, SM has taken the reins on operations and we're excited about the long-term partnership as we optimize spacing, extend laterals, realize cost savings from our newly operational sand mine, and find other ways to drive operational value. Despite some of the temporary headwinds, we saw outperformance across our portfolio's base assets and most recently with our Point assets. Vital hit the ground running and has outperformed on expected volumes.

Since taking the handoff on operations, they have been able to optimize completion techniques as well as accelerate on the underwritten drill schedule. Turning to our D&C list, we finished the year with 50.4 net wells in process, with the Permian making up about a third of our wells in process and the remaining two-thirds evenly split across the Uinta, Williston, and Appalachia. Looking ahead, the Permian had the highest levels of drilling activity of the year during Q4. Normalized costs in the region were in line with our annual average. However, we have seen some meaningful efficiencies gained on our recent co-purchased assets as our larger operators push costs lower relative to AFEs. As usual, we maintained over a 90% consent rate on recent well proposals driven by strong economics.

As we think about the cadence for 2025, we expect the Permian to account for 50%-60% of our TILs, with the Williston accounting for about a quarter of the activity, but Appalachia and Uinta evenly making up the difference. Overall, we expect TIL activity to be weighted 40/60 to the front and back halves of the year, with spending evenly split. Drilling down further, expected completion timing in the Williston will be driven by weather as is typical, while the Uinta completions will be evenly split between the first and second halves of the year. In Appalachia, two-thirds of the development, primarily from our recently announced drilling partnership, is slated to start in the second half of the year and build the D&C list as we finish the year.

Finally, the Permian makes up roughly half of the well activity for 2025, but we expect 70% of those completions will come in the back half of the year. Unpacking this further, the drivers around completion timing include the recent flurry of AFE elections, our ground game success, and certain joint venture activity that consists of high working interests and large pads with a focus on full field development. Putting all of these pieces back together illustrates the overall cadence at a corporate level and lays out the expectations of an accelerated growth profile as we exit the year. While our pace and production volumes may be muted in the immediate term, we continue to focus on long-term value drivers, optimizing development for the organization, and our capital allocation decisions will reflect as much.

Our asset base, long-term sustainability, and diversification has never been stronger, and we will continue to build on our successes as we move through the year. Pivoting to our business development efforts, NOG finished the year off strong, taking advantage of a weaker than usual A&D market. Capitalizing on depleted budgets from our competitors and flexing our creativity, we were able to close 14 ground game deals in Q4 across each basin where we have operations. During the quarter, we added over three net wells of near-term development in the Permian and continued to layer in longer-dated inventory across the Williston, Uinta, and Appalachia. We had an extremely successful 2024 ground game campaign, adding 10.7 net wells and over 7,000 net acres while strictly adhering to our internal hurdle rates.

Our success is attributed to a relentless pursuit and leveraging NOG's proprietary data and technology to accurately screen over 500 opportunities during the year. NOG continues to solidify itself as the go-to partner for operators. Our focus on alignment and equitable outcomes continues to produce opportunities, as evidenced by our previously announced 2025 Appalachian drilling partnership with a top public gas producer, which was signed in December of last year, and most recently, the acquisition and drilling partnership we announced last week in the Midland Basin. Moving on to the broader M&A landscape, our size and scale continues to attract compelling prospects across various basins, even as the opportunity set for others is shrinking. Majors and large-cap independents are looking to trim longer-dated inventory or reduce debt through asset sales, and private equity is consistently looking for full or partial exits.

All said, we've got around $8 billion in assets across 13 different processes that we are currently evaluating, with values ranging from $100 million to over $1 billion across multiple basins with varying structures. As one of the only non-operators of scale, we sit in a unique position with a total addressable market as large as any player in the space, but we will continue to be disciplined capital allocators with a focus on long-term and sustainable returns. With that, I'll turn it over to Chad.

Chad Allen (CFO)

Thanks, Adam. Jumping into our results, our fourth quarter average daily production was 131,800 BOE per day and 124,100 BOE per day for the year, above the high end of our guided range. Oil production increased to 78,900 barrels per day, up 11% from Q3 as we rolled in a full quarter of our Point acquisition and closed our XCL acquisition on October 1st. The strength of our production was offset by the various events that Nick and Adam discussed earlier. Despite those disruptions, the Permian Basin volumes remained strong and grew approximately 12% quarter-over-quarter, and our Point acquisition is materially ahead of schedule. Adjusted EBITDA in the quarter was $407 million, and free cash flow was $96 million, which remained strong even with the lower oil price, disruptions, and a higher capital investment.

Adjusted EBITDA and free cash flow for 2024 were $1.6 billion and $461 million, respectively, both all-time highs for NOG. Oil differentials came in at $3.86 per barrel for the quarter, better than our expectations as more of our production is weighted towards the Permian, even with the inclusion of our XCL acquisition, which carries a higher differential compared to our corporate average. Natural gas realizations were 81% of benchmark prices for the quarter, materially better than Q3 due to strong Williston realizations, which were partially offset by the overhang of continued weakness in Waha gas during the first half of the quarter. LOE was $9.62 per BOE, slightly higher than Q3 as a result of higher fixed carrying costs related to the aforementioned disruptions, primarily in the Williston, which was offset by lower lease operating expenses in the Uinta Basin, which is about half of our corporate average.

On the CapEx front, we invested $259 million, inclusive of elective ground game, of $27 million in the quarter. Of the $259 million, 51% of the capital was allocated to the Permian, 31% to the Williston, and 9% to each of the Appalachian and Uinta Basins, respectively. Although our development capital was in line with expectations during the quarter, we continue to see workover costs increase throughout 2024 as our producing well count grows and shale wells age. These workovers, coupled with more re-frac activity, are becoming bigger contributors to CapEx, which should be productive over time and contribute to better well performance as the work is completed. We exited the year with over $800 million of liquidity comprised of $9 million of cash on hand and $810 million of availability on a revolving credit facility.

Our net debt to LQA EBITDA ratio is close to the higher end of our stated one to one and a half times range, reflecting the addition of XCL to our revolver. However, given the strength of our base asset and the strong cash flow profiles of our base business and recent acquisitions, we expect to trend towards the lower end of our leverage range by the end of 2025 based on current pricing trends. Since closing XCL, we reduced borrowings on our revolver by $145 million, inclusive of a modest share buyback of $25 million and $42 million common dividend payment in the fourth quarter. As we execute our acquisition strategy, we've always said we'd be mindful of the balance sheet without excluding the potential for capitalizing on opportunities to retire shares when market conditions allow.

As I mentioned earlier, we found those opportunities in the fourth quarter with the repurchase of just under 700,000 shares. In fact, we are proud to have delivered nearly $260 million in returns comprised of share repurchases and dividends to our shareholders in 2024. In the interest of time, so that we can get to Q&A, I'm going to touch upon a few major line items in our guidance. The balance of the details can be found on page 15 of our earnings deck. We anticipate annual production in the 130,000-135,000 BOE per day range, of which 75,000-79,000 barrels per day for annual oil production. Based on our expected TIL cadence, we expect a relatively flat production profile with a significant ramp towards the end of the year. As always, depending on pricing, we could see a pull forward of activity, which could affect the cadence.

With respect to CapEx, we have budgeted for a range of $1.05 billion-$1.2 billion. As a reminder, the post-closing CapEx associated with our recently announced the Midland acquisition is already in this number. Approximately 25% of our budget is earmarked for ground game acquisition and development capital, and approximately 10% capital outlay for our recently announced Appalachian drilling partnership. Cash taxes in 2025 will be immaterial, with an estimate of under $10 million, mostly comprised of state income taxes. Lastly, I want to touch briefly on reserves and inventory. In 2024, we grew our proved reserves 11% year-over-year to a record 378 million BOE, despite reduced SEC pricing and record production. This increase was driven by both our organic adds and acquisitions. In addition, we added almost 200 high-quality net locations to our inventory through announced large acquisitions and organic acreage.

In an era where inventory is becoming more and more precious, it highlights the strength and quality of our asset base, the logic of our acquisitions over recent years, and the non-operated business model's superior ability to replace drilling locations and generate organic inventory. That concludes our prepared remarks. I'd like to open the call up to questions.

Operator (participant)

At this time, I would like to remind everyone, in order to ask a question, please press star, then the number one on your telephone keypad. We would like to remind participants to limit their questions to one and one follow-up. We will pause for just a moment to compile the Q&A roster. Your first question comes from the line of Neal Dingmann with Truist Securities. Please go ahead.

Neal Dingmann (Managing Director of Energy Research)

Morning, guys. Thanks for the details. Nick, activity guide, specifically what you and even Chad just sort of hit on, anticipated sort of late 2025, 2026 guidance, and then knowing that I know it's a bit difficult to go that far out being a non-operator, I'm just wondering if you could walk me through how you all come up with sort of such optimism for the notable production growth late this year and next year, and does that incorporate? I know you had a couple one-offs, wildfires, and deferments in fourth quarter. Does this sort of incorporate some of that as well?

Nick O'Grady (CEO)

Yeah, Neal, it's not terribly complicated. Look, there are two factors really driving that. One, we're spudding a significantly greater number of wells than we're completing this year. And so therefore, that inherently drives additional growth in 2026. The second factor is that, as Adam also talked about, is that the completion timing is relatively back half weighted. So you're really only getting, effectively, on a daily production basis, sort of partial credit given the partial contribution this year. So an example would be like the Appalachian JV. We're capitalizing that throughout the year, but the first production really won't be until past mid-year. So you're not getting really a meaningful BOE contribution in effect this year. Obviously, you're going to exit really strong, but then in 2026, you're getting the full annual contribution from those volumes.

So it's largely baked, but much of the development that you're getting here, you will see the benefit, but really, it's not until you get to mid and later in the year that you get that. So it gives us a lot of confidence as you get into 2026. And that translates on a 24-month average into significant growth and is fairly locked and loaded.

Neal Dingmann (Managing Director of Energy Research)

I look forward to seeing that. Second question, just on Uinta, specifically. It seemed last night that SM's Uinta production, I'd call it maybe slightly light to start the year, but it seems like, listening to them, their well expectations certainly have not changed. I just wondered, it doesn't sound like your thoughts around the assets have changed at all? Maybe you could discuss sort of 25 expectations there?

Nick O'Grady (CEO)

Yeah. I mean, look, the Uinta has been the fastest-growing play in North America over the past several years with some of the largest EUR oil wells drilled in the country. Among oil industry players, it's been one of the most sought-after areas to get into. I can't tell you how much competition we face to get into the play. Not a week goes by, I don't have one of our peers lauding us and discussing the merits of our deal and the love of the geology and specifically the part of the play where we and our partner acquired. I'm not sure Wall Street has yet warmed to it in the same way, and I'm fine with that taking time. I think we've been doubted before, and to be fair, we and our partner have to deliver results over time to prove it.

But we bought this asset for a 10-15 year development period. That being said, if you look at what Ovintiv just sold their asset for, it implies a material kind of 30%+ premium to what we just paid for our asset. And frankly, that was sold at a lower oil price than when we purchased ours, validating it even further. The reality is we've owned the asset for a couple of months, I mean, a couple of months. And look, our Point transaction, as an example, is absolutely crushing and out of the gates. And while we think that transaction's going to be great, we do, it will still take several years in our minds to determine the validity of our acquisition strategy. That's how we do our look-backs. When we look at our board, we judge all our look-backs on a multi-year basis.

Early performance is great, but it's just that it's early performance. To me, that's like judging a well on a 24-hour rate. It's just nonsensical. You can't. So SM took over operations on January 1. And prior to that, obviously, there was, as we mentioned, an unfortunate and unplanned outage, which had some effect. So I think, look, we're planning to develop this asset over the next decade. We've got an optimal spacing, long lateral, and big savings development plan here. It's an incredible resource. And I think, frankly, we're just scratching the surface geologically. We've got plans to explore more in the next several years. Of course, we want to prove it to our investors as fast as possible, but it will take time.

But I think, look, at the end of the day, I don't think there's anything you can do to judge the asset over the next couple of months. I think it's going to take, oh, all year, really, for us to deliver results. Frankly, I think it's going to be over the next several years.

Neal Dingmann (Managing Director of Energy Research)

Great details. Thank you.

Operator (participant)

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

Scott Hanold (Managing Director)

Yeah. Yeah. Thanks. Good morning. Could you all talk a little bit about your Appalachian partnership and just your understanding and thoughts on do you think that extends into 2026? And if it doesn't, what does the production profile of that asset do?

Nick O'Grady (CEO)

It is a one-year transaction with an option to extend it for another two years. It is a mutual right to extend it, Scott. Whether or not we do that is a mutual decision. So we'll come to that when we do. If it does not, we do these one at a time, and we'll take it one at a time. Production would theoretically peak in 2026 over that period of time. If it does not, I think we'll take it in stride over that period of time.

Adam Dirlam (President)

I guess just to add, Scott, to the first part of that, there will be development activity kind of finishing up in 2026, right? As we're spudding wells in the back half of the year, those will be completed in the first half of 2026.

Nick O'Grady (CEO)

Yeah.

Scott Hanold (Managing Director)

Okay. Okay. So it doesn't seem like at this point in time, you've got. There's not a lot of visibility on your partner's appetite to extend it at this point. So it seems like it's a conversation throughout this year. Is that fair? I guess that was the point of the question. That's right. It's kicking off now, and we'll have those conversations as we move along. Okay. And then, Adam, you had mentioned that you all are building out both technology and people to kind of prepare to further scale the business. Obviously, you guys have done a pretty fantastic job of building the business over the last two to three years. And just could you give us a sense of the confidence level and how built are you or how are you setting this company up?

How big do you think you can build the business here over the next few years?

Adam Dirlam (President)

Well, I think the focus on the infrastructure is to continue to scale the business. Now, where we go with that in terms of stacking assets and continuing to do what we've done over the past five years, we'll continue to stick to our knitting and focus on returns. The opportunity set is clearly out there with $8 billion of quality assets that we're underwriting now with more to come. And last year was a big push in terms of really implementing all of the infrastructure and technology to glean those insights and analytics from the data that we're getting through the 10,000 wells that we have. And the focus is, as we scale, to continue to stay nimble like we have in the past.

In order to do that, we need to pick up the velocity in terms of the overall analytics. We're there, but I don't think it's ever going to be an ending process in terms of just overall process improvement. Nick, I don't know if you want to add to that.

Nick O'Grady (CEO)

Yeah. I mean, I think the view is that we want to be able to wring the towel ever so tighter, right? So for every process that we do, Scott, we want to be able to take it a layer deeper, right? So whether it's externally focused in terms of inorganic opportunities, it's also looking inwards at the assets we own and finding ways to squeeze the lemon even harder.

Scott Hanold (Managing Director)

Understood. Thanks.

Operator (participant)

Your next question comes from the line of Charles Meade with Johnson Rice. Please go ahead.

Charles Meade (Research Analyst)

Good morning, Nick, and Adam, and Chad. I want to go back to some of your prepared comments talking about the shape of production over the course of 2025. I want to make sure I'm understanding. I think I heard you say that volumes are going to be relatively flat over the course of 2025, quarter to quarter, but then ramp into year-end. If I look at that, if I look at that relative to your guidance, does that mean that you're going to be that 1Q is going to show a sequential decline versus 4Q, and then we're going to hold that relatively flat maybe through the first half of the year and then ramp in the back half of the year? Is that what I should be thinking about?

Nick O'Grady (CEO)

That's generally been the pattern, Charles. I mean, I think, look, the reality is that we are baking in a look, you've seen in the last several years where we have seen pull forwards of activity, right? And so that's certainly a possibility. Now, we have designed our capital program this year to be able to absorb, meaning our CapEx program is designed to absorb any potential pull forwards. But certainly, we could see a pull forward, as we've seen in the past several years, of that cadence of development. So I think there's definitely room for that, but we have, on a conservative basis, certainly pushed our TIL schedule towards the back part of the year.

Adam Dirlam (President)

That's right. I mean, I think if you're going to see a pull forward, it likely comes from the Permian and with the Williston and the seasonality there, you're going to obviously have that impact on the front half.

Nick O'Grady (CEO)

So if you remember last year, Charles, we suggested the same thing in the first quarter, and then we obviously saw material pull forwards in the first quarter. That's a possibility, but I don't think we would want to push you that direction because, frankly, that's just going to be dependent on weather and other factors. And obviously, last year, things weren't more favorable. We saw deferments being pulled forward and things like that, but we can't always depend on that. It's going to be operator-specific.

Charles Meade (Research Analyst)

Right, and it's still cold right here in the back half of February.

Nick O'Grady (CEO)

That's right. I mean, that's right. It's -30 degrees Fahrenheit in North Dakota today.

Charles Meade (Research Analyst)

Glad I'm not there. Nick, I want to go back to you've touched on the 2025 and the 2026 comments. You touched on it in your prepared comments, and I think the first question, you elaborated a bit on it. So I think I don't want to flog that because I think I get that message. But I wanted to ask, it seems to me that it's different for you guys to give this kind of next-year outlook or plus-one-year outlook on your 4Q call. And if that's the case, could you maybe talk about what's different this year that kind of gives you either the or gives you more confidence in the visibility that far out?

Nick O'Grady (CEO)

It's more just a function that it's the first year in several years where we've had a material build in the D&C list, and we felt that it warranted an explanation, right? So we've had in the past two years either a drawdown of the D&C list or one that's been relatively matching, right? So when you're spending capital that's building the D&C list, ultimately, the investors need to understand where that money's going, right, and where it's going to drive. So ultimately, especially given where a lot of that capital is driven towards the back half of the year, and again, as a non-operator, the timing is a little bit murky at times in the sense of that it's going to be whether or not it's November, December, and stuff like that, it can shift from time to time.

But ultimately, you're going to have a bit of a hockey stick-type scenario because of where it's lying. We wanted to make sure the investors understood from a capital efficiency perspective that all of that capital, when you stretch it out past that 12-month window, is really driven towards driving a longer-term growth profile.

Charles Meade (Research Analyst)

Got it.

Adam Dirlam (President)

I think the only other thing I'd add is this year, right, we've got five or six different JVs of sorts, right? And that governance lends itself to longer-dated conversations with our operators. Now, does that change potentially, right? And it also only makes up, call it, 30% of the business, give or take, in terms of kind of overall activity on the year. But given the relationships, the size and scale of the Northern and the capital commitments that we have with our other operating partners, they tend to have those longer-dated conversations with us.

Nick O'Grady (CEO)

Yeah. And just as a frame of reference, and I'm probably getting these numbers off a little bit, Charles, but using the Appalachian JV as an example, you're talking about spending 80% of the capital and getting about 10% of the production credit for it, right? So your investors need to understand where that capital is going.

Charles Meade (Research Analyst)

Got it. Thank you. That is a helpful elaboration. And Adam, thank you for pointing out that dynamic with the JVs.

Operator (participant)

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

John Freeman (Managing Director of Exploration and Production)

Good morning, guys. The first topic, Chad, you mentioned that you kind of had this we've had this steady kind of increase in kind of workover, re-frac activity, which is consistent with what we've been seeing and hearing from operators as well. Can you kind of quantify how much in the budget this year is allocated to the workovers and re-frac this year relative to last year?

Chad Allen (CFO)

Yeah. I think we expect relatively similar levels of workovers and re-fracs. I think we saw more of it towards the Williston last year versus I think this year we expect it to be more spread out between the basins. I think we're expecting around 10%-15% of our budget to kind of be allocated towards the workovers and re-frac. That's pretty similar to last year.

Nick O'Grady (CEO)

But obviously, [cross talk] a larger number in total.

Chad Allen (CFO)

Yeah. That's right. That's right.

John Freeman (Managing Director of Exploration and Production)

Okay. And then just my follow-up question, obviously, there was a lot of discussions early last year about just sort of the way that y'all's kind of accrual process works with AFEs, etc. And I'm curious if now that you've been able to do kind of a look back, can you kind of quantify kind of how AFEs ended up coming in relative to the initial what was embedded in that initial 2024 budget?

Adam Dirlam (President)

Yeah. I mean, I think year-over-year, if I was looking at the normalized costs with AFEs, we saw about a 15% benefit in that regard. And then obviously, on that basis, that's also going to depend on what our working interests are. But as I alluded to earlier in my prepared remarks, we're seeing a lot of that meaningful downward pressure on AFE costs through a lot of the JVs, which obviously have super normal working interests.

Nick O'Grady (CEO)

Yeah, and not to toot Adam's horn, but we also have an evergreen massive joint interest audit program ongoing where we routinely look over our shoulder and check the operators on a regular basis to make sure we're being charged what we should be.

John Freeman (Managing Director of Exploration and Production)

Got it. Thanks, guys.

Operator (participant)

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

Paul Diamond (Equity Research Analyst)

Good morning, all. Thanks for taking my call. Just a quick one on the Appalachian Drilling Partnership. Can you talk a bit about the opportunity set to either mirror that elsewhere, or do you see any kind of opportunities to do similar structures in other basins?

Nick O'Grady (CEO)

Yeah. So I mean, dovetailing to Scott's question where he said, Well, we just signed this thing a month and a half ago, and, well, you haven't renewed it yet. Well, I don't think the ink was dry when we had had about six phone calls of people asking in the immediate area, well, that was cool. Would you be interested in doing another one? I think the answer is there is a lot of interest in structures such as these. I mean, look, we do things on small scales like this all the time. We obviously just signed a small-scale one in the Midland Basin. But the answer is I see multiple opportunities for structures such as these or structures like these embedded.

Operator (participant)

Your next question comes from the line of Noel Parks.

Nick O'Grady (CEO)

Oh, okay. Sorry about that.

Operator (participant)

From Tuohy Brothers. Please go ahead.

Noel Parks (Managing Director)

Hi. Noel Parks from Tuohy Brothers. I was just interested in your thoughts on sort of the hedging environment. As we've been hearing operators talk about their outlooks as we're going through earnings season, it seems like with both gas and oil, you've got some pretty variable drivers. And we also sort of have attitudes with different producers, some of them being acquisitive and/or looking to sort of try to bring value forward, others sort of being more in hanging back mode and looking to sort of piece out their inventory and maybe look for stronger price environments down the road. So are you just seeing anything that makes you think that there might be different patterns of hedging emerging from certain operators as we go forward?

Nick O'Grady (CEO)

I would just say this. We obviously have taken advantage of hedging windows. So as an example, you would have seen that we've had several spikes in oil prices, and we've added judiciously to our oil hedges since our last report at very favorable prices and largely completed our 2025 hedging program for oil, more or less. On gas, we have added modestly to hedges, albeit we have been very careful. And the bulk of our gas hedges coming into this year were in the form of costless collars. That's been the structure of the gas. The gas curve had been very favorable to that. And so as gas prices have rallied, even as we, on a percentage basis, have been very hedged, we've been able to participate in the bulk of the gas rally. And so therefore, you can both be hedged and participate in that upside.

We have obviously added some hedges, as you've seen the tremendous strength of late. But again, we've been able to, I think, our hedge program around gas has been very strong. Again, as we look out to the out years, we tend to be much more careful. I think the backwardation in oil is relatively unfavorable. I think in the last several years, we have been much slower in hedging our oil volumes and just much more judicious because of that backwardation. And so we've just tended to take our time in doing so. So we've been doing it kind of quarter by quarter as opposed to just on a programmatic and blanket basis. It's proven to be, I think, a more profitable angle for us. Certainly, it's prevented us from doing stupid things.

And I'd say on the gas front, contango is certainly helpful, but obviously, the market has been a lot stronger. I don't know if that answers your question.

Noel Parks (Managing Director)

Sure. Yeah. I was just sort of getting in my sense that there might be a little bit of a divergence just in terms of how aggressive operators were as they try to sort of suss out the sort of medium-term pricing environment. But it sounds like from your perspective, you kind of are sort of following your own instincts and just sort of leaving the producers to sort of do what they're going to do. Is that fair?

Nick O'Grady (CEO)

Yeah. I mean, we do our own hedging. We don't follow any of what the producers do. So we have our own volumes. We're a real property owner. So we have to deal with our own stuff, not necessarily what our operators are doing.

Noel Parks (Managing Director)

Sure. Totally fair. And just one other thing. I just wonder if you have any thoughts on permitting gas? There's been some speculation that with more supportive environment from Washington, overall, it might see more infrastructure spending. And again, sort of hear mixed things about people's attitudes towards embracing gas or sort of avoiding gas in the Permian.

Nick O'Grady (CEO)

Well, I mean, I'm not sure. What I would say to this is that we've certainly seen of late an improvement in local prices in the Permian Basin. What I do hear as part of a few industry groups is that it is a great resource, and it is constantly facing bottlenecks in the sense that the growth in the Permian Basin volumes has outstripped its ability to build out infrastructure. And so there are thoughts about, for example, building data centers directly in the Permian Basin and effectively building plants and things like that that could be direct use within the basin. So perhaps those are some things that you might be referring to. I'm not sure. Chad, is there anything?

Chad Allen (CFO)

No, no. I think you're right. We saw this in the Williston. I think it just takes time, and I think the new administration likely probably helps with the infrastructure build-out, so certainly, we'll welcome that.

Noel Parks (Managing Director)

Great. Thanks a lot.

Operator (participant)

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

Nick O'Grady (CEO)

Sorry about that, Paul.

Paul Diamond (Equity Research Analyst)

No, good morning. Apologies for audio cutting out there. Appreciate you answering the first question. Just wanted to circle back on kind of the opportunities that you're all seeing in organic growth by scale. Is it more at the leasehold level, or is it you seeing more opportunities, kind of more conversations on those larger co-purchase type deals?

Nick O'Grady (CEO)

Yeah. So I would say this that at sort of at the ground game level, I would say definitely we've had a lot of success at the leasehold level. At the package level, I would say it's been more just true, I would say, asset packages. Actually, I wouldn't say that necessarily. It's been a mix.

Adam Dirlam (President)

Yeah. I think it ebbs and flows. It's going back to the ground game. I mean, you saw us kind of do both in the fourth quarter, and we'll continue to screen it all. And I think that's where we've got to be able to zig where everyone else is zagging. And going back to some of the comments with Scott's questions around the technology, right? We've got to be able to underwrite all this stuff. I mean, we're seeing at least two to three and sometimes five of these things coming in the door. And the competition levels are going to wax and wane. When we think about some of the larger A&D processes out there, I think at this moment in time, Nick's spot on.

I think we've got a handful of regular way non-op packages, at least four of them that are kind of out there and active now. Do some of the majors or larger independents rationalize their portfolio with non-op packages post-M&A? That's certainly conversations that we've had. And then we've got a handful of drilling partnerships that we're looking at and probably another three to four co-buying types of exercises across our respective basins, as well as kind of this minority interest buy-down or partial monetization. So you're seeing kind of the whole buffet of options out there. And really, for us, it's a focus on quality and overall alignment.

Paul Diamond (Equity Research Analyst)

Understood. Appreciate the clarity.

Operator (participant)

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

Noah Hungness (Equity Research Associate)

Morning, everyone. For my first question, I wanted to ask on how you guys are seeing steel tariffs potentially impacting AFE costs, especially for smaller operators who may not have OCTG pricing or service costs contracted out.

Nick O'Grady (CEO)

Yeah, so this was a topic. We're a member of AXPC. This is a topic that just was circulated as part of that. And the answer is it's unclear at this point in time, but it's likely going to have some effect, so the answer is it's going to have some upward impact, the magnitude of which I do not know at this point in time.

Noah Hungness (Equity Research Associate)

Gotcha.

Adam Dirlam (President)

But I think from a planning purpose, maybe just to jump on that a little bit further, as a non-operator, we're generally conservative on well costs. We're going to let that flow through from an actual standpoint. And so typically, we're building in some level of buffer to mitigate that. To Nick's point, we'll see what the true ramifications are.

Nick O'Grady (CEO)

Yeah. To the extent that there are. I mean. What I would just say to this is that we've seen, in general, overall, AFE. We budgeted for zero reduction in costs when, in reality, overall, we have seen cost reductions. So we have plenty of wiggle room, I would say, in general, within our overall budget.

Noah Hungness (Equity Research Associate)

Appreciate that color. The next one is on buybacks. I mean, just given the stock's recent performance over this year, how are you thinking about buybacks right now?

Nick O'Grady (CEO)

Yeah. I mean, I think everything's on the table. And obviously, we've been in quiet period for some period of time. And these are board decisions. So we sit down with the board and discuss this every single quarter. And we basically take their guidance. And we'll have that conversation in the next week or two as we go into the next quarter window.

Noah Hungness (Equity Research Associate)

Appreciate it, guys. Thanks.

Nick O'Grady (CEO)

Yep.

Operator (participant)

I will turn the call back over to Nick O'Grady for closing remarks.

Nick O'Grady (CEO)

Thank you for joining us today. We appreciate your continued support and look forward to touching base with you in the coming weeks.

Operator (participant)

Ladies and gentlemen, that concludes today's call. Thank you all for joining. You may now disconnect.