Northern Oil and Gas, Inc. (NYSE:NOG) Q1 2025 Earnings Call Transcript

Northern Oil and Gas, Inc. (NYSE:NOG) Q1 2025 Earnings Call Transcript April 30, 2025

Operator: Greetings and welcome to the NOG’s First 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. [Operator Instructions] As a reminder, this conference is being recorded. It’s now my pleasure to introduce your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin.

Evelyn Infurna: Good morning. Welcome to NOG’s first 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 March 31st 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. First, Nick will provide his introductory remarks. Then Adam will give you an overview of 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 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 expectations contemplated by our forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as 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: Thank you, Evelyn. Welcome and good morning everyone and thank you for your interest in our company. The recent market volatility and changing outlook for commodities provides the perfect opportunity to give perspective on NOG’s adaptability in six key points. Number 1; we are in the catbird seat. NOG operates with a uniquely adaptable model; no rig contracts, no frac commitments, no field offices, and non-consent rights across the vast majority of our joint ventures and assets. This economic machine adjusts activity based solely on marketplace dynamics, focusing singularly on profitability. As commodity prices weaken, spending will naturally slow but absent significant shut-ins or curtailments, volume effects should remain modest with stable leverage levels.

Our model’s inherent flexibility ensures dynamic capital allocation centered on returns with the ability to use any downturn to add acreage and working interests in core areas on a countercyclical basis. Number 2; strength in numbers. In Q1 with oil at around $70 and gas at around $350, NOG put forth incredible numbers generating $136 million in free cash flow and $94 million after dividends, with minimal contribution from hedge gains. This year’s budget incorporates hundreds of millions in growth capital, yet requires less than $900 million in sustaining capital, demonstrating NOG’s capacity to tighten spending if needed. Over 60% of expected production is hedged for 2025 and we have additional protection beyond, ensuring resilience amid commodity cycles.

Our leverage remains extremely low on an absolute basis, offering a cushion to navigate market shifts confidently. Number 3; opportunity in uncertainty. Historical cycles show that pricing resets create valuable opportunities for capital reallocation. NOG has a proven track record, most notably during 2020 of leveraging downturns for high return investments such as small scale acquisitions. As capital becomes scarce, our model allows us to flex towards creating long-term value with exceptional returns. Number 4; understanding commodity cycles. The cyclical nature of commodities means that low prices often serve as a reset for higher prices in future periods. While short-term volatility may challenge perceptions, NOG’s hedging strategy and non-op model ensure resilience.

Patient investors will benefit as long-term implications unfold creating opportunities for growth in our business and value creation. Number 5; outlook and strategy. The duration of pricing troughs will be key in shaping activity levels. To the extent, our operators indicate a change in activity which leads to the lower end of capital spending. This provides NOG with increased flexibility between organic and ground game capital allocation. Reductions in rig counts and activity, if they transpire, ultimately drive higher prices reinforcing the cyclical nature of this sector. Number 6; capital allocation focused on returns. NOG remains committed to risk adjusted capital allocation, balancing ground game investments, debt reduction and share buybacks.

As Adam will discuss further, we’re already seeing opportunities arise out of what’s transpired year-to-date. Every decision we make revolves around creating long-term value without excessive dependence on predicting commodity cycles. NOG’s Q1 results definitively showcase the strength of our asset base. Past cycles such as those in 2020 demonstrate our ability to create significant value during downturns and we are motivated to seize on the opportunities presented by current market conditions. We are fortunate to have strategically aligned ourselves with some of the best and most efficient operators in the industry, and we’ll be aligned to adapt alongside them with any market. Thank you again for listening and for your continued interest in our company.

Adam?

Adam Dirlam: Thank you, Nick. The operational results during the quarter largely speak for themselves, so I will cover some highlights and then discuss our outlook on the macro backdrop. The first quarter shaped up largely as expected, and we hit our stride [ph] operationally. Fourth quarter’s delays and deferrals resolved themselves quickly and our operating partners were able to bring on the anticipated TILs while logistical issues were also settled. This resulted in 27.3 net wells added to production as the Permian led the way with 40% of the activity. During the first quarter, we spun an additional 15.6 net wells and elected to 19.1 net wells. Consistent with expectations, the Permian accounted for roughly 60% in each category, while also seeing a slight increase in gas weighted activity.

We are continuously monitoring and discussing plans with our operating partners. In the volatile environment we find ourselves in, our active management of the business and the benefits of a scaled non-op model will distinguish itself. We run our business and make capital decisions with constant consideration to downside risk which is why well elections are always sensitized with lower priced decks to stress test the resilience of returns in a potential lower for longer price environment. Our first quarter elections saw a 23% increase in lateral lengths relative to last year’s average, resulting in a 10% decrease to normalized well costs and driving an uplift in expected rates of return. The Permian and Uinta saw the largest increases in lateral lengths; however, this was consistent across all our respective basins.

During the quarter, we elected 96% of our well proposals which had expected returns well above our hurdle rate at a flat $55 crude and $2.75 gas price deck. To date, our operating partners are making minimal changes to their development plans. However, we expect to see a natural retreat to the core of our respective basins and could see an uptick in well productivity as a result. To the extent that we see another leg down in oil pricing, reduced activity and spending levels would likely follow. That said, given NOG’s diversification and flexibility, we can take advantage of the environment with our ground game. Even in the first quarter, we saw a market increase in opportunities, evaluating over 100 transactions while seeing a further acceleration as we move into the second quarter.

We remained highly selective and closed 7 transactions across the Permian, Appalachia, and the Williston picking up over 1,000 net acres and separately adding 1.1 net wells. As of today, we’ve already reviewed over 90 transactions in April, closed on 4, with more than 10 others committed and in various stages of diligence and completion. Navigating through the last downturn, we were able to deploy some of the most productive capital in the company’s history, and we anticipate that similar opportunities could emerge in this environment. As operators look to trim capital exposure, the first place they generally look is their non-operated assets regardless of the expected returns. Coupling that with smaller non-ops not having the ability to fund certain types of development, we’re optimistic that we can find creative ways to put capital to work.

Shifting gears to larger M&A, we’ve seen a bit of a mixed bag as would be expected in a volatile market. Many of the processes we were involved with earlier in the year were put on the shelf as bid ask spreads widened while more gas focused assets also came to market. While we expect a relative slowdown in larger M&A, we are actively engaged in over 10 processes and having bilateral conversations with asset values ranging from $50 million to over $500 million. Regardless of the environment, we will remain laser focused on total returns, mindful of the balance sheet, continue to take full advantage of the flexibility in our business model, and respond appropriately to what the macro provides. With that, I’ll turn it over to Chad.

Chad Allen: Thanks, Adam. We had a successful first quarter, mostly free from the noise of material disruptions seen in the prior quarter. First quarter total average daily production was approximately 135,000 BOE per day, up 2.5% versus Q4, with oil production coming in flat versus Q4 at approximately 79,000 barrels per day. Year-over-year total production increased by 13%, with oil production up 12%. Gas production has ramped both sequentially and year-over-year and contributed 42% to our production mix. Gas was up 6.5% on a sequential quarterly basis and 14% year-over-year. Our record Q1 production highlighted by double-digit sequential growth from the Uinta and Appalachian Basins help us to exceed internal estimates across several financial metrics.

Adjusted EBITDA in the quarter was approximately $435 million a record for NOG and free cash flow is nearly $136 million, up 41% sequentially on reduced capital spending compared to last quarter. And this is our 21st consecutive quarter of positive free cash flow totaling over $1.7 billion since the beginning of 2020. On commodity realizations, oil differentials came in at the above the high-end of our guided range at $5.79 per barrel for the quarter, reflecting disruptions from the prior quarter and typical seasonal widening. However, we expect differentials to improve from here and are comfortable with our guided range of $4.75 to $5.5 for the year. Natural gas realizations were 100% of benchmark prices for the quarter, better sequentially from Q4 due to strong Williston realizations which were partially offset by weakness in Waha gas during the last half of the quarter.

Similarly, we expect our guidance for gas realizations to accurately reflect the market outlook for the remainder of the year as it stands today. Cash operating costs continue to improve as our production mix continues to evolve. Our cash operating costs were down nearly $2 per BOE from a year ago and $1 per BOE from last quarter which is a testament to our diverse and continuously improving asset base, both by region and by commodity. On the CapEx front, we invested nearly $250 million in the quarter. Of the $250 million, 57% was allocated to the Permian, 20% to the Williston, 15% in Uinta, and 8% in the Appalachian Basin respectively. I want to remind everyone that our CapEx guidance includes $200 million to $300 million of growth capital which can be reallocated as the commodity price environment dictates over the next several months, implying an $850 million to $900 million maintenance level.

This provides us with the flexibility to pivot capital towards other uses if we find ourselves in a lower for longer commodity pricing environment as the year progresses. We exited the quarter with over $900 million of liquidity comprised of $34 million of cash-on-hand, a $4 million deposit, and $870 million of availability on our revolving credit facility. Our business continues to generate significant cash which we have allocated across multiple areas; growth, shareholder returns, and of course, continuing to focus on a strong balance sheet. Both our absolute debt levels and our net debt to LQA EBITDA ratio has trended lower, as expected, ending the quarter around 1.3x near the midpoint of our internal stated 1x to 1.5x range. And net debt was reduced by approximately $90 million in the quarter.

Moving on to guidance; we are maintaining the guidance issued on our last call. Given the fluid situation we’re in, in the event we see a material change in activity levels as the year progresses, we’ll adjust guidance accordingly. It is important to remember, however, that we do not anticipate production levels to change materially in 2025, absent significant curtailments or shut-ins, while we may potentially see CapEx spend contract significantly. With that, I’ll turn it back over to the operator for Q&A.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Noah Hungness with Bank of America. Please go ahead.

Noah Hungness: My first question here, I was just hoping you guys could add maybe a little more color on the production cadence. I mean, keeping in mind the macro uncertainty that you guys had mentioned but also your strong 1Q production print; how can we think about that production cadence trending through the rest of the year?

Chad Allen: Yes. As we discussed prior, we expect Flash [ph] production cadence to kind of the first 3 quarters of Q2 and early Q3 marking kind of the lowest in terms of activity. That means that CapEx will largely be equally weighted. It’s likely to be sequentially down in Q2. We have a large number of wells in process that are scheduled until later in the year. On the base case, we’d still expect Q4 to see the highest level of production absent any massive pullback in spending. A majority of our pullback in activity will likely affect the growth rates that we discussed but we would see — we have to see significant curtailments or deferral — deferrals to kind of have an effect on our production guidance, I guess.

Nick O’Grady: But the situation, though, will remain really fluid. So obviously, with commodity prices all over the place, we’ll adjust accordingly.

Adam Dirlam: Yes. I mean, the conversations that we’ve had with our operators kind of coming into quarter-end, you know, everybody is generally sticking to the plans that they came in on the year. That being said, I think everybody, you know, operators included, are going to stay nimble with their plans. And so if you’re going to see any sort of, you know, adjustment, that’s going to be seen towards the back half of the year.

Noah Hungness: Got you. No, that makes sense. And then, my next question was on service pricing. Could you maybe talk about how service pricing today, when an AFE comes in your door, compares to where service pricing was, let’s say, at the start of the year?

Adam Dirlam: Yes. From an AFE standpoint, on a normalized basis, as we alluded to, we’ve seen about a 10% decrease. That being said, that’s driven more from a 20% to 25% increase in overall lateral lengths relative to kind of the quarterly averages that we saw in 2024. From the conversations that we’ve had with operators and what we’re seeing on AFEs, drilling rates have generally been relatively sticky; completions is probably where we see any sort of relief. But again, I think out of conservatism, we’re keeping our estimates and guidance relatively flat as to what we released at the beginning of the year.

Nick O’Grady: Yes. And I mean — I’ll make two comments. One, for us, we will accrue basically at the AFE cost. So to the extent that costs come down, it will only be at the end. And so obviously, as new wells come in, they will be adjusted accordingly. But for older wells, to the extent we see cost relief, it will take some time for us to true that up. But what I would say is, I’ve never seen a scenario where oil prices went down a lot, well costs went up. So I’ll eat crow if I’m wrong but I don’t think I’m going to be wrong this time either. The majority of our operators have pre-purchased 6 to 12 months of their expected materials; so that is one thing to be — we have gotten a lot of questions about tariffs and things like that. So we have not seen a material impact from that type of stuff at this point in time.

Operator: [Operator Instructions] Your next question comes from the line of Noel Parks with Tuohy Brothers. Please go ahead.

Noel Parks: I apologize if you touched on this already but I’m just wondering, has the change in sort of oil and gas outlook, which of course has been particularly volatile lately, has that shaken lose any potential sellers of non-op interests out there? Just as, again, the world is looking a little different now than it did 3, 6 months ago.

Adam Dirlam: Yes. I mean I think it’s early days. What I would say in order to kind of frame that up for you; we screened, call it, a 100 round game transactions in the first quarter. As it stands today in April, we’ve already screened 100 transactions, so it’s certainly accelerating. And so, when you think about operators as well as other non-operators who may have the inability to fund some of these well proposals for operators looking to pair [ph] back their CapEx spend, the first place they’re going to go is to the — their non-op regardless of expected returns. And so that’s what we’re seeing right now. I think what remains to be seen — I mean we’re starting to make some traction in the second quarter is, you know, what does that mean from a conversion standpoint.

We’re going to be highly selective with whatever we choose to bid on and we’re running downside scenarios to ensure that we’ve got full cycle rates of return that are pencilling at a lower for longer type of price environment.

Noel Parks: Right. It’s interesting. So is fair to say then that it — as opposed to other non-operated holders who might have had positions for a long time like — generational selling, that it’s actually operators themselves taking a quick look around and saying, “Okay, what can we offload?”

Adam Dirlam: Yes. I think it’s a combination of the two. And I would say that that’s more the — the smaller side of things. On the larger kind of M&A, you’re going to see with the volatility a natural slowdown, right? You’ve got expectations coming into the year on larger packages where the bid ask spread is going to widen. Now if this settles out and you’ve got some relative consistency in overall commodity pricing and people start feeling the pain, and there’s capital needs wherever that might mean, then you could start seeing additional packages on the larger side — medium to larger side kind of coming to market. That being said, we’re still very busy, right, with 10 other kind of processes that we’re actively involved in.

Noel Parks: I mean, generally, if you don’t have to, you wouldn’t want to sell your assets at a lower oil price, right? You’d prefer to wait for a higher price because it imbued [ph] higher activity levels in that net present value calculation, as well as higher prices.

Adam Dirlam: That’s right.

Noel Parks: However, to Adam’s point, as cash flows decline and capital calls continue, the ground game tends to accelerate. And so, to Adam’s point, we think this will be an incredible opportunity over the next 18 months for us and pretty excited.

Adam Dirlam: I think the other evolution, just to build on it a little bit more, is one thing that we might see as things progresses more of these drilling joint venture types of transactions alongside operators that we’ve been successful with in the past.

Noel Parks: Good. Terrific, thanks. And just one more quick one. I’ve been a little bit struck by some of the gassy [ph] operators who’ve reported so far that they seem to me a little bit aggressive in assessing what they think mid-cycle pricing is right now. I think — I can think of one that has been talking like $3.50 to $4 and with the presumption that LNG is increasingly offsetting seasonal factors. I sort of wondered what your thoughts are on that?

Chad Allen: Yes. I don’t know if we’re great prognosticators on price. I mean, I think the street is littered with bodies of people who tried to make it [indiscernible]. You know, I think — I might have an opinion but I don’t think it’s worth very much. I think our view is, in general, we obviously will look at the prevailing strip and the pricing. We will look at highly stressed scenarios. And as a non-operator, we try to look at assets that are going to be resilient in any market. That’s why we own extremely low cost Marcellus and Utica [ph] assets that can work in pretty much any environment. And as a result, they have survived through good markets and bad. And I think that that’s where our focus will always remain.

Operator: [Operator Instructions] Your next question comes from the line of Phillips Johnston with Capital One. Please go ahead.

Phillips Johnston: In a scenario where you take CapEx to the low end of the range for this year, what do you think maintenance CapEx would be for oil for 2026 and 2027 approximately?

Nick O’Grady: It would be about the same, Phillips, call it $850 million roughly.

Phillips Johnston: Okay. Perfect. And then, Chad, I probably missed this in your prepared comments but, seems like…

Nick O’Grady: I am so sorry. Just let me caveat that; that’s at today’s drilling cost. I should also add it, right? So that’s assuming that we don’t see a change in cost.

Phillips Johnston: Yes. Okay, makes sense. So, yes — Chad, I probably missed this in the comments but you guys had a pretty nice beat on both production taxes and gas prices relative to your full year guidance. Are those expected to sort of trend back into the range for the year?

Chad Allen: They are. They are. I think it’s really — the production tax is really a function of our production mix. But as our Permian grows, they have a bit higher production taxes; so expect that to kind of move back into our guided range.

Operator: [Operator Instructions] I will turn the call back over to Nick O’Grady, CEO, for closing remarks.

Nick O’Grady: Thanks again for your interest in our company, and we look forward to talking to you in the coming weeks.

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