Northern Oil & Gas, Inc. Q1 FY2025 Earnings Call

Greetings and welcome to 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. 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.

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.

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 $3.50, 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, this 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?

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 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.

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. 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 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 $5.50 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 have trended lower, as expected, ending the quarter around 1.3x near the midpoint of our internal stated 1x to 1.5x range. 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.

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

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 Q1 production print; how can we think about that production cadence trending through the rest of the year?

Yes. As we discussed earlier, we anticipate that the production schedule for the first three quarters of Q2 and early Q3 will be the lowest in terms of activity. This indicates that capital expenditures will be distributed evenly. It's likely to decrease sequentially in Q2. We have a significant number of wells in process that are scheduled to continue until later in the year. In our base case, we still expect Q4 to have the highest production levels, assuming there are no substantial reductions in spending. Most of our reduction in activity will likely impact the growth rates we discussed, but we would need to see considerable cuts or delays to have a notable effect on our production guidance.

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

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 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.

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?

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.

Yes. I’ll make two comments. First, we will accrue at the AFE cost, so any reduction in costs will only be reflected at the end. As new wells come online, they will be adjusted accordingly, but for older wells, it will take time for us to stabilize if we see cost relief. However, I have never observed a situation where oil prices significantly dropped while well costs increased. I’ll admit if I’m wrong, but I don’t believe that will be the case this time. Most of our operators have pre-purchased 6 to 12 months’ worth of their expected materials, which addresses many questions we’ve received about tariffs and similar issues. So far, we have not experienced any material impact from those factors.

Your next question comes from the line of Noel Parks with Tuohy Brothers. Please go ahead.

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, shaken loose 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.

Yes, I think it’s still early. To give you some context, we screened about 100 round game transactions in the first quarter. As of April, we have already screened another 100 transactions, indicating a clear acceleration. When considering operators and non-operators who might struggle to finance well proposals, the first option will typically be to approach their non-operating partners, regardless of anticipated returns. This is the trend we are currently observing. What remains uncertain is the conversion rate as we move into the second quarter. We will be very selective with our bidding and are evaluating downside scenarios to ensure we achieve full cycle rates of return in a prolonged lower price environment.

It's interesting to note that, unlike other non-operated holders who may have held their positions for an extended period, the actual operators are now examining their assets and considering what they can offload.

Yes, I believe it's a mix of factors. This is more prevalent among smaller transactions. With larger mergers and acquisitions, we can expect a natural slowdown due to market volatility. There are expectations for bigger packages where the gap between bids and asks is likely to increase. However, if the market stabilizes and commodity prices show consistency, along with an increase in capital needs, we might see additional larger packages entering the market. That being said, we are still quite active with ten other processes that we are currently involved in.

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.

That’s right.

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.

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

Good. Thanks. I have one more quick question. I've been struck by some of the gas operators who have reported so far, as they seem a bit aggressive in their assessments of what mid-cycle pricing should be right now. For instance, one has mentioned a range of $3.50 to $4, suggesting that LNG is increasingly counteracting seasonal factors. I'm curious about your thoughts on this.

Yes, I'm not sure we're very good at predicting prices. There have been many who have tried and failed. I may have my own opinion, but I don't believe it carries much weight. Our general approach is to consider the market trends and pricing, including highly stressed scenarios. As a non-operator, we focus on assets that are likely to remain strong in any market condition. This is why we invest in low-cost Marcellus and Utica assets, which can perform well in almost any environment. Consequently, they have proven resilient in both strong and weak markets. That will continue to be our focus.

Your next question comes from Phillips Johnston with Capital One. Please go ahead.

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?

It would be about the same, Phillips, call it $850 million roughly.

Okay, perfect. And then, Chad, I probably missed this in your prepared comments but, seems like…

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.

Yes, that makes sense. Chad, I may have overlooked this in your comments, but you had a significant positive variance in both production taxes and gas prices compared to your full year guidance. Do you anticipate those will trend back into the expected range for the year?

Yes, they are. I believe the production tax is mainly influenced by our production mix. However, as our Permian production increases, which generally incurs higher production taxes, we anticipate that this will align back within our guided range.

I will turn the call back over to Nick O’Grady, CEO, for closing remarks.

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

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