Northern Oil and Gas, Inc. (NYSE:NOG) Q1 2024 Earnings Call Transcript

Northern Oil and Gas, Inc. (NYSE:NOG) Q1 2024 Earnings Call Transcript May 1, 2024

Northern Oil and Gas, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Greetings and welcome to the NOG’s First Quarter 2024 Earnings Conference Call. At this time, all participants are in 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 2024 Earnings Conference Call. Earlier this morning, we released our financial results for the first quarter. You can access our earnings release and presentation on our Investor Relations website at noginc.com. Our Form 10-Q will be filed with the SEC within the next few days. I’m joined this morning by our Chief Executive Officer, Nick O’Grady; our President, Adam Dirlam, our Chief Financial Officer Chad Allen and our Chief Technical Officer, Jim Evans. Our agenda for today’s call is as follows. Nick will provide his remarks on the quarter and our recent accomplishments, then Adam will give you an overview of operations and business development activities. Chad will review our financial results and after our prepared remarks, the team will be available to answer any questions.

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

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

Nick O’Grady: Thank you, Evelyn. Welcome and good morning, everyone, and thank you for your interest in our company. I’ll get right to it with four key points: Number one, coming out strong right out of the gates. We saw a significantly better-than-expected results in the first quarter, driven by two primary factors, strong well performance and a pull forward of activity with more wells turned in line than we expected. We had highlighted strong well performance last quarter as well, but it was less noticeable in Q4 results due to higher level of curtailments. With the rampant Mascot in full swing, our other JVs performing well and higher oil prices, we are seeing organic activity accelerate, which bodes well for our 2024 production overall.

The larger-than-expected till count increased our overall capital but was more than made up for by higher cash flow and production that will benefit us as we head into the second quarter. We expect modest additional pull-forward in the second quarter, though not to the same extent as good pricing continues to bring value forward for our investors. This highlights one of the greatest facets of our non-operated business model, which is the alignment with our operators. When prices are high, we typically see the economic incentives work their magic to bring forward value into the higher-price periods like it did here. And additionally, as we talk about the asymmetry of hedging, we produce more barrels when prices are higher, leaving us more on hedge than we expected in a higher-priced period.

While we’ve seen development accelerate into the highest price period of the strip for the year, boosting our profits for the quarter, our plans for all of 2024 remain largely unchanged, with only very modest changes to the pace. Our hope would be to the extent that commodity prices stay robust that it warrants activity levels and returns that trend toward the middle or upper band of our guidance, which should translate into higher production as we exit the year and into 2025. With that said, we want to remain flexible with our capital as always, to ensure we’re earning significant returns. Chad will highlight it further. But despite the lower headline free cash flow number, under the surface, we’ve made substantial progress on the working capital front and made better progress than we anticipated on our balance sheet year-to-date.

After closing the last of our Q4 acquisitions, we paid about $40 million in dividends, spent about $20 million on share repurchases and still paid down about $50 million worth of debt. All of this was during a period of hefty investment. So we expect our free cash flow pace to pick up even more meaningfully in the second quarter and continue as the year progresses. Number two, waiting for the right opportunity. As we highlight nearly every year, our ground game business typically has a quiet first quarter, and this one was no different. We characteristically see people aggressively spending their budgets early in the year. Additionally, strong crude prices can have an effect on risk taking from smaller competitors who may not have the wherewithal to invest in the down cycles.

On the larger M&A front, we’ve been actively engaged, we’ve seen relatively wide bid-ask spreads, negative risk from high crude prices and asset quality that’s kept us from being overly aggressive. The good news is that on the more scalable front, we continue to work on drilling partnerships, carve-outs and true non-op and JV front on larger, more impactful and bespoke processes. We shied away from some of the less value-added marketing processes that, in our view, have been both lower quality and saturated with returns that in many cases did not meet our thresholds. These market conditions ebb and flow and can change within a given year, so we stay active in all facets of business development to capture the right opportunity. Given the overall backlog, we’re staying disciplined for the right transaction to grow our business and I have the utmost confidence that over time, we will find great opportunities for growth.

Number three, dynamic capital allocation 101. With the positive acquisitions and relative weakness of our equity performance early in the year, we did elect to dynamically direct our capital towards share repurchases and simplifying our capital stack. Dynamic capital allocation is just that dynamic. Our flexible business model allows us to quickly adapt to changing circumstances. The contraction in our equity valuation in the first quarter, as I highlighted in our last earnings call, provided a favorable time for share repurchases and we pounced on the opportunity at attractive prices. We also cleaned up the last tranche of our remaining equity warrants, which were issued as part of an acquisition in 2022 at lower prices than current in a net exercise style exchange.

This simplifying transaction both reduces short pressure on our equity as well as long-term dilution potential in another value-added move. Most of those warrants were already accounted for in our diluted share count, but over time, the potential dilution from stock performance and dividend payments could have grown meaningfully and we’re very bullish on our outlook. As we look forward, one of the primary goals for this year is to put the business in a position to have increased optionality as we head into 2025, whether that’s to further increase the dividend, allocate more to buybacks or allocate more to growth prospects. The key to dynamic capital allocation is to make decisions that maximize total return. While dogmatic, formulaic approaches may seem tempting, over time, they are prone to miss opportunities.

Given weak natural gas prices, high interest rates and an uncertain economic outlook in an election year, there’s a high probability we will have market volatility events, which could potentially create great buyback acquisition opportunities or chances to grow the dividend for us. We want you to know that, as always, we are watching closely and are highly aligned with our shareholders to deliver. Number four, confidence for 2024 and ’25. We recently issued and updated a much-improved ESG report. And in it, I talk a lot about our philosophy of Kaizen here at NOG. Kaizen is a Japanese term which basically means continuous improvement and that’s built into our culture here at NOG. After launching our AI-powered data lake system, Drakkar last year, we continue to enhance and expand functionality.

And internally, we remain focused on improving data quality to further leverage our analytics, our underwriting and predictive capabilities to help grow our business. Now the week goes by where I don’t hear that one of our departments is building out new capabilities to exploit our massive probe data. And what that data is showing us gives me tremendous confidence in the people at NOG, our assets and our outlook for 2024, ’25 and beyond. We continue to add systems, talent and new processes to get better and better at what we do. As with Kaizen, we’re never satisfied leaving well enough alone. For 2024 specifically, as I mentioned in my first point, our sound investment process and core tenant of focusing on high-quality assets is time and time again proving itself out with better-than-expected well performance and our culture of conservatism has delivered the strong results we’ve seen to date.

While we reiterate our forecast for the year, we’re working diligently to augment those results and find additional paths to growth. Before I hand it over to Adam, I’d like to thank the entire NOG team for their hard work and dedication for another great quarter and thank our analysts and all of you for your interest in our company today. Thanks also to our operators out there for their incredible fieldwork and the great partnerships we’ve forged. We’ve had another great start to the year, and while it’s early, the assets are performing exceptionally well as we convert a lot of the money in the ground from the past six months into production and cash flow this year. As 2024 progresses, I also expect we will see more growth opportunities emerge.

And given what’s in front of us today, I remain confident that NOG remains a superior investment product to our peers and that our growth trajectory is unmatched in the upstream space. As a management team, we are aligned and incentivized to maximize total return for our investor’s year in and year out. That’s because we are a company run by investors for investors. With that, I’ll turn it over to Adam.

Adam Dirlam: Thanks, Nick. I’ll open with some commentary on the first quarter’s operational highlights and then shift gears to provide some additional color on what we’re seeing on the M&A front. The first quarter picked up were ’23 left off with continued acceleration of development and marking the fifth consecutive quarter of record production for NOG. Production increased 4% quarter-over-quarter driven by well productivity and a pull forward in the Permian, which accounted for three quarters of our well additions in Q1. Partnering with top-tier operators across all of our respective basins with the likes of Mewbourne, Permian Resources, Ascent and Continental that helped drive the beat on production. Unpacking this further, we saw 2023’s ground game investments had nearly 5,000 barrels a day of production over the fourth quarter, while also seeing outperformance on our Novo and Utica assets.

Turn in lines topped expectations with 25.3 net wells added in Q1 as the Mascot project pulled forward 2.4 net wells that were expected to come online in the second quarter. The wells were added late in March, and as they clean up, we expect to receive the production benefit in the second and third quarters of the year. With higher conversions in Q1, we had an expected drag to our wells in process and ended the quarter with 52.4 net wells in process, 40 of them in our oil-weighted basins. The Permian now makes up 60% of our oil-weighted wells in process and our exposure to top-tier operators remains consistent across all of our basins. Pace of AFEs was as active as in the fourth quarter, and we are seeing a healthy backlog of well proposals as we head into Q2.

At the end of the quarter, well proposals not yet spud totaled 24.7 net wells. During the quarter, we were validated with over 180 AFEs and elected to over 90% of the proposals on a net basis. January and February kicked things off with robust gross activity on our organic acreage offset by lower average working interest. Recently, we have seen that turnaround as March and April had three times the net well activity than in January and February. New well proposals are showing moderate signs of deflation as absolute and normalized costs in the Permian have declined and have been the lowest that we’ve seen in the last 12 months. Estimated well cost in the Williston also ticked down 5% quarter-over-quarter. All that said, we continue to remain conservative with our forecast, especially in light of a higher-priced commodity environment and accelerated development.

Turning to the M&A landscape and our business development efforts. Q1 was frothy as competition leaned in with new budgets as is typical to start the year. And customarily, we are happy to let the bull run by and stay disciplined with our underwriting, waiting for the appropriate opportunities. Despite some elevated competition in our ground game, we were able to pick up over 1,700 net acres of longer-dated inventory and 0.6 net wells in process. In the Bakken, we also closed on a joint development agreement and will be kicking off development across four to five units in the third quarter. We continue to get creative with structuring and we see significant upside with this project, having a sight line to add up to 10 more drilling units to the program.

There is no shortage of shots on goal as we evaluated over 120 transactions in Q1 and we’re already seeing momentum in conversions through April. Shifting gears to the larger M&A landscape, we remain as busy as we’ve ever been evaluating opportunities for the right fit. In the first quarter alone, we reviewed over 30 potential transactions, yet the quality of properties have been variable at best. Quality has started to pick up and the mix of prospects have included non-op packages, joint development programs, minority interest buy-downs and the co-purchasing of operated assets. Looking ahead, we are actively engaged in over 10 processes with asset values ranging from $100 million to over $1 billion, while continuing strategic discussions on other off-market opportunities.

We’re encouraged with the conversations that are taking place, but any potential transaction will need to have the right fit at an asset level as well as from a risk-adjusted return perspective. With that, I’ll turn it over to Chad.

Chad Allen: Thanks, Adam. I’ll start by reviewing our first quarter results and provide additional color on our operations. Average daily production in the quarter was more than 119,000 BOE per day, up over 5,000 BOE per day compared to Q4 and up 37% compared to Q1 of 2023, establishing a new NOG record. Oil production mix of our total volumes was in line with our guidance at just over 70,000 barrels a day and gas was a larger contributor as compared to the past, reflecting 2.3 net wells in Appalachia and a full quarter’s contribution from the Utica acquisition. Adjusted EBITDA in the quarter was $387 million, up 19% over the same period last year, but modestly lower than the last quarter, mainly due to lower average realized prices per BOE in the quarter.

Free cash flow of $54 million in the quarter was lower sequentially and from the same period last year due to the pull-forward of activity in the quarter. But the peak of this growth capital should crest as we reach midyear. We anticipate an acceleration of free cash flow in the second quarter as TIL come online and begin to contribute to production and revenue. Adjusted EPS was $1.28 per diluted share. Oil differentials were in line with our expectations at an average of $3.99 at the lower end of our guidance. Williston differentials range from a low of $6.60 in January to a high of $6.95 in February, while Permian differentials saw a market widening from $0.69 in January to $2.26 in February on the heels of higher production from areas with higher deducts within the basin.

We still expect oil differentials to moderate and have begun to see some evidence of that in late March and in April. For natural gas realizations were 118% of benchmark prices for the first quarter due to better winter NGL prices and in-season Appalachian differentials, but we are still anticipating an erosion in gas realizations as we close out heating season. With Waha gas solidly negative combined with shoulder season gas and NGL pricing, we expect markedly lower realizations in the second quarter, perhaps as low as the mid-70% range. Overall, for the year, however, we believe our guidance remains solid. Waha has been plagued by not only under capacity, but by maintenance-driven outages and we expect things to modestly improve later in the year.

It’s also worth noting our net exposure to Waha is minimal with approximately $60 million a day hedged through Waha basis and Waha gas swaps for the balance of 2024 at very attractive prices. LOE was flat sequentially at $9.70 per BOE, reflecting continued workover expenses, a pickup in activity of our Mascot project and a $2.3 million firm transport charge in the Marcellus. The transportation expense should moderate to a quarterly charge of approximately $1.5 million per quarter through the end of Q1 2025. As we discussed on our fourth quarter call, we anticipate LOE per BOE to be relatively flat through the second quarter before gradually declining as production ramps further in our Mascot project and the transportation charge falls to a lower run rate.

Production taxes were 9.6%, in line with guidance as production ramped in the Permian, which has a higher production tax rate. On the CapEx front, we continue to experience a pull-forward of organic activity driven by the strength in oil prices. This drove CapEx of $296 million, inclusive of ground-gain capital and was a bit higher than anticipated for the first quarter. Of the $296 million, 68% was allocated to the Permian, 26% of the Williston and 6% to Appalachia. If we continue to see strength in oil prices, we expect to see CapEx trend toward the higher end of our guidance range for the year. With that said, the higher CapEx should be accompanied by higher production as our D&C list is actively converting pills and spuds and drawing down our working capital.

Specifically on the working capital front, excluding the impact of derivatives, we have seen an improvement of approximately $40 million on our working capital since the end of the year. At quarter end, we had over $1 billion of liquidity, price of $32 million of cash on hand and $987 million available on our revolving credit facility, which was expanded at the end of April as a part of our semi-annual borrowing base redetermination. While our borrowing base remained constant at $1.8 billion, we increased our elected commitment to $1.5 billion and added three high-quality banks to our syndicate. At quarter end, net debt to LQA EBITDA was 1.25 times and we expect this ratio to trend down throughout 2024 barring significant cash M&A activity.

As Nick discussed earlier, we were actively repurchasing shares in the first quarter despite limited open window. We repurchased 549,000 shares for $20 million of our common equity at an average price of $36.42. We are committed to allocating capital to share buybacks where there is a market divergence between our absolute and relative performance. And finally, before we go to Q&A, I’d like to address a few adjustments to guidance. We anticipate production of 117,500 to 119,500 BOE per day in Q2. Flat versus Q1 given the pull forward in March. Barring continued pull forward, we should see CapEx down sequentially and a significant improvement in our free cash flow. Our Q2 expectation of oil volumes is also in line with Q1. We have tightened the range on production expenses, which are starting to come down as well as oil differentials, which quarter-to-date appear to be improving.

We may make further adjustments when we report Q2 as needed. With that, I’ll turn the call back over to the operator for Q&A.

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Q&A Session

Operator: Thank you. [Operator Instructions] And your first question comes from the line now. Neal Dingmann at Truist Securities. Please go ahead.

Neal Dingmann: Good morning, guys. Good details. Nick, maybe get right to it. My first question is just on what I would classify as maybe cycle time. It seems like your capital on the ground maybe has increased a little bit, but the setup, I think as you and Adam, the guys described it to me, it sounds like the future setup is better than ever. Is this just a product of cycle time for some of the producers being a little bit longer or what’s driving this? Because again, it does seem like I think your second half and 25 look as good, if not better than ever. It seems like a little bit in the fourth quarter and the first quarter that was a little more on the ground. So if you can just maybe hit on that a little bit.

Nick O’Grady: Yes. I mean, look, Neal, this is a little bit of what we are and a little bit of how things are changing. We’re a returns-based organization. And obviously, as a nonoperator, the timing of capital expenditures can shift markedly. But as I said last quarter, and I’ll say again, the total capital expenditures are the same. And to the extent it increases from one quarter to next is because we’re getting more activity if we’re getting more activity that meets our return holders, that’s a good thing. What we’ve experienced in the last nine months is an acceleration of development. I would tell you, in the last 18 months, our average spud TIL timing has gone from 234 days to 110 days. That’s a significant move, and that’s hard to perfectly model.

I’d say the difference between last quarter and this quarter is that this quarter’s acceleration also came with more tilt, which obviously translated into significantly more production. So you’ve got a lot more cash flow and benefit from it than last quarter. So it was a little bit less obvious last quarter. But I’d also say because we’re an accrual shop and because these accruals roll off over an extended period of time and as these invoices are received, it’s not something that’s done quarter-to-quarter, and we don’t run the business quarter-to-quarter nor is the capital spent quarter-to-quarter. It’s spent over the life of the wells. And so over a 12-month period, generally, the capital and the returns you can see from our standout corporate returns tends to play out.

And I want to be clear, this is a good thing. Corporate Finance would tell you bringing capital forward is ultimately bringing net present value forward. That’s corporate finance model one. We just brought forward significant production into the highest-priced part of the strip. And yes, they brought forward some CapEx. Is the same CapEx that would have been spent later in the year at a backward-dated strip, I would argue this isn’t a bad pay at all.

Neal Dingmann: And then just a quick follow-up on capital allocation. You haven’t mentioned just the shots on goal, and I continue to think you all have more opportunities than almost anybody. How do you balance that in shareholder return given you have more prospects than I think any company out there?

Nick O’Grady: Yes. I mean, I think I don’t see them as — I mean, I’d say the same thing we always would say I don’t think we view them as mutually exclusive. And I think I would also add that we look at a lot of acquisitions as things that can enhance shareholder returns. So most of the assets that we’re looking at are generally cash flowing acquisitions. So a lot of the assets that we look at, we think can enhance our dividends over time. But I would tell you that specifically, we would pay a stock buyback as an example versus — and the potential long-term benefits of that versus an acquisition and we weigh those against each other every single day of the week. And there are times where one might look more attractive long term, but we’re in the — like we talk about it might sound cliche, but it’s not.

When we talk about maximizing total return, we really are serious about it, and we’re paid to be serious about it. And so we have to think about over a three, five, seven year period of those decisions that we make today and what are the long-term implications of those things. And that’s how for the equity and what those acquisitions versus the decision to buy back stock today are going to make on that. But I would tell you, the answer is there’s one for both. Adam, I don’t know if you want to add to that.

Adam Dirlam: No. I mean, I think you touched on it in your prepared comments in terms of dynamic capital allocation. We’re always actively managing the portfolio, reviewing what’s in front of us, and we’re going to alert capital according to what dislocations we see.

Nick O’Grady: Yes. I mean I think even as it pertains to the stock buyback and admittedly, we had a relatively narrow window in the first quarter. We spent a lot of time about the mechanics and just with the Board of Directors about how we would do it and about what rules and regulations would be around it? And what would be the nuances about that and how we would weigh that against potential M&A and just the opportunity cost and to make sure we left red for that. But I would just say this that we’re not short of opportunities, that’s for sure.

Neal Dingmann: Very helpful. Thanks, guys.

Operator: Your next question comes from the line of Phillips Johnston of Capital One. Your line is now open.

Phillips Johnston: Hi guys. Thanks. So just a follow-up on the CapEx for the year, possibly landing in the upper half of the range, assuming oil prices and activity remains elevated. Chad, you sort of alluded to this in your comments, but would you think that your net well count and your production volume for the year might also be a little bit biased to the upper half of the range? Or do you think it’s a little bit too early to tell just with the lag effects and whatnot.

Nick O’Grady: Phil, this is Nick. I think I read your note, and I have to object to one of the things you said I think you misconstrued what we were saying. We’re not suggesting that our CapEx assumes that oil prices will stay high for the rest of the year. It’s quite the opposite. What we were saying was that since oil prices have increased, we’ve seen an increase of AFE activity on our acreage and that AFE activity would translate into CapEx theoretically at later in the third and the fourth quarters of the year. And our comment was that we’re returns driven, right? So our consent activity on those AFEs is driven by oil prices and underwriting those returns. And so if oil prices stay high, we’ll consent to that activity and ultimately then the CapEx would be higher, not the other way around.

So we also know to be flexible because our business model, obviously inherently is more flexible than an operated on. And so to the extent that oil prices were to change, obviously, we pivot quickly. We’re just suggesting that if things stayed as they are, we wanted to guide investors accordingly based on our status quo. So I would tell you that if oil prices stayed high, we would probably expect to see continued elevated AFE activity because what we noticed was that as oil prices rallied early in this year, we started to see a notable pickup in activity, and that’s going to translate particularly. That activity you see today is really going to be activity that’s going to translate into well proposals that are going to start to come online towards the end of this year and point towards 2025.

And so it would be turning lines that would likely be towards the end of this year in chatter.

Jim Evans: And that dovetails into your comments in terms of the spud I mean right now, we’re getting well proposals, especially with elevated working interest and depending on who those operators are and how they’re developing it, whether it’s a one to two well development program or if it’s a full cube development program, and that’s going to dictate building and so kind of on that trust as we see things socialized and development progresses, that’s where we’re at right now.

Nick O’Grady: We’re not deciding to spend the money and hoping oil prices are going to stay high. We’re saying that if oil prices stay high, we’re likely to see that kind of activity. That’s what we were suggesting.

Phillips Johnston: Okay. I appreciate the clarification there. Shifting over, I guess, to your views on the gas market. We’ve seen ’25 and ’26 strip prices actually creep up since you guys reported Q4 despite super high inventories and weak pump prices. I saw your NYMEX gas hedges for ’25, ’26 are unchanged, excuse me. But are you tempted to sort of layer in any more activity in the out years?

Nick O’Grady: Yes. I mean, I think it’s been proven time and time again that contango is a bearish formation, right? And I think we will probably act accordingly. And I think when the curve wanted to see contango over 2024 last year, we began to hedge and I think you’ll probably see us act accordingly. So, I think the answer is yes. I mean I think contango tends to give a perverse incentive to producers, right? So it will tell them to keep producing. I know you’re seeing curtailments right now, but curtailments are not necessarily a panacea because ultimately, you just turn something off that you can turn right back on and you keep drilling like if you’ll notice most natural gas producers right now are not cutting CapEx. They’re actually still drilling and curtailing production.

So effectively, they’re going to be able to turn it back on at a moment’s notice that’s not feeling the market in my opinion. And so to me, it does not make me feel overly bullish on the market like the market seems to want to be. And a backward-dated market is a much healthier market. And so what it’s telling me is that you likely want to sell in that market. I think gas is going to be $1.80 or $2, that’s not a sustainable price. Those high prices are likely and those are obviously very profitable levels for us. And so I think we’d be very happy to sell into those levels.

Adam Dirlam: Yes. Philips, just on the hedging comment, I think we have been adding some call options out in those years. So flip that in the 10-Q. But yes.

Phillips Johnston: Okay, great. Thanks, guys. Appreciate it.

Operator: Question comes from the line of Scott Hanold of RBC. Please go ahead.

Scott Hanold: Hi, all. Thanks. Look, I’m going to kind of come back to the CapEx conversation, if we could, but take a little bit different angle on it. I guess, correct me if I’m wrong, but your back half CapEx, the implied quarterly run rate is around $160 million to $170 million. And could you just give us a high-level view, I think your production probably is going to peak somewhere in that 120-plus range in the third quarter. And when you fundamentally think about like what CapEx run rate needs to occur to maintain production by your non-ops, is $160 million to $170 million adequate? Or does that sort of create a little bit of a tail off in production heading into the ’25?

Nick O’Grady: Well, our decline rate is moderating as we had our overall maintenance capital is coming down to, right? So like we’re losing about what? Jim, five points of decline rate five points of decline rates throughout the year. So as the year progresses, our overall maintenance capital is coming down mainly. So the answer to your question is it’s a little bit of a fuzzy number, but I’d say that it really depends from a pull-forward perspective in terms of the capital. But the answer is we have not determined within the year exactly how — obviously, we haven’t determined where we want to go for ’25 at this point in time. I mean, obviously, we have a long and story history of growing. And we’re incentivized to grow. So I would make every assumption that we would plan to find ways and paths to grow as we move towards next year.

But I think the answer to your question is that as it pertains to this year from a path, right Jim? Yes. I think the answer to this year is that, yes, effectively, through the path, our overall capital can step down throughout the year and production would peak and then slightly decline in the fourth quarter, but not meaningfully, even though the capital falls off materially.

Scott Hanold: Yes, no, no, I appreciate it. There’s a lot of, you know, gives and takes for the cruels and stuff like that. And that all makes sense.

Nick O’Grady: And remember, but it’s not a meaningful amount, it’s not.

Scott Hanold: Got it. Okay. And then, you know, I’m sorry, go ahead.

Nick O’Grady: It’s just not a meaningful amount.

Scott Hanold: Okay. You all had discussed in some of your prepared comments that some of the stronger production results was due to some pull-in of activity, but also some well outperformance. Could you be a little more specific on that? I mean you obviously have a couple of large joint ventures with Mascot and Novo. Can you kind of qualify or quantify what you’re seeing with some of those wells? And is that what’s really driven the performance? Or is it more broad-based than that?

Jim Evans: I think it’s a combination of the two. As far as the projects go, they’re all at or above expectations in terms of new development activity that we’ve been seeing of Novo with the New Mexico assets, our Utica assets are outperforming. We’ve seen some meaningful performance in Williston as well with the likes Continental and Conoco and exposure to Slawson Marathon, they’re all kind of sticking into the core where we’ve got some outsized working interest. So it seems to be a combination of all the above.

Scott Hanold: Got it. Thank you.

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

Charles Meade: Good morning, Nick, Adam, and Chad. I want to pick up perhaps right where we just left off on the source of the production bit. But I wondered if you could look at it or try to answer it in this framework. In late February, you guys thought that there’s going to be a slight decline until you came in with, call it, a 4% growth on the quarter. So was there a specific — I think this is — I guess he already asked about the geographies. I guess what changed in March that led to that led to that result that was different from what you guys saw at the end of February?

Nick O’Grady: Well, I think if you’re talking about what changed in what we were seeing. I think it’s going to be a combination of what wells came online in March as well as these wells are cleaning up in January and February, you’ve got very limited data in terms of what you’re seeing. And so you’ve got to let it play out over an extended period of time. And then, Jim, I don’t know if you want to comment on anything else in particular.

Jim Evans: Yes, Charles and obviously, we saw a full forward of activity as well, right? So we had three extra net wells that we weren’t really accounting for. So that added some production there, too. Like Adam mentioned the used assets, they continue to clean up, performed better than we had expected at that time. As well as we have some new wells come online kind of mid-February on the Novo asset that has significantly outperformed our expectations. So that’s another driver as well. And then as we showed in the Williston on new Continental wells that looked really good compared to our expectations. So just kind of a combination of all those things really cannot drove Q1 performance versus what we were modeling kind of that mid late February time frame.

Nick O’Grady: Yes, on just a lag of information, right? I mean we might be getting this information on a daily basis, but you need to be able to bring it in, how [Indiscernible] it against the model and then put all the pieces together. Because you’re going to have pushes in bold everywhere. And then it’s just going to depend on what your working interests are and the timing of that development and information.

Jim Evans: And there are certain things too, Charles, like from an assumption perspective, like using the freeze-off event in Williston. We were very concerned not necessarily about the freeze-off of that in and of itself, we had a pretty good handle of that, but we were pretty concerned that it was going to push particularly a lot of the completions out. So we have scheduled the assumption that a lot of the completions will be pushed out multiple weeks. And then later on in February and March we came to find out that a lot of that stuff had actually come right on schedule, right? So then you’re going back and rejiggering that as you actually get the well status and reports in. So a lot of the stuff we had anticipated kind of getting delayed, wound up not being delayed.

So then ultimately, it’s not just the TILs themselves having more TIL themselves. But even within the quarter, things being more on time and being accelerated in than you thought. So you’re getting the benefit of time within a quarter, not just the actual additional activity on top of that.

Charles Meade: Got it. That’s all helpful incremental detail.

Jim Evans: And just I will tell you like I mentioned this in my prepared comments, we are just seeing to better well performance. I mean you saw that in our times. And you may not see it because obviously, our Permian mix this year is more Midland-based so it is obviously maybe a bit lower than our average last year here today, but certainly better than what our internal forecast has been. And so in general, we’ve been doing a bit better than we anticipated coming out of the gate.

Charles Meade: Got it. And then, Nick, another question on the CapEx. And I want to get the benefit because I’m sure you participated in a lot of internal discussions. And I want to make sure I understand what you’re saying and I’m thinking about the right implications going forward. I mean, in 4Q, you guys had a big CapEx and it came in a lot higher expected you pre-released that. We got another one here this quarter. If I understood you correctly, the two main drivers appear to be increased cycle time or reduced cycle, so increased pace. And a higher oil price, which leads to more AFE proposals. And if that’s correct, what are those two vectors? Are they flat going forward?

Nick O’Grady: I’m not sure I followed Charles.

Charles Meade: Is the arrow pointed, I mean, are we — do we still — if those are the two big drivers, you go a different direction, if you want. But the question is, as we look at 2Q and 3Q, are those errors still pointed up or are we going to have further decreased cycle time? The oil price isn’t going up, but is there a building wave of AFEs? Or is this kind of a spurt that’s going to attend to that?

Nick O’Grady: I got a question like 2018 when I first started here being like, okay, it’s a productivity improvement in the Bakken done? Because well cost — wells have gotten so much better and fracking’s gotten so much better. And then every single year, they found ways to make wells better. And I got the same question last year and I got the same question a year before. And the answer is the industry is amazing. They’ve found ways to go faster and faster and faster. And frankly, the onus is on us. But look, we have candidly struggled to keep up with the pace and we’ve been, I mean, I don’t view it necessarily as a bad thing, but the speed at which our operator has gone has obviously taken a smart surprise to some degree. But at the same time, I don’t really see this as the total cap like, you can see it in our weighted average cost of a well.

We’re not blowing through, we’re not having inflationary pressures. If you look at the overall capital delta, we drilled three extra wells this quarter, right? And you saw it in the top line results, right? So, I don’t think — again, I don’t really see a major disconnect here. The delta of last quarter is masked by the fact that ultimately, it’s really a percentage of completion things as opposed to additional TILs. But ultimately, yes, you’re seeing cycle times. Can I predict if the operators are going to stop going faster? I don’t know if I can make that prediction because that would be predicting something that I don’t control. And I would say operators are incentivized to make more and more money. So I’d say they’re whether oil prices are going up or down, I’d say if oil prices go down, they’re going to still try to find a way to make more money.

So they’re going to find a way to go faster and faster and make more money. So I would say, no, they’re going to still find ways to go faster.

Jim Evans: And it’s just going to depend on the operator mix and the development mix and the working interest that we’re getting in the door, right? And you don’t necessarily have that view of AFEs because they might ballot two AFEs, one week and then they followed it up with six more and they all end up being on the same path. So those are things that we need to digest and truly understand. I think the AFE activity has picked up. We’ve seen that in March and April, and we would expect in this environment, all things remain the same that development cadence and everything else will continue, but that can change on a dime.

Charles Meade: Got it. Thank you for that.

Operator: Question comes from the line of Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield: Thanks. Good morning, all. Regarding the larger asset packages, how would you characterize the competition you’re experiencing in that market at present? Aside from the quality and wider bid-ask spreads you saw in Q1, is that still a robust market and opportunity for you?

Nick O’Grady: Yes. At the larger package, Derrick. I don’t think we felt like there’s a ton of — I mean we’ve certainly seen bankers try to make, give the illusion of competition in a couple of cases, but we haven’t really seen much competition for brand in reality. I think where the challenge has been more that I think there’s been, I think, of late, it’s been harder for us to find assets that we really wanted to lean in on meaning like where you knew the clearing price and would we really feel like they were assets that we would be willing to pay what you knew it was required to take it home. I guess is where I was.

Jim Evans: Yes. I guess framing it up a different way for you. I mean we’re certainly seeing more entrants from family offices and private equity groups and some cross over from the minerals side, which is obviously validating in terms of other sources recognizing the power of the business model, but that’s largely limited to smaller funds. And so where I think you see maybe a little bit more of an elevation in competition is on the smaller ground game side. We’re playing in different sandboxes. When you’re starting to talk about asset packages that are north of $150 million in terms of funds that are being raised and being able to handle potential concentration, those types of things. And so I think what we’re seeing in that regard is generally status quo. Obviously, that can also change. But based on kind of what we’re seeing and the feedback that we’re getting, I don’t see a material change on the large.

Nick O’Grady: Yes. I mean, I’d say where we see people we’ve definitely seen buyers of PDP centric assets. And that we’re very happy to see that because it’s just not where we’re generally focused.

Jim Evans: Yes. I mean, from time to time, I think we see some groups that raise capital and deploy it in a meaningful way. There was one group that we saw ended up paying north of 75% of where we were coming out at and we’re happy to let them have it. And frankly, they shot their one and only bullet and we haven’t heard from them again. So they can digest that for as long as they do. And then if they want to sell it, and maybe at that point, it’s worth taking another look at it, but not at those prices.

Nick O’Grady: Yes. I mean, I would just say this, I don’t think there’s been an asset that we’ve coveted yet that we really felt was very attractive to us that we haven’t built out we were outmatched for when we really of the quality that you’ve seen us execute on where we really had to stretch or go out of our comfort zone for. And I think that that’s a testament to where we are in the marketplace.

Derrick Whitfield: Terrific. And as my follow-up, really thinking about Permian macro. Regarding the pipeline outages and tighter regress conditions that are expected until Matterhorn comes on in 2022-23, are you guys expecting industry to adjust turn-in-line activity to match supply growth with Egress Group?

Nick O’Grady: You’re definitely seeing especially for some of the smaller operators, they’re having to navigate around it. I think we’re blessed with the fact that most of our operators in the Permian are bigger operators with more integrated midstream systems and better access points. But even they have to navigate around these issues, Derrick. And so it’s not a small issue, and I don’t want to sugarcoat it. And I think, were for better for worse, and I would like to say we were geniuses, but we basically have almost zero exposure this year. Financially speaking, at least, we effectively hedged all of it away. And I’d love to say we did it completely on purpose, but we just really we were a little bit concerned coming into the year, and I think we just had a heavy hand on it when we were hedging it probably because we’re so acquisitive last year.

But I think that it’s going to take some time to make some of it if you rightly highlighted some of it is it’s been made worse by maintenance. But I don’t think it’s necessarily going to get magically better this year. So next year, I think it’s still going to be a wide issue for some time. I think it’s going to take a couple of years, you’re going to need more and more to be built out. So I do think it’s going to limit some growth, particularly in the Delaware for the next year or so.

Derrick Whitfield: Makes sense. Very helpful.

Operator: Your next question comes to the line of Donovan Schafer of Northland Capital. Please go ahead.

Donovan Schafer: Hi guys, thanks for taking the questions. So I want to ask about — and I know we’ve already had a couple of people ask about the better-than-expected well performance. So it’s like beating a dead horse. But I kind of want to – in the sense of like to what extent should we care? Let’s forget about the welding pulled forward or whatever, if we’re just talking about on like a given well performance of that well versus your own expectations, if we just focus on that, and you said, I think, Nick, you said flat out better well performance. Who gets sort of the credit for that. Is it just a chance phenomenon and there’s a statistical distribution, and it just happens to be that the roles of the guys were better at this time around?

Or can you identify changes in sort of well design? Or do you feel like this supports strength to particular operators or is it alternatively like a matter of conservative underwriting? Another way to put it is, should this be seen as an achievement of some kind, somehow tied to a human agency? Or is this just a matter of chance. And if it’s some sort of like achievement, who gets that credit? Is it a reflection of your business model? Is it a reflection of your operators? That would be really great.

Nick O’Grady: I mean I think I would certainly want to give credit to the operators for their great performance. I mean, certainly, they do all the hard work, and I don’t want to not give credit where credits do. But to our engineering team, we work really hard to set a standard and underwrite accordingly and then try to meet and beat those expectations. And so I think that we try to – and then obviously, for you guys to under promise and over deliver, and it’s not to lowball or anything like that, but you really do, is this a risky business. It is a risky business and well the oil and gas business is still with optimists. And I always joke that as a nonoperator, you really need to be pessimistic because you find out that many operators they make a change in well design and they see better IPs and they carry it forward and think everything is going to be better or they do a one refrac is good, and they think all refracs is going to be better, and it turns out that it’s locational.

And so we try really hard to take a skeptical lens and be conservative about this. And I think that’s why generally, our reserves have been conservative, and we tend to do well. So I want to give a lot of credit to our team that we tend to see better results, but also it comes down to a philosophy, and I talked about this in my prepared comments, of assets Novo, which is that you can’t engineer bad assets, which is that you can try to pay a high discount rate for really bad assets. But at the end of the day, those assets aren’t going to be resilient. And when I was a stock analyst back in the day, I would always rather pay a premium for a really good management team and a really good company than pay a low price for a really bad stock because the chances were over time that bad stock or that cheap stock is something bad is going to happen because it was a bad company, and it was not going to be resilient.

And it goes the same thing for oil gas assets, which is that you buy really high-quality reservoirs and really high-quality operators and chances are they are going to do good things with that. And I think that’s what our team really focuses on here, which is focus on the best operators in the best areas, and you tend to be pleasantly surprised. I don’t know, Jim, if you want to add to that?

Jim Evans: Yes. I think the other thing to think about, too, is that operators are always trying to innovate and be more efficient. So it’s not just about getting more EUR more reserves out of it. They’re also trying to optimize their artificial lift operations. So that’s constantly changing, and we’re constantly updating our tide curve based on what the operators are doing. So some of it is they’re just getting oil out faster. It’s not necessarily that they’re going to get more EUR over the life of it. They just found a way to get more out, more efficiently through the first 12 to 18 months, which is a big driver of NPV and IRR, which is what we want. And so we’re constantly taking that into account like I said, we want to make sure that more often than not the wells outperformers versus underperformance.

So that’s just part of our culture here at how we look at things, and we do constant look backs on performance, how wells they doing versus what we originally underwrote. And over the last three, four years, we’ve been less than 5% off in terms of that. So we feel very confident about our underwriting here. This is just a pleasant surprise by some of our operators in really good areas, and they come to a way to just do better than what we had expected.

Donovan Schafer: Okay. Great. Thank you. Very helpful. And then as a follow-up. So Nick, in your prepared remarks, you called out, and I thought this was a good thing to call out and a good insight, is the potential for increased the volatility. And you’re talking about with respect to your own positioning as a company and the importance of kind of financial flexibility because of opportunities, it gives you different leverage or other things to pull or opens up opportunities. But I’m curious just specifically because I think you were saying, well, with such low gas prices and also I think maybe you mentioned just that it’s an election year or maybe it’s like a just a geopolitical dynamic. But it does seem like a setup that we could see more volatility between now and November, December.

And so I’m curious, were you specifically talking about like in terms of thinking about what might happen with the own volatility of stock and like other securities you could potentially bring in? Or are you talking more broadly like commodity prices as well, and the potential for any type of wild swings around anything like that? I want to be clear because I thought that was a good point. But I’m just curious with your thinking, what things are the volatility you’re talking about, price commodities, stocks, bonds, all of it.

Nick O’Grady: I think volatility means volatility, I think if you look at our track record for the last few complete years, we bought our bonds, we bought our stock. We have bought assets, that we bought gas assets, we bought oil assets. We’ve done a lot of — I would say, we spent $200 million buying distressed assets during 2020, it was 90% of our capital. Our organic capital basically went to zero during 2020. And so I think during, you want to be in a position to be able to act if extreme events happen. Now, obviously, you’re at an extreme point in natural gas spot pricing. I’m not sure you’re at an extreme point in terms of the strip or in terms of asset pricing or you haven’t seen distress, certainly, in natural gas. For the assets themselves, necessarily yet.

But I think the overall market, to the extent we see a change in the interest rate cycle or things like that, we could definitely see things happen. And so I think we have to see what happens with the overall economy. And yes, it is an election year and typically you can see changes in policy and other things that could potentially happen. But I think we just always want to be in a position to act and I always use that same dynamic and I think its because we want to have flexibility to make changes to those decisions. And that’s why having a business, walk softly and carry a big stick, to have that cash flow, to be able to make those dynamic decisions and make changes. We’ve been able to buy our bonds in the low 90s. Now they trade well north of par.

You have those ability to make good decisions when the market gives them to you.

Donovan Schafer: Okay. Very helpful. Thank you guys.

Operator: Your next question comes from the line of Lloyd Byrne of Jefferies. Please go ahead.

Lloyd Byrne: Hi guys. Thanks for all the info. Let me come about the CapEx differently. It seems like there’s a lot of concern. But if I look at the CapEx versus the tills, it feels like the AFEs are either in line or coming down. And maybe you can comment on that. And then also you talked about a little bit of a deflation at Mascot and Novo. Maybe you can just comment on that as well.

Adam Dirlam: Hi Lloyd, this is Adam. I made some comments in my prepared remarks. We’re definitely seeing it across the board, both from an absolute and normalized on a lateral foot basis. We’ve certainly seen that with our Mascot assets as well as our Novo assets. And I think that’s both the function of what we’re seeing in terms of drilling as well as just kind of spud to till timing as well. I think some of the tangibles casing those types of things are still pretty sticky. But operators are doing a pretty good job of being able to kind of pick away around the edges and see that persisting.

Lloyd Byrne: Thanks. And then, Nick, just remind us, more free cash flow coming forward, debt targets?

Nick O’Grady: Yes. We still target around one time. And I think we were about 1.1 last quarter. We’re about just over 1.2 this quarter. And that’s just a function that we closed our Northern Delaware acquisition. So we did that. We should see, absent any material changing again, we’re already close to May here, a material step down this quarter again, absent some unforeseen change in commodity prices over the next couple of months. But just given the fact that CapEx is scheduled to step down some, so we should see a material step down on the revolver balances in the second quarter. We should be right down the trend.

Lloyd Byrne: Thank you, guys.

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

Paul Diamond: Thank you. Good morning. I appreciate you taking my call. Just a quick one on the M&A purchase cadence. So you had a pretty good except in Q1. Are you seeing the same type of opportunity given current pricing levels and as you look forward through, what’s expected to be a relatively volatile period in the market?

Nick O’Grady: I mean, there’s certainly no shortage of opportunities. I think it’s always about balancing the risk you, right? It’s just about, I think I would just tell you, I think the higher, the lower the price goes, I think our risk appetite increases. I think the higher the price of oil go is probably the more wary we’re going to become. So you have sort of, I’d say, from a $65 to $85 range, it’s probably a better rate than above those, I’d say, below $70, I think you’re going to find that sellers are probably going to dry up because they’re going to feel that they’re not getting good value for their assets. But I think that, you know, in that range, that’s sort of a good enough environment from a pricing perspective. I think that we’re in a relatively decent market.

I think that, again, the beginning of the year is always kind of a tricky, if you look at our pattern, generally, we’ve done less M&A in the first half of any year, historically speaking, for whatever reason. It’s just, if you go back, historically speaking, I’ve done very little stuff in the calendar going back my entirety of my time here. So it tends to be something that happens towards the middle or the back half of the year. So stay tuned. But I do think that we’re not short opportunities, I can tell you that much.

Jim Evans: No. I think Nick you nailed it. I think it’s a function of banks and organizations bringing these packages to market and what the lead time is on a lot of that stuff. You’ve got the smaller competition coming in with the bullish view on oil pricing, which creates some volatility in terms of the ground gain, what I’d say, I mean even just looking at some of our April activity as we’ve been making some pretty strong headway in that regard, being able to pick things up across all three of our respected basins. And then to Nick’s point, it’s really just going to be a balance of what that quality looks like, seller expectations can be wildly different, especially in a volatile commodity environment. And so for bone along at relatively static pricing for an extended period of time that generally level set expectations and narrowed spread, but if you have a material step up or a material step down in the short term, that’s going to just widen it.

Paul Diamond: Understood. Thanks for the clarity. And just a quick follow-up. You’ve talked pretty at length about the product improvements on the oil side, what does your perspective sit on the net gas side of I know it’s a much small perspective or a much smaller piece going forward? Should we expect to see the a similar cadence in your view?

Nick O’Grady: Yes. I’ll just tell you from my perspective and I’m not an engineer here, but our Marcellus assets have outperformed really from the get-go. They have outperformed our internal modeling. They’re really every quarter since we’ve owned them. Literally, I think there’s not a month tell me I’m wrong, but they have done a excellent job and I think we’ve had a little bit less development than we had initially modeled. But the decline rates have been shallower. They have just consistently outperformed, no wonder if gas is $1.80, because they just simply don’t decline. I don’t know if you want to add to that?

Jim Evans: Yes, that’s right. At EQT, we completely changed the design of these wells from when we originally hockey assets. They’ve widen spacing, change the completion of time, changed the pullback methodology. So these will just continue to hang in much better than we had expected. And obviously, there’s not a ton of activity that’s been happening out there. And so our modeling is still based on old methodology, and we continue to update that as we go and we see more. But yes, the Marcellus stuff just continues to outperform. And the Utica be in the first quarter as well. Those wells continue to clean out better than we had expected. So that was a nice outperformance there as well.

Nick O’Grady: And while it’s not huge for us, if you actually model out our Appalachian asset, just how much cash flow it has generated for us over the life of its ownership, it has been an amazing investment for us. It is paid out in less than a year and then just continues for very little capital investment continues even with low gas prices to generate significant cash flow for us. It’s been a great investment.

Paul Diamond: Good. Thanks for the clarity.

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

Noel Park: Hi, good morning. Just had a couple. I was wondering, do you have any sense of maybe where incremental service cost trends are heading in your basin feel like so far in the earnings season, we’ve been getting sort of a mixed picture, just depending on location and type of service. So any thoughts here would be great.

Nick O’Grady: I would say no, very modest deflation we’ve seen year-to-date, but I would imagine as oil prices have increased, I would guess that’s a flattening trend.

Noel Parks: Great. Fair enough. And I was just wondering, you did mention what you’ve all seen was your gas in the Permian and so forth. And I believe over time, you’ve discussed that you are pretty vigilant about the state of infrastructure when you’re looking at potential deals out there and look to steer clear of areas where you have many questions or doubts. I’m just wondering, are you getting deals brought to you that fall into that category these days?

Nick O’Grady: Yes. I think specifically, a lot of assets in parts of the Delaware, you have to be very wary around, particularly as you get parts that New Mexico and other parts where they might be in. They might not have access to midstream systems and you have to understand that going into it. You need to know who your operator is. And so absolutely, all of that goes into the equation. Do you know who are your operators? Do they have firm access? Are they interruptible? Can they be kicked off the system all that stuff. That’s why you hear us talk a lot about this, but knowing who your operator is knowing what kind of midstream access they’re going to have is critical. I think as an issue overall, I think it’s something that it’s the Permian Basin.

So it will, over time, get solved, but I think it’s going to be chronic for some time. In the end, it’s a minor economic none, meaning it doesn’t really destroy the economics of the wells. It just is something that we can model in and still make the level economic, but it certainly doesn’t help.

Jim Evans: That’s right. You just make sure that you’re modeling it. The costs as well as the development time stand.

Nick O’Grady: We were trying to buy something in helping or something like that, it might be a different equation, but that’s helpful.

Noel Parks: Great. Thanks a lot.

Operator: That concludes our Q&A session. I will now turn the conference back over to Nick O’Grady for closing remarks.

Nick O’Grady: Thank you all for joining us today. We appreciate your continued support and look forward to touching base with you in the coming weeks.

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