Northern Oil and Gas, Inc. (NYSE:NOG) Q1 2023 Earnings Call Transcript

Northern Oil and Gas, Inc. (NYSE:NOG) Q1 2023 Earnings Call Transcript May 5, 2023

Operator: Greetings, and welcome to the Northern Oil and Gas First Quarter 2023 Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. . As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Evelyn Infurna, Vice President of Investor Relations. Thank you. You may begin.

Evelyn Infurna: Thank you, Operator. Good morning and welcome to our first quarter 2023 earnings conference call. Yesterday, after the market closed, we released our financial results for the first quarter. You can access our earnings release and presentation on our Investor Relations website. Our Form 10-Q will be filed with the SEC with the next few days. I’m joined this morning by NOG’s Chief Executive Officer, Nick O’Grady; our President, Adam Dirlam; our Chief Financial Officer, Chad Allen; and our EVP and Chief Engineer, Jim Evans. Our agenda for today’s call is as follows: Nick will provide his remarks on the quarter and on our recent accomplishments, then Adam will discuss an overview of operations and last, Chad will review our first quarter financials.

After our prepared remarks, the executive team will be available to answer any questions. Before we go any further, let me cover our Safe Harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by our forward-looking statements. Those risks include, among others, matters that we have discussed in our earnings release, as well as in our filings with the SEC, including our Annual Report on Form 10-K and our quarterly reports on Form 10-Q.

We disclaim any obligation to update these forward-looking statements. During today’s call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliations of these measures to the closest GAAP measures can be found in our earnings release. With that, I will turn the call over to Nick.

Nick O’Grady: Thank you, Evelyn. Welcome, and good morning, everyone, and thank you for your interest in our company. Given the strong consistent results and lack of big changes this quarter, I’ll be more brief than usual. I’ll get right down to it with only three key points. Number one, stellar execution. In our first quarter of the year, NOG’s national diversified model delivered once again with better than expected production and cash flows. We continue to fire on all cylinders. Our Mascot acquisition was closed on time and our assets are on track to deliver growth throughout 2023. Generated record adjusted EBITDA in the quarter and record oil and total volumes, despite significantly lower commodity prices. Even with the closing of our Mascot acquisition this quarter, our LQA leverage ratio was down sequentially.

Our capital spending is right on track at about 28% at the midpoint of our guidance and in line with our anticipated 60% first half waiting. In a year of notably weak gas pricing, our oil properties have picked up the slack with our oil cut rising materially in the past few quarters. Number two, growth. In the middle of year for commodity pricing, we are seeing tremendous opportunities on all fronts, from our organic properties, from our ground game, and from an ever expanding variety of growth prospects. Given our size, scale and diversity is the largest national non-op franchise, we are unique in having access to the best of the best properties across both commodities and multiple basins. Additionally, we’ve expanded our bolt-on opportunity set beyond our traditional fractional non-op asset acquisitions.

We are pursuing other growth avenues, including partnerships directly with the operating groups, as seen with MPDC, co-bidding and M&A as a partner to operators with similar economic discipline, and other unique structured solutions to deliver solid returns for our investors and drive the compounding of returns over time. Adam will talk about it further. But we continue to make traction with our operating partners as the superior capital provider for the co-development of oil and gas assets. We have the scale and the capital to provide solutions for these operators in ways other can’t, and we pride ourselves on being a straightforward and reliable counterparty with a track record of execution. Number three, capital allocation. Our goal is to provide our shareholders with the highest possible total return over the long-term.

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We have implemented a multi pronged approach including a share repurchase program, repurchasing debt securities at discounts, and increasing the cash dividends for our common stockholders. We recently announced a 9% increase to our common stock dividend for the second quarter of 2023, our ninth straight increase. Additionally, we tactically repurchased common shares during periods of volatility. Since we initiated our dividend program and share buyback in mid-2021, we’ve returned well north of $200 million to investors. And our view at NOG is that our scale should help us build a shareholder return program that can grow over time. As always, we’ll be mindful of risk and leverage, but the power of what we built should continue to deliver an attractive risk adjusted total return as the company under our management has consistently done over the past five and a half years.

During our tenure, NOG’s total return outperformance versus the upstream sector has been significant. Driven by a capital allocation strategy included in dynamism. The flexibility inherent in our strategy, as well as our business model has allowed us to adjust our capital allocation to where the greatest opportunities exist at any point in time, all the while providing a solid and growing cash return via the dividend. We continue to see this as superior to more dogmatic return programs, and the results in the marketplace speak for themselves. In closing, 2023 is off to a strong start for the NOG team, and we remain confident that we can continue to deliver growth opportunities in the coming years. I will remind you, as I always do, that we are a company run by investors, for investors.

With that, I will turn it over to Adam.

Adam Dirlam: Thanks, Nick. The first quarter was seasonally strong as we kicked off 2023’s operations. Turning lines for the quarter were as expected, adding approximately 13.1 net wells to production organically, which was up over 20% versus Q1 of last year despite multiple periods of inclement weather. The Williston made up approximately three quarters of the organic activity driven by larger working interests with several of our top operators. The closing of our Mascot joint development project in January added another 16.4 net wells of current production and we continue to be encouraged with the project’s overall productivity. So far, on average, actual production results have outperformed our internal estimates by 10% in the Mascot project.

The productivity and outperformance across each basin are testaments to our capital allocation process where we target areas and operators that we believe will deliver a superior return on capital. The drilling and completing list finished the first quarter with 59.3 net wells, up from 55.4 net wells where we started the year. During the quarter, we added 14.1 net wells across the Williston and the Permian via organic and ground game activity with an additional 9.2 net wells added from our Mascot project as drilling continues. First wave of Mascot completions since we joined the project is slated to turn in line over the next couple of months with the second batch set to start completions in the fourth quarter. Our D&C list grew during the quarter and our near-term backlog of well proposals has also been consistent.

During the quarter, we received over 200 well proposals are highest on record, albeit with varying working interests. Well cost inflation has been consistent with our recent AFEs. We are seeing leading indicators of deceleration and we expect to realize that towards the back half of the year as operators continue to reset terms of service providers. The quality of the proposed wells also remained high as we had over a 95% consent rate during the quarter. The M&A landscape continued to evolve during the first three months of the year. Large asset packages were a bit slow coming out of the gate and the quality of what came to market was not particularly enticing. As such, we passed on a number of potential transactions while continuing to search for opportunities that are better aligned with our strategic positioning and return profile.

We are being patient and are beginning to vet in more compelling and higher quality opportunities. NOG’s total addressable market has expanded given our size and scale, and we have been invited to COVID on a number of operated prospects, as well as explore sell downs from operators looking to partially monetize and remain as operator. These opportunities are not necessarily available to smaller non-ops as size and scale are required to participate in these large asset packages. This puts NOG in a unique position where we can have a seat at the table with our operating partners, determine a long dated development schedule, and underwrite accordingly. Looking at the entire landscape, there are currently 14 opportunities we are reviewing across our basins of interest, totaling over $6 billion across large asset packages and joint development structures.

Volatility in commodity pricing was also a headwind during the quarter and there were several M&A processes that were put on hold. While the Bid/Ask spread was alive and well, we pivoted to our ground game to target drill ready opportunities in situations where most sellers needed to transact to manage budgets and capital outlay. Taking advantage of that backdrop, we reviewed over 140 opportunities and closed on 10 transactions during the quarter, picking up 2.6 net wells and 369 net acres. We’ve maintained that momentum moving into the second quarter for the backlog of attractive deals under negotiation. Our Midland Petro transaction last year has shown the art-of-the-possible and while we’re exploring large joint development agreements, we’ve also been able to bring this concept to our ground game, putting together one-off operated units and bringing in operators to develop.

While our total addressable market for non-operated properties is as large as ever, we remain steadfast in our discipline. We will never be focused on growth just for growth sake. Our strict underwriting remains focused on returns. With that, I’ll turn it over to Chad.

Chad Allen: Thanks, Adam. I’ll start by reviewing key first quarter results, which outperformed our expectations despite a volatile commodity pricing backdrop. Our Q1 average daily production top the high end of our expectations of 87,385 Boe per day, an 11% increase over Q4 of 2022. Oil volumes were up 12% sequentially over Q4 as we experienced better well performance across all basins and the addition of our MPDC acquisition which closed in early January. Our adjusted EBITDA was $325.5 in Q1, a record for our company. Our first quarter free cash flow was robust at $84 million despite growing activity and commodity price volatility. Oil realizations continue to be better than internally expected as Q1 differentials came in at $2.57 per barrel due to continued strong in basin pricing and having more barrels weighted towards the Permian, which are typically priced tighter.

Natural gas realizations were 142% of benchmark prices for the first quarter, substantially higher than our stated guidance due to the stabilization of NGL prices and some of our Permian gas tied to West Coast deliveries versus Waha. Balance sheet remained strong. Leverage is trending in the right direction and is down sequentially on an LQA basis versus year-end even with the closing of our MPDC acquisition, which added approximately $320 million to the balance sheet. Our net leverage ratio should return to our target level by the end of 2023 as our acquisitions contribute to our operations and we are able to organically delever. We still have over $1 billion of liquidity in the form of unused revolver and borrowing base capacity. Since year-end, we have retired $19.1 million of our 2028 notes at attractive prices and have reduced our outstanding revolver balance by approximately $50 million post closing of the MPDC acquisition.

Mindful of our net leverage target, we will continue to look for ways to efficiently reduce leverage if market opportunity arises. We are reaffirming our CapEx guidance and reiterating the amount and cadence of our CapEx spend. As a refresher, the range is $737 million to $778 million for 2023. Our Q1 CapEx investment was $212 million, represented approximately 28% of our CapEx guidance at the midpoint, keeping with our expectation of realizing 60% of our annual spend in the first half of the year. With respect to cost inflation, year to-date, we are within our internal expectations, but as Adam mentioned, we are beginning to see early indications of stabilization and with the continuation of weak natural gas prices, we anticipate the potential for a reduction in rig count and subsequent cost savings over the next six to nine months at current trends stay in place.

We are not adjusting our 2023 production guidance and continue to expect a range of between 91,000 and 96,000 Boe per day for the full year, barring unexpected disruptions. With respect to our production case for the year based on our current TIL schedules, we still expect fairly ratable increases each quarter. With slightly more modest volume growth in Q2 and an acceleration into Q3 as the next wave of Mascot wells come online. We have made minor adjustments to our guidance on gas realizations and LOE. On differentials, we are upping our gas realizations to 80% to 90% given stronger than expected NGLs thus far, but keeping our oil differentials the same for the time being as in basin pricing in the Permian and Williston remains volatile. LOE was adjusted for higher NGL prices realized year to-date.

We’ll update you in the coming quarters if we anticipate material changes. 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. Ladies and gentlemen, at this time, we will be conducting a question and answer session. Our first question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your questions.

Scott Hanold : Yes. Thanks. Hey, Nick and team. Just a question on the shareholder returns, obviously, you all were able to hit your dividend target much sooner than anticipated. And you’ve flexed several different aspects of shareholder returns. How do you see that progressing like through 2024 — into and through 2024? Are you looking to target maybe another dividend that is driven by rate? Or do you continue to look at buybacks as an option that increasingly becomes more important?

Chad Allen: Morning, Scott. We’re obviously proud of having grown our base dividend and achieved and exceeded our target plan well in advance. And as you know, we have active stock and debt repurchase authorizations that allow us to take advantage of market opportunities as they arise. But I say this virtually every quarter, but dynamic capital allocation is critical. In our opinion, its creating long-term value. And the ability and flexibility to act when things change. So I think, you can trust us to be nimble as we evaluate where we deploy our free cash flow. But the obvious places for the future are dividends, share and debt repurchases and reinvestment in the business. So I think we’ll take it all in stride.

Scott Hanold : Okay. Thanks for that. And I think Adam, you had mentioned that a lot of opportunities coming in the door. You’ve turned down a number of these just because it sounds like maybe like a Bid/Ask kind of a spread. Or do you guys have a higher bar now with the success you’ve seen from Mascot that fundamentally means that some of these opportunities that historically have come in need to really kind of do a little bit more to compete versus the JV opportunities or partnerships?

Adam Dirlam: Yes. I mean, we look at everything on a risk adjusted basis. And so, the specifics of any particular transaction and the assets and maybe some of the other kind of qualitative details are going to go into that underwriting. I think the fact that we have so many of these opportunities in front of us, and I feel like a broken record every quarter is saying as much, but it gives us the ability to be picky, right? And so, that’s going to come out in our conservative underwriting as well as the way that we approach any given particular transaction, as we’re not going all in love with any deal, because there’s plenty for us to choose from.

Scott Hanold : Right. And maybe my underlying kind of question was. Do these JVs and partnerships, do they tend to be better return opportunities than say the historical buying of non-op working interest, we’ll say?

Nick O’Grady: I think they’re just different. I’d say, in general, the short answer would be yes. But it’s a combination — Adam used the term risk adjusted. I mean, you have to think about you have concentration, both benefit and risk, you have line of sight and development timing risk. And when you combine all those things together, that’s really what, from an underwriting perspective, what really will drive the decision making in. So what I mean by that is that you could buy a non-operated fractional business with 2% working interest across those things, across the board. And you kind of underwrite it to a very high discount rate. But ultimately, it takes a lot of activity to be impactful on those assets if you buy something with a 20% or 30% working interest that has different sets of risks.

But especially when you’re working alongside the operator, the timing and confidence in that underwritten value, it can be a lot higher. But I would tell you that generally speaking, when you’re talking about bigger ticket items, the discount rate is going to be wider. You are just simply going to be able to have a — Adam?

Adam Dirlam: Yes. And that’s a function of knowing who your competition is. And as we see larger and larger non-op types of transactions that’s going to effectively filter out a lot of the competition that we would otherwise see maybe on some of the smaller ground game things. That’ll give the opportunity to raise our discount rate and still get things across the finish line.

Nick O’Grady: And I think not to be too tongue-in-cheek, but anyone who tells you that, we’re picking up the small things that no one else is paying attention to. I think that’s not true. Because I think the smaller and the lower the barriers-to-entry, the more competitive with any processes.

Scott Hanold : Appreciate that. Thanks.

Operator: Our next question comes from the line of Neal Dingmann with Truist. Please proceed with your question.

Neal Dingmann: Good morning, guys. Thanks for the time. Nick, my first question for, and Adam, just on the Mascot project. Specifically, could you discuss just since you did, I guess it closed out terribly long ago, but since closed any update on the development plan or just maybe what returns are looking like there? I know its a quite interesting project when you first announced like it was mid last year now. Just wonder how that’s progressed?

Nick O’Grady: Yes. I mean, I would just give an overall. I’ll let Adam talk about the details, but I’d say, overall, we’re really pleased. We take every thing day-to-day, month-to-month, but everything so far has been wonderful. I think the productivity, obviously, some of this is just conservatism on our end, but the productivity has been better than we had certainly underwritten so far. I’d say, they’ve been hammering away in the field and doing a great job so far and everything moving according to plan. I don’t know if you want to add to that.

Adam Dirlam: No. That’s right. I mean, I alluded to the fact that, outperforming expectations were about 10% on current production. We’ve got about 9 net wells in process. The drilling and the spudding of the wells is humming along and that will be ratable across the rest of the year. And then, from a completion standpoint, in the next couple of months, they’ll be getting after that. And so, you’re talking about — excuse me, about half those WIPs give or take, tailing in late June, kind of early July, and then kind of that next wave coming into 2024, give or take. So down the fairway with no surprises, pretty much everything that we underwrote.

Neal Dingmann: No. That’s good to hear. I’m looking forward to that. And then, just on, Nick, I think it was in the press release. You continue to talk about the record number of just proposals you’re seeing. Maybe could you just speak to that? I mean, again, I guess my question around it is, are you seeing more today than you did even a year ago? And if so, has sort of what your restrictions are when you’re looking at these maybe talk about what the requirements are? How much tougher they’ve gotten since the company is now much larger?

Nick O’Grady: Sorry. I want to make sure I’m answering the right question. You’re talking about like, just well proposals or you’re talking about like transactions and opportunities. I just want to make sure.

Neal Dingmann: No. I’m just wondering exactly just on well proposals, like, how many are you getting in, when you and Adam are looking at it now. Is the bogey to hit how much higher would you say it is these days versus a couple of years ago?

Nick O’Grady: Yes. I mean, I think But, I mean, I think we had 200 gross proposals in the first quarter. Yes. I mean, we had a record number, and sometimes these could be a fraction of a percent of an interest, so 40%, 50% in some cases. And what I tell you is it goes into the same meat grinder. It goes right through the engineering group. Every single one goes through the same process, whether it’s a tiny bit of money or a large amount of money net to us. And I’d say overall, the fact as we’ve span, you’re talking about a million gross acres now, plus or minus four-hour assets. So, you’re seeing tremendous amounts of activity even as commodity prices have weakened somewhat. But, if we’re doing our job, just like any portfolio manager, if you’re buying lands in the right places, you’re going to see consistent development.

And I think we’ve certainly seen that. We’ve continued to high grade and already high graded set of acres over the last several years. And so, I think we’ve seen activity that’s been at or above our expectations. The net interest in those can vary wildly from quarter-to-quarter, but I don’t know. Adam, you want to add anything else?

Adam Dirlam: No. I think you nailed it. I think it’s just a function of the effective management of the portfolio and your working interests are going to vary, and you’ve got your plan. And so you can hit the gas where it when you need to and you can bump the brakes on the ground game when you need to, and it’s all going to depend on what the organic asset is pulling and then the opportunity set that seeing and we just continue to manage it day-in and day-out.

Neal Dingmann: Perfect. Thanks, guys. Great work.

Adam Dirlam: Thanks, Neal.

Operator: Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question.

John Freeman: Thank you. First I want to touch on was just on the cost inflation side. I know you all had budgeting for kind of 7.5% cost inflation this year. And I know that last quarter, Nick, you mentioned that you’re really seeing more of the cost creep in the Bakken. We had some operators that were seeing some longer-term service contracts that were rolling off relative with Permian, which you had said was a lot steadier. And I guess, I’m just wondering if in the first quarter when as Adam mentioned, you all were like three quarters of your activity was in the Bakken. If that maybe skews a little bit of the cost inflation that you’re seeing relative to the rest of the year when it’s obviously a lot more balanced with Permian and Bakken especially the Mascot continues to ramp?

Nick O’Grady: I mean, maybe a touch, John, I’d say that, we have to think about how fragile the overall, let’s — I don’t want to get on my macro horse here, but the overall market in general is quite fragile right now, right? And I’m not talking about the oil market per se. I’m talking about the entire capital markets. And so — and you’ve had material selloffs to natural gas. You’ve had oil go through probably two hard selloffs in the last five months. But like anything else, this takes time. And so, you’re correct. We definitely have seen cost rising year-over-year and certainly even since, say last fall. As Adam pointed out, the biggest challenge last year was not necessarily cost, but actually logistics like getting items.

And I think I remember on a prior call saying, hey, building a steel pipe or sand or not, things that are going to be in long-term short, it’s just going to take time and those thing. Those logistical things and shortages of materials have largely passed. I think where it goes from here is really going to be determined by as dumb as it may sound. It’s going be determined by the price of crude. What you find is that overall EP margins stay relatively static over time, whether oil’s a 100 or if it’s 65. And so, if oil prices are to materially weaken, I would expect over time, you’re going to see material reductions to margins for service providers as that overall activity falls. If prices hang in there and do their thing where they are today, I still think through drilling efficiencies, we continue to see operators drilling longer and longer laterals and larger amounts of wells at a pad level at any given time.

And those will add up to material kind of collateral foot savings over time. And so, I would expect you probably can see some relief as time goes on. And, yes, I think as our program moves to be more balanced over the year, I think you’ve definitely seen a material slowdown in the Permian specifically in inflation of well cost. And so, I think that will ease it over time. I think to the extent that we’re going to see any relief is going to — we’re going to have to wait and see over time. I think, you know, everyone from a service provider to and an operating group are going to have their chest puffed out when you see periods of volatility, and we’ll see how that plays out.

Adam Dirlam: Yes. John, I think the only other dynamics that I’d add to that is just kind of operator kind of cadence and flow. And you mentioned the Williston, Continental and Conoco, we’ve seen the most activity within the quarter and just looking at kind of their weighted average AFPs, it’s certainly encouraging. And Continental being one of our most active operators and being ratably lower than the overall based on average.

John Freeman: Great. And then just my follow-up. Adam, you kind of gave us an idea of how the production cadence kind of looks over these next few quarters and gotten clear on sort of the CapEx breakdown of that 60% in the first half of the year. But I was hoping to maybe get a little bit more color on the till cadence, obviously last year, it was sort of averaged 10 TILs the first half of the year and had the big step up in the second half of the year. And then, this year, it sounds like a kind of build that you go throughout the year. Can we get any more of a breakdown on how you kind of get to that 80 to 85 TIL guidance for the full year? Kind of how the remaining quarters look, just rough numbers?

Nick O’Grady: Yes. I mean, without going specifically into the numbers, John, just because I don’t have those sitting right in front of me. But I would expect you’ll see consistent to slightly higher activity this quarter, and that should generate some modest growth in the third quarter. Obviously, you really — early third quarter, you should have the bulk of the first wave of Mascot wells on, so you’re going to have a material step up in the third quarter. And the CapEx doesn’t really track our TILs. Like, the money we spent this quarter for 13 TILs isn’t really necessarily going to those wells. Those wells were largely — that money was spent last year. And so that’s why the waiting is upfront, because the way we accrue on a on a percentage of completion basis, right, the TIL is just sort of the icing on the cake at the end.

So the capital we spent in the first and second quarter will really go towards that waiting in the back half of the year. And so, I would imagine even from a production and a TIL cadence, which will be more closely aligned than the CapEx cadence would that you’re going to see a more material step up in the third quarter and into the fourth quarter than you would necessarily in the second even as you’re drilling a lot of those wells. And it also to be candid depends on what time they come on in the quarter. If we have a bunch of wells come online in June, that’s not going to have a huge impact on the second quarter necessarily. So we try to be very mindful of that, because those drill schedules move around all the time So, really, I think you would see probably, and Jim correct me if I’m wrong, but I would say the third quarter is probably going to be the most active quarter from a from a TIL cadence this year with the fourth quarter not far behind.

John Freeman: That’s perfect. Thanks, Nick.

Nick O’Grady: Yep.

Operator: Our next question comes from the line of Derrick Whitfield with Stifel. Please proceed with your question.

Derrick Whitfield: Thanks, and good morning all.

Adam Dirlam: Morning.

Derrick Whitfield: With respect to the larger operator specific opportunities you may pursue, how important is line of sight activity and investment pacing in your evaluation process? And would you generally require a modestly greater return to offset operator concentration risk?

Nick O’Grady: And Derrick, just to be clear, you’re talking about, like, co-bidding assets or partnering in some sort of partial sell down. Is that kind of where the question is based?

Derrick Whitfield: Yes. And I’m thinking more like the Mascot opportunity. I was directionally seeing that was the 14 larger packages as you’re referring to?

Nick O’Grady: Yes, I mean, the answer is all those risks weigh in to it. What we really focus on is alignment with the operator, and that can be through governance. It can be through what share of what everyone owns, and it can be a combination of all those things, with concentration risk comes just that, But the line — we are a an IRR, NPV, and risk adjusted return on capital weighted company. That’s how we evaluate these projects. And so, line of sight is also incredibly important. But that line just because you have line of sight, you need to make sure that you have governance that they can’t change their mind and not do that, because that’s obviously an easy way to store values. So we try to weigh all those things contractually and to ensure that the operator is aligned to do the same thing that we would want to do with our money.

Adam Dirlam: Yes. And I think it’s understanding the needs and the wants of the operating partner, right? Because each individual operator is solving for something different. We’ve had conversation with operators that say, hey, Northern choose your own adventure. You tell us what you want to drill in order to come up with the best number that you can. And then you’ve got other operators that want more autonomy in terms of what that drill schedule looks like and we’ll underwrite it accordingly and take those factors into consideration.

Derrick Whitfield: That’s great. And then, building on John’s earlier question on service prices Are you guys seeing any improvement in well cost across any categories on a leading edge basis? And then separately, regarding your Continental commentary, does that price advantage appear to be efficiency or market pricing based?

Nick O’Grady: On the latter part, what I could tell you is that there’s a huge difference between a one or two rig private company and a large several hundred thousand barrel a day company from a both a technical perspective and from just a sourcing. I mean, you’re talking in some cases millions of dollars per well. And that means, it’s — because the small guy is borrowing a frac crew in between time and sourcing their tubulars on the spot and all those sort of things. And so, that’s why the bulk of our operation, general, we’re a smaller company by public standards, but our operating group is mostly large companies. It doesn’t mean there aren’t private companies that are incredibly good drillers and can make up for it. In other ways, there are exceptions to every rule.

But by and large scale is incredibly important from a sourcing perspective. There’s just a big difference between a company like Amubert , and that operates a lot of our Permian assets with, you know, 20 rigs running versus someone with a stand up rig and sourcing things on the spot. Everything from midstream contracts to drilling costs to every ancillary cost along the chain.

Adam Dirlam: No. That’s right. I think, having conversations with our operators, they’re seeing some really fund the tangibles. Not necessarily having to put down deposits in order to secure supplies, all of that kind of comes through from a pricing standpoint as well, from an inflationary standpoint.

Derrick Whitfield: And on the leading edge, is there anything worth discussing?

Adam Dirlam: No. I mean, I think it’s the tangibles that really we’ve seen in the release. There’s been some drilling contract and those sets of things that we’ve seen that make up the largest percentage the overall AFE? No. Does it help? Yes.

Derrick Whitfield: Makes sense. Very helpful, guys.

Adam Dirlam: Thanks Derrick.

Operator: Our next question comes from the line of Donovan Schafer with Northland Capital Markets. Please proceed with your question.

Donovan Schafer: Hey, guys. Thanks for taking the questions. I want to start off talking about — it’s a little bit kind of further looking. I mean, this would be talking about one to maybe even like three-year time horizon. But I want to focus on infrastructure and pipelines and so forth. So obviously, you have pretty big stakes in some of the major basins, the Permian, the Williston and then you’ve got a certain amount involvement in Appalachian. And these are all areas that have potentially meaningful benefits from some addition to pipeline infrastructure, maybe LNG capacity in the Gulf. Just other types of developments like that? And then, you’ve got the situation now like I also cover a lot of the kind of clean energy names.

And I was at a conference this week in California with commercial fleets are getting forced to like electrify or do something. And they’re freaking out because of the infrastructure. Like they are – I mean, it was like just shy of panic in terms of being able to hit targets that are being legislated and so forth. So now you’ve got Democrats and Republicans, it’s like what Mansion tried to do. Try and get like a permitting reform something where it seems like they might be able to get Republicans on board or the key to it could be giving concessions on traditional sort of oil and gas type infrastructure, making it easier for all that to happen. So I’m just curious, if you guys have any kind of unique insights if this is something you follow.

There’s kind of the bigger picture macro political stuff. But even anything worth pointing out like even near-term at the regional level, I think some couple of pipelines are coming on in like South and parts of Texas. But like the Williston or Appalachia, anything at the regional or national, but just kind of bigger picture what you pay attention to and what you think could be beneficial from a pipeline infrastructure standpoint?

Nick O’Grady: Well, we do spend a decent amount of time and money on understanding the political land shape and as it pertains to infrastructure. Because as it pertains to traditional energy and oil and gas, the bulk of the impediments to the business have been attacking infrastructure projects in order to choke off supply. And generally, to the detriment of American citizens, that’s a larger conversation. But I tell you as it pertains to the three basins that were active in today, the Williston is candidly oversupplied from a takeaway capacity. You’ve seen that in better pricing over time. And the basin as a whole, while our volumes are set to hit records, the basin as a whole is not growing tremendously. And so, I don’t think we have a ton of concerns in the Williston.

In terms of the Marcellus, while there you have Mountain Valley pipeline and other things that that could potentially change the game there or even LNG expansions. Our base case assumption has been nothing gets better ever. And that’s how we generally underwrite there. That’s generally our view. It’s just been challenged. It’s both political, geographical, all of those things going into above. Do I hold some optimism that at some point, logic will prevail sure, but we’re not counting on it. And in the case of the Permian, you do have a ton of LNG expansions coming on that the gas infrastructure in particular is quite tight right now, and we’ve had that view internally for some time. But those logistical issues are getting solved in real time.

And I have no doubt in my mind that that we we’ve even seen operators find ways around it. As Chad mentioned, rerouting gas especially because the bulk of our Permian assets are in New Mexico, which has more options. And so, money is amazing thing and motivates people to solve problems and where there’s capital. And so, I don’t think we have a ton of long-term worries within the Permian Basin. And I think given its proximity to the Gulf Coast relative to other places where business is largely still open. I think LNG expansion over time will both help ease the glut of natural gas over not necessarily this year or next year, but over a multi year base basis, as well as infrastructure projects getting ahead of it.

Donovan Schafer: Okay. That’s helpful perspectives. It’s good to know you’re not baking anything and that’s a good thing for me to know as I look at things.

Nick O’Grady: Yes. I mean it.

Donovan Schafer: It’s nice to know there’s the conservatism there. I’m optimistic. I mean like, or I’m hopeful, let’s call it, hopeful. But okay, that’s helpful to know at least you’re not baking anything in there, which is good. So I want to ask for the record level of M&A opportunity that – I mean you guys talked a lot about this and you gave out the number, $6 million kind of an opportunity. But I don’t remember getting like a dollar number. Maybe you did and I’m just blanking on it, before like last quarter. So, can you give us a sense like the magnitude of how that’s changed since the last update? Is it — was it $5 billion a quarter ago? Or like what’s been the magnitude change over the kind of near-term or short term time frame?

And then, with respect to magnitude, does that mean like if the opportunity had doubled? Should we think of it as like that kind of like doubles your appetite and you’re like, oh, we can scoop up 2x the amount of things, we wanted to scoop up. Or does it translate more into – or just skew more towards quality, where you’re like, well no, we can just – it doesn’t change as much of our appetite per se. But like, wow, now we can really beat guys up and bargain and negotiate and get some good economic terms?

Nick O’Grady: I think like any business, the more optionality you have, generally, the more opportunity you have. So, if you have access to more opportunities and you have scale to participate in more opportunities and those barriers-to-entry rise in those opportunities, you’re going to have better return prospects. And as we’ve scaled, we’ve seen nothing but a benefit. But in terms of the — we have, in the past, talked about our pipeline and it had — this is certainly probably a record level. But I’d use an analogy to this, which is, like, take the real estate market and take commercial real estate as an example. Whatever that total addressable market is in the United States, there’s only a smaller portion of minority interest donors across all of those commercial buildings.

There might be billions of people that own 20% of a building or something like that. But if you’re large enough and you have the scale enough to talk about, working with the majority owners of those buildings to own it, you’re addressable market is growing in kind. And I’d say that that’s where we are in the life cycle of our company. And so frankly, I don’t think we could even really tangibly –you’ve got hundreds of billions of dollars worth of oil assets in the United States and we’re really just scratching the surface. But as Adam and I tell our investors a lot, you can carve a working interest out of anything. You can carve in an already interest out of any asset in oil and gas. And so, what we’re finding is that total addressable market has increased markedly from our sizing.

But if you want to go back to kind of how we select this stuff — M&A is one of those things that is about having a thousand yard stare. We don’t fall in love with anything. We don’t do something just because strategically we want to do it. We do it because when we can earn as much money as we require ourselves to or more. And when you do that, you can make good decisions and the thing is you’re not going to have to take a lot of swings at bat. I mean, I think our success rate on the ground this past quarter was about 5%, but that still adds up to tens of millions of dollars. And so, no different for corporate M&A. It might seem like it’s easy, because we’ve obviously done $1.7 billion in just the last two years, but it really masks a lot of failure, which is you’re probably looking at three or four times multiplier to that when you back into the success.

But I will say, we’re moving to avenues in which we remain one of the few people that can participate in those and that allows us to target the returns that we want and also broaden the horizons. I don’t know if you want to add to that?

Adam Dirlam: No. You covered it.

Donovan Schafer: Okay. And then just one last question and I’ll take the rest offline. Is the NGL to gas ratio, I know is kind of above historical levels and that showed up kind of nicely in this quarter. I also know that’s a hard thing to predict and know exactly where that’s headed. I mean, the only one I know, I think Rusty Braziel is the only I know who’s like actually wrote a book on it. And knows the stuff inside and out, but kind of beyond my skill set. But can you tell us like what you look at — I know it’s like the next to impossible for you guys to kind of guide on anything like this. But just – I know you don’t control over it, right, like when the operators are electing to go ethane rejection or keep it or do the extraction and so forth.

But what are you like watching and how are the trends and what you’re watching that underlay this. If you can just elaborate all on that? And if there’s anything like we could watch or monitor that helps, give a sense of where it’s going?

Nick O’Grady: Well, I mean the NGL basket trades every day, the mix of which we receive varies from day-to-day, you mentioned ethane. And I think rejection is probably at a high. There are limits to how much you can do. Some operators extract it one way or the other because of contracts they might have entered and you’re going to get a worse realization in a market like that when that happens. But ultimately, you’re talking about probably about four variables. You’ve got in base and differential, you have the NGL basket as a ratio to gas, and then you have to fix gathering and transportation costs. And then in some cases, you have the percentage of proceeds piece, in which there is an added cost as those go up. Chad, I don’t know you want to add to that?

Chad Allen: No. I think here you said it right. I think, we would expect our guidance just be more realistic going forward. Obviously, gas differentials are volatile. And then the recent weakening in oil prices will have effect on kind of the go forward price, we believe. I think rejection, obviously played a role this quarter. As well as kind of the takeaway to the West versus Waha in the Permian for us.

Donovan Schafer: Okay. That’s helpful. Thanks guys.

Operator: Our next question comes from the line of John Abbott with Bank of America. Please proceed with your question.

John Abbott: Hey, thank you very much for taking our questions. First question is on capital allocation. Appreciate you got a dynamic process here of allocating towards growing the dividend, paying down debt, buybacks. But when you sort of see what investors can sort of earn as far as a return on cash, does that change the calculus at all? Does it make grabbing maybe makes potentially buying back shares or reducing debt more attractive in the near-term. So, how do you think about that?

Nick O’Grady: I think we think about it as — you mentioned the word dynamic. We think about it dynamically because those inputs change every day, right. The stock price versus our ability to reinvest capital versus taking risk off by paying off debt to ever increasing dividends and that balance matters. And I also think that, like anything in life, too much of anything is not a good thing, right? And so we’ve really tried to keep it balanced. I think in the coming months, we’re going to spend a lot of time. We’ve laid out we viewed as a long-term plan a couple years ago. And we really need to think about what’s next for us in the next couple years. And I think it’s going to be a balanced approach to all of those things, right?

And I think we’ll spend a lot of time with our board and our advisors to really go through. Because ultimately, I think certain things come in and out of vogue from special dividends to dividends to buybacks and they tend to oftentimes reach a fever pitch and we’ve really tried to issue that and think really long-term. Because when oil was a $100 last year, a special dividend sounded like an awesome plant until prices pull back and then those special dividends go down. And you may have foregone other opportunities that might have created more value for the long-term. And so, we really try to be very, very careful and methodical about this. That’s why we’ve really stuck to a base dividend. We do believe we have a path to grow it over time, as well as to leave enough meat on the bone and enough excess cash flow to allocate it to things that are going to drive that dividend growth in a solid fashion over that long term period.

John Abbott: Yep. It does. And then, as a broader question, more on production, you had – it looks like you had a beat here from the Bakken. Also, if we sort of look back earlier during the week, there was another operator that said relatively strong performance out of Bakken. There was some prepared remarks on productivity in the Bakken. But could you provide any more color on how you see productivity trends sort of in the Bakken?

Nick O’Grady: Broadly speaking, what I would tell you is that what I’ve been impressed at when I get shown the raw data and I’d rather answer most of this question. Is that stuff we would have viewed as Tier 2, three or four years ago is performing about as well as Tier 1 stuff now. And so, the one thing about the Bakken is a higher cost basin, say it, than the Permian, it has a higher breakeven. It’s also a lot more consistent. And because the activity has been relatively muted, there have been about 50 rigs consistently for the past couple of years. You’ve seen a lot of discipline to that development. You don’t see the wild variations, you see the best of the best in the Permian, and you see the worst of the worst. It’s a much more consistent both dolomitic rock that is more consistent as well as consistent behavior from the operators.

I don’t know you — and I would say, John, honestly, we saw better than expected productivity in all three of our basins including the Marcellus. I mean, the declines in the Marcellus have been notably better than we would have expected. I don’t know if you want to add to that.

Adam Dirlam: Yes, that’s right. With the place completions and operations, we have seen some improvement where you used to take Tier 2, Tier 3 was uneconomic. Now we view it as Tier 1 in some cases. Obviously, operators are trying longer laterals, so laterals that’s helping on the production as well. And then part of it for us, again, as going back to the active management, we focus on areas that are highly productive within the core. So that’s kind of how we manage the business.

John Abbott: Very helpful. Thank you for taking our questions.

Operator: Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.

Charles Meade: Morning, Nick, Ed, and Chad and Adam in the whole NOG team there. Nick, you’ve made a couple of comments, I guess, in the Q&A section about the importance of operators. And I think you made a comment or two about the importance of having operators that have scale. For the Mascot project, talking with that to investors, what is your — what’s the message or what’s the context you give to people when they say Permian and Deep Rock, well, I’ve never heard of them?

Nick O’Grady: Well, as I said, there are exceptions to every rule. I think there’s also — there’s an operator piece, there’s a geology piece. But I would tell you that this is a company with a team and a history, a long history of excellent performance. You have multiple rigs operating, not just on our lands, but also on his other properties. We had a good look at a multiyear. He had built out all the infrastructure directly on the properties, which is atypical for a company of their size. And that all went into the primordial soup of our decision making, but I can tell you they know how to drill wells.

Adam Dirlam: Yes. Dave has been doing this for years. And when we went into underwrite this, there’s — a number of wells obviously that they had already drilled and completed and brought online and that gave us the conviction with David team that they could put down highly productive wells and keep well costs under control. And so, when we’re going into these types of things, we need to make sure that our analysis is bespoke.

Chad Allen: Yes. And I would say, you’re talking about a company that has everything from redundant in excess water disposal to excess gathering for crude and gas takeaway and long-term contracts in place for the operations and we’ve been thrilled at how they do it. But you you’re right. And the sense of that is if you think we weren’t worried or thinking about that when we went into this, you’d be mistaken. We definitely — that that was a big part of the analysis that we went into.

Charles Meade: Got it. So a reasonable question, but that’s helpful detail that you gave. Nick, if I could go back to your prepared comments and you’re talking about the — not just the size of the opportunity in front of you, but also the nature of the kind of opportunities more of these as you say like bespoke carve outs. I recognize that it’s — the role of all management across companies is to allocate capital. So everyone’s doing that. But hearing your comments, it seems to me like you’re — maybe there’s a shift in how you guys are thinking about yourselves away from being an oil and gas company has to be — happens to be focused on non-op and more towards a capital provider to the industry. Is that a shift that’s going on in your mind or in the minds of the management team and the Board? And if so, what — how should we change? What we expect from you guys?

Nick O’Grady: Maybe it’s a change in how we explain it, but I’d say, we’ve always been both. We’re both a capital provider, but we’re an investment company and we’re an oil and gas company. And what I tell you is that for operators that require capital to develop and these aren’t necessarily small. We hear from the biggest independence and quasi majors in a country about needs for capital for certain reasons or another. But what I tell you is, at the end of the day as a non-op, you are a capital provider and it really — but difference is we are an oil and gas company. We do our own engineering. We do our own technical work. We have the infrastructure to manage those assets ourselves. And so, what we found is, five to 10 years ago, you had a lot of true financial, whether it be private equity groups or others that provided capital in non-operated ways to operators.

And what we found is that ultimately the need to securitize or find some buy and then exit path for those capital providers made it very untenable for the operators. And we find them seeking us out not just we are — like, the concept that we would ever abandon or that we’re leaving for others, our traditional non-operated business is far from the truth. We are as active in just our normal course of businesses we’ve ever been. But what I would tell you is that we have a lot of operators who come to us who say, I did a deal with XYZ financial firm. And I don’t want to do that ever again. I want to deal with someone who understands oil and gas, who’s willing to take the risk and who’s a permanent owner of these assets. And in that respect, cost of capital matters.

But really, what matters is alignment and risk sharing and an understanding of what we’re actually doing, not the need to just scrape a return and then move on.

Charles Meade: Thank you for that comments. Thanks. Appreciate it.

Nick O’Grady: Sure.

Operator: Our next question comes from the line of Paul Diamond with Citi. Please proceed with your question.

Paul Diamond: Thank you. Good morning. Thanks for taking my call. I just want to touch quickly on, you guys talked about hitting — kind of hit rate of like 10 of 140 ground game opportunities. As of the way just puts in kind of a low to mid single digit or mid single digit hit rate, is that the — could that be thought of its kind of your target for the longer term or is that just — is that going to shift quarter-to-quarter depending what’s in front of you?

Nick O’Grady: Yes. It’s going to shift quarter-to-quarter. It’s all going to depend on the quality and other qualitative factors in terms of what the average size working interest is as it going to move the needle. So, it’s all going to be rig and seller dependent. We’ve got our hurdle rates. That’s what we’re sticking to. And then from there, it’s a matter of just distilling down the quality opportunities. We mentioned 140 opportunities. 70 of those probably went in the garbage as soon as they hit the inbox. So, it’s all dependent on overall activity flows, as this stuff all comes in a linear fashion.

Paul Diamond: Got it. Understood. And then just one more kind of circling on M&A as well. You discussed 14 opportunities you’re currently looking at. Is there anything we should expect as a departure from scale from the ones we’ve seen over the past 18 months? Or they all relatively within that same range?

Nick O’Grady: Yes. I mean, the range generally at the kind of package level is kind of like $10 million to a $1 billion. I’d say the average size is still probably less than $200 million. I think there’s a point at which a big deal and a small deal take the same amount of time. And so, obviously, you want something that’s significant enough to be worthwhile of your time and to be impactful to the bottom line. You have a lot of costs associated with these evaluations, legal costs, all sorts of stuff. And so, you want to make sure that it’s going to be meaningful to the investor, but we’re still the Dustbuster. We’re still picking up tiny, tiny interest every single day. And going back to your last question just for a second, I think it’s worth noting that, we’re pretty robotic in terms of how we look at this.

Right? When you have 10 times the amount of things coming at you that you’d ever want to underwriter go through, you can afford to be. Right? And so it’s pretty robotic. And what we found is that there’s a lot of cyclicality within all of the different businesses that we — business lines that we have. And we – that hit rate goes up and down and oftentimes it really comes down to risk. We find when oil prices are 100 and convexity is weak, we’re highly uncompetitive in most things. And when things get ugly and crude breaks $60, I promise you it will be the last game in town and there you you’re dealing with situations where we can extract more value. So that convexity plays into that decision making and our own competitiveness.

Paul Diamond: Got it. So makes more sense to think it more or think of it more as like counter cyclical to the aggregate price of in the commodity?

Nick O’Grady: I like to think of us as a counter cyclical investor in general. I mean, I think that the most active we ever were as percentage of our size on the ground was in 2020 when things were pretty ugly.

Paul Diamond: Understood. Makes perfect sense. Thanks for your time.

Operator: Our next question comes from the line of Phillips Johnston with Capital One. Please proceed with your question.

Phillips Johnston: Hi, guys. Thanks for squeezing me in. I’ll keep it short with just one more question on the 14 opportunities. Just wondering if any of those are located outside of your existing three regions?

Chad Allen: The majority of across the Delaware Midland and Bakken, as well as Appalachia. We’ve seen a number of properties in the Eagle Ford as well. And we’ve been looking at the Eagle Ford that we’ve alluded to and in prior calls haven’t necessarily found the appropriate fit or assets for us, but it’s definitely one basin that we keep an eye on.

Phillips Johnston: Yes. Okay. And then, I realize you guys don’t typically do PDP only types of deals with no real upside. But you guys ever look at conventional non shale types of packages with low PDP decline rates that would be accretive, but we’re also to help keep your overall PDP decline rates down?

Nick O’Grady: Yes, I mean, we have bought a handful of PDP assets, that you may remember, we bought some assets from Comstock a few years ago that we owned about 90% of already, and they were low decline PDP. And so, the decline rate for a PDP only asset is really important. I’d say on the conventional side, the one challenge there are that typically, if you took like a C02 flood asset or something like that. It might have low declines, but it also probably has $20, $25 LOE cost. So it’s going to be much more sensitive to oil prices. And so that’s another risk factor. It may have less operating risk or need for growth from an underwriting perspective, but it’s going to be more sensitive. One of the things that we talk to our investors a lot about and particularly as it pertains to PDP assets are that — you really have no upside to your returns besides pricing when you buy a PDP asset.

And so you really need to think about where you are in the cycle. Ultimately, what we find is that undeveloped assets in a period of traumatic pricing, the NPV of those undeveloped assets comes very low, and that’s when you can ultimately underwrite things based on PDPs and get that upside for relatively a de minimis amount, conversely, buying a PDP asset when the crude strip is a $100, you really don’t have a ton of anything but downside.-

Chad Allen: In a lower price environment, it’s going to be seller dependent and what is their balance sheet and financial health look like, right? Because you’re going to be looking at a pretty big Bid/Ask spread. The majority of the time to the extent that they’re healthy.

Nick O’Grady: Yeah. I mean, I think — we think in general there are better buyers for PDP assets than us, but there are occasions where it makes a ton of sense. Phillips, I just tell you, in terms of what we see, we get sent everything. I mean, I’m talking we’ve been sent Alaska Gulf of Mexico, Tuscaloosa, Tuscaloosa Marine Shale, Alabama Conventional Production. We’ve been sent everything, but I wouldn’t say anything has made it past the email inbox as it pertains to those types of opportunities.

Phillips Johnston: All right. Sounds good. Thanks, guys.

Operator: There are no further questions in the queue. I’d like to hand the call back to management for closing remarks.

Nick O’Grady: Thank you guys for joining us today. We’ll continue to work to execute on our plan this year. We’re dedicated to providing superior return to the marketplace. And, again, thank you for your interest. This is the way.

Operator: Ladies and gentlemen, this does conclude today’s teleconference. Thank you for your participation. You may disconnect your lines at this time and have a wonderful day.