Greetings. Welcome to the NOG Fourth Quarter 2021 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] Please note this conference is being recorded. I will now turn the conference over to your host, Michael Kelly, Chief Strategy Officer. Thank you. You may begin.

Good morning. Thank you for joining us for our discussion of Northern’s Fourth Quarter of 2021 earnings release. Yesterday after the market closed, we released our financial results for the fourth quarter. You can access our earnings release on our website and our Form 10-K will be filed with the SEC within the next few days. We also posted a new investor deck on the website, as well last night. I'm joined here this morning with Northern's CEO Nicholas O'Grady, our President, Adam Dirlam, our CFO, Chad Allen, and our EVP and Chief Engineer James Evans. Our agenda for today's call is as follows. Nicholas will start us off with his comments regarding Q4 and our go-forward strategy. After Nicholas, Adam will give you an overview of our operations, and then Chad will review NOG's Q4 Financials and 2022 Guidance. After that, the executive team will be available to answer any questions. Before we go any further though, let's 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 these forward-looking statements. Those risks include, among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During the conference 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 the earnings release…

Thanks, Nicholas. NOG continues to execute smoothly as we close out a transformational year. During the fourth quarter, we saw a meaningful increase in completions and turn in line 12.1 net wells. There are a number of completions that were slated to come online in Q1, that were pulled forward during the quarter and our growing Permian acquisition accounted for a third of our well additions as we continue to scale in Texas and New Mexico. With the increased activity during the quarter, we expect a quieter Q1 completion count to the tune of five to six net wells. As we enter Spring, the cadence of completions is scheduled to pick up dramatically, with a material step-up in activity as we move through the second quarter and into the back half of the year. Elevated drilling activity on our acreage has also remained consistent. We ended the year with 42.5 net wells in process, replacing the 12 net wells that were brought online during the quarter. Our in-process list continues to diversify, as we scale on the Permian, which as of the end of the year, made up about 1/3 of our net wells that are in process across our oil - centric basins. This has only been bolstered in Q1 with the closing of our Veritas acquisition. New well proposals swelled in the fourth-quarter across Northern’s footprint, bringing in 130 new AFEs, 110 of which came from the Williston. Our elected proposals accounted for 9.7 net wells and represents a 60% increase from Q3's activity. Given the discipline we're seeing among our operating partners, and even when we sensitize our price decks for a lower commodity environment, we consented to 95% of our proposals during the quarter. To the testament to the Shale 3.0 era and a more disciplined…

Thanks, Adam. I'll start by reviewing some of our key fourth quarter results. Our Q4 production increased 11% sequentially over Q3, and increased 80% compared to Q4 of 2020. Our adjusted EBITDA and our free cash flow increased 29% and 28% respectively over Q3, ahead of Wall Street analysts and internal expectations. We produced over $214 million of free cash flow for 2021 above our target of a $175 million for the year. Our adjusted EPS was a $1.06 per share in the fourth quarter, above consensus estimates. Oil differentials were flat and gas realizations were 20% higher compared to Q3. Lease operating costs were $50.6 million in the fourth quarter of 2021 or $8.57 per BOE, an increase of 5% on our per unit basis compared to the third quarter. The increase in unit costs was primarily driven by the acquisition of higher unit costs production in the Williston Basin and higher NGL processing costs. However, this was more than offset by higher natural gas revenues. Capital spending for the third quarter was $83.7 million, excluding non-budgeted corporate acquisitions, which was slightly above Wall Street expectations due to the pull forward of completion activity and additional Ground Game opportunities in Q4. We exited the year in a great spot from a balance sheet perspective. After closing the Veritas acquisition in late January, we currently have approximately $400 million drawn on the revolver leaving approximately $350 million in availability. Given the cash flow we expect to generate; we plan to pay down additional borrowings on the revolver in Q1. Based on our forecast and expected capex spend, we forecast our revolver to be undrawn in the Q1 of next year. As we head into the spring borrowing base re-determination, we think our current asset base would support a substantially higher…

Thank you. At this time, we will be conducting a question-and-answer session. [Operator Instructions]. Our first question comes from the line of Neal Dingmann with Truist Securities, Inc. Please proceed with your question. Mr. Dingmann, please go ahead.

Sorry about that. Morning, guys. Nicholas, I thought I'd maybe just jump to the top of [Indiscernible] course shareholder returns. My question around that is, especially for a smaller company your size, you guys certainly want to look at the dividend and other things within that plan. Not only could be one of the leaders in the smaller [Indiscernible] but certainly [Indiscernible] coverage group. But my question I guess is when you brought onboard a positive that bad is that -- can you co-exist by doing that in creating value if you maybe give an overview of how you invest. And again, you guys have really turn this company around. I'm just thinking the next innings. How do you [Indiscernible] do both from this point on? Nicholas O’Grady: Thanks, Neal. Good morning. I think the way I would couch it is if you look back at when we did the Comstock transaction in the fall. Transactions like that, that's a pretty run-of-the-mill PDP assets that we purchased. While you're capitalizing the cost of acquiring that property, ultimately, it almost immediately adds cash flow that can be returned back to shareholders. So it actually -- while you're spending money, you are actually accelerating your ability to repay shareholders. I think that's how we think about it. I think it's a function of how you capitalize those transactions and making sure you adjust for that risk factors. So you are borrowing some money when you buy a property like that and need to make sure the asset can repay that money over time. But also that a good portion of that property can go back to the stockholders. And so, we see most of the bolt-on stuff will do over the next several years. Generally speaking, as something that's going to accelerate that path, especially where we are in the world of shale today, I think it is maturing. We saw an interesting banking report done a few months ago, in which five years ago, about 80% of the average M&A transaction was for undeveloped land, and today it's roughly the opposite. And so with a lot of proved developed properties coming alongside every package we look at, that means that that's cash flow that can both self-fund the undeveloped portion and also return some to the shareholders.

Right. Great. I think that's exactly right. To be able to do both. And then lastly, [Indiscernible] some time that's really just on the non-op model. I looked at it for a while. You guys maybe were getting a knock on basically premium reverses and discount because being a non-op. And now I look at it and say, you guys seem to have -- I'm looking out there, and based on my numbers, you could have some of the highest returns. You certainly might not have as much strength in capital as some other folks in the South. I guess, my question around all that is, you think or how do you basically justify or get the higher premium and show investors now basically the new models that you've shown? Nicholas O’Grady: I think there's a difference between non-op assets in the market and what they will sell for and us as a company and a public security and what that should be valued by the market. I would undoubtedly tell you that we believe we can purchase and you can just see it in the assets that we've purchased versus operating peers who have bought things in similar areas, what they paid per location for the reserves, etc. We don't -- we obviously don't have the same level of G&A overhead on top of that. So undoubtedly we're buying assets for less than others. But just because a non-op asset in the market trades for a discount, it doesn't necessarily mean a non-op business and a non-op equity in public company should trade at a discount. I mean, that is my opinion. I'm sure not everybody will agree with that, but I think that is the arbitrage that we ultimately have built with a large diversified model. And I think it will take time. I think it will be driven by cash returns, but I think when you have a business that can deliver better cash-on-cash returns, better free cash flow per share, better across-the-board, ultimately, that will translate into an equity that has a premium valuation. I think -- I look at the minerals model that is a non-operator business as well. It is a pass-through. It's also a lower return business, but it's been given a premium in the marketplace because of the structure. And I think it will take time, but I think we'll get there.

Just to add on to that. I mean, I think the differentiation between NOG and a lot of other non-operators out there is the active management, right? So, it's not just picking up a package and sitting out and waiting for the rigs to come. It's bringing the towel on, grossing up your interest, getting in front of the rigs with the ground game and truly bringing all that together, so that you've got all these different prongs of assets coming through one filter and being able to identify and being agnostic, as to where you're going to allocate that capital. Nicholas O’Grady: Yeah. And I mean, I'll just use an example, Neal, in real-time. We have two existing mineral partnerships within our Williston base and asset, in which we have teams selling and buying minerals underneath our working interest constantly and grossing up our NRIs. We don't really report it as a separate asset, but that's an example of the active management where our NRI and overall working interest are changing just as I guess -- what's the term? Wring the towel. I like that. As we wring the towel on every single unit as it's being developed.

Great detail. Thank you all again.

Thank you. Our next question comes from the line of John Freeman with Raymond James Ltd. Please proceed with your question.

Good morning, guys. Nicholas O’Grady: John.

I just want to follow-up a little bit on Neal's question on the shareholder returns front just to make sure that I understand the way you are thinking about it going forward. So if we go back to the dividend framework that you all put in place at the end of last year or that $50 oil, $3 gas base commodity price you all were using. The plan was the basically pad upon 1/3 of your free cash flow in the form of the base dividend. So I guess from here, if we're just thinking about the next 12, 24 months with obviously the commodity environment, while north of that. Should we think of it as the first objective with that excess free cash flow is just you're going to pay down the bank facility like Neal said, in the first quarter '23, I think what you're targeting. Then after that's done is the options to start. You could potentially lay on additional, whether it's dividend increases or special dividend buybacks or whatever, or do you start tackling that 28 notes? Just how you all are thinking about it. Nicholas O’Grady: Yes. I mean, I think what we -- the conclusion we've come to is, as we achieve higher prices than we run internally. Just to give you some context, at the pace we're going right now and the business as it stands, we're going to exit a year from -- we're not just looking out next quarter, we're looking out the end of 2023. And by the end of 2023, you're talking about having hundreds of millions of dollars of total cash on the balance sheet. And that's good and bad. I mean, I think in the sense that it's obviously not earning a return. And so, as you…

I appreciate all the color. My other question, when I look at the '22 budget, you've got about 90% of budgets with equally between the Bakken, the Permian, and then the remaining amount in the Marcellus. When you're looking at M&A opportunities outside of those three operating areas, how important is scale? In other words, for you all to jump into another basin, does the initial entry need to be pretty sizable or would you be fine methodically building a position in a forward pacing? Nicholas O’Grady: I will be very frank, we got a $25 million Eagle Ford package shop to us the other day and I think that the teaser went directly in the trash. And it's not that it's a bad asset necessarily, but we want to keep -- we want to stay focused. And so, if you were to go to another base then it wouldn't have to be something significant enough. It is a tax on the organization to manage and evaluate and be an expert in all of these things. We've spent a lot of time, money, people to become an expert in the basins that we operate today. And that's not something we do on a whim. And so, I would expect the vast majority of opportunities in front of us, particularly given -- I don't know what is it, 90% of the rig count is in the Permian right now.

Yes. What I was going to say it largely solves for itself. We talked about $1 billion backlog, and if I'm looking at 12 to 15 packages that are out there that make that up, I mean, it's largely the Delaware and the Bakken. At the end of the day, it's going to be asset quality and that's where the asset quality is in terms of the non-op, and that's again our business model. Going back to Neal's question, we have the ability to pick up assets in the core of the basin regardless of where, what [Indiscernible] any of these basins are in. So I think our focus will generally remain in the Delaware, the Midland, and North Dakota. That being said, we are screening asset packages across the Haynesville, Eagle Ford, you name it. Just a much higher bar relative to some of the other asset packages that we're seeing.

Thanks guys, and congratulations on a fantastic year. Nicholas O’Grady: Thanks John.

Our next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question.

Thanks Sam, I'm going to jump on the shareholder returns bandwidth too here, but take a little bit different angle to the question. Obviously you guys have shown there is multitude of things you can do, these commodity prices and taking out the preferred and is an option as well as taking out bank debt. But can you just speak to -- especially as you embark on your fixed dividend plan increases, just the sustainability and durability of being able to do that with your existing asset base. Meaning, if you didn't get Ground Game opportunities or acquisition opportunities. What oil price deck do you need to make the current plans sustainable with your existing asset base? Nicholas O’Grady: Yes. I mean, I think the what we put out, we spent a lot of time with us at the board level, Scott. So we said 50 and 3, and that plan was based on the assets we have today for a 10-year period, right. So effectively, we didn't -- we never bought another thing, that's what that's based on. I can tell you, the Williston is a mature basin and many people think it's fast as [Indiscernible], I would tell you, we -- what do we see? A 60% increase in AFE activity in Q4? Our asset is quite young and the way we have built it, and we are about as busy as we can be, we've had on the Veritas assets as an example, we've already had an entire net well proposed that we didn't even underwrite or put in our inventory, since we purchased the properties. And so I would say we're conservative guys by nature, but I would -- we didn't do this lightly. We spent a lot of time and effort to make sure that especially when you're doing it as a base dividend, which you know is effectively a commitment as opposed to a special which you can come on or off. And we see a lot of durability to that.

Got it. Great. And that's down to 50, right? So 50 can continue down that path and feel pretty good for the next 10 years. Is that right? Nicholas O’Grady: That's right.

Okay. So my follow-up question. And Nicholas, I know you and I talked about this a bit. Just about your technical team and how you all look at the assets and do some work and with that influx of lot more AFE proposals and a number of acquisition opportunities out there. Can you just speak to, with all that stuff coming in? How does your team approach go through all that stuff? I know your consent rate, is some like as around 95%, but it seems like a lot of work to do in a short period of time. Can you give us a sense of the depth of your technical team and how you guys approach that to get through all that and making sure you're maintaining the quality of your investments? Nicholas O’Grady: Yeah. That's right. I mean, I think we've spent a lot of time and money Scott, over the last couple of years, and we've added a fairly substantial number of people well at least relative to our size. I think we're up to 30. I like bragging our revenue per employee, but we are up to about 30 people. Our engineering department is the largest group in this company, and it is obviously the lifeblood and the most important. On the AFE front that is -- that funnel is very simple in the sense that we have a team of professionals that go through every single AFE and then they're individually approved by our Chief Engineer and Adam. Over time that part is relatively old hat whether we were still in the Williston only or today that part is quite easy because all of those type curves are build-out. On the evaluation front, that is the part where we have continued to -- and I…

No, that's right. I mean, I feel like a broken record, but it largely sells for itself. First, we are taking a look at whether the asset itself is going to solve mostly and if it makes sense at a corporate level, it's probably not something that we're necessarily interested in because we're looking at resilient assets and the rocks are the rocks, but the operators can differentiate that significantly. And that's where we leveraged the 350 type curves that we've got in North Dakota and building out our proprietary database in New Mexico and Texas because we've got all of the lease operating expense data. We've got the stuff that comes through on the jibs and the revenue checks that you can't necessarily get through a subscription service. And so it's building out those basin-wide databases so that we can meticulously go through this stuff, but do it in a fashion where we can filter out three quarters of these things upfront and focused on the assets that are going to trade based on the social issues that are effectively in place. At the same time that often influenced these processes.

That's great. Thank you.

Our next question comes from the line of Charles Meade with Johnson Rice & Company, L.L.C. Please proceed with your question.

Good morning, Nicholas. You and the rest of the crew there. What do you -- you actually just touched on this just a little while ago. The Veritas deal, and what has changed since you guys evaluated it? You mentioned there's been one more net well proposed. But I'm also curious about if the schedule has changed because going back to your comments on -- I appreciate your comments on inflation in the Permian versus the Bakken, but also service availability is a growing concern as well. Can you talk about maybe not just the total number of wells that you're looking at with Veritas, but also the schedule there? If anything's changed. Nicholas O’Grady: I mean, I think as a non-op, the schedule is always moving around, particularly this time of year in the winter and the spring, things move around. I would say, if you look at the operator mix on the Veritas assets, service availability is not an issue. You're talking about some of the largest and best capitalized companies, and I can tell you what we see in real-time from our 50 + operators are small 1 and 2 rig operators are really struggling. Frac crews are not showing up when they're supposed to. They can't source drill pipe all those sort of things. If you're Devin or Melbourne or one of the largest and most active operators, you're not having those same types of issues. So in terms of that, hasn't changed. The schedule is moving around all the time and that's the art of how we guide. And you can look throughout history, we've gotten pretty good at being very careful and meticulous in playing for those things, as things move from a month to around and particularly in the Williston, around this time of year given when or whether things are going to get completed before the freeze or not. But in terms of Veritas overall, James, I don't know if you want to comment otherwise, but I don't really think there's been any material changes. I think what I was trying to highlight, Charles, more than -- we said we saw another 40 net locations on there. We were trying to be about as conservative as possible. And on the small working interest stuff, we didn't even underwrite it. And so, we're already seeing the benefits from that.

That's all helpful. And then, if I could ask a question about the Ground Game. Historically, I'm curious how, how it may maybe be changing or where you might see changes going forward. My understanding historically is that was about like you said earlier, you're getting in front of the rig and picking up working interest in properties where you already having interest and just trying to accrete your interest in front of some activity. It sounds like you guys may also be kind of lumping in just some little deals that you just finding out of cash that maybe or maybe are a little deal on properties where you don't currently have an interest. Is that the case and is the opportunity set shifting that way. Nicholas O’Grady: I'll let Adam talk about this a little more than me. But I would say, I think it's always sort of been a combination of other things. Sometimes it'll be -- it'll come with a little bit of PDP. You're buying an interest in a unit that has two wells that have already been drilled, another eight coming kind of stuff, so it's always moving around in that respect. I don't think it's really changed. I think the difference in 2022 versus the last several years, as I would say, the explosion in organic development on our properties has probably made us a little less active than we've been in the last few years. Is that fair?

Exactly. I mean, I think there's probably two to three of these Ground Game opportunities coming on the door on a daily basis, and a lot of these were in just by nature of our acreage position, and there's a number of them that aren't invest in the case for the past five years. It's really just high grade in what's your opportunity set is and that's what I was alluding to in the prepared remarks in terms of we've got an explosion in terms of activity levels. Operators are staying disciplined, and so you can feather the Ground Game based on the activity that you're seeing on your organic acreage and given the fact that where we're at in terms of commodity pricing and operator activity as well as the Ground Game activity that we were able to get done in the third and the fourth quarter, it's effectively set up, 2022's activity where we're comfortable at. And so as we kind of move through the first quarter and end of the second will continue to keep a beat on all this stuff and start planning for the back half and into 2023.

That's helpful insight. Thank you.

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

Thanks and good morning all. Picking up with Charles last question just there. With regard to the Ground Game opportunities, could you comment on if you're seeing additional competition in the current higher pricing commodity environment? Nicholas O’Grady: I mean, there's always competition, especially the smaller the dollar amount, the more competition there is, right? So there's always competition, I would say. I wouldn't -- I don't know if I would say it's any more or less than the past than.

I think, viewpoints changed with maybe some of our competition. And if it's new money, and they've kind of scrambling to put it to work, then maybe they are stretching. But I think it also -- you've got some variability between basins as well. And the next point, you've got a well-pad that comes with four or five well proposals, but working interest is 30% to 40% versus that same well,

with 2% to 3% working interest, your competition's that it's just wildly different in that regard. And that's where we can do a bit more damage with maybe some of the higher concentrated opportunities on the Ground Game basis, because some of our smaller counterparts aren't necessarily comfortable with that level of concentration. Whereas when you look at our base and relative to everything we're throwing off, it doesn't necessarily move a little bit needle nearly as much.

That makes sense. Staying with you Adam, with the material increase in rig count we've observed particularly with privates, could you speak to your private exposure and how that has trended over the last few quarters?

Yes. I mean, we've always look to the true privates I would say, the ones that are focused on making money, Slawson and North Dakota they'd continued to be active in this particular environment. We've made it a point to get underneath Melbourne oil and the Delaware side of things. Between those two of the most cost efficient operators, as well as two of the most active operators in our respective basins. We continue to have that activity level flex forward in this particular environment. As far as some of the private equity groups, we typically stay away from those guys. So you solve for that more on the acquisition side of things. So I would say that's largely Melbourne and Slawson as it pertains to the private exposure.

That's great. Thanks for your time.

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

Good morning and thank you for taking our questions. First question is -- Nicholas O’Grady: Morning, John.

You gave that free cash flow outlook here with a potential next four years equal to your market cap. Could you just speak about the cash tax trajectory over a multiyear horizon? Nicholas O’Grady: Yeah. I'll let Chad cover them. The answer is, eventually we will have to pay taxes.

Thanks, John. Obviously you saw us pace some fairly immaterial state taxes in Pennsylvania and Texas and New Mexico because we don't have any [Indiscernible] established there. But in the past, we've been elected not to fully develop IDCs or bonus appreciation for the past several years to kind of preserve future reductions for us. It's clearly -- clearly it's based on our drilling activity and commodity price, but I think based on our current model, there'll be some small amount of taxes that will pay and at the end of 2023. Once we pay taxes, it will be a mid-20% overall tax rate, but obviously adjusted for any changes in tax law. And obviously, we also have the IDC deductions in future tangible drilling, bonus depreciation stuff that we can take there as well. Nicholas O’Grady: And so, our overall effective rate will be well below that, and the number that I threw out when I talked about that is net of that. And we have a -- internally we run it, so it's running at the strip, so it's going to adjust for any change in commodity prices as to the timing of that.

That's very helpful. Then, just sticking with cost here. Looking at LOE's expense, looks like that's ticking a little bit higher in 2022. It's on NGL pricing. I guess you have some FT that year and I guess that FT would roll off and then maybe sort of into 2023. Just thinking about LOE expense and FT in general, how does LOE have been trend over a multiyear horizon? Nicholas O’Grady: It really depends on the price of NGLs. So first of all, each for the next two years are FT associated with the Marcellus will pay that in the first half of the year. So it has a way of elevating your front half LOE. It doesn't go in smoothly really. It goes, you pay it twice a year and you can't accrue throughout the year. In the first six months of the next few years that FT and then it will roll off over time. We’re trying to be conservative in the sense that you have a lot of POP contracts, particularly in the Williston amongst our largest operators and some in the Permian. With really high NGL prices, we run our processing charges, which will adjust for that through there. You obviously also known as we did tick up our gas realizations as part of that. But we're trying to be conservative on both fronts. And so, it's not a function of actually operating costs, really materially going up. I mean, obviously, as well as age out there, LOE does rise. And so, as our production matures, you're going to see some of that offset by new well activity. But the big driver, John, of that is just that, with the NGL basket, particularly propane as high as it is, you're going to see some of that in those charges on there. And so, we're trying to adjust for where we are today. Obviously, if oil and NGL prices were to go materially down, it would have a downward pressure on that and also on the revenue side, but I would tell you on an EBITDA basis, on a cash-flow basis, it is a net positive to say where you might have been otherwise.

Appreciate it. Thank you for taking our questions.

Our next question comes from the line of Nicholas Pope with Seaport Global Holdings L.L.C. Please proceed with your question.

Good morning, guys. Nicholas O’Grady: Nicholas, I went out and I told you I could just go in the market and buy the preferred stock and I did it just at the year, right?

Excited. I am happy to model it. I was hoping you guys could talk a little bit about, you look at the big portfolio and I think a lot of the focus is on the newer wells and the acquisition front. But now you've got these interest in 8,000, 9,000. How are you all thinking about in this market potential, divestitures or call in weaker performers and kind of the existing producing asset. Or is that a focus? I'm just curious how you all think about the hierarchy of the existing producing asset, and if there's ever a shift to look at that opportunity set and maybe selling into the strong M&A market. Nicholas O’Grady: I think the last point, you have to think about a call and oil prices there for a second, because if, even if you sell a PDP asset as an example of PV ten, you're still talking about a 10% cost of capital, right? You're borrowing money at 3%, so you're saying this thing, if I needed money, it's a pretty expensive way to do it. That being said, we have particularly in the Williston seen a handful of operators buying in non-operated assets at what we view as fairly elevated values. We considered going to some of our operating partners and divesting of our working interest in their properties, if it was worth more to them than us, yes. Maybe you could form that in the way of a trading which we're taking other non-operated properties that they don't want. And so this is a trend we've been watching for the last year or so. So I would say -- I would never say never. I would say to be candid, we have never in my time here at Northern, we've never sold a material asset except to form an operable acreage to operators and so we've never really been a material seller. But I do think it's something we're looking at, particularly as you said. There may be operators that we don't necessarily want exposure to when we -- if the price is right, we'd happily either sell or trade them our assets for perhaps other assets they don't want.

That's right. And the price for an operated acreage or at least the way that some of our operators see it, might be worth 1.5 times what they're -- the viewing their non-op them. That might have nothing to do with their actual economics book more of the control. And so if you can leverage and exploit that trade-off so that everybody is getting what they want and it's mutually beneficial, it's something that we'll explore. Obviously a bit more complicated than typical asset package, but those are the conversations we are having.

Got it. That's actually really helpful. But -- and as you look at the existing portfolio base, is there a ranking process you look at either operating costs, age, well performance. How do you think about that existing portfolio base? Is that how it should be thought about? I mean, is that where the focus is on? I mean, it's a lot of wells now, for obviously, what's two years ago? Nicholas O’Grady: Yes. You mean just in terms of the ranking, if you were to divest them?

Yes. I mean, is that how you guys think about it? I mean, if that -- Nicholas O’Grady: Yeah. If you hear me, I'll give you a little history lesson. I watched a lot of operators in 2010 to 2017 sell PDP assets that had higher operating costs to go fund new drilling wells and so they could show really low LOE. But what they would really do is just deepening their decline curve materially. I think higher operating costs, yes, it's lower margin, but it's also lower decline. So there -- it's not one for one. I would say where we would look at potentially divesting assets is which it appears it would more on which the upside on those assets is worth less to us than it might be to the operator or to somebody else or our view on the future development and possibility. We have acreage in some non-core parts of the Williston that might be worth more to the operator than it would be to us because we frankly wouldn't want, even if it was to be developed, it wouldn't necessarily be where we want to put our capital [Indiscernible] County out there or something like that. But it wouldn't mean it's uneconomic. It just wouldn't be our choice to put our capital there. I think it's less to do with where the assets are now, probably more to do with the upside associated with future development on those properties.

Got you, Nicholas. That's very helpful, very interesting. Thanks for indulging me. I appreciate that. Nicholas O’Grady: Yeah, my pleasure.

Our next question comes from the line of Noel Parks with Tuohy Brothers. Please proceed with your question.

Hi. Good morning.

Good morning.

Just a couple of things. Continuing on the conversation about operators you are happier being involved with close to those that you more look to avoid. I'm just curious, in your basins, are you aware of -- is there anything significant that on the market, as far as operated acreage in a package, that would benefit sells with a lead to a meaningful shift in your operatorship profile in any other basin? Nicholas O’Grady: No, I think in the Williston there's going to be some large operated packages that change hands in the next couple of years. And I would say we would view that as a huge positive for us if it was to transpire.

I mean, as far as North Dakota goes, I think we're in 40% of all Bakken and 3 forks wells that have ever been drilled and so again, regardless of those packages coming to market, the non-op nature, it's not going to move around all that much. And it's also going to depend on the average working interest for a lot of these packages that were seeing, have average working interest there's that are probably half of what ours is. Nicholas O’Grady: Yeah. There was a large operated packages sold at the beginning. It was either late '20 or beginning of last year. A private operator took it over and we've seen a meaningful improvement as they actually are focused on the asset, right? You can imagine there are other large operated packages, both in the Williston and the Permian. I'd used the -- our Marcellus properties as the poster child for that, which is you have a focused operator that takes over and does it a huge improvement; both the well design, cost structure, well performance, all those things. We would see a lot of meat on the bone on some of the properties that we existed particularly when assets are non-core and to that operator and they're just not putting development dollars towards them. We have a lot of undeveloped assets under some of the operators that if they were to change chance, that would be a huge benefit to us. Even if there wasn't a change in cost structure, which usually there is.

Really interesting. Thanks. And another sort of similar question, but looking more at the Marcellus, just trying to get a sense. I feel like I'm kind of hearing some mixed signals from some of the Marcellus operators, the public ones, around what they're thinking about inventory. And I'm just wondering, do you see an overall trend either of inventory concentrating itself into fewer hands, fewer hands with bigger operators through either consolidation that's underway or that you think might happen? Or I was wondering if you see any sort of opposite force of people paring down their positions? Because some of the larger ones, of course, have decades of inventory at this point, it's not so likely they're going to get around the funding. Nicholas O’Grady: Yeah. I think consolidation has continued theme. I think I'm on the record and I'll repeat what I've said publicly before, which is that there's a lot of focus on Shale 3.0 and the slowdown in the lack of acceleration in drilling. And I've told people that it is as much about inventory preservation as anything else, which is that there is a limited amount of Shale. And if you go to the Marcellus as an example, that region's been getting hit hard for 15 years and some of the best areas in the Marcellus that we've looked at, our very drilled up. Now, when it comes to our properties in the Marcellus, there were less than 450 wells drilled over 10 years there. It has 30 years of inventory and it was less hit hard partly because of the prior Operator and partly because there were better regions to drill at the time. But it's highly economic and so I don't see that as an issue for our asset, but do I see further consolidation within the region? Yes. Particularly as infrastructure is a challenge in the region in general, it means that only the big companies can really be able to navigate through there. It's not like you could pick up acreage and get easy firm access to transportation. You really have to have that scale. And you've already seen that, right? You've seen Alto trade hands, you've seen Chief, you've seen a significant amount of consolidation already. Will there be more? I can't say. I can't say if there will or they won't, but I don't think it's the type of thing where you're going to see a small group go and pick up a rig run in there because I don't think it would really be conducive to that. I will say for our asset in particular, one of the things we identified was just it has decades of inventory on it and it has been fairly touch, not to mention the fact that we bought a half a decade's worth of ducks one week up when we bought the property.

And just to extend that a little bit. So is it safe to say that and I'm thinking particularly about the Marcellus, that there isn't really fresh money looking attracted by higher gas prices. Looking to a comment and start something new from the ground up there. It's just -- it's people are getting squeezed out in other words? Nicholas O’Grady: I would say that's a fair assessment. I mean, I certainly -- I think capital in general, no. New capital is going to put a significant long-term operator footprint in areas in the I'd say, is waning. I think that it is turning into a larger consolidation wave. I think for every new dollar being raised, there are $2 that need to mature and go out. And that's obviously created the environment that's allowed our company to grow over the last few years.

Great, thanks a lot.

Thank you. Ladies and gentlemen, we have reached to the end of the question-and-answer session. I will now turn the call over to Nicholas O'Grady, NOG’s CEO for closing remarks. Nicholas O’Grady: Thanks everyone for listening to us today. We'll work hard to put up phenomenal results over the next several years. Again, thank you for your time and interest.

Thank you. [Operator instructions]. Thank you for your participation. You may disconnect your lines at this time.