Greetings. Welcome to the NOG Q4 2021 earnings call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. Please note this conference is being recorded. I will now turn the conference over to your host, Mike Kelly, Chief Strategy Officer. Thank you. You may begin. Good morning. Thank you for joining us for our discussion of Northern's Q4 2021 earnings release. Yesterday, after the market closed, we released our financial results for the Q4. 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, Nick O'Grady, our President, Adam Dirlam, our CFO, Chad Allen, and our EVP and Chief Engineer, Jim Evans. Our agenda for today's call is as follows. Nick will start us off with his comments regarding Q4 and our go-forward strategy. After Nick, Adam will give you an overview of our operations, and then Chad will review NOG's Q4 financials in 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 that we issued this morning. With that taken care of, I will hand the call over to Northern CEO, Nick O'Grady. Thanks, Mike, and thank you for joining us this morning. As usual, I will get down to it with five key points. Number one, execution. We closed out 2021 in a very strong fashion, with record profits across the board, record cash flow, record free cash flow, and we exceeded all material internal goals we set at the beginning of the year. We are particularly proud of exceeding our free cash flow target of $175 million by over $30 million, higher than forecast production volumes and strong execution and integration of acquired properties. Number two, capital allocation. At current strip prices, over the next four years, the company could generate its entire market cap and free cash flow. This puts us in an incredible position to allocate capital, which we will do in the following four ways. Number one, our organic development. Number two, small scale and bolt-on package M&A. Number three, further debt retirement. Finally, number four, shareholder returns, primarily in the form of growing dividends, and we can also opportunistically repurchase stock, particularly if the valuation remains low even at mid-cycle. I wanna emphasize one more time what we said when we purchased Veritas. We believe the vast majority of bolt-on M&A can be done within the confines of our balance sheet going forward, which will not likely require raising equity in the public markets. The capital from our 2021 equity offerings was intended to provide us with enough dry powder for us to be able to take advantage of strategic acquisitions on a go-forward basis. We remain the largest and most active working interest consolidator. Adam will discuss further the opportunities we currently see in front of us. Number three, shareholder returns. As mentioned above, we have a tremendous amount of confidence in our business model, which has given us the ability to communicate a dividend plan for the next two years. We have already delivered higher than promised dividends, and we are confident that we can continue to exceed our dividend plan. Given the predictability of our free cash flow, we expect to retire all our bank debt in 2023 and then start building cash and returning more to our shareholders. Recently, our board has authorized a modest but important preferred stock repurchase program. We have already retired $7.2 million in face value of preferred stock. This has multiple benefits. It simplifies our balance sheet, reduces our annual dividend payments by about a $500,000 a year, and effectively reduces the diluted share count by approximately 316,000 shares. Number four, outlook. Chad will go into our 2022 guidance in more detail, but there should be relatively few surprises for our investors as we integrate the Veritas assets, execute on the organic activity on our acreage, and weigh additional ground game and redeployment opportunities as they become available. We see significant and steady production growth on our properties throughout 2022. We have tremendous optimism as we head into 2022 and 2023 that NOG is poised for some significant multiyear growth. We feel that we are in an enviable position, and our process remains unchanged, disciplined, and focused on the best opportunities. Number five, consistency. You'll notice if you've listened to our conference calls over the last three years, there's a lot of consistency. We've talked about capital allocation, debt reduction, and ultimate returns to shareholders consistently since mid-2018. If you watch our actions, we have carefully scaled a business from less than 15,000 barrels equivalent per day while continuing to cut the cost of our credit and materially lower leverage ratios. All of the hard work for the past three years has given us the power of scale, and our focus on asset quality should deliver consistent and predictable results for our shareholders. When we bought 66 acres in the Permian to begin our diversification in 2020, it might have seemed insignificant, but that position has grown to 9,000 acres in substantial production less than two years later, and it should account for almost half of our capital spending in 2022. When we declared our first dividend in May of last year, it was small, but we told you it was just the beginning. The quarterly dividend has increased over four and a half times since then. In the coming quarters and years, we'll work hard to execute in such a fashion so that we can deliver and even exceed our dividend plan. The entire team at NOG is up to the challenge, and we will continue to deliver superior results for our shareholders. NOG is a company run by investors, for investors, and I'd like to thank each and every one of you for taking the time to listen to us today. With that, let me turn it over to Adam. Thanks, Nick. NOG continues to execute smoothly as we close out a transformational year. During the Q4, we saw a meaningful increase in completions and turned in line 12.1 net wells. There were a number of completions that were slated to come online in Q1 that were pulled forward during the quarter, and our growing Permian position accounted for a third of our well additions as we continued 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-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 Q2 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 in the Permian, which as of the end of the year, made up about a third 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 Q4 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. This is a testament to the Shale 3.0 era and a more disciplined approach to inventory development with a focus on returns from our operating partners. From a well cost standpoint, we continue to keep an eye on inflation and labor. Our new proposals averaged $7.1 million during the quarter, effectively in line with the Q3 and comfortably within the range of our internal estimates in the $7 million-$8 million range. In the Williston, we expect to see more moderate levels of inflation while seeing more pronounced levels in the Permian, concentrated with some of the smaller operators. We continue to review multiple ground game opportunities daily, but with elevated commodity prices and the corresponding increases in service costs for some operators, we've gotten significantly more selective in the opportunities that we plan on pursuing. Given the increased levels of activity across our acreage position, we will actively manage both the inbound drilling proposals along with feathering our ground game activity to augment returns and capital efficiencies. During the quarter, we closed on nine acquisitions, bringing in 9.6 net wells and 317 net acres. Given the success that we had on the acquisition front during 2021, as well as the increase in drilling on our acreage, much of our anticipated 2022 activity has been taken care of, and we will be focusing more of our efforts planning for the back half of the year and into 2023. At a package level, there are multiple opportunities that we've been reviewing both on and off market. With the scale that we've been able to achieve over the last 12 months, closing on over $800 million in acquisitions, those opportunities are also expanding outside the typical asset package. We've had multiple conversations with some of our operating partners, putting together drilling partnerships, as well as exploring opportunities to work on acquisitions together. The opportunity set has only expanded for us with over $1 billion of opportunities in the backlog. However, the variability in asset quality is also elevated, and we will continue to prosecute using the same methodology we have in the past in order to grow the business with discipline. As we move into the new year, our scaled and diversified business model provides us the ability to optimize the deployment of capital across the portfolio and adjust to changing market conditions. We look forward to continuing to differentiate ourselves from our peers and build on last year's successes in 2022. Now I'll turn it over to Chad Allen. Thanks, Adam. I'll start by reviewing some of our key Q4 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 $175 million for the year. Our adjusted EPS was $1.06 per share in the Q4, above consensus estimates. Oil differentials were flat and gas realizations were 20% higher compared to Q3. These operating costs were $50.6 million in the Q4 of 2021 or $8.57 per BOE, an increase of 5% on a per unit basis compared to the Q3. The increase in unit cost was primarily driven by the acquisition of higher unit cost 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 Q3 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 Q1 of next year. As we head into the spring borrowing base redetermination, we think our current asset base would support a substantially higher borrowing base should we desire more liquidity. On the hedging front, we've added volume since our last report, mostly in connection with the recently closed Veritas acquisition. We continue to target hedging 60%-65% of production on a rolling 18-month basis, with select longer-dated hedging tied to corporate acquisitions. With respect to 2022 guidance, our production guidance is 70,000-75,000 BOE per day. We expect our production to ramp as we move through the year and exit closer to the high end of our range. As Adam mentioned, Q1 is typically our slowest quarter, so in terms of cadence of our capital spend, we expect it to be more weighted towards the last three quarters of the year. One note on our production expense guidance. Our firm transport commitments related to our Marcellus properties are paid in the first half of the year, so we expect that production expenses will be elevated and higher than our annual guidance ranges in Q1 and Q2. This outlook should generate, at current strip prices, well in excess of $375 million in free cash flow after our preferred stock dividends and will result in modestly increased production volumes and consistent growth in our common stock dividend. As Nick mentioned, the steady volume ramp we expect throughout 2022 also bodes well for a strong setup for 2023. I'd like to close out highlighting our reserves we noted in our release. Inclusive of Veritas, our proved PV-10 at SEC pricing is $3.8 billion, which is over 20% higher than our current enterprise value. We'd like to remind investors that as a non-operator, we typically book a significantly less aggressive PUD schedule than operators despite our robust inventory and activity. This is simply to highlight the value that is not being recognized in the marketplace today. With that, I'll turn the call back over to the operator for Q&A. Thank you. At this time, we'll be conducting a question-and-answer session. If you'd like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question comes from the line of Neal Dingmann with Truist Securities. Please proceed with your question. Mr. Dingman, please go ahead. Oh, sorry about that. Morning, guys. Nick, I thought I'd maybe just jump to the top of du jour, and that's, of course, shareholder return. My question around that is, especially for, you know, a smaller company your size, you guys certainly, when I look at the dividend and other things within that plan, not only could be one of the leaders in the smaller caps, but certainly just in my entire coverage group. My question, I guess is, you know, when you were on board and Bernie talks about that, is that? Can you sort of coexist by doing that and creating value? If you maybe give an overview of how you invest. Again, you guys have really turned this company around. I'm just sort of thinking the next innings, you know, how do you sort of do both from this point on? Yeah. Thanks, Neal. Good morning. I think the way I would couch it is, you know, if you look back at when we did the Comstock transaction in the fall, you know, transactions like that's a pretty run-of-the-mill, you know, PDP asset that we purchased. And, you know, while you're capitalizing, you know, the cost of acquiring that property, ultimately, you know, it almost immediately, you know, adds cash flow that can be returned back to shareholders. So it actually, while you're spending money, you're 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 factor. You are borrowing some money when you buy a property like that, and you 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. We see most of the bolt-on stuff we'll do over the next several years, generally speaking, as something that's gonna accelerate that path, especially where we are in the world of shale today. I think, you know, it is maturing. You know, we saw an interesting banking report done. Five years ago, about 80% of the average M&A transaction was for undeveloped land, and today it's roughly the opposite. With a lot of proved developed properties coming alongside every package we look at it, that means that that's cash flow that can both self-fund the undeveloped portion and also return some to shareholders. Right. Great. No, I think that's exactly right, to be able to do both. Then lastly, the second just I want to have an answer sometime that's really just on the non-op model. You know, I look at it for a while, you guys maybe were, you know, getting a knock on, you know, basically premium versus a discount because being a non-op. Now I look at it and say, you know, good, you guys seem to have. I'm looking out there and based on my numbers, you know, you could have some of the highest returns. You certainly might not have as much stranded capital as some other folks. I guess my question around all that is, you know, do you think or how do you basically justify or get the higher premium and show investors now that, you know, basically the new model that you've shown? Yeah. I mean, 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 purchased versus operating peers who have bought things in similar areas, what they paid per location for the reserves, et cetera, et cetera. We obviously don't have the same level of G&A overhead on top of that. Undoubtedly, we are buying assets for less than others. 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 and 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. I think it will take time. I think it will be driven by cash returns. I think when you have a business that can deliver, you know, better cash on cash returns, better free cash flow per share, better, you know, across the board, ultimately, that will translate into an equity that has a premium valuation. I think, you know, I look at the minerals model that is a non-operated 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. 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, you know, between, you know, NOG and a lot of other, you know, non-operators out there is the active management, right? It's not just picking up a package and sitting on it and waiting for the rigs to come. It's, you know, wringing the towel and 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 kind of coming through one filter and being able to identify and being agnostic as to where you're gonna allocate that capital. Yeah. I mean, I just use an example, Neal, in real time. We have two existing mineral partnerships within our Williston Basin asset in which we have teams going 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 interests 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 details. Thank you all again. Thank you. Our next question comes from the line of John Freeman with Raymond James. Please proceed with your question. Good morning, guys. John. I just wanna follow up a little bit on Neal's questions on the shareholder return front, just to make sure that I understand the way you all are thinking about it going forward. If we go back to the dividend framework that you all put in place at the end of last year, where at that $50 oil, $3 gas sort of, you know, base commodity price you all were using, the plan was to basically pay out about a third of your free cash flow in the form of the base dividend. I guess from here, if we're just thinking about, you know, the next 12, 24 months with obviously the commodity environment, you know, well north of that, should we think of it as the first objective with that excess free cash flow is just you're gonna, you know, pay down the bank facility like you all said, you know, Q1 2023, I think what you're targeting. Then after that's done is the option to start. You could potentially layer on additional, whether it's dividend increases or special dividends, buybacks or whatever, or do you start tackling the 28, you know, notes? Just how you all are thinking about it. Yeah. I mean, I think the conclusion we've come to is as we achieve, you know, higher prices than we run internally, you know, just to give you some context, at the pace we're going right now and the business as it stands, we're gonna exit a year from now. You know, we're not just looking out next quarter, we're looking out, you know, the end of 2023. By the end of 2023, you're talking about having hundreds of millions of dollars fallow cash on the balance sheet. That's good and bad. I mean, I think in the sense that it's obviously not earning a return. You know, as you noticed, we bought back some preferred stock in the last month. I think we can kind of start to feather all of those things in along the way. It means we think we can get ahead of it a little bit, which means I do believe if the environment stays as it is today, we'll be able to accelerate forward some of that dividend plan. You know, we said we would do $0.12 this quarter. The board, you know, looked at where we were and decided that we could bring it to $0.14. I would hope that if the environment stays strong, that we can continue to bring that forward. I think the inevitability is over time that even with all those things, you're still talking about hundreds of millions of dollars in cash. Now the bond is a bond, and it's not callable till 2025. I don't know if it's particularly. It's certainly a higher cost piece of debt than our revolver. And so you do a little bit more damage buying it. It does trade at a premium to par. And so that's always an option to repurchase those over time. I would hope that we can either find a way to deliver some of that to the stockholders as well. You know, there is some level of debt that we're gonna wanna keep to be capital efficient over time. I mean, I think being debt free is great, but it creates other avenues, and we would hope we can find ways to grow value for the stockholders along that. You know, if you look at the preferred stock, you know, I wanna highlight something, which is that the preferred stock is in the money today. What that means is that the average, you know, arbitrage convert holder is actually short stock against it. When you look at our short interest, a good portion of that is preferred holders that are hedging themselves, and it's about 90 delta today. As we buy, you know, preferred stock over time, it effectively creates a buyback in the marketplace as well. I think it is definitely our most expensive cost of capital, particularly as the stock has rallied over time. I think where I'm going with this is I think we think we can do things all along the way, not just get the debt done first and then go there. We think we can feather, you know, additional things for stockholders over time along the way, just because of the inevitability of the cash wall we're building. That's great. No, I appreciate all the color. My other question, when I look at the 2022 budget, you've got, you know, about 90% of the budget split, you know, equally between the Bakken and the Permian, and then the remaining amount in the Marcellus. I guess when you're looking at M&A opportunities outside of those three operating areas, like how important is scale? Like in other words, for you all to jump into like another basin, does the initial entry need to be, you know, pretty sizable, or would you be fine sort of methodically building a position in a fourth basin? Yeah, I mean, I'll be pretty frank. We got a $25 million, you know, Eagle Ford package shopped to us the other day, and I think the teaser went directly in the trash. It's not that it's a bad asset necessarily, but, you know, we wanna stay focused. If you were to go to another basin, it would have to be something significant enough. You know, it is a tax on the organization to manage and evaluate and be an expert in all 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. I would expect the vast majority of opportunities in front of us, particularly given, you know, I don't know, what is it, 90% of the rig count is in the Permian right now in the United States? Yeah. I mean, what I was gonna say is, I mean, it largely solves for itself, right? I mean, we talked about $1 billion backlog, and if I'm looking at kind of the, you know, call it 12-15, you know, 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 gonna be, you know, asset quality, and that's where the asset quality is in terms of the non-op. 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, you know, regardless of what inning, you know, any of these basins are in. I think our focus will generally remain in the Delaware, you know, the Midland and North Dakota. That being said, you know, we're screening, you know, asset packages across, you know, 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. Thanks, John. Our next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question. Yeah, thanks. Hey, I'm gonna jump on the shareholder return bandwagon too here, but take a little bit different angle to the question. Obviously, you guys have shown there's a multitude of things you can do at these commodity prices and taking out the preferred and is an option as well as taking out bank debt. Can you just speak to, you know, especially as you know, embark on your fixed dividend plan increases, just the sustainability and durability of being able to do that with your existing asset base, meaning, you know, if you didn't get ground game opportunities or acquisition opportunities, you know, what kind of oil price deck do you need to make the current plan sustainable with your existing asset base? Yeah, I mean, I think what we put out, you know, we spent a lot of time with this at the board level, Scott, so we said 53. And that plan was based on the assets we have today for, you know, a 10-year period, right? So, effectively, if we never bought another thing, that's what that's based on. I mean, we, you know, I can tell you know, the Williston is a mature basin and, you know, many people think it's past its prime. I would tell you, 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. You know, we've had on the Veritas assets, as an example, we've already had, you know, an entire net well proposed that we didn't even underwrite or put in our inventory since we purchased the properties. I would say we're conservative guys by nature, but I would, you know, 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 kind of come on or off. We see a lot of durability to that. Got it. Great. That's down to 50, right? 50 can continue down that path and feel pretty good for the next 10 years. Is that right? That's right. Cool. Okay. My follow-up question, and Nick, I know you and I talked about this a bit, you know, just about your technical team and how you all, you know, look at the assets and do some work. With that influx of, you know, a lot more AFE proposals and a number of acquisition opportunities out there, can you just speak to, you know, with all that stuff coming in, you know, how does your team kind of approach going through all that stuff? I know your consent rate, it sounded like it was 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, you know, the depth of your technical team and how you guys approach that to kind of get through all that and making sure you're, you know, maintaining the quality of your investments? 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, at least relative to our size. I think we're up to 30. You know, I like bragging how 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, you know, 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 built out. On the evaluation front, you know, that is the part where we have continued to and I would also add on the engineering side, before I get to that, you know, on the technician side, you know, we have two engineering technicians dedicated now that have continued to build out systems to automate as many of these processes as possible. We just signed a five-year contract on a data warehouse project that's gonna effectively integrate almost every system we have. Then going to the evaluation part, that is the trick. I think given the volume, you know, oil's $90, right? You can imagine even the best and the worst assets are all coming to market right now, you know, trying to monetize, you know, on assets that may, you know, as I've told you in past conference calls, that probably needed to be sold three or four years ago, and now finally, the market is high enough that they can get out above water. The part that is the art of what Adam, Jim and I, and Mike spend a lot of time on, which is filtering through those things and seeing what is worth our time. You know, when there are things in our existing areas, it's obviously very easy, and those answers can generally come in 24 hours. When it's something new or something in an expansion with even within basins we operate, we have to make a judgment call internally about whether we wanna dedicate resources to it. I would say on the technical front, we have that is really, you know, if there's a huge shift in Northern over my tenure here and over the last five years, is that really the technical focus is everything, and everything starts and ends with that. The key thing is the volume of transactions is somewhat overwhelming, and we really solve for that by only focusing on things we both know we have a high probability of winning if we want to, and secondly, that meet our criteria. I don't know, Adam, you wanna add to that? No, that's right. I mean, I feel like a broken record, but it largely solves for itself. I mean, first we're taking a look at, you know, whether the asset itself is gonna pass muster. Even 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. The rocks are the rocks, but the operators can differentiate that significantly. That's where we leverage, you know, the 350 type curves that we've got in North Dakota and building out, you know, 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. 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, you know, three-quarters of these things up front and focus on, you know, the assets that are gonna trade based on, you know, the social issues that are effectively in place, at the same time that often influence these processes. That's great. Thank you. Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question. Good morning, Nick, to you and the rest of the crew there. Morning. You know what? 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, you know, going back to your comments on, I appreciate your comments on inflation and in the Permian versus the Bakken, but also service availability is a growing concern as well. Can you talk about not, maybe not just the total number of wells that you're looking at with Veritas, but also the schedule there, if anything's changed? Yeah, I think, you know, as a nod, the schedule's always moving around, particularly this time of year, right? You know, 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. I can tell you what we see in real time from our 50-plus operators are, you know, small one and two rig operators are really struggling. You know, 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 Devon or Mewbourne or one of the largest and most active operators, you're not having those same types of issues. In terms of that, it hasn't changed. The schedule is moving around all the time. You know, that's the art of how we guide. You know, 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, particularly in the Williston, you know, around this time of year, given winter weather, whether things are gonna get completed before the freeze or not. In terms of Veritas overall, I mean, Jim, I don't know if you wanna comment otherwise, but I don't really think there's been any material changes. I think what I was trying to highlight, Charles Meade, is more that, you know, when we said we saw another 40 net locations on there, we were trying to be about as conservative as possible, you know. 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. If I could ask a question about the ground game. Historically, I'm curious how it may be changing or you might see it changing going forward. My understanding historically is that was about you know like you said earlier you know getting in front of the rig and picking up working interests in properties where you already had an interest and just trying to you know accrete your interest in front of some activity. It sounds like you guys may also be kind of lumping in just some you know little deals that you're just funding out of cash that maybe or maybe are little deals on properties where you don't currently have an interest. Is that the case? Is the opportunity set shifting that way? 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 those things. Sometimes it'll be, you know, 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. 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 is, I would say, the explosion in organic development on our properties has, you know, probably made us a little less active than we've been in the last few years. Is that fair, Adam? Yeah, exactly. Then I think there's probably, you know, two-three of these kind of ground game opportunities coming in the door on a daily basis. A lot of these we're in just by nature of our acreage position, and there's a number of them that aren't. That's been the case for, you know, the past, call it five years. So it's really just kind of high-grading what your opportunity set is. That's kind of what I was alluding to in, you know, the prepared remarks in terms of we've got an explosion in terms of activity levels. Operators are staying disciplined, and so it, you know, you can feather the ground game based on the activity that you're seeing on kind of your organic acreage. You know, given the fact that where we're at in terms of commodity pricing and operator activity as well as, you know, the ground game activity that we were able to get done in the third and the Q4, it's effectively set up, you know, 2022's, you know, activity where we're comfortable at. So as we kind of move through, you know, the Q1 and into the second, we'll continue to keep a bead 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. Morning. Picking up with Charles's 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? I mean, there's always competition, especially, you know, the smaller the dollar amount, the more competition there is, right? There's always competition, I would say. I don't know if I would say it's any more or less than in the past. I don't know. You wanna- No, I mean, I think viewpoints change with maybe some of our competition, and if it's, you know, new money in, they're kind of scrambling to put it to work, then maybe they're stretching. I think it also, you've got some variability between basins as well. The next point, you know, you got a well pad that comes with, you know, four or five, you know, well proposals, but the, you know, working interest is 30%-40%, you know, versus, you know, that same well with, you know, 2%-3% working interest. Your competition set is wildly different in that regard. You know, that's where we can, you know, do a bit more damage with maybe some of the higher concentrated opportunities on a ground game basis because some of our smaller counterparts aren't necessarily comfortable with, you know, that level of concentration, whereas when you look at our base and, you know, relative to everything we're throwing off, it doesn't necessarily move the 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? Yeah. I mean, we've always kind of looked to, I guess, the true privates, I would say, you know, the ones that are focused on making money. You know, Slawson in North Dakota, you know, they've continued to be active in this particular environment. You know, we've made it a point to, you know, get underneath, you know, Mewbourne Oil and The Delaware side of things. Between kind of those two, you know, two of the most kind of cost-efficient operators as well as, you know, two of the most active operators in our respective basins, we continue to have that activity level, you know, kind of flex forward in this particular environment. As far as, you know, some of the private equity groups, you know, we're typically, you know, stay away from those guys. You solve for that more on the acquisition side of things. I would say that's largely, you know, Mewbourne 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 on tax. Morning, John. Yeah. You gave that free cash flow outlook here over the potential next 4 years equal to your market cap. Could you just sort of speak about the cash tax trajectory over a multiyear horizon? Yeah. I'll let Chad cover that. I mean, the answer is, you know, eventually we will have to pay taxes. Yeah. Thanks, John. I mean, obviously, you saw us pay some fairly immaterial state taxes in Pennsylvania and Texas and New Mexico because we don't have any NOLs established there. You know, in the past, we've been elected not to fully deduct IDCs or bonus depreciation for the past several years to kind of preserve future deductions for us. You know, it's clearly based on our drilling activity and commodity price. I think, you know, based on our current model, you know, there'll be some small amount of taxes that we'll pay in at the end of 2023. Once we pay taxes, it'll be kind of a mid-20% overall tax rate, but obviously adjusted for any changes in tax law. Obviously, we also have the IDC deductions and future tangible drilling bonus depreciation stuff that we can take there as well. Our overall effective rate will be well below that. The number that I threw out when I talked about that is net of that. You know, internally, we run it, so it's running it at the strip, so it's gonna adjust for any change in commodity prices as to the timing of that. That's very helpful. Just sticking with costs here, you know, looking at LOE 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 then trend over a multiyear horizon? Yeah, I mean, it really depends on the price of NGL. First of all, each for the next two years, our FT associated with the Marcellus will pay that in the first half of the year, so it has a way of elevating sort of your front half LOE, and then it doesn't go in smoothly. It really goes, you pay it, you know, kind of twice a year, and you can't accrue throughout the year. So, you know, in the first six months of the next two years, that FT, and then it'll 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 noticed we did tick up our gas realizations as part of that, but we're trying to be conservative on both fronts. It's not a function of actually operating costs really materially going up. I mean, obviously, as wells age out, their LOE does rise. As our production matures, you're gonna 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 gonna see some of that in those charges on there. 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. 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. Okay. Our next question comes from the line of Nicholas Pope with Seaport. Please proceed with your question. Morning, guys. Nick, you know, I went out and, you know, I told you I could just go on the market and buy the preferred stock, and I did it just to figure, right? Yeah. It's exciting. I'm happy to model it. I was hoping you guys could talk a little bit about, you know, you look at this, the big portfolio, and I think a lot of the focus is, you know, on the newer wells and the acquisition front. But now you got these interest in, you know, 8,000, 9,000 wells. How are you all thinking about in this market potential divestitures or kind of culling, you know, weaker performers in kind of the existing producing asset? Or is that a focus? I'm just kind of curious how you all think about the hierarchy of kind of the existing producing asset and if there's ever kind of a shift to look at that opportunity set and maybe selling into the strong M&A market. Yeah. I mean, I think to the last point, you have to think about a call on oil prices there for a second because if even if you sell a PDP asset, as an example, a PV-10, you're still talking about a 10% cost of capital, right? You're borrowing money at 3%. So you're sitting there saying, "If I needed money, that'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. You know, would we consider 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, and maybe you could frame that in the way of a trade in which we're taking other non-operated properties that they don't want. This is a trend we've been watching for the last year or 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 farm out non-operated acreage to operators. We've never really been a material seller. I do think it's something, you know, we're looking at, particularly, as you said, you know, there may be operators that we don't necessarily want exposure to, and we, if the price was right, we'd happily either sell or trade them our assets for perhaps other assets they don't want. That's right. The price for an operated acreage, at least the way that some of our operators see it, might be worth, you know, one and a half times what they're, you know, the view in their non-op, and that might have nothing to do with the actual economics, but more the control. If you can leverage and, you know, exploit that trade-off so that everybody's kind of 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're having. Yeah, that's actually really helpful. As you look at the existing portfolio base, I mean, as you look at, you know, either operating cost, age, you know, kind of well performance, like 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, a lot more obviously than it was two years ago. Yeah. You just mean in terms of the ranking, if you were to divest them? Yeah. I mean, is that how you guys think about it? I mean, if that, you know. Yeah. If you'll humor me, I'll give you a little history lesson. I watched a lot of operators in, you know, 2010-2017 sell PDP assets that had higher operating costs to go fund new drilling wells, and so they could show really low LOE. 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. They're it's not, you know, sort of one for one. I would say where we would look at potentially divesting assets is a period more in 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, you know, the future development possibilities. You know, 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, you know, frankly wouldn't want, you know, even if it was to be developed, it wouldn't necessarily be where we wanna put our capital, you know, throw like Divide County out there or something like that. But at this, you know, 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. That's very helpful, very interesting. Thanks for indulging me. I appreciate the time. Yeah, my pleasure. Yeah. 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 things. You know, continuing on the conversation about operators you are happier being involved with as opposed to those that you more or less look to avoid. I'm just curious, in your basins, are you aware of is there anything significant that's on the market as far as you know, operated acreage in a package that would, if it sells, lead to a meaningful shift in your operatorship profile in any of the basins? Yeah. I think in the Williston, there's gonna be some large operated packages that change hands in the next couple years. I would say we would view that as a huge positive for us if it was to transpire. Yeah. I mean, as far as North Dakota goes, I think we're in 40% of all Bakken and Three Forks wells that have ever been drilled. I mean, regardless of kind of those packages coming to market, the non-op nature, it's not gonna move around all that much. It's also gonna depend on the average working interest. A lot of these packages that we're seeing have average working interests that are probably half of what ours is. You know, I would usually. There was a large operated package sold at the beginning. It was either late 2020 or beginning of last year, and 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. You know, I'd use the you know our Marcellus properties as the poster child for that, which is you have a focused operator that takes over and does a huge improvement, both the well design, cost structure, well performance, all those things, and we would see a lot of meat on the bone on some of the properties that we exist at, 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 hands, it would be a huge benefit to us, even if there wasn't a change in cost structure, which usually there is. That's really interesting. Thanks. Another sort of similar question, but looking more at the Marcellus. Just for 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. I'm just wondering, do you see an overall trend either of inventory concentrating itself into fewer hands, you know, but bigger operators, you know, through either consolidation that's underway or that you think might happen. I was wondering if you see any sort of opposite force of people powering down, sort of paring down their positions, because some of the larger ones, of course, you know, have decades of inventory at this point that it's not so likely they're gonna get around to funding. Yeah. I mean, I think consolidation is a continued theme. I think I'm on the record, and I'll repeat what I've said publicly before, which is that, you know, there's a lot of focus on Shale 3.0 and the slowdown and the lack of acceleration in drilling. 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. 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 Right. Of the Marcellus that we've looked at are 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. It's highly economic, and so I don't see that as an issue for our asset. 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. You've already seen that, right? You've seen Alta trade hands. You've seen a signi- Chief. Chief, you've seen a significant amount of consolidation already. Will there be more? I can't say if there will or there won't, but I don't think it's the type of thing where you're gonna see a small group go and pick up a rig and 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 barely touched. Not to mention the fact that we bought, you know, a half a decade's worth of DUCs when we bought the property. Just to extend that a little bit, is it safe to say that, and I'm thinking particularly about the Marcellus, that there isn't really fresh money looking, you know, attracted by, you know, higher gas prices, looking to sort of come in and start something new from the ground up there. It's just people are kind of getting squeezed out, in other words? I would say that's a fair assessment. I mean, I certainly think capital in general, new capital is gonna put a significant long-term operator footprint in areas in the United States 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 Nick O'Grady, NOG CEO, for closing remarks. 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. To access the digital replay, please dial eight seven seven six six zero six eight five three or two zero one six one two seven four one five and enter access code one three seven two six seven five two. 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