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. 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 that we issued this morning. With that taken care of, I will hand the call over to Northern CEO, Nicholas O'Grady.

Thanks, Michael. Thank you for joining us this morning. As usual, I will get down to it with five key points. Number 1, execution. We closed out 2021 with very strong 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 2, capital allocation. At current strip prices over the next four years, the company could generate its entire market cap in free cash flow. This puts us in an incredible position to allocate capital, which we will do in the following four ways: Number 1. Our organic development. Number 2. Small-scale and bolt-on package M&A. Number 3. Further debt retirement. And finally Number 4. 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 want to 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 3, Shareholder Returns. As mentioned above, we have tremendous 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 $0.5 million a year, and effectively reduces the diluted share count by approximately 316,000 shares. Number 4, 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 stable 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 listen 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 the business for less than 15,000 barrels equivalent per day, while continuing to cut the cost of our credit and materially lower leverage ratio. 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. We bought 56 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 4.5 times since then. In the coming quarters and years, we will 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, 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 turned 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 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 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 represent 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 in labor. Our new proposals averaged $7.1 million during the quarter, effectively in line with the third quarter and comfortably within the range of our internal estimates in the $7 million to $8 million range. In the Williston, we expect to see even 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 have 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 furthering 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 '21 as well as the increase in drilling on our acreage, much of our anticipated '22 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 '22. Now I'll turn it over to Chad Allen.

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 $175 million for the year. Our adjusted EPS was $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-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 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 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 borrowing base should we desire more liquidity. On the hedging front, we've added volumes since our last report, mostly in connection with the recently closed Veritas acquisition. We continue to target hedging 60% to 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 to 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 dividend and will result in modestly increased production volumes and consistent growth in our common stock dividend. As Nicholas mentioned, the steady volume rent 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 PV10 and 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 will turn the call back over to the Operator for Q&A.

Thank you. At this time, we will be conducting a question-and-answer session. 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 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 coverage group, but certainly my question, I guess is when you brought onboard a positive that bad, can you co-exist by doing that in creating value? If you could give an overview of how you invest. And again, you guys have really turned this company around. I'm just thinking the next innings. How do you do both from this point on?

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 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 we’ll 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.

I think that's exactly right. It's important to be able to do both. Looking at the non-operating model, I've noticed that you may have faced some criticism regarding premium reverses and discounts due to your non-operating status. However, it seems like based on my analysis, you could potentially achieve some of the highest returns. While you might not have as much capital strength as some others in the South, my question is how you justify or demonstrate that higher premium to investors with the new models you've presented.

I believe there is a distinction between the market price of non-operating assets and their actual value to us as a company and as a publicly traded entity. We are confident in our ability to acquire assets, as evidenced by what we've purchased compared to our operating peers who have invested in similar regions and what they paid for their reserves. We don't have the same level of general and administrative overhead, which means we are acquiring assets at lower prices than others. However, just because a non-operating asset in the market is sold at a discount, it doesn’t mean that a non-operating business or its equity in a public company should also be discounted. This is my perspective, and while not everyone may agree, I believe that our diversified model creates an arbitrage opportunity. It will take time, but I expect it will be driven by cash returns. A business that can provide superior cash-on-cash returns and better free cash flow per share will ultimately command a premium valuation. I also consider the minerals model, which operates as a non-operator business. It has lower returns but has received a premium in the market due to its structure. I believe we will reach that point as well.

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.

We have two existing mineral partnerships in our Williston basin where our teams are continuously buying and selling minerals under our working interest, which increases our net revenue interests. Although we don’t report it as a separate asset, it illustrates our active management approach where our net revenue interest and overall working interest are frequently changing. We maximize our assets as they are 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.

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 to 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 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.

Yes. We've concluded that as we achieve higher prices, we can look at our business more broadly. Currently, we're on pace to have hundreds of millions of dollars in total cash on our balance sheet by the end of 2023. While that’s beneficial, it also means that cash isn't earning a return. Recently, we bought back some preferred stock, and we believe we can manage these issues effectively. If the environment remains steady, we could possibly accelerate our dividend plan. We initially planned for a dividend of $0.12 this quarter, but the board has decided to increase it to $0.14. If conditions allow, I hope we can continue to increase that. However, we will still have significant cash reserves over time, and while our bonds aren't callable until 2025, they are a more expensive form of debt compared to our revolving credit. Repurchasing them over time is an option. We also want to ensure we are providing value to our shareholders while keeping a manageable level of debt for capital efficiency. Being debt-free is desirable but presents challenges, so we're looking to create shareholder value in various ways. I also want to highlight that our preferred stock is currently in the money, meaning that many holders are hedging their positions, contributing to a significant portion of our short interest. As we buy back preferred stock, this will also act as a market buyback. Given that preferred stock is currently our most expensive capital source, we believe we can address multiple financial strategies simultaneously rather than just focusing on debt repayment first. We're confident we can manage our cash flow effectively to benefit our shareholders.

I appreciate all the color. My other question, when I look at the '22 budget, you've got about 90% of budgets split 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?

I will be very straightforward, we recently received a $25 million Eagle Ford package, but I think it went straight to the trash. It's not necessarily a bad asset, but we want to stay focused. If we were to explore another basin, it wouldn't need to be something substantial. Managing and evaluating different options demands resources, and we have invested significant time, money, and personnel to become experts in the basins we currently operate. This is not a decision we make lightly. Therefore, I anticipate that most of the opportunities available to us will be primarily in the Permian, especially considering that about 90% of the rig count is currently there.

Yes. What I was going to say it largely solves for itself. We talked about a $1 billion backlog, and if I'm looking at 12 to 15 packages 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 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.

Thanks John.

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

Thanks, Sam. I would like to address the shareholder returns topic from a slightly different perspective. Clearly, you have demonstrated a variety of actions you can take regarding commodity prices, including eliminating preferred shares and reducing bank debt. Could you discuss the sustainability and longevity of your fixed dividend plan increases in relation to your current asset base? Specifically, what oil prices do you need to maintain these plans if new opportunities for growth or acquisitions do not arise?

Yes. I believe the plan we outlined, which involved $50 and $3, was thoroughly discussed at the board level. This plan is based on our current assets for a 10-year period. Essentially, we haven't made any additional purchases; that's the basis of our projection. I want to emphasize that while many consider the Williston a mature basin, our asset is relatively young, and we've developed it in a way that maximizes our activity. For instance, on the Veritas assets, we've already proposed an entire net well that we didn't even include in our inventory when we acquired the properties. We're naturally conservative, and we didn't approach this lightly. A significant amount of time and effort went into this decision, particularly since it involves a base dividend, which represents a commitment rather than a special dividend that can be adjusted. We believe there is significant durability in this approach.

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?

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 a 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 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?

We've invested significant time and resources in expanding our team over the past couple of years, and we now have around 30 employees. Our engineering department is the largest group in the company and plays a crucial role in our operations. When it comes to AFE proposals, we have a dedicated team that reviews each one, ensuring they are individually approved by our Chief Engineer and Adam. This process has become quite streamlined, given that we've established the necessary type curves. On the engineering side, we have two technicians focused on automating processes, and we've recently signed a five-year contract for a data warehouse project to integrate our systems. The evaluation process is where we face challenges. With oil prices at $90, many assets are coming to market, and we need to determine which ones are worth pursuing. We rely on our past experiences to filter through these opportunities and assess their viability. When it comes to existing areas, we can quickly evaluate proposals, but for new expansions or different basins, we must carefully decide how to allocate our resources. Over the past five years, the technical focus of our company has grown significantly, and it is critical to our success. The sheer volume of transactions can be daunting, so we concentrate on those with a high likelihood of success and that align with our criteria. Adam, do you want to add anything?

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 focus on the assets that are going to trade based on the social issues that are effectively in place at the same time that often influences 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 and the team. You briefly mentioned the Veritas deal earlier. Could you share what's changed since your evaluation of it? You noted there's been one additional net well proposed, but I'm also interested in whether the schedule has been adjusted. I appreciate your insights regarding inflation in the Permian compared to the Bakken, but service availability is becoming a larger concern as well. Can you discuss not only the total number of wells you are considering with Veritas but also any changes to the schedule?

As a non-operating entity, the schedule is constantly shifting, especially during the winter and spring months. However, if you examine the operator mix on the Veritas assets, service availability is not a problem. We're dealing with some of the largest and best-capitalized companies. From our experience with over 50 operators, smaller one and two rig operators are facing significant challenges. Frac crews often fail to arrive on time, and they struggle to obtain drill pipe, among other issues. In contrast, major operators like Devon or Melbourn are not experiencing these problems. The schedule remains fluid, and managing it is part of our guiding process. Historically, we've become adept at carefully planning around these changes, particularly in the Williston area during this season as we anticipate whether work will be completed before the freeze sets in. Regarding Veritas overall, I don't believe there have been any significant changes. I aimed to emphasize that we've identified an additional 40 net locations while remaining conservative in our approach. We did not underwrite the smaller working interest items, and we are already noticing the benefits from this strategy.

That's all helpful. And then, if I could ask a question about the Ground Game. Historically, I'm curious how it may 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 have an 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 find out of cash that 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?

I'll let Adam explain this in more detail. However, I would say that it has always been a mix of various elements. Sometimes it involves acquiring a little bit of PDP, where you're purchasing an interest in a unit that already has two wells drilled and an additional eight planned. So, there's always some variability in that regard. I don't think much has changed. The main difference in 2022 compared to previous years is likely due to the significant increase in organic development on our properties, which has made us somewhat less active than we have been in the past few years. Is that a fair assessment?

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 investing in the case for the past five years. It's really just high grade in what 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, we 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?

There's always competition, especially with smaller dollar amounts, which tends to attract more competitors. So, I would say competition is always present, but I can't say if it's greater or lesser than in the past.

I think perspectives have shifted among some of our competitors. If they're dealing with new funds and trying to invest quickly, they might be overextending themselves. There's also variability between different basins. Additionally, a well pad can have proposals for four or five wells, but the working interest can range from 30% to 40%, compared to just 2% to 3% in other cases, which makes competition quite distinct. This is where we can leverage some higher concentration opportunities effectively because some of our smaller competitors may not be comfortable with that level of investment. In contrast, looking at our overall performance, it doesn’t significantly impact our results.

Yes. I mean, we've always looked at the true privates I would say, the ones that are focused on making money, Slawson and North Dakota, they continue 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. The first question is about the activity level flexing forward in this particular environment. We usually stay away from private equity groups, focusing more on acquisitions. So I would say that's largely related to Melbourne and Slawson in terms of private exposure. That's great. Thanks for your time. Our next question comes from John Abbott with Bank of America. Please proceed with your question.

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?

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 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 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.

Our overall effective rate will be significantly lower than that, and the figure I mentioned is net of that. We manage it internally, so it adjusts according to changes in commodity prices over time.

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?

It really depends on the price of NGLs. So 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 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 among 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 know 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 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.

I 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, 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 interests in 8,000, 9,000. How are you all thinking about in this market potential, divestitures or calling 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.

I think it's important to consider the relationship between oil prices and asset sales. Even if you sell an asset with a present value of ten, you're still looking at a 10% cost of capital. If you're borrowing at 3%, it becomes a costly way to secure funds. However, in the Williston, we've seen several operators purchasing non-operated assets at what we consider high values. We have thought about approaching our operating partners to sell our working interest in their properties if it's more valuable to them than to us. This could potentially lead to trades where we take on non-operated properties they no longer want. We've been observing this trend for about a year. While I wouldn't rule anything out, historically, we've never sold a significant asset, except for reallocating operable acreage to operators, and we haven't been active sellers. Nonetheless, we are exploring options, especially considering there might be operators we want to distance ourselves from. If the price is right, we would be open to selling or trading our assets for other properties they may not want.

That's right. The price for operated acreage, as viewed by some of our operators, may be valued at 1.5 times higher than their non-operated counterparts. This valuation might not reflect their actual economic figures but rather the control aspect. If we can leverage this trade-off to ensure that everyone benefits, we will pursue it. It’s more complex than a typical asset package, but these are the discussions we are currently having.

Got it. That's actually really helpful. As you consider the existing portfolio base, is there a ranking process you use for factors like operating costs, age, and well performance? How do you approach the existing portfolio base? Should that be the focus? There are a lot more wells now compared to two years ago.

Yes. You mean just in terms of the ranking, if you were to divest them?

Yes. Is that how you view it?

I observed many operators between 2010 and 2017 selling PDP assets with higher operating costs to finance new drilling wells, allowing them to report low LOE. However, this often resulted in a significant decline in their production curve. It's true that higher operating costs indicate lower margins, but they also lead to lower decline rates, which is not a direct correlation. Regarding potential asset divestiture, we consider whether the future value of those assets is less significant to us compared to their value to other operators or based on our outlook for future development. For instance, we own some acreage in less central areas of the Williston that might hold more value for another operator, even if we would choose not to invest our capital there. It doesn’t mean those assets are unprofitable; it simply wouldn’t be our preferred choice for capital allocation.

Got you, Nicholas. That's very helpful, very interesting. Thanks for indulging me. I appreciate that.

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.

I have a couple of questions. Continuing with the discussion about operators, it seems you prefer to work with some over others. I'm curious if you’ve noticed anything significant in your basins regarding operated acreage that could potentially lead to a meaningful change in your operatorship profile in other areas.

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 we're seeing, having average working interest, they're probably half of what ours is.

There was a large operator package sold at the beginning, either late 2020 or early last year. A private operator took it over, and we've seen significant improvements since they are focused on the asset. There are other large operator packages in both the Williston and the Permian. Our Marcellus properties serve as a prime example of this, where a dedicated operator takes over and makes substantial improvements in well design, cost structure, and well performance. We see a lot of potential in some properties we have, especially when the assets are non-core to the operator, who is not investing in their development. We possess many undeveloped assets under certain operators, and if those were to change hands, it would greatly benefit us, even if there wasn't a change in cost structure, which typically occurs.

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.

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, 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. 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 untouched, not to mention the fact that we bought a half a decade's worth of ducks when we bought the property.

To add to that, it seems accurate to say that particularly in the Marcellus region, there isn't a significant influx of investment driven by higher gas prices aimed at starting new projects. Essentially, it appears that existing operators are facing challenges.

I believe that's a reasonable point. In general, new capital is likely to establish a significant long-term presence in certain areas, which seems to be diminishing. This situation appears to be evolving into a broader consolidation trend. For every new dollar that is invested, there are two dollars that need to be utilized and distributed. This has clearly fostered an environment that has enabled our company to expand in recent years.

Great, thanks a lot.

Thank you. Ladies and gentlemen, we have reached 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.

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. Thank you for your participation. You may disconnect your lines at this time.