Northern Oil and Gas Inc (NOG) 2021 Q4 法說會逐字稿

Greetings. Welcome to the NOG Fourth Quarter 2021 Earnings Call. (Operator Instructions) 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 fourth quarter 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 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 Q 4 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's CEO, Nick O'Grady.

Thanks, Mike and thank you for joining us this morning. As usual, I will get down to it with 5 key points. Number one, execution. We closed out 2021 in a very strong fact, 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 2, capital allocation. At current strip prices, over the next 4 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 4 ways. Number one, 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 a tremendous amount of confidence in our business model, which has given us the ability to communicate a dividend plan for the next 2 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 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 5, consistency. You'll notice if you've listened to our conference calls over the last 3 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 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 3 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 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 and substantial production less than 2 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 4.5x 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, Nick. NOG continues to execute smoothly as we close out a transformational year. During the fourth quarter, we saw a meaningful increase in completions and turn in line 12.1 net wells. There 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 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 5 to 6 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 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 fourth quarter across Northern's footprint, bringing in 130 new AFEs, 110 of which came from the Williston.

Our elected proposals accounted for 9.7 net wells and represents a 60% increase from Q3's activity. Given the discipline we're seeing among our operating partners and even when we sensitize our price deck 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 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 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 feathering our ground game activity to augment returns and capital efficiencies.

During the quarter, we closed on 9 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 had 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. These operating costs were $50.6 million in the fourth quarter of 2021 or $8.57 per BOE, an increase of 5% on a per unit basis compared to the third quarter. 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 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 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, post 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 BOE 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 to be more weighted towards the last 3 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 to 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. And we'd like to remind investors that as a nonoperator, 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.

Our first question comes from the line of Neal Dingmann with Truist Securities.

Nick, I thought I'd maybe just jump to the topic of zero net core shareholder return. My question around that is, especially for a smaller company of 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 small accounts, but certainly just in mind sort of coverage group. But my question I guess is when you brought onboard, you’ve already talked about that, is that -- can you sort of co-exist by doing that and creating value if you maybe give an overview of how you invest. And again, you guys have really turned this company around. So I'm just sort of thinking the next innings. How do you sort of do both in this point on?

Yes, thanks, Neal, Good morning. I think the way I would couch it is if you look back at when we did the Comstock transaction in the fall, transactions like that, that's a pretty run-of-the-mill PDP asset that we purchased. And while you're capitalizing the cost of acquiring that property, ultimately, almost immediately 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 and I think that's how we think about it.

And I think it's a function of how you capitalize those transactions and making sure you adjust for that risk factor, so 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. And so, we see most of the bolt-on stuff, we'll do over the next several years.

Generally speaking 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 5 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 it, that means that that's cash flow that can both self-fund the undeveloped portion and also return some to shareholders.

Got it. Great. No, I think that's exactly right to be able to do both. And then lastly, the second just don't want to have it at some time that's really just on the non-op model. I look at it for a while, you guys maybe were getting a knock on basically premium versus a discount, because being a non-op now I look at it and say, good, you guys seem to have -- I'm looking out there and based on my numbers, you could have some of the highest returns, you certainly might not have as much stranded capital with some other folks. And so I guess my question around all that is, do you think or how do you basically justify or get the higher premium and show investors now that basically the new model that you've shown?

Yes, 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. And so 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, and we don't -- we obviously don't have the same level of G&A overhead on top of that.

So undoubtedly, we are buying assets for less than others, but just because a non-op asset in the market trades for a discount, it doesn't necessarily mean a non-op business and a non-op equity 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, that is the arbitrage that we ultimately have built with a large diversified model.

And I think it will take time, I think it will be driven by cash returns. But I think when you have a business that can deliver better cash-on-cash returns, better free cash flow per share, better across the board, ultimately, that will translate into an equity that has a premium valuation. I think I look at the minerals model, that is a non-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.

And I think it will take time, but I think we'll get there.

And just to add on to that, I mean, I think the differentiation between NOG and a lot of other nonoperators out there is the active management, right? So it's not just picking up a package and sitting on it and waiting for the rigs to come, it's bringing the tow 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, being agnostic as to where you're going to allocate that capital.

Yes and I mean, I just use an example, Neal, in real time. We have 2 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 ring the tow, I like that as we bring the tow on every single unit as it's being developed.

Our next question comes from the line of John Freeman with Raymond James.

Yes, I just want to follow-up a little bit on Neal's questions on the shareholder return front, just to make sure that I understand the way you're always thinking about going forward. So if we -- if we go back to the dividend framework that you all put in place at the end of last year were at that $50 oil, $3 gas sort of base commodity price you were using, the plan was to basically pay out about a third of your free cash flow in the form of the base dividend. And so I guess from here, if we're just thinking about the next 12, 24 months with obviously the current environment well 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 you all said, first quarter '23, I think what you're targeting? And 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 note. Just how you are thinking about it?

Yes, I mean, I think what we -- the conclusion we've come to is as we achieve higher prices than we run internally, just to give you some context at the pace we're going right now and the business as it stands, we're going to exit a year from -- we're not just looking out next quarter, we're looking out the end of 2023. And by the end of 2023, you're talking about having hundreds of millions of dollars of follow cash on the balance sheet and that's good and bad.

I mean, I think in the sense that it's obviously not earning a return. And so as you noticed, we bought back some preferred stock in the last month. And I think we think we can kind of start to feather all of those things in along the way. And so 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. We said we would do $0.12 this quarter, the Board looked at where we were and decided that we could bring it to 14. And I would hope that and if the environment stays strong, that we can continue to bring that forward I think, but 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 until 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 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.

And there is some level of debt that we're going to want to 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. If you look at the preferred stock, I just -- I want to highlight something which is that the preferred stock is in the money today.

And what that means is that the average arbitrage convert holder is actually short stock against it. So when you look at our short interest, a good portion of that is its preferred holders that are hedging themselves and it's about 90 delta today. So as we buy preferred stock over time, it effectively creates a buyback in the marketplace as well.

And so I think and it is our -- definitively our most expensive cost of capital, particularly as the stock has rallied over time. And so 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 additional things for stockholders over time along the way just because of the inevitability of the cash flow we're building.

That's great. Appreciate all the color. My other question, when I look at the '22 budget, you've got about 90% of the budgets with equally between the Bakken and the Permian and the remaining amount in the Marcellus. And so I guess when you're looking at M&A opportunities outside of those 3 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 pretty sizable or would you be fine sort of methodically building a position in a fourth base?

Yes, I mean, I'll be pretty frank. We got a $25 million Eagle Ford package shop to us the other day and I think that the teaser went directly in the trash. And it's not that it's a bad asset necessarily, but we want to keep -- we want to stay focused. And so, if you were to go to another base when it would have to be something significant enough. It is a tax on the organization to manage and evaluate and be an expert in all of these things.

We've spent a lot of time, money, people to become an expert in the basins that we operate today. And that's not something we do on a whim. And so I would expect the vast majority of opportunities in front of us, particularly given -- I don't know what is it 90% of the rig count is in the Permian right now.

Yes, I mean what I was going to say it largely solves for itself, right? We talked about $1 billion backlog and if I'm looking at kind of the call it 12 to 15 packages that are out there that make that up, I mean, it's largely the Delaware and the Bakken. And so 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. And 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.

Congratulations on a fantastic year.

Thanks, John.

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

I'm going to jump on the shareholder return bandwidth too here, but take a little bit different angle to the question. Obviously, you guys have shown there is multitude of things you can do, these commodity prices and taking out the preferred and is an option as well as taking out bank debt.

But can you just speak to especially as you embark on your fixed dividend plan increases, just the sustainability and durability of being able to do that with your existing asset base, meaning, if you didn't get Ground Game opportunities or acquisition opportunities, what kind of oil price deck do you need to make the current plans sustainable with your existing asset base?

Yes, I mean, I think the what we put out, we spent a lot of time with us at the board level, Scott. So we said 50 and 3 and that plan was based on the assets we have today for a 10-year period, right? So effectively, we didn't -- we never bought another thing, that's what that's based on. I can tell you, the Williston is a mature basin and many people think it's fast as ramp, I would tell you, we -- what do we see a 60% increase in AFE activity in Q4. Our asset is quite young and the way we have built it and we are about as busy as we can be, we've had on the Veritas assets as an example, we've already had an entire net well proposed that we didn't even underwrite or put in our inventory, since we purchased the properties. And so I would say we're conservative guys by nature, but I would -- we didn't do this lightly. We spent a lot of time and effort to make sure that especially when you're doing it as a base dividend, which you know is effectively a commitment as opposed to a special which you can come on or off and we see a lot of durability to that.

Got it, great. And that's down to 50, right? So 50 can continue down that path and feel pretty good for the next 10 years, is that right?

That's right.

Okay. So my follow-up question and Nick I know you and I talked about this a bit, just about your technical team and how you all look at the assets and do some work and with that influx of lot more AFE proposals and a number of acquisition opportunities out there. Can you just speak to with all that stuff coming in?

How does your team kind of approach go through all that stuff? I know your consent rate is some like as around 95%, but it seems like a lot of work to do in a short period of time. Can you give us a sense of the depth of your technical team and how you guys approach that to kind of get through all that and making sure you're maintaining the quality of your investments?

Yes, that's right. I mean, I think we've spent a lot of time and money Scott, over the last couple of years and we've added a fairly substantial number of people well at least relative to our size, I think we're up to 30. I like bragging our revenue per employee, but we are up to about 30 people. Our engineering department is the largest group in this company and it is obviously the lifeblood and the most important.

On the AFE front that is -- that funnel is very simple in the sense that we have a team of professionals that go through every single AFE and then they're individually approved by our Chief Engineer and Adam. Over time, that part is relatively old hat whether we were still in the Williston only or today that part is quite easy because all of those type curves are build-out.

On the evaluation front that is the part where we have continued to and I would also add on the engineering side before I get to that. On the technician side, we have 2 engineering technicians dedicated now that have continued to build out systems to automate as many of these processes as possible.

We just signed a 5-year contract on a data warehouse project that's going to effectively integrate almost every system we have. And then going to the evaluation part, that is the trick.

I think given the volume -- oil is$90, so you can imagine even the best and the worst assets are all coming to market right now trying to monetize on assets they made, as I've told you in past conference calls that probably needed to be sold 3 or 4 years ago. And now finally the market is high enough that they can get out above water. The part that that is the art of what, Adam, Jim and I and Mike spent a lot of time on, which is filtering through those things and seeing what is worth our time.

And 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 even within basins we operate, we have to make a judgment call internally about whether we want to dedicate resources to it.

But I would say, on the technical front, we have -- that is really -- if there's a huge shift in Northern over my tenure here and over the last 5 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 and I don't know Adam, you want to add to that?

No, that's right. I mean, I feel like a broken record, but it largely sells for itself. I mean 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 3 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 influence these processes.

Our next question comes from the line of Charles Meade with Johnson Rice.

You actually just touched on this just a little while ago, the Veritas deal and what has changed since you guys evaluated it? You mentioned there's been one more net well proposed, but I'm also curious about if the schedule has changed because going back to your comments on -- appreciate your comments on inflation in the Permian versus the Bakken, but also service availability is a I guess growing concern as well. So can you talk about maybe not just the total number of wells that you're looking at with Veritas, but also the schedule there, if anything's changed.

I mean, I think as a non-op, the schedule is always moving around, particularly this time of year in the winter and the spring, things move around. I would say, if you look at the operator mix on the Veritas assets, service availability is not an issue. You're talking about some of the largest and best capitalized companies. And I can tell you what we see in real-time from our 50 plus operators are small one and 2 rig operators are really struggling, frac crews are not showing up when they're supposed to, they can't source drill pipe all those sort of things.

If you're Devin or burn or one of the largest and most active operators, you're not having those same types of issues. So in terms of that hasn't changed. The schedule is moving around all the time and that's the art of how we guide.

And you can look throughout history, we've gotten pretty good at being very careful and meticulous in playing for those things, as things move from a month around and particularly in the Williston, around this time of year given when or whether things are going to get completed before the freeze or not.

But in terms of Veritas overall, I don't know, may Jim if you want to comment otherwise, but I don't really think there's been any material changes. I think what I was trying to highlight, Charles, more than -- we said we saw another 40 net locations on there. We were trying to be about as conservative as possible and on the small working interest stuff, we didn't even underwrite it. And so, we're already seeing the benefits from that.

That's all helpful. And then if I could ask a question about the Ground Game. Historically, I'm curious how -- how it may maybe be changing or where you might see changes going forward. My understanding historically is that was about like you said earlier, you're getting in front of the rig and picking up working interest in properties where you already have 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're just finding out of cash that maybe or maybe are a little deal on properties where you don't currently have an interest, is that the case and is the opportunity set shifting that way?

I'll let Adam talk about this a little more than me. But I would say, I think it's always sort of been a combination of other things, sometimes it will be -- it will come with a little bit of PDP. You're buying an interest in a unit that has 2 wells that have already been drilled, another 8 coming on a stuff. So it's always moving around in that respect. I don't think it's really changed. I think the difference in 2022 versus the last several years as I would say, the explosion in organic development on our properties has probably made us a little less active than we've been in the last few years.

Is that fair enough?

Yes, exactly. I mean, I think there's probably 2 to 3 of these kind of Ground Game opportunities coming on the door on a daily basis and a lot of these were in just by nature of our acreage position and there's a number of them that aren't invest in the case for the past call it 5 years. And so it's really just kind of high grade in what's your opportunity set is and that's what I was alluding to in the prepared remarks in terms of we've got an explosion in terms of activity levels, operators are staying disciplined.

And so you can feather the Ground Game based on the activity that you're seeing on kind of your organic acreage. And given the fact that where we're at in terms of commodity pricing and operator activity, as well as the Ground Game activity that we were able to get done in the third and the fourth quarter, it's effectively set up, 2022's activity where we're comfortable at. And so as we kind of move through the first quarter and end of the second will continue to keep a beat on all this stuff and start planning for the back half and into 2023.

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

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?

I mean, there's always competition, especially the smaller the dollar amount, the more competition there is, right? So there's always competition I would say. And I wouldn't -- I don't know if I would say it's any more or less than the past than.

No, I think, viewpoints change with maybe some of our competition and if it's new money and they kind of scrambling to put it to work, then maybe they are stretching. But I think it also -- you've got some variability between basins as well. And the next point, you've got a well-pad that comes with 4 or 5 well proposals, but working interest is 30% to 40% versus that same well, 2% to 3% working interest, your competition's that is wildly different in that regard.

And that's where we can do a bit more damage with maybe some of the higher concentrated opportunities on a Ground Game basis, because some of our smaller counterparts aren't necessarily comfortable with that level of concentration, whereas when you look at our base and relative to everything we're throwing off, it doesn't necessarily move the needle nearly as much.

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

Yes, I mean, we've always kind of look to I guess 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 and we've made it a point to get underneath new burned oil and the Delaware side of things. And so between kind of those 2 -- 2 of the most cost efficient operators, as well as 2 of the most active operators in our respective basins, we continue to have that activity level kind of 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 new burn 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.

You gave that free cash flow outlook here with a potential next 4 years equal to your market cap. Could you just sort of speak about the cash tax trajectory over a multiyear horizon?

Yes. I'll let Chad cover them, the answer is, eventually we will have to pay taxes.

Thanks, John. I mean, we obviously you saw us pace some fairly immaterial state taxes in Pennsylvania and Texas and New Mexico because we don't have any NOLs established there. But in the past, we've been elected not to fully develop IDCs or bonus appreciation for the past several years to kind of preserve future reductions for us. It's clearly -- clearly it's based on our drilling activity and commodity price, but I think based on our current model, there'll be some small amount of taxes that will pay. And at the end of 2023 and once we pay taxes, it will be kind of 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.

And so, our overall effective rate will be well below that and the number that I threw out when I talked about that is net of that. And we have a -- internally we run it, so it's running at the strip, so it's going to adjust for any change in commodity prices as to the timing of that. So...

That's very helpful. And then just sticking with cost here, looking 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?

Yes, I mean it really depends on the price of NGLs. So first of all, each for the next 2 years are FT associated with the Marcellus, we'll pay that in the first half of the year. So it has a way of elevating your front half LOE. And then it doesn't go in smoothly really it goes, you pay it twice kind of twice a year, you can't accrue throughout the year. So in the first 6 months of the next 2 years that FT and then it will roll off over time.

We're trying to be conservative in the sense that you have a lot of POP contracts particularly in the Williston amongst our largest operators and some in the Permian. And so with really high NGL prices, we run our processing charges which will adjust for that through there. You obviously also note as we did tick up our gas realizations as part of that, but we're trying to be conservative on both fronts.

And so, it's not a function of actually operating costs really materially going up. I mean, obviously, as well as age out there, LOE does rise. And so as our production matures, you're going to see some of that offset by new well activity. But the big driver, John, 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 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.

Our next question comes from the line of Nicholas Pope with Seaport.

Good morning, guys.

Nick, 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?

Yes, excited. I am happy to model it. I was hoping you guys could talk a little bit about, you look at the big portfolio and I think a lot of the focus is on the newer wells and the acquisition front, but now you've got these interest in 8,000, 9,000 wells. How are you all thinking about in this market potential, divestitures or kind of call in weaker performers and 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?

Yes, I mean I think to the last point, you have to think about a call and oil prices there for a second, because even if you sell a PDP asset as an example of PV-10, you're still talking about a 10% cost of capital, right? You're borrowing money at 3%, so you're saying this thing, if I needed money, it's a pretty expensive way to do it. That being said, we have particularly in the Williston seen a handful of operators buying in non-operated assets at what we view as fairly elevated values.

And so we considered going to some of our operating partners and divesting of our working interest in their properties, if it was worth more to them than us, yes and maybe you could form that in the way of a trading which we're taking other non-operated properties that they don't want. And so this is a trend we've been watching for the last year or so.

So I would say -- I would never say never, I would say to be candid, we have never in my time here at Northern, we've never sold a material asset except to form an operable acreage to operators. And so we've never really kind of a material seller, but I do think it's something we're looking at particularly as you said there may be operators that we don't necessarily want exposure to when we -- if the price is right, we'd happily either sell or trade them our assets for perhaps other assets they don't want.

That's right and the price for an operated acreage or at least the way that some of our operators see it, might be worth 1.5 times what they're -- the viewing their non-op them, that might have nothing to do with their actual economics book more of the control. And so if you can leverage and exploit that trade-off, so that everybody is 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 are having.

That's actually really helpful. But and as you look at the existing portfolio base, I mean is there a ranking process you look at either operating costs, age, kind of well performance. How do you think about that existing portfolio base? Is that how it should be thought about? I mean is that where the focus is on? I mean, it's a lot of wells now more obviously than it was 2 years ago?

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

Yes, I mean, is that how you guys think about it? I mean, if that...

Yes, if you hear me, I'll give you a little history lesson. I watched a lot of operators in 2010 to 2017 sell PDP assets that had higher operating costs to go fund new drilling wells and so they could show really low LOE. But what they would really do is just deepening their decline curve materially. And so I think higher operating cost, yes, it's lower margin, but it's also lower decline.

And so there -- it's not sort of one for one. I would say where we would look at potentially divesting assets is which it appeared more on which the upside on those assets is worth less to us than it might be to the operator or to somebody else or our view on the future development and possibility.

We have acreage in some non-core parts of the Williston that might be worth more to the operator than it would be to us because we frankly wouldn't want, even if it was to be developed, it wouldn't necessarily be where we want to put our capital drill like Divide County out there or something like that, but it wouldn't mean it's uneconomic, it just wouldn't be our choice to put our capital there.

So 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.

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

Just a couple of things. You know, continuing on the conversation about operators you are happier being involved with close to those that you more look to avoid. I'm just curious, in your basins, are you aware of -- is there anything significant that on the market as far as operated acreage in a package, that would benefit sales would lead to a meaningful shift in your operatorship profile in any other basin?

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.

Yes, 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 kind 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, have average working interest probably half of what ours is.

And yes, obviously, there was a large operated package sold at the beginning, it was either late '20 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? And so you can imagine there are other large operator packages both in the Williston and the Permian.

I'd use the -- our Marcellus properties as the poster child for that, which is you have a focused operator that takes over and does it a huge improvement both the well design, cost structure, well performance, all those things.

And we would see a lot of meat on the bone on some of the properties that we exist particularly when assets are non-core and to that operator and they're just not putting development dollars towards them. So we have a lot of undeveloped assets under some of the operators that if they were to change hence there would be a huge benefit to us, even if there wasn't a change in cost structure, which usually there is.

It's really interesting. 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 coring down sort of pairing 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.

Yes, I mean 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 and 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 regions have 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 all the 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 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 fairly touch, not to mention the fact that we bought half a decade's worth of ducks one week up when we bought the property.

And just to extend that a little bit. So is it safe to say that and I'm thinking particularly about the Marcellus, that there isn't really fresh money looking attracted by higher gas prices. Looking to sort of comment and start something new from the ground up there, it's just -- it's people are kind of getting squeezed out in other words?

I would say that's a fair assessment. I mean, I certainly -- I think capital in general, no, new capital is going to put a significant long-term operator footprint in areas and I'd say is waning. I think that it is turning into a larger consolidation wave. I think for every new dollar being raised, there are $2 that need to mature and go out and that's obviously created the environment that's allowed our company to grow over the last few years.

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 Nichole 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 and again thank you for your time and interest.

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