Greetings, and welcome to Northern Oil and Gas Fourth Quarter and Year-end 2020 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Mike Kelly, Chief Strategy Officer. Thank you, sir. Please go ahead.

Thank you, Donna, and good morning, everybody. We're happy to welcome you to our fourth quarter 2020 earnings call. I'm joined here this morning with Northern CEO, Nick O'Grady; our COO, Adam Dirlam; our CFO, Chad Allen; our Chief Engineer, Jim Evans; as well as Northern's Chairman, Bahram Akradi. Our agenda for today will be as follows: Bahram is going to give you the opening remarks and then he's going to hand the mic over to Nick. After Nick, Adam will give you an overview of our operations, followed by Chad, who will review Northern's Q4 financials and 2021 guidance. After that we will head into the Q&A. Before you go on though, let's cover the 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 this conference call, we may discuss non-GAAP financial measures, including adjusted net income and adjusted EBITDA. 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 now hand the call over to Northern's Chairman, Bahram Akradi.

Thank you, Mike. As most of you know, I began investing in Northern in 2016. And subsequently I filed a 13D, outlining changes that I thought were needed in order to transform NOG into a strong and exceptional business. I am pleased to report this morning that I believe that we have been successful in implementing almost every one of these changes and very excited about more improvements ahead. We are in an enviable position. We have become the largest US non-op consolidator and the opportunities ahead of us are tremendous. We have a pipeline of acquisition opportunities and the capital to take advantage of these opportunities as well. The strategy is to continue to get bigger and stronger. However, we will do so in a financially prudent fashion, which includes a commitment to building and maintaining a fortress-like balance sheet. When I joined the Board in 2017, we had a leverage ratio greater than six times. Today, we project our leverage below two times for 2021 and our goal is to further reduce leverage to around one time in the next several years. We also have a great alignment between our shareholders, Board of Directors and management. This is a unique and clear advantage. Our Board of Directors are a significant shareholder in Northern. Finally, we have assembled an all-star management team, led by one of the most experienced and accomplished executives in energy sector Nick O'Grady. Nick originally joined Northern as a CFO in 2018, and I quickly realized that he was the executive that should be leading the company. Nick was promoted to CEO at the end of 2019. I have truly enjoyed partnering with Nick in developing and implementing the Board of Directors strategic vision for Northern. Our hedging strategies in 2019 provided Northern with financial…

Thanks very much Bahram for the kind words and the vote of confidence in our Executive team. All right everybody. As usual let's get down to it with six points. Number one; Teamwork. I know that 2020 was the tumultuous time for investors for oil and for the industry. But as we sit here today, I'm exceptionally proud of how we've managed through it. Our team has worked around the clock and thanklessly at times. As painful as it was no one wavered and we continue to plug away and not lose sight of our long term mission. We entered the year larger, stronger and with a clean delevered balance sheet. When we started this path in early 2018 and the company shareholders carried over $136 of debt and over $9 of annual interest expense for every share they owned. We project this year that number will be well under $15 of debt less than $1 of interest and expect production to be up this year over threefold from 2017 levels. Put simply our debt adjusted cash flow per share this year is expected to more than double from those 2017 levels. It has not been easy and our employees, Board of Directors and my executive team at Northern truly deserve credit for it all. Number two; Execution. The quarter was strong as production and activity continue to ramp up methodically. Costs continue to be in control and the assets performed admirably. We produced over $30 million of free cash in the quarter, a record for the company. What's more impressive is that our volumes have continued to improve despite significant shut-in activity. With workover rigs going at a furious pace, despite winter conditions in the Williston we expect a further boost as the vast majority of these remaining shut-ins…

Thanks Nick. Operationally 2020 was a transformational year for Northern. And as we move into 2021, we see ourselves in an enviable position. Since expanding to both the Permian and Marcellus, we now have three premier basins to deploy capital in. With the expansion of our business model, the active management of allocating capital across a broader opportunity set will enable us to continue to high-grade our returns on capital employed while diversifying and taking risk out of the enterprise. In Williston, curtailments are subsiding with the increase in commodity pricing and we expect that the remaining productions will be brought back online towards the beginning of the second quarter. While the rigs in the basin have stayed at lower levels, high-quality ground game opportunities have never been better as operators focus on the core of the play. As a result, our wells in process are expected to be some of the most productive drilling projects we have seen in years. We saw well-completions get pulled forward in the fourth quarter. And once the seasonal weather of the first quarter subsides, we expect both completions and new drills to pick up moving into the second and third quarters of the year. In the Permian, we continue to build our position well-by-well and acre-by-acre, focusing our efforts with leading operators. Since we entered the basin last September, we have closed seven deals for approximately $32 million inclusive of development costs. Acquisition opportunities both at a ground game level and a package level are at multi-year highs. We screen each and every one of them with the level of discipline and specificity that is needed to prosecute only on those that meet or exceed our hurdle rates. In the Marcellus, we look forward to closing our acquisition with Reliance in April. At the end of Q4, EQT took over operatorship of our asset. And with the proposed operational changes, we are expecting improvements in both cost reductions and well-productivity. Unique joint venture structure provides Northern collaboration and long-term transparency that will dovetail nicely with the active management of the rest of our portfolio. As we responsibly scale the business, the opportunities afforded to us have never been better or more abundant. We remain disciplined with our allocation of capital as we work towards further reducing debt levels and returning capital to shareholders. With a balanced approach of investing in additional drilling and executing on high quality acquisitions, we will continue to solidify Northern as the non-operated clearing house in oil and gas. With that I'll hand it over to Chad.

Thanks Adam. I have a few highlights to go over this quarter starting with a quick summary on Northern's financial performance. Our production averaged 35,738 barrels of oil equivalent per day, a 23% increase over the third quarter and came in towards the high end of our guidance. Production continues to be impacted by curtailments in shut-in production, which we estimate reduced our fourth quarter production by approximately 4,200 BOE per day. Our adjusted EBITDA for the quarter was $94.3 million, up 14% over the third quarter due in large part to increased production levels and the pull-forward of activity towards the end of the quarter. Oil differentials were $6.94 during the quarter, which was an improvement of approximately 35% over the lowest in the second quarter. Gas realizations continued to impact our revenues during the fourth quarter, but we saw a significant improvement as we close out the year and we expect these improvements to continue into 2021. Lease operating expenses for the fourth quarter came in at $28.2 million, or $8.58 per BOE, which was down 5% sequentially compared to the third quarter. Cash G&A came in at $1.04 per BOE this quarter, and continues to be exceptional even with the impacts of our production volumes from curtailments and shut-in production. We have also given detailed cost guidance for 2021. One thing to highlight there is workover activity. We expect LOE to be higher earlier in the year as costs from higher workover activity flows through. But to moderate as new wells turn to production. I'd also like to highlight, cash G&A costs, pro forma for the Reliance transaction and our growing oil volumes are projected to be approximately $0.80 per BOE, the lowest in our company's history and by far one of the lowest in the industry.…

Great. Thanks, Chad. Donna, we are now ready for Q&A.

Ladies and gentlemen, the floor is now open for questions. [Operator Instructions] Our first question is coming from John Freeman of Raymond James. Please go ahead.

Good morning, guys.

Good morning, John.

First topic I wanted to address is, just the comments that you all made about this summer looking to talk with the Board about potentially implementing a dividend strategy going forward, and just I realize we're all the ways off before you are going to start to have those conversations. But just maybe some more color on, how you're thinking about just from a shareholder return perspective, if it's a base dividend? Is it a variable dividend? Like, just sort of, I guess, how you're thinking about this just from a high-level perspective going forward but very encouraging to hear?

So I think it's -- this is Bahram speaking back. We actually obviously intended to start dividend last year. And unfortunately, the bottom fell out, but our vision has always been to get this company strong enough. Make sure, as I mentioned, we have a fortress-like balance sheet, and then start building program for dividend, where we can start small and have the opportunity to grow it regularly. We still have a couple of technical things we have to take care of here between now and May, June. And then -- but then we'll start a dividend. My intention is not -- our intention is not to start with something substantive, just modest that we can grow responsibly and over time, because as we get through the end of this year, I think we will finally have gotten this company to that. My goal and Nick's goal, company goal has always been to get to under 2 times, then under 1.5 times debt and then get closer to 1 time debt to EBITDA. We have -- it's the situation is dynamic. As these guys have said, there is billions of dollars of opportunities for acquisition. We just need to do this responsibly, grow the company and improve the balance sheet at the same time. And then we will have the opportunity to continue to grow the dividend. But it's just important for us to start being a dividend company this summer and then just -- and then build it from there. Nick, you want to add to that?

Yes. And I would just say, in response to the variable dividend, I think we're watching it with keen interest. I think in my prior comments I've been fairly skeptical that certainly in a robust oil market like today, people love the idea of a variable dividend, but could it introduce volatility if there's a downturn at some point. And so, I think, we'll consider it. I want to watch and I think we're going to spend a lot of time and data on some of the strategies that we've seen announced from peer companies and see which works best. So I think we'll remain open-minded to it. But I think to Bahram's point, our view, generally speaking, is a dividend that can grow and as the leverage continues to decline and the risk overall to the business declines, you can accelerate that growth even faster. And so, certainly, the business can handle it. It could frankly -- it could have handled it in 2020, but I don't think it would have been a responsible thing to do. But it's time and I think we have to have those discussions with the Board. And I think when your Board owns 30% of the company it's their money. And so as long as the risks are balanced we integrate the Reliance acquisition. To Bahram's point, we have some other technical things we have to take care of. But once we get through that period, I think it's something that makes sense at this time.

That's great. And then, my follow-up question now with the recent entries into the Permian and the Marcellus. And as you all kind of phrase that you've got, a national non-op franchise now. Are those three legs to the stool, is that kind of the way we should think about it going forward? Or are there -- are you all basically now basin commodity agnostic to where there's other basins in addition to those three that you all may consider in the future?

Yes. I mean, I think, I always talk about this and it sounds like just words, but it's not. I think we are economic creatures. We actually -- we're not focused on drilling holes in the ground. We want to make money. And so, we are agnostic in the sense that we look at things that we want to make money, but there are different risks in different regions. And generally speaking, the oil and gas business, if you go where the rigs are and where activity is, you have a better chance of having lower risk. I think there are some places in the country that I think we would be reticent to enter. I think that Oklahoma would be one that I will likely pass on. I think there's way too much geologic risk. The DJ Basin, as well, has a ton of political risk. But I think the Permian the Marcellus and the Williston are all active basins with high returns. There are maybe a handful of others that would make some sense. But I think we also want to retain focus. We've spent two years building up data in the Permian and is the most active basin in this country. And so, it's the most logical to see the most deal flow and the most potentiality for returns.

Looks great. I appreciate the answers. Well done, guys.

Thanks, John.

Thank you. Our next question is coming from Scott Hanold of RBC Capital Markets. Please go ahead.

Thanks. Good morning and great performance in the quarter. I wouldn't mind following up a little bit more on the dividend, because certainly it's a point to think that differentiates you all from some of your small-cap peers, the ability and willingness to pay a dividend this year. And can you give us just sort of a high level construct? And what really drove the confidence to start it this -- potentially this summer? Is it a combination of commodity prices and just where the business is going? Or is this strictly look, the business is moving in the right direction? Commodity is going to play a point into this, but certainly the business is a bigger driver. Because the point I'll make is that, if the goal is to get leverage to 1 times, certainly, not paying a dividend gets you there faster. So with other small-cap peers not paying one, just give us a sense of like why now?

Yes. I mean, I think, Scott, to put it simply, number one, why now versus why later? One, we have a pretty clear path. I mean when we had analyzed this in 2019, we had stressed the business down to $40. And ironically oil averaged about $40 last year, but the volatility introduced from how violent was to the rest of the space changed the dynamic to some degree. I think our bar for where aggregate leverage ratios had to be in order to prosecute that went down. And I think to Bahram's point as we get into the summer and fall, we're going to be well on that path. And I think if you do a modest dividend that provides some return, it will have yes a modest impact on that pace of deleveraging, but not one that's going to materially slow it down. And so ultimately it ends up being -- I don't want to make the dividend sent out to be a rounding error but the overall effect and the leverage might be. So -- and so, I think we feel like we can do both. I think we have the luxury of high-margin businesses with stability and we have a low -- much lower decline curve than your average US oil company. And what that means is that, our base business is much more stable and that affords dividend. The business was -- as we've built it with a PDP centric focus over the last three years has afforded this. It was really -- I would just say the final piece is that ultimately we have really cleaned up the balance sheet. We really have one piece of term debt outside of our revolver we have a lot of liquidity. And Bahram you want to add something to that?

Yes. And Scott I remember when we had discussions you we talked clearly about the company needs to be bigger and stronger. We want to be a multibillion-dollar market cap company as well as a bigger EBITDA business. So -- but the opportunities are there and I emphasize again we're going to start incredibly small, modest just because we want to be a dividend-paying stock company. Our focus here is to grow cash flow. Be a very, very substantial cash-generating machine as an entity. And so -- but I think it's important for us to put our commitment forward start paying a dividend. But just like Nick said, not something that would hinder our original goal of getting bigger and stronger. So, we have a clear path how we can do all this. And then we want to also start at the level that we can steadily grow that dividend in the quarters to come as we go forward.

I appreciate all that context. That's perfect. And if I could have another question here. I'm curious with some of the stuff obviously say with the Bakken still being obviously the largest portion of your production base rate or EBITDA growth. What are you seeing in the basin right now? One of your peers in the Bakken, I guess one of the operators out there has recently stated that there's a couple of their partners that have deferred some completions to maybe later in 2021. And if you -- and with I think roughly 15 rigs or so in the basin right now like where do you think that's going? How do you see some of the operators progressing? Are you impacted by also some of those deferrals? And does this really kind of provide a nice production ramp in sort of the back half of the year? And any color you have on just the basin of the whole if we're at 15-ish rigs now where do you all see that by the end of the year?

Yes. I mean Scott, I think you have to think about it and the operators think about it is how fast they can recycle their capital. So in the fourth quarter we saw the easiest way to convert your capital to be productive was through the DUC count. And so you saw a furious pace of completions and that's still ongoing now. And as we come out of spring as everyone knows basically nothing happens for about two months in the Bakken and then it accelerates in March, in April and May. The other thing that we've seen is work-over activity. And these are really high return whether DSPs or flushing out wells that have been curtailed. And so that pace goes on very quickly because you can turn the wells on within a month. It's a very productive use of your capital. As the DUC log backlog burns down we would expect and have indications that the rig count will come up some, but that's not necessarily to drill baby drill not to grow the volumes. It's simply going to be to replace development activity and so most of the operators have indicated that we should see the rig count rise. And I think in general what's been interesting like in the other basins that we operate in such as the Permian, which is that the bulk of our customer base and acquisitions have been the operators and the operators who have been the most active in the Permian and accelerating have been the private in the Williston we haven't really seen that yet, but I would expect to see the rig count pick up fairly substantively in the middle of the year.

Okay. That's clear. And any kind of comment -- are you also partner with…

On the deferrals, I don't know the specific case. I mean, we have things that move up and back in the drill schedule all the time. I can't say that with the exception of one mega large operator that tends to do things on like a three-year basis, we haven't seen anything push to the right. But I would say in fact, it's largely been the opposite. I would expect in the middle of the year that we'll see some things that we have forecast to be later to come sooner if oil prices stay robust.

That's right. I mean, we saw completions get pulled forward in the fourth. Everybody will take a breath here through the winter and then things will start picking up in the second and third quarter.

Yes. That make sense. Thanks.

One item just for what it's worth and it’s a little different from basin-to-basin. The lead time for capital from AFE to sales date for a Bakken well can be six to nine months. And so the time lag between rigs being picked up and being dropped it's a little bit slower. The cycle time in the Permian is sometimes three or four months and it's just a function of how the pads are developed. So that's probably why if you're wondering why the rig count hasn't spiked right now it's, because you're still working through six to nine months of development from prior. So it just -- it tends to -- it's like steering a cruise ship as opposed to a speed boat.

Yes, yes. I think the NDIC said, well, the 650 to 700 DUC still out there. So that's a pretty big backlog.

Yes.

Thank you. Our next question is coming from Dun McIntosh of Johnson Rice. Please go ahead.

Good morning, Nick.

Dun, how are you?

Good. Also been -- if we could just get a little bit of color maybe for Adam, but a little bit of color around the production and CapEx cadence over this year. Now that you've got the Bakken, you've got the Permian and the Marcellus. How should we think about product mix and spend over the course of 2021?

Yes. I mean, Chad and I can handle the spending piece. I'd say that we would expect the spending in the first quarter to be lower than the fourth quarter just because you had some bring forward. I think the highest CapEx by far will be in the second quarter just because we expect the bulk of the Marcellus CapEx. We gave the guidance $20 million to $25 million. We would expect most of that to incur in the second quarter and a little bit into the third. And then I would expect it to then step down ratably in the third and the fourth quarters. We've built in a decent chunk of consistent ground game activity within that particularly in the back half of the year. We're inundated with stuff now, but when prices go up we become a little bit more selective because the risk becomes a bigger factor.

That's right. I mean, 2021 is effectively big. So I mean 90% of the activity is effectively going to be allocated towards the Bakken and then it's really going to boil down to what we're seeing both from an organic and a ground game activity in terms of the mix between Permian and the Bakken. And what I'd say is even with 13 to 15 rigs that's in the Bakken, we're still seeing some of the best ground game opportunities that we've seen in a very long time and we've capitalized on that. So I think we've got two or three kind of under our belt within the first quarter. We'll continue to keep our ear to the ground there. And then as we look towards 2022 I would expect with the ground game and just the functions of opportunities within the Permian that might start taking a little bit more market share, but it's really going to be just based on really what we're pulling organically and then what we're seeing and what we're able to prosecute and stuff that's going to meet or exceed our hurdle rates.

Yes. And on the production cadence done, I would just say this that we would expect on the gas properties the first completions I think are scheduled for June right? They go to sales in June. So you've had no completions on those properties really until took control, and so we would likely see a large surge in the back half of the year on the production. So it should kind of gently crest down in the first half. And then -- and we should see it at its high later in the year. On the Bakken, it should be more linear. Obviously the winter period is a slow period. We tell people this every quarter. But generally speaking nothing happens for about two months in North Dakota. But we are seeing that work-over activity, which has a pretty short-cycle time. And so we would expect to see a pretty meaningful ramp from the first quarter into the second quarter kind of more in tune with our sort of annual guidance. And then I think Jim correct me if I'm wrong, but peak production will be sometime midyear and then be fairly stable thereafter. So overall, I think no surprises really there. I mean, I think the only thing that Chad highlighted in his comments is just about that work over activity and we started to see it pick up meaningfully in December when prices did because the economics are there. And we think that peaks out about March.

All right. Thank you. And then I guess tacking on to that a little bit with the ground game and everything. You all have made tremendous progress on the balance sheet, but also clearly have a pretty big desire to continue to grow and scale up the non-op model. So how should we think about opportunities whether it's ground game, whether it's something like the Reliance transaction kind of with respect to your CapEx budget the $200 million to $250 million for the year. It should be more ground game deals this year? Would it be fair to assume that if the right bigger deal comes along you'd be willing to take -- or transact on that?

Yes. I mean I think on the ground game side, we budgeted fairly within that $200 million $250 million, when we talk about ground game. It's in there. I think we felt like we don't want to -- I think by budgeting for that ahead of time it just -- it means that the free cash that you model is truly free. And I think it's the right way to show it to our investors. So we budget for that. So frankly if we didn't remain active that the number would only probably go down we are opportunistic. We have -- we are inundated with opportunities candidly and that is what we spend a lot of our days on beyond -- our day job. But the bar is pretty high done. We haven't even closed on this existing transaction, we see huge opportunities, but it has to be on our terms. And as I mentioned in my comments, it's got to be an immediate win for everybody. And so for anything to be even considered, it's got to be credit enhancing materially accretive to the equity holder and beneficial to the overall long-term strategy of the business. So we're not a deal junky -- there is a huge backlog of non-op that needs to be rationalized in the next several years. If you look at our pattern, we've typically been about 18 months in between every large transaction. Given prices are up, it could that change potentially. But I want to say that the bar is always very high and we face a very meaning Board with almost anything we want to do and they really want to understand why they win when we do something. So understand that everything will go through the same process. We'll be very careful and judicious. But don't think we're just going to go back-to-back to back. If the opportunities call for it, I think largely, we would hope that if we do get to that point in 2021 where there's another opportunity that you're all suggesting that it was an obvious thing as we felt like we got for the Marcellus transaction.

All right. Thank you.

Thank you. Our next question is coming from Derrick Whitfield of Stifel. Please go ahead.

Thanks. Good morning all and great update.

Thanks.

Staying on the last topic perhaps for you Nick or Adam, regarding your comments on the ground game and the size of the ground game opportunities, could you offer some additional color on the degree of deal flow you're seeing by basin and comment on your potential and desire to add more depth in the Marcellus?

Yes. I mean, I think I'll cover the first part the Marcellus part and I'll let Adam talk about the risk because you'll know better than me from the split. But it remains to be seen. We've since we executed on the Marcellus transaction, we've been inundated with packages small and large in the Marcellus of potentiality. I'm not sure the same type of ground game kind of well bore by wellbore by wellbore acre by acre type business exists there because it's fairly blocked up and mature at this point. It does not -- and I think the operators have largely traded with each other. So it doesn't mean there won't be any opportunities, I just don't think it's going to be the same level that you see in the Permian and the Williston. And I think you can talk about the kind of split?

Yes, that's right. I mean, I think the Marcellus is going to be more on kind of a package by package level. What Nick alluded to in terms of kind of what we're seeing on a daily basis, I'd say that there's probably one to three ground game deals that walk in the door from the Permian. What I'd say is there's much more variability in terms of the overall kind of economics just given the breadth and number of rigs that are out there. And so we're certainly -- our batting average is a lot lower in that regard because we're picky in the way that we weigh it against a lot of the stuff that we're seeing in the Bakken and kind of goes back to my comments there's only 15 maybe rigs within the basin the stuff that we're seeing in North Dakota, both from a competition standpoint as well as just the overall quality of the ground game opportunities that we're seeing have been really encouraging. And I think it kind of goes back to the old shale 3.0 paradigm in that you've got operators and other non-operators alike that just can't necessarily write the ticket for some of these pad well developments, especially in North Dakota. And so it's giving us an opportunity to kind of step in there. And so I'd say the quality of the opportunities in North Dakota is clustered much more closely relative to the Permian, but just the function of the overall activity in the Permian gives us plenty of lux that's for sure.

Great. And regarding my follow-up your Q4 production curtailments at 4,000 barrels. Could you offer any color on the nature of the curtailments and if it's concentrated with one to two operators?

Yes, this is Jim. It is pretty concentrated with just a few operators. And some of it's due to offset activity where wells have been shut in as completion crews come into frac and wells. That's a function a part of it. And then the other function is just wells that got shut-in in the middle of the year. They've run out of pressure. They need to work over to install ESPs. But the quickest way to get production back on as turn new wells on. So, they focused on that first. And like Nick mentioned, there's a flurry of work over rigs running out there now. One of our operators I think have seven work over rigs and so they're installing ESPs as we speak and we expect a lot of that production to be coming back on. I think we still had in January roughly that same number. But as we moved into February, that number was coming down quite a bit. We probably had 1,000 to 2,000 barrels come back on in February. And so like Adam mentioned, by kind of early second quarter, we expect a lot of that to be back on.

Yes. And if I can make a skeptical comment. I saw some smarty-pants research pipeline scrape shop try to suggest that there's no deferred production because as the curtailments came off, production didn't match the prior curves. That's typical because one of the things you saw with almost every US independent was massive reductions to LOE in the back half of last year. That's because you're not spending -- you may turn the well back on, but you haven't spent the maintenance capital yet and that's a decision you're going to make when you're going to make that when it's economic and when prices are higher. So, you got some of that production back, but you get the rest of it back when you go through the maintenance cycle and that's what we're seeing right now.

Great. Nick just to follow-up on that and to clarify, I'm not this smarty pants.

No, I'm not accusing you Derrick. You are very smart though.

The 4,000 barrels that you referenced would it be fair to assume maybe 1,000 barrels of that would be offset completion. So, that would kind of be a residual impact that you would continue to see throughout the year?

Yes, that sounds about right. But we always -- in our guidance, we always maintain a sort of a downtime factor. So, that's within our guidance. That would be normal course. When we're clarifying the full amount, it's just to make the point of what we saw. And to Jim's point, what we were -- what was interesting to see is we were pleasantly surprised at how fast some of the completed, but delayed wells were turned back to sales. And I think we've been waiting kind of in watching the environment in which we'd see that work over activity take on and it's going at a pretty robust pace right now. So, I really think as we get into April and May we're going to be pretty much full bore.

Very helpful. Thanks again for your time guys.

Thank you. Our next question is coming from Neal Dingmann of Truist Securities. Please go ahead.

Hey guys hopefully I can be in that smart camp at some time -- some point as well. But my first question -- my first question really, I guess Nick for you to add them one of the guys. On your deal focus, you mentioned in the prepared remarks a lot of deals since last summer -- a lot of very successful deals I might add. Could you talk a little bit more just when you look at these now going forward, you brought all the guys transaction wise, is it just purely looking at best returns in cash flow? Or now that you have more of a size behind the company, would you prefer larger working interest? Are there other variables other nuances that sort of play in there that when you were smaller and growing at a more -- a different position that you now might consider?

I mean I think our methodology is largely unchanged. I mean, we've raised our hurdle rates significantly over the last couple of years and I think that that's been a good thing. But generally speaking the methodology is all -- is basically the same thing. It's all return on capital employed focus sort of total return IRR, soup-to-nuts including everything not pretending acreage costs don't exist or something like that. In terms of the working interest, I mean I think the Marcellus deal is a good example of that. It's a much higher working interest than we typically do. But it came with governance that matched and took some of that risk off. I think we get offers every day to farm in at 50% of a well. And usually we run far away from that because that comes -- why would anyone want to give up 50% working interest without -- and you bear a lot of that risk. And so I think generally speaking we -- it has to come with some substantiality to support that. In the case of the Reliance deal, it was obvious. I don't know, Adam, you want to add?

Yes. And I mean, I guess with the scale of the business provides us a different landscape from -- just from a competition standpoint, when you're looking at ground game deals where you've got maybe 30%, 40% working interest within a unit. A lot of times that's going to be much too large and concentrated for a lot of our competition. And so when we start looking at those types of opportunities, we see a lot of our competition maybe falling by the wayside. And the other thing I'd add is, when our competition might be looking at those types of deals it might also be an opportunity for us to partner with those types of things and collaborate on it. So -- and we see that. That doesn't mean that we're not looking at the five, 10, 15 acres at a time. We're still the dust buster out there. And so we're not going to skip over those types of opportunities just based on size. But I think it's been an interesting kind of shift in terms of the landscape of overall competition and what we're seeing in some of the larger packages.

Yes. And governance is key on that, Neal and I just complete the thought by just saying that we all think you're brilliant. So don't worry.

My second question just to make sure I understand this. On slide 5 looking particularly at that Williston, I like that math you guys have in there. Knowing that winter activity upcoming again for the next winter is always going to be a bit weaker in the Bakken. But notice also there's -- I like that you put the wells in progress very notable. You did talk around this in prior questions, but I'm just wondering can you talk a little bit more? I'm just wondering as you look forward to the next winter, how we should think about is these wells in progress that you all mentioned on there for your Adam or the guys again is that -- are those wells that we should see likely would come on in the very -- if they are already in progress is that wells that you'll likely see come on before the winter? And then you'd still have that kind of a bit of a weak period in the winter? Nick, I'm trying to just get a sense of timing I guess for the latter part of this year.

Yes. I mean I think I'll let Jim cover most of that. But I would just say that, if oil as an example, Neal, I think if oil had been $65 in December you might see the operators buck the trend and be much more aggressive. They plan months in advance. And so they can't necessarily shift it there. I think it was we had a mild winter maybe two winters ago and we saw operators plough right through it and we saw huge volume gains in the first quarter. So it can vary from time-to-time. So it really will depend on where the strip is when they're planning that activity, but I'll let Jim cover some of the details as it pertains to the next winter.

Yes, we would obviously expect as you kind of go into the winter season that activity levels will drop. This year was a little bit different because one of our operators spent a lot of time just completing wells throughout the third quarter. So even when winter weather started to kick in they were able to turn those wells on because they'd already completed the wells. I think the site will be a little bit different, this time where wells will be getting drilled and completed in the second and third quarter and then activity levels kind of declined through the fourth quarter and into the first quarter kind of what we see with typical winter seasons.

Great details, guys. Look forward to the upcoming day and all the upcoming activity.

Thank you.

Thank you. Our next question is coming from Philips Johnston of Capital One. Please go ahead.

Hey, guys. Thanks. Just a couple of housekeeping questions. First is just a follow-up on the production cadence. Obviously, you updated production guidance under the Reliance acquisition a couple of days ago to $75 million to $85 million a day for the full year. But can you give us a ballpark in terms of what the net production level will be on that asset when it closes in April?

In April, yes. So Jim you want to walk through kind of a rough kind of guideline in terms of sort of second -- or second, third and fourth quarter kind of?

Yes. So obviously, the effective date was July was doing about $90 million a day in July 2020, because the lack of activity production has been declining. It's probably going to be doing about mid $60 million a day through the first quarter. And then going into the second quarter, they're going to start completing some of those wells in process, and we expect that to pick back up to closer to the $75 million to $80 million a day kind of range and then kind of hold that flat throughout the rest of the year on the Marcellus side. And so that kind of gets us to our guidance of $75 million to $85 million. And then on the Williston side, kind of what we've laid out we expect kind of Q1 to be relatively flat with Q4 as we go through the winter season and activity levels stay low. And then going into the second quarter, we expect that to be one of our busier quarters and so production should ramp pretty quick through the second quarter and then hold relatively flat through the rest of the third and fourth quarter to meet our mid-quarter guidance.

Yes. And on the gas asset, we just had our budget meeting with the operator yesterday. So no surprises there. The timing has stayed consistent. And so we should see a bunch of IPS, I believe in June. And so you're going to see kind of above that average for a good portion of the back half of the year, just because you're starting at a lower. And just so everyone is crystal clear on this we want to make sure, we've given a full year guidance it will close April 1. So the first quarter of production and all those things will be received in the form of a reduction to the purchase price that -- so those are full year numbers. So the actual quarter and I can understand, why you're asking Phillips. So I just want to make sure that everybody understands that, we've given a full 2021 you will really only have three years on the books, but the first quarter we will own it, or that we will own those cash flows so we'll receive those cash flows in a purchase price reduction.

That's perfect. Thank you for that. And then obviously, you guys are cash tax payers today, and you have a fairly large NOL position. But I know, there was technically ownership changed during 2018 that sort of makes those in those NOL subject to some limitations. My question is, as we look out to the next few years when you start generating a ton of free cash flow. Would you guys expect to start paying cash taxes at some point?

No.

No. The way -- there's a three-year rolling structure on it long story shortage that we would have to do something pretty extreme in order to…

That's right. That's right. Yes. We would -- I mean, we've got a lot of that three year actually happened in 2018. So that stuff will roll off here too. So no, we don't -- we expect we'll be fine from an NOL standpoint.

Excellent. Thank guys.

It's in our standardized measure, I think in the K, when it comes out you'll see it's a minimis amount.

Okay. Thank you.

Thank you. Our next question is coming from Nicholas Pope of Seaport Global. Please go ahead.

Good morning, guys.

Good morning, Nicholas.

Couple of quick questions. Just wanted to clarify a few things, the Marcellus asset win with that preferential rights being exercised. I wanted to clarify, what that working interest looks like? I guess, what current production looks like? And what it is going forward? Just to clarify that a little bit.

Net to us it's about 27%, 28%, right? It's 40% across the PDA, but we have a 30% partner. So it's about 27%, 28%. And it should be fairly consistent unless the overall units change or acreage ownership changes over time.

Got it. And then just with the dynamic of how the dividend is going to work out relative to the cumulative preferred how exactly does that play into it? I think is it around $20 million that's been accumulated right now as a non-cash dividend on the preferreds and that needs to be paid kind of concurrent with the dividend being paid? Is that how that -- am I correct in that?

Yes.

Yes, but it's not $20 million.

It's -- call it $16 million-ish.

Yes. I think it might -- yes, let's call it, $16 million. So, obviously, prior to a common dividend we would have to begin to put the preferred back into pay status, which obviously we would intend to do for discussing a common dividend.

And is that a cash payment? Or are there other options with how that kind of structured for the cumulative?

There are options.

Okay. That's all I need. That's very helpful. Congratulations again.

Thank you.

Thank you. Our next question is coming from Gregg Brody of Bank of America. Please go ahead.

Hey, guys. My question was just on the preferred. But when you think about the other options to pay the preferred where are they?

If I can punt that question, Gregg, I don't think we're prepared to talk about that publicly.

Got it. Thank you for letting me on.

Thank you. At this time, I'd like to turn the floor back over to management for closing comments.

Thanks everyone for joining this morning. We're excited about the future about 2021. Thanks for everyone for sticking with us through thick and thin, and we'll see you on the next one.

Ladies and gentlemen, a replay of today's conference will be available in approximately one hour by dialing either 877-660-6853 or 201-612-7415 and entering in the access code of 13717215. The phone replay will be available through March 19 of this year. An archive of the webcast will also be available on the company's website. This concludes today's presentation. Thank you for your interest in Northern Oil and Gas. You may disconnect from the webcast or log -- sorry, disconnect your phone lines or log off the webcast at this time. And have a wonderful day.