Northern Oil & Gas, Inc. Q4 FY2020 Earnings Call

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. 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's 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. 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 we have been successful in implementing almost every one of these changes, and I am 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 is 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 the energy sector, Nick O'Grady. Nick originally joined Northern as 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 security and stability in 2020. It provided NOG's significant free cash flow last year, while many other companies did not make it through. We've been able to secure and extend new financing and raise additional equity, which has allowed the company to significantly improve our balance sheet and our future cash flow, which is now approaching $150 million in 2021. I have complete confidence in Nick and the entire executive team at Northern to continue executing our long-term strategy. We have accomplished a tremendous amount over the past several years, but I am most excited about the future at Northern. We now have the balance sheet and acquisition opportunities that will enable Northern to accelerate its growth. I'm very excited to see our strategy play out through the remainder of 2021 and beyond. We are also in the position to start a responsible and modest dividend by this summer that we can grow over time. Because of my confidence in Nick and the leadership team at Northern, I no longer feel that it's necessary for me to be on NOG's conference calls. Of course, I will continue to be a very active Chairman in formulating the vision and long-term strategy for the company with other members of the Board, Nick and the rest of the executive team. Finally, I want to thank Wells Fargo, Bank of America, and RBC, among others, for being great partners and supporting Northern throughout this exciting adventure. With that, I will now turn it over to our CEO, Nick O'Grady.

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 a 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; we continue to plug away and not lose sight of our long-term mission. We entered the year larger, stronger, and with a clean, deleveraged balance sheet. When we started this path in early 2018, 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 should be back online as we exit spring. Number three; Consistency. I have explained in each of the last four conference calls that we have been dedicated to managing risk, continuing to deliver, and that the non-op model gives us significant flexibility in the allocation of capital. As we stand today, we successfully counter-cyclically invested in projects throughout 2020 that are beginning to bear fruit and will likely vastly exceed what we had underwritten. Risk management in the form of hedging meant that we were able to reduce debt in the downturn rather than lean on it. And with higher prices today, that will accelerate. Number four; Expansion. We exit 2020 very differently than we began. We entered it as a Williston pure play. We will soon be a three-basin company, diversified and with increased flexibility to allocate capital to different commodities, different regions, and simply put into places that have the highest return on capital employed. Number five; Discipline. While oil prices are high and the market is ebullient today, I want to be clear about Northern's strategy. While we certainly welcome more normalized levels of drilling, we continue to be disciplined in how we deploy capital. As I have repeated ad nauseam, growth should be the output of good investment discipline, not the driver of spending decisions. We are dedicated to responsibly returning capital when the risks are balanced properly for our debt holders as well as for our equity holders, which brings me to my final point. Number six; returns. As we integrate the Reliance assets and continue to deliver, we will begin discussions with the Board of Directors over the summer about establishing a long-term dividend strategy. We are watching others carefully as they craft their dividend policies to see what works best for investors in the marketplace. But it's clear that higher prices in the short-term are accelerating our cash flows to retire debt faster and with it the mission to deliver real shareholder returns. In conclusion, to those that have stuck by us through thick and thin, thanks for the patience, but we are not done. In fact, we're just getting started. There are north of $10 billion worth of working interest opportunities out there that need to be rationalized. We are focused on making our enterprise stronger, more profitable, and providing exceptional returns to our shareholders. But at the same time, we will not lose our strong financial discipline. We are not deal junkies. Everyone must win for anything to be even considered. These aren't just words. We are a company run by investors for investors, and I truly thank each and every one of you for your interest. With that, I'll turn it over to Adam.

Thanks, Nick. Operationally, 2020 was a transformational year for Northern. 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 production 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. The 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 closed 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 flow through, but to moderate as new wells turn to production. I'd also like to highlight that 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. We significantly improved our leverage profile since the end of last year, and remain focused on debt reduction. We reduced our debt levels by approximately $39 million during the fourth quarter and $178 million during 2020 in total. Capital spending for the fourth quarter was $48.9 million, which consisted of $17.9 million of organic D&C capital and $31 million of total discretionary acquisition capital, inclusive of acquisition D&C capital. Northern's 2020 development capital expenditures were $162.8 million, a reduction of 56% compared to 2019. In February, we disclosed reduced 2021 capital expenditure guidance and bumped up our production forecast at the same time. In terms of cadence, as it stands today, we expect the second quarter to have the highest levels of CapEx for 2021, particularly for the Marcellus assets where the majority of the development is projected to take place midyear. In closing, I wanted to highlight our recent capital markets transactions, whereby we further strengthened our balance sheet through a common equity offering and a regular way unsecured senior notes offering. These transactions allowed us to fully equitize the Marcellus acquisition and extend our maturity wall by retiring the remaining $65 million of our VEN Bakken note, and 95% of our second lien notes, of which the remainder will be called on or before May 15 this year. The remainder of the proceeds were used to pay down the revolving credit facility. As of today, Northern has $287 million of borrowings outstanding on its revolving credit facility, leaving $373 million of available borrowing capacity. Absent further capital spending acceleration, we would expect the RBL balance to fall further by the end of Q1 prior to closing the Reliance Marcellus acquisition. With that, I'll turn the call back over to Mike Kelly.

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

Ladies and gentlemen, the floor is now open for questions. 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 made about this summer looking to talk with the Board about potentially implementing a dividend strategy going forward. I realize we're all a 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? Just sort of how you're thinking about this from a high-level perspective going forward, but very encouraging to hear?

So I believe this is Bahram speaking again. We had initially planned to start a dividend last year, but things didn't go as expected. Our vision has always been to strengthen the company, ensuring we have a solid balance sheet before we establish a dividend program that can start small and grow steadily. We have a few technical matters to address before May or June, but we plan to initiate a dividend then. Our aim is not to launch with a large amount but to begin modestly and allow for responsible growth over time. By the end of this year, I believe we will have successfully strengthened the company. Our goal has always been to reduce our debt to under 2 times, then under 1.5 times, and ideally close to 1 time debt to EBITDA. The situation is fluid. There are significant acquisition opportunities available, and we must proceed responsibly while improving the balance sheet and growing the company. This will allow us to continuously increase the dividend. It is essential for us to start becoming a dividend company this summer and build from there. Nick, do you want to add anything?

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? 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 to see which works best. 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. Certainly, the business can handle it. It could frankly have handled it in 2020, but I don't think it would have been a responsible thing to do. It's time, and I think we have to have those discussions with the Board. I think when your Board owns 30% of the company, it's their money. 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 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're not focused on drilling holes in the ground; we want to make money. 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. 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. 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 may be 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 it is the most active basin in this country. So, it's the most logical to see the most deal flow and the most potential 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'd like to follow up a bit more on the dividend, as it's a key factor that sets you apart from some of your small-cap peers in being able to pay a dividend this year. Can you provide a high-level overview of what led to the confidence in potentially starting it this summer? Is it a combination of commodity prices and the direction of the business, or is it primarily about the business's positive trajectory? While commodity prices play a role, the business itself is a larger factor. If the goal is to achieve leverage of one times, not paying a dividend would certainly expedite that. With other small-cap peers not paying one, can you explain why now is the right time?

Yes, Scott, to simplify, we have a clear plan in place. In 2019, we assessed that the business could support operations at $40 per barrel. Interestingly, oil averaged that same price last year, but due to the volatility impacting the whole sector, the situation shifted somewhat. Our threshold for aggregate leverage ratios necessary for moving forward has decreased. As we approach summer and fall, we'll be on track with this. A modest dividend could provide some return and slightly influence our pace of reducing debt, but it won't significantly hinder it. Ultimately, while I don't want to downplay the importance of the dividend, the overall effect on leverage may be minimal. We believe we can manage both the dividend and growth. We benefit from high-margin, stable businesses and a much lower decline rate compared to typical US oil companies, which enhances the stability of our base operations, allowing for dividend payments. Our focus on developing a PDP-centric business over the last three years has enabled this. Additionally, we've significantly improved our balance sheet; we only have one piece of term debt outside of our revolver and maintain substantial liquidity. Bahram, do you want to add anything?

Yes. And Scott, I remember when we had discussions, 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. 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. But I think it's important for us to put our commitment forward start paying a dividend. Just like Nick said, not something that would hinder our original goal of getting bigger and stronger. We have a clear path how we can do all of this, and 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. If I could have another question here. I'm curious with some of the stuff, obviously say with the Bakken still being 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 has recently stated that there are a couple of their partners that have deferred some completions to maybe later in 2021. As roughly 15 rigs or so in the basin right now, 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? Does this really kind of provide a nice production ramp in the back half of the year? Any color you have on just the basin as a whole - if we are 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. In the fourth quarter, we saw the easiest way to convert your capital to be productive was through the DUC count. You saw a furious pace of completions, and that's still ongoing now. 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 workover activity. These are really high return, whether DSPs or flushing out wells that have been curtailed. 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 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. Most of the operators have indicated that we should see the rig count rise. What’s interesting in the other basins that we operate in, such as the Permian, has been that the bulk of our customer base and acquisitions have been the operators. 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. Do you have any comment about your partnership with…

On the deferrals, I don't know the specific case. 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 makes 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. The time lag between rigs being picked up and being dropped is 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. It just tends to be like steering a cruise ship as opposed to a speedboat.

Yes, yes. I think the NDIC said, well, the 650 to 700 DUCs 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. Could you provide some insight, perhaps for Adam, regarding the production and capital expenditure schedule for this year? With the Bakken, Permian, and Marcellus in the mix, how should we view product mix and spending throughout 2021?

Yes. I mean, Chad and I can handle the spending piece. I'd say that we would expect 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 of $20 million to $25 million. We would expect most of that to incur in the second quarter and a little bit into the third. I 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. 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. 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 based on 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, Dun, 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. You've had no completions on those properties really until we took control. 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 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. We are seeing the workover activity, which has a pretty short-cycle time. We expect to see a pretty meaningful ramp from the first quarter into the second quarter, kind of more in tune with our annual guidance. I think Jim, correct me if I'm wrong, but peak production will be sometime midyear and then be fairly stable thereafter. Overall, I think no surprises really there. I think the only thing that Chad highlighted in his comments is just about that workover activity, and we started to see it pick up meaningfully in December when prices did because the economics are there. We think that peaks out about March.

Thank you. Building on that, you have made significant improvements to your balance sheet and have a strong desire to continue growing and expanding the non-operational model. How should we view the opportunities available, whether through ground game or a deal like the Reliance transaction, in light of your CapEx budget of $200 million to $250 million for the year? Should we expect more ground game transactions this year, and would it be reasonable to assume that you would consider a larger deal if the right opportunity arises?

Yes, I believe that on the ground game side, we have budgeted appropriately within the $200 million to $250 million range. When we discuss the ground game, it is included in that budget. By planning for that upfront, we ensure that the free cash modeled is genuinely free. This approach is the best way to present it to our investors. We budgeted for it because if we were inactive, the number would likely decrease. We are the type to seize opportunities, and frankly, we are inundated with them. This is a significant focus for us beyond our regular responsibilities. The standards we set are quite high. We have not yet finalized the existing transaction, but we recognize substantial opportunities that must align with our terms. As I noted earlier, any potential deal must provide immediate benefits for all parties involved. For anything to even be contemplated, it must enhance credit, materially benefit equity holders, and align with our long-term business strategy. We're not just looking to make deals for the sake of it; there is considerable backlog that needs to be addressed in the next few years. Historically, we have averaged about 18 months between large transactions. With current prices on the rise, could that timeline potentially change? I would say the standards will remain high, and our Board is quite demanding of us, wanting to understand the advantages of any action we take. Please know that any opportunity will undergo the same rigorous process. We will act cautiously and thoughtfully. We are not going to simply pursue back-to-back deals. If the right circumstances arise, I hope that by 2021, should another opportunity present itself, it will be as clear as our reasoning was 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. 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 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. I think you can talk about the 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. 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 that goes back to my comments; there's only 15 perhaps 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 has been really encouraging. It kind of goes back to the old shale 3.0 paradigm, where 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. It's giving us an opportunity to kind of step in there. The quality of the opportunities in North Dakota has 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. 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. Some of it's due to offset activity where wells have been shut in as completion crews come in to frac wells. That's a function, a part of it. 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. The quickest way to get production back on is to turn new wells on. They focused on that first. Like Nick mentioned, there's a flurry of workover rigs running out there now. One of our operators, I think, has seven workover 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. As we move into early second quarter, we expect a lot of that to be back on.

Yes. If I can make a skeptical comment. I saw some 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. 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. 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. I think we've been waiting kind of in watching the environment in which we would see that work over activity take on, and it's going at a pretty robust pace right now. We really think as we get into April and May, we're going to be pretty much full bore.

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

Hey guys, hopefully, I can be part of that smart camp at some point too. My first question is for you, Nick. In your deal focus, you mentioned a lot of successful deals since last summer. Could you elaborate on how you view these deals moving forward? With the company's growth, are you focusing solely on the best returns in cash flow, or are you now considering larger working interests? Are there other factors or nuances that you would take into account that you may not have considered when you were smaller and in a different phase of growth?

I think our methodology is mostly the same. We've significantly increased our hurdle rates over the past few years, which has been beneficial. Overall, our approach remains focused on return on capital employed, emphasizing total return IRR and being fully transparent about costs, including acreage expenses. The Marcellus deal serves as a strong example of our working interest strategy, as it involves a much higher working interest than usual, but it came with governance that mitigated some of the risks. We receive daily offers to farm in at a 50% working interest, but we often avoid those because they usually involve significant risk without clear benefits. Therefore, any substantial offer must come with strong support. The Reliance deal clearly met that criterion. Adam, do you have anything to add?

Yes. The scale of our business offers us a unique competitive landscape, particularly when considering ground game deals where we might hold a 30% to 40% working interest in a unit. Often, these interests can be too large and concentrated for many of our competitors. As we evaluate these types of opportunities, we notice that many competitors may struggle to keep pace. Additionally, when our competitors consider such deals, it presents an opportunity for us to collaborate and partner on these ventures. We are still attentive to smaller opportunities, as we have not abandoned our focus on smaller scale deals. It has been a notable shift in the competitive landscape and how we engage with larger packages.

My second question is to clarify my understanding. On slide 5, particularly regarding Williston, I appreciate the calculations presented. Considering the upcoming winter, I know that activity tends to be a bit slower in the Bakken. I also appreciate that you included the wells in progress, which are noteworthy. You touched on this in previous questions, but I would like to hear more about it. As we approach the next winter, how should we view the wells in progress that you mentioned? Are these wells expected to come online before winter if they are already underway? Will there still be a weaker activity period during the winter? Nick, I am trying to gain a clearer sense of the timing 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, 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 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. It can vary from time to time. 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. 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, 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 guideline in terms of second, third, and fourth quarter kind of?

Yes. The effective date was July, and it 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. 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 range and then kind of hold that flat throughout the rest of the year on the Marcellus side. That kind of gets us to our guidance of $75 million to $85 million. On the Williston side, we expect Q1 to be relatively flat with Q4 as we go through the winter season, and activity levels stay low. Then going into the second quarter, we expect that to be one of our busier quarters, and so production should ramp pretty quickly through the second quarter and then hold relatively flat through the rest of the third and fourth quarters to meet our mid-quarter guidance.

Yes. On the gas asset, we just had our budget meeting with the operator yesterday. No surprises there. The timing has stayed consistent. We should see a bunch of IPS, I believe in June. 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. To make sure that everybody understands, we want to clarify that we've given full year guidance. It will close April 1. The first quarter of production and all those things will be received in the form of a reduction to the purchase price; those are full-year numbers. So the actual quarter, and I understand why you're asking, Philips. I want to make sure that everybody understands that we've given full 2021 guidance; we 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 short, we would have to do something pretty extreme in order to...

That's right. 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. No, we don't expect we'll be fine from an NOL standpoint.

Excellent. Thank you, guys.

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

Good morning, guys.

Good morning, Nicholas.

A 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? 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%. 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 before 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. 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 of 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 off the webcast at this time. Have a wonderful day.