Greetings, and welcome to the Northern Oil and Gas First Quarter 2020 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mike Kelly, EVP of Finance. Thank you, sir. You may begin..

Thanks, Jessie and good morning, everyone. We're happy to welcome you to Northern's First 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 Senior Vice President of Engineering, Jim Evans; as well as Northern's Chairman, Bahram Akradi.

Our agenda for today is as follows. Nick and Adam will give us some state of the union type comments before turning the call over to Chad, who will recap Q1. Allen Chad, Bahram will wrap up our prepared remarks before we get into the Q&A session. Before we go any further though, let me cover our safe harbor language.

Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act.

These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements.

Those risks include among others, matters that we have described in our earnings release as well as in our filings with the SEC, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements.

During this conference call, we may discuss certain 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 off, I'll hand the call over to Northern CEO, Nick o'Grady..

Thanks, Mike, and good morning to everyone. In a similar manner to last quarter, let's get right down to it in 7 points. Number one, the balance sheet. Northern's leverage profile continues to improve.

We reduced leverage by a staggering $78 million in the quarter, including open market repurchases of our senior secured notes at steep discounts from par value. Since the first quarter ended, we've made more progress, particularly on our revolver.

With the elevated activity in the back half of 2019, the working capital needs of the business were a material drag versus book cash flows in the fourth and first quarter. And as this reverses, we expect our deleveraging to accelerate.

As of Friday, we've already paid down an additional $9 million on our revolver, have over $20 million in cash and plan to pay another $10 million in the coming days as 1 of our bank tranches matures. In addition, since quarter end, we've eliminated another $6.1 million in principal of our senior secured notes, again at steep discounts to par.

The senior notes are by far our largest maturity over the next several years and through various modes, we have eliminated over $96 million of them in less than 5 months of this year.

We expect to continue to ratchet down our revolver borrowings, in particular, second quarter end and estimate we will reduce over 10% of our total debt in just 6 months. In addition, our Board and Directors made the tough decision to defer dividend payments for both our preferred stock or common stock.

This is the right thing to do in an environment like this and to focus that cash flow on our senior obligations first. Number two, hedging. Our hedge book as of Friday, as a whole, has an undiscounted market value of approximately $375 million, up from approximately $300 million last quarter.

Even more impressive, given that it excludes $31.5 million of realized gains in the first quarter. We have done some modest work to the book. In particular, restructuring forward 2022 hedge value into 2021 at even higher net prices, protecting those future gains, as well as materially improving net present value.

Given the strong move in the natural gas strip, based on optimism surrounding associated gas production, we've been able to layer in some natural gas hedges as well.

Since we last reported, we've seen operators scrambling to unwind their three-way collars in order to save face at prices that may be a premium to the current strip, but are now at subeconomic prices that are going to be long-term destructive to their equity values, particularly, as the sector heals.

Since this management team took control of Northern a little over 2 years ago, we have focused on risk management on the front end, not as a stop gap measure after the fact. Number three, shut-ins. This is a hot topic I want to address before the Q&A, as the sector attempts to balance the steep drop in demand.

While these targets are moving and the exact timing is difficult, I'm pleased to let you know, that Northern is about as well prepared as anyone to weather these issues.

As a nonoperator, there may be some billing delay in LOE costs coming down, but regardless of the shut-ins and given our hedge portfolio, we expect margins and ultimately cash flow to remain extremely resilient.

The Williston rock is highly conducive to curtailments, as the rock and age of the wells should not see material issues, as they return to sales, when appropriate. Second, the cost of LOE, which are driven in large part by saltwater disposal and workovers and to a lesser extent electricity, should see drop-offs in kind.

Given the delay in billing via non-op, we'd expect the full benefit of this to be felt in June for the second quarter, and to continue on until wells return to sales. Secondly, as I mentioned on last quarter's call, we do not want wells producing in this environment anyway. The oil is still in the ground.

Oil production is a depleting resource, and we do not want our wells producing hedges or not in an environment such as this. Instead, because of our strong risk management, we have the potential to earn returns twice on these assets, with the hedge gains we are scheduled to receive, and the reserves that are preserved for the future.

Depending on a few variables, there's likely only a moderate impact to cash flow in 2020 from curtailments. And long term, it is a massive positive for our reserves and future production. There are even select scenarios in which it increases our cash flow. This is why you hedge. Number four, development.

We are carrying a record number of completed wells waiting to be turned to sales and drilled but uncompleted wells. This means that we have a coiled spring of sorts, if and when, commodity prices improve.

I'd note that, despite significant curtailments, we experienced starting in March and half as many wells turned to sales in Q1 versus Q4, we still saw nearly flat production. While like the entire U.S., we expect to start from a lower production base when the call for U.S.

production activity returns, we'll be well situated both on a capital efficiency basis from wells ready to return and from the fact that our volumes have not been wasted in a sub-$20 oil price environment.

Post curtailments, we also expect our base production to be significantly higher and the corporate decline rate to normalize, given the elevated activity in the back half of 2019. This elevated base production level is a big positive to the value our banks underwrite in our RBL, and longer term, a huge net benefit to our equity holders.

Number five, differentials. Differentials for gas have started to show steady improvement as we -- as seen in our first quarter results, especially given how poor they were late last year.

We don't expect to see gas differentials as strong as we saw in the first quarter for the remainder of the year, but as we've been telling investors for the past few months, as the infrastructure build-out from 2019 takes hold, many of the issues plaguing our gas prices would see improvement.

In addition, they will be influenced as always by the ratio of gas to NGL prices. Oil differentials are another matter. In a normal world, the shock from lower oil prices and lower production should be having a material net benefit to our in-basin pricing.

In fact, we believe strongly that when the market returns to normal, we will see a multiyear horizon for vastly improved differentials for oil takeaway, from the slack capacity that will exist. In the short term, with demand so weak, the physical limitations of the market have been driving very wide pricing differentials.

However, if you believe, as I do, that at some point, we'll all go back to work and the stay-at-home orders will continue to ease, it would suggest the differentials with plenty of available takeaway in the Williston will be improved dramatically for the next several years as those take place.

In the short term, it will be volatile, but the future for our netbacks should be bright. Number six, guidance. I promised more meticulous guidance this quarter, and we are mostly delivering on that. Although, given the wild swings we're seeing in the sector, it is more challenging than where we stood in early March.

In the immediate term, production will be nearly impossible to predict. And while we know the second quarter will carry significant shut-in volumes, only the pace at which the COVID-19 battle is solved, will we know how production begins to normalize. The operators do not know this, let alone us.

The good news for Northern is that it doesn't really matter, because we're prepared for this. Our cash flows are well insulated, regardless of the outcome. Our incredible hedge portfolio means, we can give ranges that actually matter, which is not production levels but cash flow.

We expect to produce $350 million to $410 million in adjusted EBITDA in 2020 and spend approximately $175 million to $200 million in CapEx. This points out that approximately 45% of the anticipated capital spending for the year has already occurred, and that is driven by the first 2 months of the year being relatively normal.

However, this should not be treated like any typical midpoint of guidance. The variables driving these will be shut-ins, in-basin differentials and the price of WTI for our net gains on our hedges. This range will be driven by the mix that ensues. Our book interest expense should range between $55 million and $60 million.

This equates to approximately $135 million in free cash flow at the midpoint. I note that, by our definition of it, only about $5 million of that free cash flow was realized in the first quarter, as our normal waste spending ramped down. So the bulk of it yet -- still yet to be realized.

We'll also note that we're holding $50 million of completion capital as a reserve in the event that oil prices come roaring back, and we see a flurry of wells completed and turned to sales. However, based on the current forward strip, we see that it's highly unlikely, but we want investors to be aware, should we see a strong rally in pricing.

Number seven. Finally, opportunity knocks. If I can leave our investors with 1 message, it is this. We are on the offensive. I told you on our last conference call that I believe firmly, there would be opportunity. It is beginning to show up.

Our superior risk management puts us in an enviable position to acquire producing assets underwritten to earn and exceed our cost of capital based on the environment that we are in today, something that is not likely to endure.

If successful, this will give us an enormous convexity to the upside and potentially give us additional undeveloped resource for literally no cost. Opportunities abound everywhere.

Bankruptcies and distressed asset sales, mispricing of our own capital structure that belies our financial strength, and the fact that we have incredibly supportive stakeholders who share our vision.

We continue to evaluate all the opportunities in front of us, including continuing to opportunistically reduce debt, and we'll deploy our capital to those opportunities with the greatest return for our stakeholders on a risk-adjusted basis. That's it from me this quarter.

For everyone on the call, most importantly, I hope you and your families are safe and healthy. I hope you're managing through the market impacts and economic hardships that are affecting so many.

And I said -- and as I said before, and I'll say again, I'll conclude that this difficult period is a tremendous opportunity for Northern, and we continue to strengthen the balance sheet, the asset base, and we are on the hunt for opportunities to make a stronger, lower risk enterprise.

As I stated in my prepared quote in this morning's press release, I cannot emphasize enough that Northern is different. While others scramble and react to this crisis issuing multiple revisions to their guidance and scramble to cut G&A, we prepared our business in advance, with our balance sheet moves and multiyear risk management program.

In addition, we have been focused on doing right by our investors long before the situation called for it. That's because this Board and Management are actually significant owners of this business. Our cash G&A is already at industry lows, with only 24 employees and an executive team that has paid at some of the lowest levels in the industry.

This was done on the front end, not in reaction to the current market conditions. Flexibility of our non-operated model allows us to execute on capital decisions in real-time, without the burden of a loaded cost structure. Thanks, and let me briefly turn it over to our COO, Adam Dirlam, to talk about field activity.

Adam?.

Thanks, Nick. From an operations standpoint, I'd like to quickly touch on first quarter's well elections and Ground Game acquisition activity and then, what we are seeing as we move forward.

In the current environment, the wells that we are electing to are only wells located in the core of the basin, where completions will be deferred in the near term, but will generate an acceptable return in a lower for longer price environment.

Total rig count and drilling activity has slowed tremendously, as operators elected to lay both the drilling and the completions of any new wells. In the first quarter, we received a total of 159 well proposals, non-consenting 43.

During the month of April, we really saw the reduction in activity as we received only 28 well proposals or about half our 2020 monthly average. Of the proposals that we received, and to be we elected to participate and 37% of them on a net well basis.

As it stands today, we anticipate fewer and fewer well proposals as rig contracts are satisfied or get renegotiated. And the conversations that we've had with our operating partners, most completions for 2020 will be back-half weighted, although, many operators continue to take a wait-and-see approach.

For the wells that we have elected to, we've been encouraged at the reduction in average well costs. In the first quarter, we elected 5.6 net wells with an average cost of $7.6 million, inclusive of facilities.

We believe there could be some downward trajectory, as we review the well proposals that we have received in the second quarter, but overall cost will depend on the operator, lateral length and completion methodology.

From an acquisition standpoint, we closed on 12 transactions during the quarter, working with both non-operators and operators alike to create transactions that are mutually beneficial. In the first quarter, we acquired 965 net mineral acres, 61 net royalty acres and 3.6 net wells.

We continue to stay creative, and in one instance, we were able to work with an operating partner to carve out a nonoperated working interest in a handful of their own wells, where we would mutually agree upon completion timing. As we move into the second quarter, we anticipate the ground game acquisitions to slow down.

In this price environment, we have no intention of moving our hurdle rate for either acquisitions or well elections. With prices, basin-wide activity and the bid-ask spread where they are, spending will come down.

That being said, we will continue to be opportunistic and continue to review all types of acquisition opportunities in order to make Northern a stronger entity coming out of this downturn. With that, I'll turn it over to Chad Allen to discuss the financials..

Thanks, Adam. I have a few highlights to go over this quarter, starting with a quick summary on Northern's financial performance. First and foremost, our first quarter return on capital metrics remained strong, with our return on capital employed coming in at 11.7% and our recycled ratio staying flat sequentially at 1.8x.

Our production increased 28% year-over-year and was effectively flat sequentially to an average of 43,735 barrels of oil equivalent per day. Production held in nicely during the quarter despite continued curtailments and, to a lesser extent, the COVID-19 economic shock in March.

Adjusted EBITDA was $108 million for the quarter, which was down only 5% sequentially, despite a 20% drop in oil prices. Cash G&A came in at $0.95 per BOE this quarter, 14% lower than the fourth quarter, which continues to be one of the lowest in the industry.

Well differentials were $8.50 during the quarter, which was due in part to poor in-basin pricing as we moved through the quarter and other seasonal factors. In the current environment, we would expect oil differentials to narrow substantially throughout 2020 and we are seeing that as we speak today.

Lease operating expenses came in at $9.38, up 6% sequentially during the quarter, due to higher production processing costs and fixed charges on wells that were shut-in. As Nick's mentioned, we significantly improved our leverage profile since the end of the year, and our focus continues to be on debt reduction in these challenging times.

We reduced our net debt by approximately $86.3 million or 8% since year-end.

We are in the midst of our spring borrowing base redetermination and given the current corporate lending environment, we expect a reduction in our borrowing base, but not nearly to what has been experienced by many others to a large part through our robust hedge book, our PDP coverage base and healthy leverage metrics.

Capital spending for the first quarter was $86.7 million, which consisted of $64.9 million of organic D&C capital and $21.1 million of total discretionary acquisition capital, inclusive acquisition D&C.

We expect that approximately 50% of our annual budgeted 2020 CapEx was incurred in the first quarter, as we ride our activity levels down from a normal CapEx environment.

We expect our 2020 capital expenditure budget to range between $175 million to $200 million, a reduction of 53% to 59% compared to our actual development capital expenditures in 2019. Our wells in process grew 27.2 at quarter end, up 1.4 net wells since the beginning of the year.

It is important to note that the 27.2 net wells in process, 6.1 net wells have already been completed and are ready to be turned to sales when the time is right. On the hedging front, our hedge book is a testament to our commitment to protect invested capital, cash flow stream and our balance sheet.

We have approximately 27,000 barrels a day hedged at an average price of $58 for the remainder of 2020. Based on the May 2020 closing oil strip, the undiscounted market value of our hedge book is approximately $375 million. So we expect to generate a significant amount of free cash flow from our hedge book.

And with that, I'll turn the call over to Northern's Chairman, Bahram Akradi..

one, enhance our balance sheet; two, increase free cash flow; three, reduce our debt to EBITDA; and four, put the company in a position to have access to lower cost borrowing. At all times, we're playing the long game and sometimes that requires tough decisions in the short run.

A few months old, we decided not to move ahead and pay a dividend on our common shares. Now we have to do the same and defer the dividend on our preferred stock. Ensuring the most possible cash flow in this uncertain environment is a must. Additionally, as you can probably anticipate, the opportunity to acquire assets is increasing by the day.

However, in the event that we find any opportunity to acquire anything, it would have to fit with the 4 criteria I mentioned before. With that, I will turn it back to Mike and look forward to answering any of your questions..

Thanks, Bahram. With that, I'll turn the call over to the operator for the Q&A portion of the call. Jesse, if you could please go ahead and give instructions for the Q&A. Thanks..

[Operator Instructions]. The first question comes from Dun McIntosh with Johnson Rice..

First question is for Bahram. You and some of the other Board members own about 30% of the stock here. And just wondering kind of what are you all expecting to see out of this management team? You have accomplished a lot over the past 12 months, and I assume you're expecting a lot more over the next 12.

But just, I guess, maybe kind of framing it in the context of as you alluded to a little bit here, M&A opportunities versus debt reduction and kind of how you see them navigating this unprecedented time we found ourselves in here with oil at $25?.

Well, I appreciate the question. First of all, I could not be more thrilled with this team. This is an All-star team. They're always on. They're agile, they're thinking, they're responsible. Again, I can't say enough great things about them. I have utmost level of confidence in them.

Next is really the opportunities for companies like this and many companies is really when things are really, really tough or when things are really, really good.

At this point, with the hedges that this team has put together, strategy of the company, we are well insulated and sitting in a great position to study, understand and pull the trigger in the events we see opportunity. So we are looking at every opportunities out there.

However, as I've mentioned in my prepared remarks, in the events we find something that make sense, it would have to be in the structure that will enhances the balance sheet of the company going forward and it's consistent with the philosophy that we have put in place over last two years.

Less debt, more equity, more cash flow and play the game as long as -- played a very long game in the oil and gas business. I have the most confidence in this company in terms of our ability to continue to build a very, very large substantial business that is managed professionally, and the team is fantastic..

Great. And then maybe next for Adam or Jim.

At what price do you think or at what point do you think operators start thinking about bringing volumes back on? And then ultimately, maybe even putting activity back out in the field, is it -- I mean, is it more of a headline price or obviously, what your realizing in basin is going to be ultimate driver there? And just kind of may be from a timeline perspective, as obviously there’s a lot of uncertainty out there.

But as things stand today, maybe you’re kind of vision on the next 3 to 4 months through the summer in the Bakken, specifically?.

Yes. I can go first and Jim can fill in on any holes. At a high level, I mean I think it was production curtailments to start picking in mid-March, we saw that pickup into April and we anticipate that kind of continuing into May as operators kind of get all their [indiscernible] in that regard.

And I think, based on the conversations that we’ve had with our various operators, they’re taking a look at their breakeven prices across the basin, taking a look at lease hold obligations, whatever it might be and kind of curtailing those and such. Certain operators have different midstream and marketing contracts, they have minimum volumes.

A lot of those operators are still continuing to try to meet those volumes. And so it definitely varies in terms of curtailments across the basin by area, and by operator. But that being said, we’re seeing a quick and swift reaction across pretty much all of our operators.

There’s maybe only 1 or 2, even from like, well proposal standpoint that are still kind of going, most operators are either renegotiated or satisfied their rig commitments. And so I don't necessarily anticipate a whole lot of new well proposals, kind of going forward at least in the near term. And Jim, is there anything else you want to....

Yes, that all is kind of dependent on which operators are receiving you. Some operators have lower operating cost than others. And so they can turn these wells back on a little bit sooner.

And we would expect to probably mostly through the second quarter of that, there are some decreasing significant curtailments, probably till we get north of $30 and then into the third quarter and fourth quarters, when we really start to see some of those wells come back on..

Yes. And this is Nick, I mean I think you have to take into account few things. The absolute price to oil and then the in-basin pricing. I think, in April, when differentials were $10 to $20 depending on the various methods that probably drove those decisions as much as the absolute price of oil.

And so I think that is going to be of -- and to Jim's point, it's going to vary. Some operators may have contracts that insulate them from that. But even when you had Gulf Coast pricing good with discount, that can have an impact is, obviously, gap of volumes touch the Gulf Coast. And so I think it's really going to be dependent on that.

So the absolute price of oil does matter. I would say this that, it appears to me and I think my team would agree me with that, the markets in North Dakota is imbalanced based on the shut-ins that we're seeing today and might even be tied to DAPL contracts and trading at premium to WTI, I have never seen that before.

And so that would tell you that the shut-ins are working.

I would expect, if absolute WTI prices go back up, it could get a little wobbly in the first months as operators bring production that's needed to come back to market, but doesn't -- but you could see those in-basin pricing points wobble around, as they try to balance that out and bring some volumes back.

Like any recovery, it will be a little wobbly..

Our next question comes from Derrick Whitfield with Stifel..

Congrats on a strong update, despite the macro environment. Perhaps, for Nick or Chad, I wanted to address your prepared comments regarding accelerated debt repayment.

Given the potential value this could create with the notes trading at material discounts, I wanted to understand, how aggressively you could pursue this? And if there are any conditions or covenants within your capital structure that will limit your ability to pursue this action?.

Derrick, I'll just give you sort of -- I talk about risk-adjusted all the time. I think the most important thing is that, the return on capital from buying our bond with a discount is substantial, right? We also -- especially relative to repaying your credit facility, however, by repaying your credit facility, you build liquidity.

And so, as we mentioned, the capital reserve for completions that we would look for in the event of a recovery, you want to make sure, you maintain adequate liquidity, you'd be able to prosecute those because, those returns can exceed -- certainly exceed that sort of 30% threshold that the bonds offer in the future.

And so it really comes down to a balance. I would say that, we have a lot of strong stakeholders. We're creative guys, and we're thinking in lots of creative ways to deal with -- to take advantage of those bonds, we've certainly used them so far.

But I also think, like I said last quarter, this is an art of balance of thinking about the future and not just the present opportunity. I mean I think, we've gotten asked a lot in the past about stock buybacks, and it's not that we haven't been insulted by our stock price at various points in time.

But I also think that, that's an example of -- you've seen lots of companies buying their shares back at much higher prices. And here we are with the equity markets crashing and they're canceling those when the stock price is actually low.

And so when you have $1 in your hand, you have to be very careful, not just to allocated to the highest return today, but to be playing the long game, as Bahram mentioned, and thinking about the future and making sure you stay for a rainy day.

Chad, do you want to add to that?.

That's great, guys.

And then as my follow-up, perhaps, sticking with you, Nick, regarding your comments on Northern being in a position to play offense, could you share with us your views on the current environment in both deal flow and seller expectations as M&A could present a near to medium-term opportunity for you guys?.

Yes. I think it's still early stages. The distress -- we're going through 1 bank redetermination season. What I'd tell you is that, most companies, when prices are low, do not want to part with their producing assets because they need the cash flow more than ever. So usually for them to part with them, it's because they have to.

And that is going to take pressure from their lending institutions, from their covenants or what have you. So I think we're in the beginning phases of that. It's starting to show up.

I'd say that the opportunities set is going to be broader than I would have anticipated because I think -- look, let's be honest here, low-cost play, high-cost play, the only thing that really matters when oil prices are at $24 is, are you hedged? And what's your aggregate discount levels? And so a lot of good companies are going to find themselves with good assets in a bit of a pickle here.

And so I'd say that we -- I think the way we look at this is simple that, at today's strip, very little undeveloped nationwide makes an adequate return. And so there's very little value for that today. Do I think that, that's going to -- do I think the strip in 2 years is accurate? Probably not, but we have to underwrite it based on that.

And so we have to focus on producing assets net of any curtailments they're experiencing, net of any obligations that they have and value them accordingly and try to design win-win situations, where we can help them and obviously earn our cost of capital day 1.

I think that, given that banks will own a lot of assets in this downturn, I think that's obviously well publicized. I think that, they have to weigh the difference between their own liquidity and ultimately, how long it will take them to recoup their losses in those cases. And so we're hopeful that we can be a helpful partner in those conversations..

Our next question comes from Phillips Johnston with Capital One..

Just a follow-up on the curtailments.

Do you guys have any guesstimate as to how much of your May production is either shut-in or curtailed?.

Yes. We're still getting information coming in. The operators haven't given us a lot of specific data on which wells it's going to be or that sort of thing. So we're still kind of in the early stages of that. Obviously, we saw quite a bit in April, and we'd expect more in May. But we haven't seen the information yet for -- we can't really speculate yet..

Yes. The plans seem to be changing on a week-by-week basis. And so we're staying in contact with our operating partners, consistently to understand exactly kind of how they're looking at things..

Okay.

Has Slawson been as aggressive as Continental in terms of shuts-ins that you know?.

Slawson will certainly be aggressive. I don't know, relative to Continental, but both those operators seem to be curtailing a significant portion of their production..

Yes. Okay.

And then maybe just a housekeeping question since the Q isn't out yet, what was cash outlay for the $90 million of senior secured notes that you guys repurchased?.

Well, you can actually -- let's just -- a portion of it was done with the preferred stock in January. I don't know the number off the top of my head..

It is $79 million in preferred stock..

Yes.

So I think in total, the $90 million, I think it was something like around, please don't punish me if I'm incorrect, around $10 million, $10.5 million for the entire $90 million, I think?.

Yes. That's right. That's exactly right, yes..

We want to preserve the cash for the opportunities set that we think is coming, but it doesn't mean that we're not paying attention to when the bonds trade at a discount and want to take advantage of that..

Our next question comes from Neal Dingmann with SunTrust..

Nick, my first question is about the sensitivities you touched a bit on your prepared remarks. And really want to digging into just -- in the prepared remarks, you suggested or the guidance you're suggesting $350 million to $410 million in this forecasted EBITDA.

I'm just wondering, can you walk through a bit as far as how you all view operators as far as the preference on -- do you have some out there, as you mentioned Slawson, Continental, et cetera, that are still curtailing quite a bit, others not curtailing very much.

I'm just wondering, kind of based on the guide that you have out there, I guess, more generally statements, if you could just give some color on what you'd like to see in the next several months, given, I guess, sort of based on different prices?.

Yes. So I mean, I think I'll give you an ironic statement which is that, for the better part of the year, the Williston has been capacity-constrained and so our LOE has been somewhat elevated because wells were curtailed from what they could. So we carried some cost of operating them, even though they weren't running at full capacity.

But what I would tell you is, one of the big drivers of that's going to be that -- as I mentioned in my prepared comments that LOE will drop dramatically, as these wells are curtailed, because you're not hauling water, you're not paying for electricity and you're not working those wells over.

And so there will be some time lag to that, and it will depend -- operator to operator, how that starts to feed into our system. We're taking a pretty conservative tact, to be honest with you, about -- of those overall impacts and what we carry.

Obviously, for the wells that are producing, it's going to matter of what are the marketing agreements for those barrels. I would imagine, just being economic creatures, the barrels that are still producing and not being curtailed are going to be those that satisfy contracts that are the most favorable.

And so what I mean by that is that, the netbacks and the in-basin pricing which can happen when prices are this low, can have a huge impact on the net revenue. And so I think that with -- in recent periods, we've seen in-basin pricing rally strongly.

So far the barrels that are producing and that are sold in-basin, I think you're going to see better pricing certainly than we would have expected even a few weeks ago. But then the question is going to be, how quickly does the cost burden come down? And then the third variable, obviously, is just the realized gains on our hedges.

And so in some -- as I mentioned, there are some scenarios in which we can actually see increasing cash flow, certainly, if oil prices go back to negative $37, we can make more money than we would, if the wells are actually producing. And so I think it's just going to be the cocktail of those variables that drives the aggregate cash flow levels.

But what I would say is that, you can run some free mean-spirited outcomes, and ultimately, those hedge values are pretty sticky.

And so -- and the market is fairly flexible, for most of these volumes, they can be -- if pricing rallies really hard to which extent that our hedge gains would be coming off some, those volumes can return to sales quite quickly, within a few weeks, in most cases. And so I think that we're going to find that range to be pretty accurate..

Okay. Good details. And then second, just for Adam. Adam, I think you mentioned that somewhere -- I think you participated in just 37% of proposals.

I'm just wondering, if you talk about required rate of return or why that -- kind of how that level versus -- it has been versus maybe the -- even just the prior quarter or 2?.

Yes. I mean -- I think -- first off, I think it highlights the nonoperated business model, right? We've got the ability to pull back the reins of faster than a lot of our other operating partners that have these commitments. And so when we look at that well proposals, we're running a handful of different sensitivities.

What's the rate of return, when it comes on x price, y price, z price? And then from there, Jim and I and our team are getting together to understand exactly what the mentality of the operator is and what they're doing.

And so a lot of the wells that you saw us elect into, in kind of late March and April were wells that we have certainty that we're going to be ducked in the near term. But that -- if lower pricing were to persist, it was something that we're comfortable and would generate an acceptable rate of return based on the sensitivities that we ran..

Our next question comes from Jeff Grampp with Northland..

Was curious, first off, I'm looking at Slide 20 of the updated deck, it looks like seeing another maybe step change in well performance, albeit with limited data here on 2020, but can you guys just talk about your views on the sustainability of that? Is there -- I guess, the high-grading opportunity still left in the basin, that operators are kind of consolidating into? Or are we just reading into early data here a little too much, maybe?.

Well, what I will say, I'll let Jim talk about the well performance, but I will say, one thing we haven't really anticipated much of, but I expect we'll see, we've seen some incremental data, but we tend to be a lagging indicator -- is that, but I do think, from a return perspective, well costs are going to come down some further.

We see the operators' presentations of what they say, their wells cost, I would say, the AFEs certainly don't put to those numbers. But the AFEs also have contingency costs in them, which likely in this environment, are not going to be realized.

So I do think from a return perspective, if the wells are the same as they were before, you're going to see materially lower costs.

And then, Jim, I don't know if you want to talk about the high-grading?.

Yes. I mean you could kind of see on Slide 19, we've got that map on there that kind of lays out where all the wells are located. And so you can see the wells that they completed in 2020, have mostly consented within the core of the basin. We came into the year with a really good set of wells in process.

And so we felt pretty strongly, so initially that this was going to be a good year in terms of well performance. We're probably not going to feel whole lot more of efficiency gains in terms of well performance within the core. I think we're at kind of an optimal standpoint.

Last year, we had quite a few wells that got completed outside the core, and that was kind of a mix of Tier 2 stuff, operators testing new areas as prices were higher.

So I think for 2020, with prices being low, we'll see most of the well performance be kind of centered within the core, and we should continue to see good performance on our 2020 program..

Got it. Really helpful. And for my follow-up, I noticed, and you guys highlighted, I think, in the prepared remarks, acquiring some royalty acreage.

I know that hasn't been a huge focus for you guys historically, but is that maybe a sign of maybe some loosening of that market in the basin? Is that an increased focus for you guys? Or maybe just a one-off, I guess, just trying to handicap future opportunities, specifically on the royalty side?.

Yes. I mean we looked at working interest and royalty deals all the time. And generally speaking, the working interest opportunities that are presented in front of us generated a significantly better rate of return. So that's where we're allocating our capital.

But with the volatility and the opportunity set changing out there, we saw a handful of deals that we were able to kind of get done on the royalty side of things. Nick, I don't know if there's anything else you wanted to comment on in terms of....

Yes. I mean, investors have heard me rant about this, but the royalty in the working interest business are really the same thing. One just has a higher return and one has a lower return. The lower return one is a little bit less risk. And we do own some minerals.

And oftentimes, we view it as a supplement to our working interest in which we can increase our NRI and something that we're already participating in. So just think of it as using your NRI from 80% to 85% as opposed to some pivot to the business itself..

Our next question comes from Jason Wangler with Imperial Capital..

Was curious on the remaining CapEx budget, I guess, about $100 million or so on the high end.

How you see that being used throughout the year? I assume it's going to be drilled uncompleted wells and kind of where you think you'd kind of exit the year from a wells and process standpoint under that scenario?.

I think the cadence, we've looked at it as somewhat equal weighted. I think there's the chance -- I think the hardest part with how we accrue for it is that, will accrue for these wells based on a percentage of completion and then the operator may say, sorry, we took a pause. And so then we'll reverse that.

And so I don't want to -- we tried to give a broad range. I don't want to get too granular. We certainly would expect a lot of stuff to get pushed to the back half of the year.

And we sort of put that reserve number in there, just because in the event that we see in the fall some huge ramped oil prices, and we see a lot of the DUC count getting brought forward, I want to make sure that we account for that, and you guys don't think we're out there overspending or something like that.

But I still see that as a remote possibility at this point. Obviously, we're carrying 27 net wells today. That's a huge number, especially given 6 of them are already fracked and paid for.

And we think that, that should continue to build throughout the year because we are seeing the DUC count continuing to build and we're not completing very many wells. I would say, in terms of the exit, it's really going to depend on what happens with pricing in the fall. If we see a rally in pricing, we may see some of those get completed this year.

And some may -- if prices stay in the [indiscernible], we'll see them come out at the end of the year. So I think we'll just -- I'd say, we'll watch how that goes, and we'll react accordingly. And I think we've tried to give that capital with the assumption that the majority of those are going to be turned to sales, but some of them could get delayed.

We'll just have to see how it plays out. I just want to add -- yes and just one thing on that, I can't emphasize enough. This is for our banks and for everyone else, which is that the hedge value means that we're collecting on this cash flow. But as we push those curtailments forward, that production is saved for a future day.

So that base production that we restart in a higher price, even if it's, say, a $35 world, will be materially higher than if we had just blown down the production from the beginning of the year, like it would normally happen in a $40 world. So we view this as a really serendipitous set of events.

And I think that, if you're prepared for this and you're not taking on water or having to borrow money through that period of time, which we're certainly not going to be, it puts us in a really strong position, and we'll make resuming growth at some point in the future, a heck of a lot easier..

Our next question comes from Gregg Brody with Bank of America..

Just picking up on the last question that you mentioned, sort of your base production will be materially higher. Just -- there's a general question about shut-ins, potential leading degradation and performance. And obviously, the Bakken's had little history of shut-ins just due to the winter weather.

Could you just help us think through, how that's managed and there -- we should not expect too much issues with well performance post shut-ins?.

Yes. So I would say for wells that are fracked and not turn into sales, it can sometimes mean that there's a lower IP rate when they are returning to sales. But from an EUR perspective, generally, it actually can sometimes have a net benefit. So the well will produce more for longer, just as it builds that pressure.

If we were -- I want to -- for everyone's reference, the Bakken is not a shale. It's a dolomitic rock in between two shales. Shale production in shales, which are more fractured in porous, and that -- and where there's lots of water, there can be issues with shut-in and curtailed volumes, damaging those reservoirs.

I'd say, I never say never, but the Williston is about as good of a place as you probably could be before that. We deal with shut-ins all the time. Some of our producers curtail their volumes on a quarterly basis. We dealt with some pretty significant ones last -- in the beginning of last year with very little long-term impact.

Jim, do you want to add to that?.

No, just like Nick said, we feel the Bakken is a great reservoir. You don't really see a lot of damage, especially with the low water cuts. If you're in an area with 60-plus percent water cut, I would expect to see some degradation in that well performance, when it comes back on.

But for us, we're not really expecting any degradation in well performance..

Yes. I mean I think the Delaware Basin can produce like 85% water, like I wouldn't want to curtail volumes there, and that's what we are a producer there, but there are places where it's going to be more troublesome than others..

Interesting. Nick, maybe shifting gears.

Obviously, a lot opportunity here for you, given that you're coming into the cycle, is there a possibility that you -- that you ship strategies a little bit and think about taking on operating positions? Or is it still not up all the way?.

I think we'll do anything that makes economic sense. I think that the hurdle rate for everything that's outside of our core strategy is a lot higher. I think that we will do what's best for the business. And we'll be very, very careful about that.

I think that -- the one thing I would say and maybe it's kind of ironic, given that sometimes we feel like we get punished in the market, is that our observation has been that most of our nonoperating peers are in a hell of a lot better financial position than our operating peers.

So maybe there's something in the water of nonoperators that we tend to manage our businesses a little bit better. So we haven't seen the same level of distress in nonoperating as we have in operating. But I would say the hurdle rate for any operated business is very, very high..

That's helpful. And then maybe just the borrowing base.

How do you -- do you see -- how do you see the potential availability of credit affecting your ability to pursue the strategy?.

I mean it depends on what that strategy winds up being. I'd say, for good ideas, there's always the money available. It certainly is difficult of period as I ever remember. Banks are wearing real losses this cycle. They didn't even have that really in 2016, to a large degree.

I'd say, we have, what I believe a really strong bank syndicated number that our bank line is newer than most. And so while some may have, syndicate members who are trying to get out of the oil and gas business, by and large, those that were trying to get out, weren't around by the time we started ours.

So I'd say we have a healthy group of banks who have been tremendously supportive. I do think that, as Chad mentioned, it's going to go down some, certainly at a manageable level. Our business doesn't require a ton of liquidity and because we're spitting off cash, we're not a user of cash.

And I think we've looked at pretty much every draconian scenario can look like, and we feel really confident that we're going to have more than enough liquidity to prosecute everything we want to do. I would say that being in the position that we've been in, we have never been taking more inbounds from people looking to provide capital.

And so that should tell you something that people are looking for the winners in the cycle. And I think, if the right appropriate structure is there and something like that, we'll certainly find other ways to bring money in. Do I think the bank market is going to be tough for the next couple of years? Absolutely..

Just last one. You talked -- you gave us some great color on the crude market. You mentioned the gas market appears to be back to normal.

Just any observations about where the potential bottlenecks could be or opportunities would be with gas and just NGLs?.

Yes. I mean you had over 1 billion cubic feet a day of processing capacity to come online at the end of last year. It's been a real thorn in our side. Frankly, the gas has been holding back crude production. North Dakota steps up to 91% in the fall.

And so what you're seeing is our oil volumes are pretty consistent, and we're putting more gas, the sales were capturing more of that at the time that new NGL and gas processing takeaway is there.

So it added a little bit of cost because those new systems are more expensive than the legacy ones, but you've seen it more than pay-for-itself in the netbacks. We're still taking a pretty conservative tactic, hence so, volatile, that I don't want everyone to think that we're going to be at 140% of NYMEX all year.

I just don't -- I don't think at this point in time, that's a reasonable prognosis, though, who knows. I'd say, though, that the Williston peaked out at about 1.5 million barrels. Whatever the baseline is going to be, when curtailments and everything shut-ins, all the stuff are taking place, it's going to be a lot lower than that.

It has 900,000 barrels a day of pipeline takeaway alone. And so I see a system that is built off for a much larger production base, and it will be many years before it's maxed out again, which means, generally speaking, that net pricing in the basin is going to be really, really good.

And I think that, that is something that I would not have said coming -- I would have expected multiple years of tightness, frankly, coming into 2020. So it's been a puzzle -- it's a good thing that it's come out of a pretty bad time..

We have reached the end of our question-and-answer session. So I'd like to pass the floor back over to management for any additional closing comments..

Yes. Thanks, Jesse, and thanks, everybody, for dialing in this morning. We look forward to speaking with many of you over the next few months on the virtual conference call or NDR circuit. We've got pretty good -- at Zoom has a management team here over the last couple of months and look forward to speaking to you in some venue sometime soon. Thank you.

Jesse, will you please give the replay information at this time?.

Absolutely. Ladies and gentlemen, this does conclude today's conference call. To access the digital replay of today's event please dial 877-660-6853 or 201-612-7415 and enter access code 13703183. We thank you for your participation, and you may disconnect your lines at this time..