Greetings, and welcome to the Northern Oil and Gas First Quarter 2020 Earnings Conference Call. 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. Chad and 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 of, 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 one of our bank tranches matures. Additionally, 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. 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 stopgap 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 non-operator, 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 is 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 saw 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 improve dramatically for the next several years as those take place. In the short term, it will be volatile, but the future for our net backs 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, 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 is 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 one 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, 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 delay 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, we elected to participate in 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 renegotiated. The conversations that we've had with our operating partners indicate that 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 by 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 costs 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 non-operated working interest in a handful of their own wells, where we mutually agreed 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 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 of 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 has 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 drilling and completion capital and $21.1 million of total discretionary acquisition capital, inclusive of acquisition drilling and completion. 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.

Thanks, Chad. Mike, Nick, Adam, and Chad have done a great job articulating our results. Accomplishments here at NOG speak for themselves, despite unprecedented challenges in the energy sector. We have stayed on track to generate free cash flow, and we are set up to significantly increase free cash flow in the second quarter and beyond. As we move ahead, similar to the last few years, every move we make will aim to: 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 ago, 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 four 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.

The first question comes from Duncan 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 the 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, the strategy of the company, we are well insulated and sitting in a great position to study, understand, and pull the trigger when we see opportunity. So we are looking at every opportunity out there. However, as I've mentioned in my prepared remarks, in the events we find something that makes sense, it would have to be in the structure that enhances the balance sheet of the company going forward and is consistent with the philosophy that we have put in place over the last two years. Less debt, more equity, more cash flow, and play the game as long as it goes. 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. Could you provide insight on when operators might consider increasing volumes again and possibly resuming field activity? Is it largely influenced by headline pricing, or is the realization in the basin the key factor? Additionally, from a timeline perspective, what do you envision for the Bakken over the next three to four months, especially given the current uncertainties?

Yes. I can go first and Jim can fill in 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 things 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 leasehold 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. 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 a well proposal standpoint, that are still kind of going; most operators have either renegotiated or satisfied their rig commitments. And so I don't necessarily anticipate a whole lot of new well proposals 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. Some operators have lower operating costs 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, this is Nick. I think we need to consider a few factors, including the absolute price of oil and in-basin pricing. In April, when differentials were between $10 and $20 depending on the methods used, that likely influenced decisions as much as the actual price of oil. This situation will vary; some operators may have contracts that protect them from that. Even with good Gulf Coast pricing, the discount can affect things, especially since volumes are connected to the Gulf Coast. The absolute price of oil is important. From my perspective, and I believe my team agrees, the markets in North Dakota appear to be imbalanced due to the current shut-ins, which might be related to DAPL contracts and are trading at a premium to WTI; I’ve never encountered that before. This suggests that the shut-ins are effective. If WTI prices rise again, there could be some instability in the early months as operators work to return necessary production to the market. In-basin pricing points might fluctuate as they aim to balance that and bring volumes back. Like any recovery, it will likely be somewhat unstable.

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 frequently discuss risk-adjusted returns. It's crucial to note that buying our bonds at a discount yields significant returns. While repaying your credit facility enhances liquidity, it’s also important to keep a capital reserve for potential recoveries so you can capitalize on those opportunities, which may yield returns that surpass the 30% threshold that the bonds provide in the future. It’s about finding a balance. We have strong stakeholders and are exploring creative strategies to leverage these bonds, which we have utilized effectively so far. However, as I mentioned last quarter, it’s crucial to balance immediate opportunities with future considerations. We often get inquiries about stock buybacks, and while there have been times we've been disappointed with our stock price, many companies have repurchased their shares at higher prices and now face declining stock values. Thus, it’s vital to be prudent with every dollar spent, rather than just chasing the highest immediate return. It's essential to think long-term and prepare for the unexpected. Chad, do you want to add anything?

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, it's still in the early stages. We're currently experiencing a bank redetermination season. Most companies, when prices are low, tend to hold onto their producing assets because they need the cash flow more than ever. They usually only sell when they have to, often due to pressure from their lenders or covenants. We're just starting to see this happen, and I believe the range of opportunities will be broader than I initially expected. To be frank, when oil prices are at $24, the key factors are whether you're hedged and what your overall discount levels are. Many strong companies may find themselves in challenging situations with valuable assets. At today's pricing, very few undeveloped assets nationwide will provide an adequate return, so they currently hold little value. While I doubt the accuracy of the pricing forecast in two years, we have to evaluate based on it. Our focus needs to be on producing assets, taking into account any current curtailments or obligations they have, and assessing their value accordingly to create mutually beneficial scenarios. Since banks will likely possess many assets in this downturn, as is well-known, they'll have to consider their own liquidity and how long it will take to recover their losses. We hope to be a supportive partner in those discussions.

Our next question comes from Phillips Johnston with Capital One.

Just a follow-up on the curtailments. Do you guys have any estimate as to how much of your May production is either shut-in or curtailed?

Yes. We're still receiving information. The operators haven't provided us with detailed data on which wells will be affected or anything similar. So we are still in the early stages of understanding this. We noticed a significant amount in April, and we anticipate more in May. However, we don't have the information yet to make any predictions.

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 how they're looking at things.

Okay. Has Slawson been as aggressive as Continental in terms of shut-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 the cash outlay for the $90 million of senior secured notes that you guys repurchased?

A portion of it was done with the preferred stock in January, but I don't have the exact number right now.

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 mentioned in your prepared remarks. I want to dive deeper into the guidance you provided, which suggests a forecasted EBITDA of $350 million to $410 million. Can you explain how you view the operators' preferences? You mentioned Slawson and Continental, among others, some of which are still significantly curtailing their operations while others are not. Based on your guidance, could you share your insights on what you hope to see in the next few months, taking into account the varying price scenarios?

Yes, I think it's a bit ironic that for most of the year, the Williston has been limited in capacity, which has led to higher Lease Operating Expenses since wells were not operating at their full potential. We incurred operating costs even when the wells were not running optimally. However, I expect a significant reduction in LOE as these wells are curtailed, meaning less water hauling, lower electricity costs, and less work on the wells. There will be a delay in seeing these benefits, which will vary by operator. We're taking a cautious approach regarding the overall impacts. For the producing wells, the marketing agreements for the barrels will play a crucial role. Generally, it's likely that the producing barrels that aren't curtailed will be those fulfilling the most favorable contracts. This impacts net backs and pricing in the basin, especially when prices are low. Recently, in-basin pricing has rallied, so I anticipate better pricing for barrels sold in-basin than we would have predicted a few weeks back. The key questions are how quickly costs will decrease and the realized gains from our hedges. There are scenarios where we could actually see increased cash flow, even if oil prices fall below $37, potentially yielding more than if the wells were operational. Ultimately, it's a combination of these factors that will determine our overall cash flow levels. The values of our hedges are quite stable, and the market is adaptable, meaning if prices rise sharply, we could quickly return some volumes to sales, often within weeks. I believe the range we find will be accurate.

Okay. Good details. And then second, just for Adam. Adam, I think you mentioned that you participated in just 37% of proposals. I'm just wondering if you could talk about the required rate of return and how that level compares to previous quarters.

Yes, I believe it emphasizes the non-operated business model. We are able to adjust our pace more quickly than many of our operating partners with commitments. When we assess well proposals, we consider various scenarios regarding the rate of return at different price points. Then, Jim and I, along with our team, collaborate to gauge the operator's mindset and actions. Many of the wells we opted into around late March and April were chosen because we were confident they would be drilled soon. However, if low pricing continues, we are still comfortable with our projections and believe they will yield an acceptable rate of return based on our analysis.

Our next question comes from Jeff Grampp with Northland.

I was looking at Slide 20 of the updated presentation and noticed what seems to be a significant improvement in well performance, although we have limited data from 2020. Can you share your thoughts on the sustainability of this performance? Is there still an opportunity to focus on higher-quality assets in the basin that operators are consolidating, or are we perhaps overinterpreting the early data?

Well, I will let Jim discuss the well performance, but I expect that we will see some changes that we did not anticipate. There is some incremental data available, but we usually see these effects after a delay. I believe that from a return perspective, well costs will decrease further. The operators' presentations indicate their well costs, but the AFEs do not align with those figures. However, the AFEs include contingency costs that will likely not be utilized in the current environment. If the wells perform similarly to how they did before, we should expect to see significantly lower costs. Jim, would you like to discuss the high-grading aspect?

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 consisted of 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 a 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 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 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 and 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. 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 but 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 believe the timing we've assessed appears fairly balanced. The challenge we face in accounting for this is that we accrue costs for these wells based on their completion percentage, but the operator might decide to pause, which would lead to adjustments on our end. We aimed to provide a broad range without getting into too much detail. We do anticipate many projects will be delayed until the latter half of the year, which is why we've included a reserve number. This is to ensure we are prepared in case oil prices surge in the fall, leading to an increase in our DUC count. We do not want to give the impression that we are overspending, though I think that scenario is unlikely right now. Currently, we have 27 net wells, a significant figure, especially since 6 have already been fractured and paid. We expect this number to grow throughout the year as the DUC count increases while our well completions remain low. The outlook for the end of the year will largely depend on pricing trends in the fall. If prices rise, some wells might be completed this year; if they remain stable, we may see them complete by year-end. We plan to monitor the situation and adjust as necessary. We have structured our capital with the belief that most of these wells will be turned into sales, albeit some may encounter delays. We will need to observe how things unfold. Additionally, it's important to highlight that the hedge value enables us to benefit from cash flow. Delaying production allows us to conserve it for future, potentially more profitable days. The production we restart in a higher price environment, even at around $35, will significantly outperform if we had depleted production at the start of the year like typical scenarios would in a $40 market. We see this situation as a fortunate opportunity. If we are well-prepared and not facing cash flow issues, which we are not, we will be in a strong position, making it easier to resume growth in the future.

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

Regarding your previous question, I understand that your base production is expected to be significantly higher. There is a general inquiry about shut-ins and the potential for performance degradation. The Bakken has had minimal shut-in history mainly due to winter weather. Could you clarify how this situation is managed and whether we should be concerned about well performance after shut-ins?

Yes. I would say that for wells that are completed but not yet generating sales, this can sometimes lead to a lower initial production rate when they do start selling. However, from the perspective of estimated ultimate recovery, this can actually result in a net benefit, as the well can produce more over a longer period while pressure builds. For reference, the Bakken formation is not a shale; it's made up of dolomitic rock situated between two shales. In traditional shale formations, which are more fractured and porous, water issues can lead to shut-ins and reduced production, which can harm those reservoirs. I want to emphasize that while I don’t like to make absolute statements, the Williston is among the best locations for managing these scenarios. We frequently face shut-ins, and some producers reduce their output on a quarterly basis. Last year, we managed significant shut-ins with minimal long-term effects. Jim, do you have anything to add?

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's 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, perhaps we should change the topic. There seems to be a significant opportunity for you as you enter this cycle. Is there a chance you might adjust your strategies and consider taking on operating positions, or is that still not a consideration?

I believe we will pursue any opportunities that make economic sense. However, the threshold for initiatives outside our core strategy is significantly higher. Our focus will always be what’s best for the business, and we will approach this with great caution. It is somewhat ironic that, despite occasionally feeling penalized in the market, we have noticed that many of our non-operating peers are actually in a much stronger financial position than those who are operating. This may suggest that non-operators tend to manage their businesses more effectively. Consequently, we have not experienced the same level of difficulties in non-operating segments as we have in operating ones. That said, the criteria for any operating business we consider is very stringent.

That's helpful. 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 money available. It certainly is a difficult 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 syndicate 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. 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. 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.

You provided insightful details about the crude market and noted that the gas market seems to be stabilizing. Can you share your thoughts on potential bottlenecks or opportunities related to gas and NGLs?

Yes, we had over 1 billion cubic feet a day of processing capacity come online at the end of last year, which has been a significant challenge for us. The gas has been limiting crude production. North Dakota is expected to reach 91% in the fall. Our oil volumes remain fairly stable, and we're capturing more gas sales as new NGL and gas processing systems are now available. While these new systems are costlier than the older ones, they've proven to be beneficial in terms of profitability. We're maintaining a conservative approach; it's so volatile that we're not expecting to consistently achieve 140% of NYMEX prices this year, and I think that projection is unrealistic for now. The Williston region peaked at around 1.5 million barrels, but any baseline after curtailments and shutdowns will be significantly lower. The pipeline capacity alone stands at 900,000 barrels a day. I see a system designed for a much larger production scale, and it will take years to reach maximum output again, which means that net pricing in the basin will remain quite strong. I wouldn't have predicted this positive shift, as I expected several years of tight conditions leading into 2020, so it's fortunate that it's emerged from what has been a difficult period.

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.

Thank you, Jesse, and thanks to everyone for joining us this morning. We look forward to connecting with many of you in the coming months during the virtual conference call or NDR circuit. We have had a strong management team at Zoom over the past few months and are eager to engage with you in some capacity soon. Thank you. Jesse, could you please share the replay information?

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.