Greetings and welcome to the Northern Oil and Gas Second Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] Please note, that this conference is being recorded. I will now turn the conference over to our host, Mike Kelly, Executive Vice President of Finance. Thank you. You may begin.

Thank you, Diego, and good morning, everybody. We're happy to welcome you to Northern's second quarter 2020 earnings call. I'm joined here this morning with Northern CEO, Nick O'Grady; our COO, Adam Dirlam; CFO, Chad Allen; Senior Vice President of Engineering, Jim Evans; as well as Northern's Chairman, Bahram Akradi. Our agenda for today is as follows. Bahram’s going to kick things off, and then I'll turn it over to Nick and team to provide their state-of-the-union comments and recap our second quarter. After that we will 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 now hand the call over to Northern's Chairman, Mr. Bahram Akradi.

Thank you, Mike. Good morning. I wanted to lead off today's call to deliver a very clear message on Northern's vision and what shareholders can expect from the company moving forward. In order to properly frame this, first, I would like to reflect on the progress that Northern has made over the last two years. Our net debt to EBITDA was nearly 7x at the start of 2018 is now only slightly above 2x. Our production growth has increased more than 2.5x over the same period while we have posted the very highest corporate returns in E&P space. When you review Northern's second quarter, the company generated meaningful cash flow, and we continue to reduce debt despite unprecedented industry challenges. We believe our approach for the oil and gas business is unique in both its strategy and its success, and this was evident again this past quarter. As we look ahead, our Board and management team are committed to making it abundantly clear that Northern's financial health is a strong and our business model is sustainable in the long run. Our goal is to build a multibillion dollar E&P company, a company that will have a further slight balance sheet with leverage that is 1x EBITDA or less. You may ask, how do we intend to do this? Our playbook consists of two major pillars. One, we will grow our cash flow by investing in high return assets, and two, we will continue to strengthen our balance sheet by reducing debt in terms of the specific actions you can expect us to take, it will be continuation of what we have done in the last two years where every move we made not only grew the company, but strengthened the company by paying down debt and taking advantage of opportunistic…

Thanks, Bahram. All right. Let's get down to it in five points. Number one, the second quarter was one of the most volatile in decades, but it should mark the bottom. Production, differentials and commodity prices have already dramatically improved compared to Q2. Production curtailments and deferred completions disrupted by production by an average of about 40% of potential production in 2Q, and peaked in June at nearly 57% of our volumes expected in a normal environment. These issues are beginning to slowly ease and we project a steady return of our volumes to sales throughout the second half of 2020. The crude price is up sharply in the past quarter, we are supportive of these moves by our operators. As we have discussed in the past two quarters, we have appreciated the rational behavior of our partners, and the moves taken in the second quarter to curtail volumes allowed us to capture hedge gains and now earn much higher margins on those same barrels. These gains add up to tens of millions of dollars at the current strip that could have been squandered. We expect, assuming supportive pricing to see curtailments, shut-ins and completed wells not turn to sales slowly, but steadily come on line throughout the remainder of the year. Ultimately, we expect completion activity to resume at a more robust pace. Number two, we expect logic and common sense to prevail as it pertains to the Dakota Access Pipeline, but if that doesn't come to fruition, the Bakken is still set to thrive. In regards to the pipeline, we believe cooler heads will prevail. The legal case against it is and always was weak. But in politically charged times, it is always difficult to predict the outcomes in such cases. Whatever your political beliefs, the solution without…

Thanks, Nick. From an operational standpoint, activity levels have certainly fallen to historic lows in the Williston Basin. But in an environment like this, Northern's competitive advantage is most apparent. Through our active management during the second and third quarters, we have been able to high-grade our wells in process and inventory, which is continuously being prosecuted through ground game acquisitions and non-consent process, wellbore and anchorage trades as well as other initiatives. As we recently announced, the opportunities available to us have never been better at the ground game level. Operators have retreated to the core in order to develop some of their best inventory in a depressed price environment. So our basin-wide activity has slowed to just 10 rigs, it is through our ground game acquisitions that we're able to increase our exposure to the best areas and best operators where the wells are still economic inclusive of all costs. By doing this on a real-time basis, we have been able to adapt to the changing environment and increased Northern's net activity to set up one of the strongest lists of wells in process in our history. As noted by one of our acquisitions announced last week, even in these unsure times, we can adapt if necessary adjusting for potential Dakota Access disruption in our economic analysis. Through the second quarter and first part of the third, we have signed up or closed on over 850 net acres, 0.7 net producing wells and 4.1 net wells in process all while staying within our stated budget for the year. As our guidance suggests regarding curtailments and well completions, we expect curtailments to readably ease through the end of the year. During the second quarter, most of our operators heavily curtailed their volumes and as we moved into the third…

Thanks, Adam. I have a few highlights go over this quarter, starting with a quick summary on Northern's financial performance. Our production decreased 32% year-over-year to an average of 23,804 barrels of oil equivalent per day. Production was significantly impacted by curtailments, shut-in production and delayed development plans by our operating partners. We estimate that our second quarter production was reduced by approximately 16,800 Boe per day as a result. We've given production guidance based on the ramp we expect from curtailments. We recognized particularly in the third quarter, these estimates are below Wall Street estimates, which are challenged by the fact that we did not give prior guidance. However, it's worth noting that even versus consensus production estimates due to our strong hedge position, this would have little impact on our cash flow estimates. We estimate the delta will be less than $4 million at the current strip. Oil differentials were $10.60 during the quarter, which was due in part the poor in-basin pricing and storage constraints as we move through the quarter. In the current environment, we would expect oil differentials to narrow substantially for the remainder of 2020 and we are seeing that as we speak today. Gas realizations were significantly impacted during the quarter much like we saw in the oil markets. Natural gas and NGL prices were affected by physical storage constraints and higher processing costs, which created a negative pricing for NGL products as demand collapsed due primarily to the COVID-19 pandemic. Lease operating expenses for the quarter came in at $26.6 million, down 29% sequentially, driven by a 46% reduction in production volumes, partially offset by increased processing and saltwater disposal costs. We've already experienced further reduction early in the third quarter and expect to continue to see basin-wide cost savings during the…

Thanks, Chad. Diego, if you wouldn't mind queuing up the Q&A, we'd appreciate it.

Thank you. At this time, we will be conducting your question-and-answer session. [Operator Instructions] Our first question comes from Derrick Whitfield with Stifel. Please state your question.

Thanks. Good morning, all.

Good morning.

Good morning.

Hi, Derrick.

Hey. Perhaps for Nick or Adam. Regarding your comments on the ground game heating up, could you offer some additional color on the degree of deal flow you're seeing in current seller expectations?

Yes. I mean the deal flow that we're seeing is has been relatively consistent with what we've seen in, and call it, the past 12 to 18 months. I think even with the activity levels dropping, you've got a handful of both non-operators and operators that either don't have the ability or they've got a mandate in certain circumstances where they're unable to invest in OBO or non-operated working interest opportunities. And so what we're seeing is a lot of the operators with the 10 or 11 rigs that are going right now, retreat into the double bullseye of the basin, but you've got eight, 10 AFEs maybe being validated at any given time given the development that's going on, and no one wants to participate in those. That creates the opportunity for us to quickly evaluate these with the engineering type curves that we have ability to move quickly and close these out. And the only other thing I'd add is in times like this, certainty to close is even utmost importance relative to valuation and with Northern's balance sheet and track record, we can offer that to both our non-operating and operating partners.

The only thing I'd add Derrick is that, we have continued to up our own internal hurdle rates and by dramatically. And so in times like these and certainly early in the second quarter, we may able to execute on these at higher returns than we've ever done before with all the optionality of upside to commodity prices. And so in the deals that Adam has prosecuted in the last few months, what we underwrote is already significantly higher – or should I say, the returns are likely to be significantly higher than what we underwrote just because we have the convexity on oil prices.

That's great. Great color, guys. And then shifting over to DAPL and your potential exposure, if we were to receive an adverse ruling in the coming months, could you speak to the degree of exposure you have in the ballparks more than fine. And then offer some commentary on the current dynamics of available rail takeaway and how much is immediately available for dispatch?

Yes. So let's start with the last part first. There's 700,000 barrels a day plus of idle rail capacity in the basin. So there's plenty of takeaway. The thing with rail is pretty simple, which is that there's term rail and then there's spot rail, spot rail is very expensive. Term rail is sometimes about half of what that is. And let's just be clear here that the Dakota Access Pipeline is not a cheap form of transportation. With Gulf Coast oil prices where they are today, it does not compete with in-basin pricing. So it is among our more expensive forms of transportation. The differential on DAPL today is a high, $4.1 net and that would be – that's before you include the gathering costs of getting the oil to market. So relative to rail, DAPL was a very cheap alternative in 2017 when Gulf Coast spreads were $7 versus WTI. MEH was less than $1 yesterday. And so in terms of its overall impact, it's going to be relatively muted. In terms of our own production volume, I would say it's relatively low to the overall period. It does shift from time-to-time, but I would wager to say is less than 20% of our aggregate volumes on a normalized basis. Our largest operator doesn't transport anything to DAPL. The only thing I would tell you is that the biggest purchaser of oil in the basin, very few operators have firm transportation on pipelines in general. Marketers are the purchasers of many of those barrels. And so where they ultimately end up, they go to the terminal and they're resold. So some of those barrels maybe resold so it's a difficult question to answer. However, what I would tell you is, I think, based on the current Gulf Coast…

And the only other thing I'd add to that just from an underwriting standpoint, I mean that's the way we're viewing this is in a worst case scenario. We alluded to it in our prepared comments a little bit, but the acquisitions as well as the inbound kind of organic AFEs that we're looking at – we’re looking at it through that lens. So should this get resolved in a beneficial way? We'll see an uptick in terms of rate of return.

Yes. And finally, just to Adam's point is that these numbers I'm discussing are assuming that the pipeline has shutdown and nothing else ever happens. My guess is the industry is dynamic and with an arbitrage that would be opened up, you will see modifications, expansions and other things that will go in over time to add additional capacity in other ways that is competitive on a cost basis.

That's great, guys. I certainly agree with your views and thanks for your time and response.

Our next question comes from Duncan McIntosh with Johnson Rice & Company. Please state your question.

Good morning, Nick. Quick question on the guidance for kind of 3Q and 4Q, pretty wide ranges there. Just wondering, what are some of the levers that you all would pull or I guess maybe hurdles you'd have to get over that would kind of push you towards the upper or lower end of those ranges?

So if you look at our stated guidance Dun, we're only assuming about 3.6 net turned in lines through the remainder of next year. So the vast majority of the volumes returning is just the pace of curtailments coming back on. That's as a non-operator, that's the hardest thing for us to predict, I would say based on public comments, we've seen from the operators and early results in the third quarter, we're very encouraged. But it's early to tell and especially given how tenuous the recovery in oil prices are, we are going to be as conservative as we possibly can. Given that we have 26 plus wells in process today prior to some of the closings of these ground game deals, there's also the potential that more wells turned in line especially if prices remain relatively robust. And so that can have a dramatic impact on those numbers. We've really just taken with what we know. As you guys all know, we live and die by our engineering analysis. And so we have to take the most cautious approach. But the range is purposely wide because the number of outcomes is equally wide and so we will update you guys accordingly as we know more.

All right. Thanks. And then kind of along the same lines, but just going forward a little bit into 2021. The 40,000 a day looks really good relative to consensus and even the lower end as well. But my question is more on the CapEx side and how it sets you up longer term for 2022, not necessarily looking for numbers, but how you're thinking about the spend? I'd imagine there's going to be a lot more on the ground game based on your comments this morning, and just kind of how the spin next year sets you up for 2022 and really the longer term strategy of Northern Oil and Gas?

Yes. I mean, I'll let Jim set that up, but I would just say from – obviously, as you've had a lower activity levels, our maintenance capital call is declining from where it was. And I think going forward from there on out using that sort of range, we could expect to spend a very similar amount of money and sustain those volumes. I think it will depend obviously on the opportunity set and the quality of those wells and the timing. What I would say is, as we gave that sort of early look at 2021, it's important to understand that the timing of that spend is as important as ever. So as I mentioned in my prepared comments, if you spent towards the higher end of the range, it would mean likely that there's more organic activity that develops throughout 2021. What that would mean would be more volumes and more cash flow and more production towards the back half of that year given the timing of spuds. And so that ultimately will then somewhat reduced the capital column in the following year. I'll let Jim talk about it a little bit because he's done some good analysis on this.

As we've kind of mentioned, we expect to exit the year with about 30 net wells in process. And so with the curtailments coming back off towards the end of the year with three net wells in process, we think that's an enough well that could hold production flat at roughly 40,000 barrels a day next year. A significant portion of that capital is already spent on those wells. So if we were just shooting for a one-year goal to hit 40,000, next year, we'd be at the lower end of that capital spending. But obviously, we're looking more at kind of a three, four-year outlook. And so in order to maintain those barrels in future years, we need to spend a little bit more in the back half of 2021 to set up 2022 and 2023 and beyond that. So in that scenario where we're trying to hold production flat at 40,000 a day over the next couple of years, we'd be at the higher end of that guidance range on CapEx.

And I'd say from a sustaining capital perspective, again subject to timing of when the money spent, you're talking somewhere between $200 million and $240 million as a consistent maintenance number for the years beyond that, maybe less. It just depends on the how flush the production is at any one given point in time.

All right. Thank you, all.

Our next question comes from Jeff Grampp with Northland Capital Markets. Please state your question.

Good morning, guys. I was curious how you're visiting or thinking about potentially revisiting the dividend conversation. I know, obviously, the markets have kind of flipped everything around, but is there a leverage goal, commodity stability level that you guys might want to see before revisiting that or just any high level thoughts would be great?

This is Bahram. I'm going to take this one. Obviously, as I've mentioned multiple times, our focus is to make sure the entities are strong and we make every move to make sure the company will remain solid. The question for dividend is that our goal has been to make this company a dividend paying company, but however, we want that dividend to be sustainable. So rather than picking a exact time that we could say we want to resume the condition at which we want to resume paying dividend is when we have visibility to the stabilization of the oil prices long enough that we have the ability to put in strong hedges for the following years as well as balancing debt to EBITDA a bit more, and then combination of these dynamic things will allow us to get to a point where we believe we can start the dividend and maintain it in a sustainable fashion through any commodity pricing. And that's what this management and the executive members of the board have done so well with this company as you can see right now. I think it can soon. It could be early next year, where we could resume into some form of a dividend. But it's really a function of the conditions coming together, allowing us to run a incredibly safe entity and a solid movement to dividend where there's never a chance that we have to pull that dividend back.

Got it. I appreciate that Bahram. And for my follow-up, it sounded like you guys were maybe a little bit more constructive on out of basin opportunities then you've been in the past, which is kind of curious, how you guys would evaluate the framework in terms of – I don't necessarily want you guys to name, what basins are doable versus not, but kind of the framework for what that would need to look like to get you guys to pull that trigger?

Jeff, it's Nick. What I said in my prepared comments is pretty succinct, I think which is that we've told people we get asked constantly, and the reason that we're discussing it now is that we've looked – we've been looking for two years and we don't even really have to look that the opportunities come to us. We added it all up and it's over 50 things that have come our way. And what I'd tell you is that we're just driven by economics. And so if we can look at our entry costs, full cycle return, have full confidence in underwriting, it shouldn't matter what basin you're in. But what I would tell you on the latter part is that that confidence in that data that we have is really hard to match. And so it's made for a very high bar. I would say in a lot of the active basins in the country, you've had a lot of funding money going around, which has really meant that regardless of how good wells are in any given basin, when you added it all up, it didn't earn a return on capital employed. And what I was suggesting is that it maybe that we're entering a time now where it's really just, does it make money or not, and the bloom is off the rose. And in that case, these deals may start to compete. And so we'll have to see how it plays out. But again, I'd say that the concept of us going somewhere else and testing out some Tier 2 area is very low. If we're going to find something, it's going to have to check every single box because our appetite for risk is about zero. But I do think there's no reason that this business model can't work everywhere. I think I've been consistent in that, and I think everybody here feels the same way. It's just that it has to be done the right way. And you can't – we've seen plenty of public companies who felt that they needed another arrow in the quiver and spent tons of money to jump into some other basin only to spend way too much money and never earn a return, even if that basin itself was okay. We're not going to do that. What we're going to do is make sure that every deal we do basically adds value day one, not just to make some symbol, we're about making money here. And I'll leave it at that.

Got it. Appreciate and thanks for the time guys.

Thank you. Our next question comes from Neal Dingmann with Truist. Please state your question.

Nick, my question is you all have been pretty, I guess, probably for you, or one of the guys there. You guys have been very nimble on looking at maybe going non-consent and then taking that capital and going elsewhere? I'm just wondering going forward, will that – are you going to continue to sort of use funds that – and do that to really, I guess use funds most prudently?

I mean we talk about return on capital employed and rate of return until the answer should be obvious. I'll let Adam talk in a second, but I'd say that if we have an organic well that is wishy-washy in terms of its return will not consent it because we know we have 10 deals behind it that will earn our cost of capital and so we're just capital allocators and that's what drives every decision we make. Adam…?

Yes. I mean, you've got operators that will drink their own Kool-Aid even in an environment like this. And so we look at the ground game and the organic AFE is kind of a little bit one in the same, and so we're taking a look at what we're getting on an inbound basis on a daily basis and then we're proactive in-sourcing other opportunities getting in front of the drill bit as well as the inbounds on a deal flow standpoint. And so we kind of put all those together, high-grade everything and then that's what we've been able to do. And so we've been able to pick up a handful of ground game deals in the third quarter and kind of late Q2. We non-consented a handful of wells and then we've also been able to kind of trade out other kind of tweeners in the meantime, and that's effectively set up for one of our most impressive kind of wells in process with the best operators, best rocks. So certainly encouraged in that regard.

Yes. You go on one of my standard ramps, one of the things that I think we find the most frustrating is that people view us as some sort of ETF on the Bakken that if Continental or Marathon or Conoco or whoever and their rig count and their activities going one way or another that that dictates what our capital and what our outlook is going to look like. And that's the farthest thing from the truth. We're no different than any portfolio manager, just because one sector is going down doesn't mean that your portfolio has to if it's structured correctly. And so what our moves in the last few months to show you is that if the economic returns are there, we're able to add activity that may not correlate with some passive entity sitting there waiting for those things to happen. That's not what we're doing. It's not what we've ever been doing. Our growth rate could meet or exceed the basin, even with 10 rigs active. We continue to add net wells and process to a near record. And so I think for anyone who thinks that they can look at other company's activity as a barometer to how Northern is going to perform over time are wrong. If you look at our own growth in the last several years, it's had almost no correlation to those of our other operators even our production net to any one operator has not shown any correlation, and that's going to continue as long as we're here.

Got it. And my second question for Bahram. Bahram, you've been active in recent quarters buying shares back. Certainly, you perceive as undervalued and I would agree. But my question is, first, how strongly do you still believe that these are undervalued? And then I'm just thinking. Secondly, is there something else you could do with that capital within the company besides buying shares such as potentially taking a more active position with a deal or something like that that would actually benefit potentially the company even quicker and more material than they would just find the shares?

Yes. I think if there was a need to provide cash to the company, me and the rest of the large shareholders would do so. At this point, the company has been able to do that. Obviously, I have been acquiring shares for four years and haven't sold any, so I certainly believe that the company is undervalued from the standpoint that we aren’t getting – never really have gotten any value for the intellectual knowledge and capabilities, the data of the company and the performance of the management. The price is always sort of the, hey, what's the SEC value of the wells and reserves. They're really not giving any credit to this amazing management team and the board. So we will do that when necessary. I do want to emphasize that I think 2021 can be an incredibly amazing banner year for NOG in the sense that – while we have been producing positive cash flow this year, and unfortunate for me being on a any sort of a call of as a CEO or the Chairman of a company, I hate to see any misses of any kind. We're very competitive. We want to make sure everything is a win, but I have to look at it in a fair perspective. What's really happening is we have invested a substantial amount of cash into wells. We have a lot of money invested where it actually is not producing right now. So 2021, as these guys have tried to highlight has the potential to have a significant amount of production. If the oil price has come up through the $55 or $60, any reasonable range, obviously, the operators will open the faucets and start kind of letting the oil come out. We have invested the money already. We will have massive production. And like Jim said, the money we would spend before the future year. So I think we can come into 2021 where the spending is a moderate, but the production, the returns and the cash flow will be significant. So patience is the virtue here. Unlike many other company, we don't have any guns to our head. We're still going to be in a positive cash flow situation in this company under any circumstance. So we have the staying power to wait and see when that moment of time turns around. And then all of that oil that is being saved in the ground right now will come up at the prices that would be more lucrative for us. So I'm very, very, very bullish on this company probably more than I've ever have been.

Very good. Thanks Bahram. Thanks team.

Thank you. [Operator Instructions] Our next question comes from Phillips Johnston with Capital One. Please state your question.

Hey guys. Thank you. Just one for me as a follow-up on the topic of dividends for either Bahram or Nick. About seven quarters ago, I asked you guys about the idea of variable dividend, given your business model and just your attractive free cash flow profile. I'm sure you saw a couple of days ago that two larger E&P companies laid out a strategy of returning capital to shareholders through what's essentially a base plus variable dividend strategy. My question is once we get back to an environment that Bahram outlined where you're able to return free cash flow to shareholders. Does it make sense for Northern just from a conceptual point of view to adopt a base plus variable dividends strategy? And if not, what kind of flaws or drawbacks do you see that type of payout strategy other than the fact that it hasn't really been done before in the E&P space? Thanks.

Yes. Phillips, so I say that to be intelligent, you have to be willing to change your mind. And I think that I kind of shown some skepticism to that in the past. And what I'd say is that I saw what Pioneer announced, and I think it's interesting. I think it's something to take it, especially given that it's been quite a volatile time over the last several – it feels like forever now, but really since 2014, it's been constant volatility in the oil and gas sector. And so I do think that that idea has merit of a small base dividend and then an ability to go through. I certainly think that I think as Pioneer also alluded to it, we get pressure oftentimes to buyback stock. And it's proven that companies are really, really bad at that. And who's to say that we'd be any better. I do think that you always have to have that arrow in your quiver. However, I think that ultimately, the most important thing that we can do is deliver a total return. And I think that's certainly that adds flexibility. I think my skepticism on that in the past has been, will the market ever credit you for that variable dividend? Will it give you consistent value and things like that when it's going to vary from quarter-to-quarter and could it create more volatility? I think, we need to do some more work on our end on that, but I certainly think that we're open minded to the concept.

And I want to add on, so I'm committed strategically to get this company to a point where we can pay a dividend as soon as it's practical. I also believe that in an environment where I believe in the future, cost of capital is going to continue to come down across the board for almost any business, returns are going to be challenged for most businesses. It's important to not get yourself in a situation where you would have to borrow extensive money. So we're going to chip away as long as we can at this – it's kind of 8.5% bond. And hopefully at some point, I expect to be able to completely eliminate that. Whenever that's done, I think this company can have a clear, clear path for a sustainable dividend on an ongoing basis, whether or not, we do a hybrid where a portion of it is fixed and a portion of it is variable based on the cash flow of the company, but Nick and I and the rest of the Board will come up with strategies. But know for fact that we are thinking already about when and how we can resume the dividend for our shareholders.

Does you all still have sometime to see how it works out for these guys in the meantime? Thanks guys for the color.

Yes.

Thank you. Our next question comes from Scott Hanold with RBC. Please state your question.

Thanks. Hey, Nick. I appreciate your commentary on how not to use other Bakken participants as a barometer for Northern. Obviously, you guys have proven that's the case here recently. But as you guys look forward and understanding that E&P companies obviously are being a little bit more disciplined with Captor, at least that's the intent right now, and obviously the potential risks over DAPL and whatnot. I mean does that – how does that change your strategy? Does that change your strategy? Does that make your beef up your ground game a little bit more and certainly then obviously have – and you talked about the appetite or at least evaluating other opportunities outside of the base and that have come to you. But how does that change your strategy going forward considering other operators are being a little bit more tied with their wallets?

Yes. Scott, I think that's actually a very prescient in the sense that that's exactly how we think about it, which is that it's not like we sit here with some amount of money that we want to spend and then we go out and spend it kind of regardless. Really we have a hurdle rate we want to meet, and if we can find opportunities under that hurdle rate, whether they be organic or through the ground game, then we'll do them. And in times like we've seen recently where there's almost no activity and we have additional monies available to us, and those hurdle rates popup and we can execute on them. And so I do think there is the potential that that becomes a bigger part. It also could be that we start to build up additional inventory in areas that are going to be active. But what I would say is that, we want to recycle our capital to the highest return opportunities wherever that might be. And so if you – what I would tell you this is that the rates of return and positive capital to enter any of these assets tends to be fluid. So if DAPL is shut forever and differentials go up modestly, you'll just see that reflected in the cost for every acre you purchase and the return will wind up being quite the same no different than. If you look at E&Ps return on capital in a $50 world versus $100, there's not much difference because the cost of entry changes accordingly. And so what I would say though is that we have never had so many and I would say very varied opportunities in front of us. So from a risk to being able to reinvest our capital into return into things that earn our returns, I see is a risk that we're not terribly worried about. I don’t know Adam…

Yes. I mean the only other thing I would add is the capital discipline push has limited the number of rigs that are running, and what operators are doing now rather than running around an HBP in acreage in order to most efficiently develop their units, they're developing a significant majority of them all at once. And so what that translates into from a development standpoint is significantly more AFEs validated and that cash call going significantly higher. And so that has created an opportunity that we've seen both in North Dakota as well as elsewhere creating an opportunity where we potentially have the ability to step into these units that are being developed in totality. And so then the optionality in terms of deal structure gets wider and whether you're picking it up on a wellbore only basis, whether you're picking up the acreage, it doesn't necessarily matter as much because you're developing the entire unit, right. And so between the capital call, the push to development and then the chunkier interests that we're seeing based on the actors that are out there that don't have the ability to deploy the capital is all dovetailed very well under our strategy.

Great. Appreciate that answer. On your view on hedging going forward, I mean, to keep leverage at, I think you all stated at 1x kind of range and maybe even lower. I mean that's certainly a pretty high bar for E&P companies, especially with a lot of your peers. And would you envision becoming much more active on the hedge front, maybe even get as much as being more a 100% hedged as you go on these years to help protect that balance sheet and allow you to pay the dividend more sustainably?

I certainly think it's possible. I think we got to get there first, obviously. And I think that – I think our philosophy is, when we underwrite any dollar we spend, we want to make sure we are in the return, we underwrote and that's really driven our decisions and that's not going to change. I would say as we get larger, the flexibility you get from your lenders in terms of how, we already have seen a material uptick in the last three years twice now of our ability to hedge. Thanks to the folks at Wells Fargo. When we redid our credit facility in November, they gave us much more flexibility and we're directly benefiting from that. The moment the credit facility closed, we were able to hedge an additional 10% of our volumes and for much longer duration periods of time. One of the reasons we're so well hedged next year. So I think as our debt metrics continue to whittle away, I mean even at the strip today, we see them improving materially over the next two years just from the cash and that we’ll generate from some of the moves we've made in the last three to six months. But what I would say is, I think, at least for – as it pertains to my policy, to the extent that you underwrote something at a return that meets your hurdle rates, and you can hedge that, and you should because so much capital in the space has been destroyed by people who spent money based on certain assumptions and those assumptions tend to change over time. That being said, you never are going to really be able to hedge a 100%, maybe you can for the first year or so. But at a PDP level, there is some risks you're creating for yourself as you go too far out. And you also, obviously from a development perspective, if you're hedging future development, yet you cannot hedge those costs. Those well costs may change. So oil, if you hedge at $60 in 2022, and then oil winds up being $80, and you hedge wells, you thought you were going to be drilling those that the cost of the well might be significantly higher from inflation, so you've got to be somewhat careful. But I do think our strategy will be continued to add duration and consistency to those hedges, particularly when you're paying fixed obligations.

Appreciate that. Thank you.

Thank you. There are no further questions at this time. I'll turn it back to management for closing remarks.

Great. Thanks, Diego, and thank you everybody, for dialing in, in today's call. Have a great weekend.

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