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. 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 is going to kick things off, and then I'll turn it over to Nick and the 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, 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 and 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 the 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 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 a continuation of what we have done in the last two years, where every move we made not only grew the company but strengthened it by paying down debt and taking advantage of opportunistic debt-for-equity exchanges. Going forward, you can expect us to adhere to those same principles. Furthermore, given the struggles highly-levered companies are experiencing in the E&P space, we believe the time to accelerate our business model is now. The opportunity set is impressive, actionable, lucrative, and accretive. I believe the company is well positioned for major success in the second half of 2020 and beyond. One final comment as it pertains to the proposed reverse split stock. I am pleased to announce that we have received significantly more votes than needed in support of this split. Over the next couple of weeks, we will determine the exact split ratios, but our desire is for a high single-digit stock price immediately after the split. The benefits to shareholders of the reverse split are undeniable. It will enable institutional investors who have wanted to invest in our company but have simply been unable to due to internal restrictions against trading stocks for less than $5 each. Two, it will lower our trading costs, and three, it will open the company up for inclusion in additional equity indices. I would now like to turn the call over to Nick. But before that, I want to thank Nick and the rest of the management team and members of the Board of Directors who have been working incredibly hard during these months, and I am forever grateful for what they've done. Nick?

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 our production by an average of about 40% of potential production in Q2, 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, and 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 slowly and steadily come online 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. Regarding 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 DAPL will be a higher-cost one for American consumers and producers alike by rail. Despite what the detractors seem to desire, the oil will not be stopped at all, but rather travel through a more expensive and dangerous method over bridges in the very same areas of dispute. We are prepared in the event it faces long-term issues as we underwrite acquisitions and deploy capital with this mindset, but by no means do we think it is a killer to our business. However, it will add modest costs to our differentials and, until such resolution takes place, will slow the pace of activity. The Williston is full of opportunity; we are seeing the best sets of wells we've ever had in process. The Williston survived prior to 2017 without DAPL, and it will survive and thrive without it now, but we hope it will not come to that. Number three, we remain committed to paying down debt. We have continued on a dual path of growing our business where there are attractive returns while continuing to de-risk the balance sheet. We have been doing this consistently since the rebuilding of this company two years ago. Through recently announced deals both on the debt and acquisition fronts, we continue to strengthen the company. We have several other ground game deals in process, and if completed, we will update you accordingly. When completed, our tally year-to-date will cut our senior notes by over $124 million and cut our revolver by an additional $12 million. As we reduce debt through next year, we can also focus on moves to extend maturities, increase liquidity further, and simplify the balance sheet, all in good time. There is a fine line between doing things when you can and when you should, and we will continue to reduce risk. We also continue to bolt-on core net inventory at the ground level, wellbore-by-wellbore and acre-by-acre, which brings me to my next point. Number four, we are confident for the remainder of 2020, and we are set up well for 2021. We currently forecast our capital spending, which was down dramatically in the second quarter, to be well within our stated guidance, even though our ground game has been active and continues to add to our wells and processes inventory. We have been encouraged by our operator's recent public commentary regarding their shut-ins returning to sales, and this could mean a path faster than we are modeling. There are only 3.6 net turned-in-line wells expected in our guidance for the remainder of the year. This would mean spending toward the lower end of our current capital guidance. However, if both the return of production and turned-in-line wells accelerates faster than we anticipate, it could mean more production and more new wells online, bringing us to the higher end of spending as well as significantly more production. With potentially 30 or more net wells ready to be turned to sales by year-end, what this also means is that even as we've reduced debt dramatically by year-end and spent substantially less capital, we can still see a path in early 2021 to production levels within striking distance of where we began the year, nearing 40,000 BOE per day. What does this mean in aggregate at today's strip? It means that EBITDA could actually be higher year-over-year and free cash flow higher as well, despite an 80% reduction in the Williston rig count year-to-date. Importantly, much of the capital in those 30 or so wells that we can exit the year would have been completely or partially paid for. This means the capital call in 2021 should remain very efficient, and we should be able to roughly sustain those levels with the capital spending provided in our release. Similar to 2020, the range we've provided for 2021 is driven at the high-end by how much additional activity develops throughout next year. If oil prices are supportive and we see more activity, this would mean spending at the higher end and likely more cash flow and production in the back half of 2021 and into 2022, depending on the timing. The credit for this goes in part to our operators who have not wasted those producing volumes in a low-price environment and to our engineering and land team, who have continued day-in, day-out to find the best economic drilling opportunities for us to recycle our capital. Number five. We remind investors that the durability and flexibility of the working interest business model is second to none. We get asked constantly by investors if we would take our strategy out of the basin. We have responded that we are data and economically driven, and our advantages in the Williston give us underwriting confidence that is not easily replicated. In my two-plus years here, we have looked at over 50 opportunities in other basins in the past. If one good thing has happened in 2020, it’s that the downturn has brought more realistic expectations to other basins closer to our economic hurdles as the flippers fade away. And importantly, with capital scarce, many parties from other areas are seeking to partner with us. We are cautious and conservative by nature and believe in walking before running. We focus on top-tier operators and the best of the best areas, and this is a must from a risk management perspective for anywhere we look. As we build our data and experience, we expect that we can find opportunities in other basins, assuming they compete for capital. As demonstrated by recent announcements, we also continue to see ample opportunities within the Williston. There is no shift in priorities or basins, but merely potentially an extension of our strategy. We are focused on making money, not on being bigger, although we have clearly benefited from our cost structure as we build scale. But if we can replicate our data advantage and use the same methodical processes in other basins, we would be able to benefit from an expanded opportunity set. I'll conclude by saying that while things are undoubtedly better than when I last spoke to you, our focus on risk remains in place. Our hedges are deeply in the money through next year and in fact netted us over $77 million in realized gains last quarter alone. The gas hedges we just put on in April have already begun to pay out, netting us approximately $1 million since inception. We've also added our first hedges in 2022 for 1,000 barrels a day at about $50. Hedges have served their main purpose and given us the ability to continue to build for the company's future during a very trying time. However, if all of you have learned one thing in this business, it's that risk management is critical on the front end to create long-term value in the commodity space. As we seek acquisitions and find economic drilling opportunities on our acreage, we won't change our stripes, which have allowed us to weather these times. We'll continue to hedge away risks and continue to whittle away at the debt on our balance sheet. The equity-infused moves we've used in recent times directly benefit the company and its investors over the long term and have been done on an accretive basis to the enterprise. Despite where activity in the United States is, we literally as a team have never been busier. We have analyzed over 25 separate major transactions in the past three months and continue to look for ways to add value to Northern. It's not just some hollow catchphrase. This is a company run by investors, for investors, and we believe, as we prosecute our plan, Northern will come out on the other end stronger than ever. Thanks for your time, and let me pass it on to Adam Dirlam, our COO.

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 acreage 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 while 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 increase 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 to adjust 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 readily 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 quarter, we were starting to see meaningful volumes come online. While many other basins have already seen the bulk of their volumes come online, given our strong hedge position, we are pleased that our operating partners have been rational and patient. This in turn will lead to both a stronger base of production and a stronger reserve report as we head into the fall. The result is more production at a time of higher prices than having been wasted in the low-priced environment of the second quarter. Put simply, we'll earn on these barrels twice. While we've used our ground game acquisitions to step into more drilling opportunities that have met or exceeded our hurdle rates, we have also non-consented a number of wells and traded out of others that no longer penciled in this priced environment. In the second quarter, total well proposals fell through about half of what we would typically see in any three-month period. Of the well proposals that we did see, we elected to participate in about two-thirds of them for a total of 2.3 net wells. Our ability to react quickly to a volatile market enabled us to elect out of wells with operators that might have worked in a normalized price environment but not the current one. We ended the quarter with 26.7 net wells in process, and we expect a significant majority of the completions will be deferred until the latter end of the year and into 2021. Well costs remain relatively consistent with the first quarter as our average AFE came in at around $7.7 million. However, July has been encouraging as the average well was validated for approximately $7 million. Northern will continue to stay nimble in a volatile market, high-grading our asset base and taking advantage of the distressed and lack of capital availability in the market. I cannot stress enough that we will remain disciplined, only electing to invest in projects that will continue to reinforce our best-in-class return on capital employed. As we look to 2021, we see production bolstered by the rational curtailments from 2020, participating in only the best wells in process that will drive a strong cash flow and production profile while continually augmenting the asset from our active management throughout this year. With that, I'll turn it over to our CFO, 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. 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 recognize particularly in the third quarter, these estimates are below Wall Street estimates, which are challenged by the fact that we did not provide 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 partly due to 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 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 reductions early in the third quarter and expect to continue to see basin-wide cost savings during the remainder of the quarter. Cash G&A came in at $1.61 per BOE this quarter and continues to be one of the lowest in the industry, even though production volumes decreased over 46% compared to the first quarter. In the third quarter, we expect to see a slight increase in cash G&A costs in the form of acquisition costs for both deals we've executed on and deals we have not. As a result of the significant effort we put forth analyzing numerous acquisition targets in recent months, the additional acquisition costs could range from $200,000 to $400,000. As Nick mentioned, we have 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 have reduced our net debt by $132 million or 12% since the end of the year, which has reduced our run-rate interest expense by approximately $11 million. We finalized our spring borrowing base redetermination shortly after the quarter, with our borrowing base set at $660 million, which is less than a 20% reduction while many of our peers experienced well over 40% reductions. This is a testament to our hedging strategy, high-quality PDP asset base, and our healthy leverage metrics. Even at this reduced level, we expect to have ample liquidity, and we'll expand our liquidity profile through our free cash flow generation. We ended the quarter with $568 million outstanding on our revolving credit facility. On the working capital front, we continue to work down our operating current liabilities, which are down 41% since the beginning of the year. We expect it will take through the third quarter to work down our working capital deficit because of the non-operating partners. We tend to see capital spending costs lag compared to that of our operating partners, so it will depend on the timing of those costs. Nevertheless, we expect to reduce our revolving credit balance significantly by the end of the year from its current levels. Capital spending for the second quarter was $34.5 million, down 60% compared to the first quarter, which consisted of $32.7 million of organic D&C capital and $1.8 million of total discretionary acquisition capital inclusive of acquisition D&C capital. As you saw in our earnings release this morning, Northern has reiterated its 2020 capital spending guidance to a range between $175 million and $200 million, or a reduction of over 50% compared to our actual capital development expenditures in 2019. On the hedging front, our hedge book is a testament to our commitment to protect our invested capital, cash flow stream, and our balance sheet. We have approximately 26,500 barrels per day hedged at an average price of $58.26 for the remainder of 2020 and approximately 21,400 barrels per day hedged at an average price of $54.66 for 2021. We've also added natural gas hedges and begun to hedge oil for 2022. At the end of the second quarter, the fair value of our hedge book was 188.4, so we expect to generate a significant amount of cash flow from our hedge book. With that, I'll turn the call back over to Mike Kelly.

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. 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 and current seller expectations?

Yes. I mean the deal flow that we're seeing has been relatively consistent with what we've seen over 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. What we're seeing is a lot of the operators with the 10 or 11 rigs that are going now retreating into the double bullseye of the basin. You have about eight to ten AFEs 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. We have the ability to move quickly and close these out. The only other thing I'd add is in times like this, certainty to close is of 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 dramatically. And so in times like these and certainly early in the second quarter, we may be able to execute on these at higher returns than we've ever done before with all the optionality of upside to commodity prices. The deals that Adam has prosecuted in the last few months are already yielding significantly higher returns than what we underwrote just because we have 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 Bakken and then offer some commentary on the current dynamics of available rail takeaway and how much is immediately available for dispatch?

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: there's term rail and then there's spot rail; spot rail is very expensive, while 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. The differential on DAPL today is a high $4.1 net, and that is 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. 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 it's 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. So some of those barrels may be resold, making it a difficult question to answer. However, what I would tell you is that I think based on the current Gulf Coast spreads and what DAPL barrels ultimately receive, rail barrels can actually get a slightly better price. I wouldn't anticipate it having a huge impact on differentials over time. Our strongest marketing partners that we work with would suggest that there may be a $2 differential increase. The only thing that will take some time, and I think one of the reasons why curtailments have been slower in the Bakken in general is that to sign those long-term rail agreements, you only want to do so if you know that you have to. There will be some time for those barrels to spool up over time and for the rail cars to be delivered and then for those systems to go active. My final comment on that is just that the Mobridge crossing, which goes over Lake Oahe, is directly across from the Standing Rock reservation. Ultimately, the same barrels that they don't want to go thousands of feet underground are going right over that rail bridge in a more dangerous manner. Our view, both ethically and I would just say legally, is that longer-term these issues will be resolved, but it may take time. We are not talking about people necessarily who are thinking rationally. But ultimately, we want the oil to be transported in the safest method if possible.

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 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 shut down 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 into effect over time to add additional capacity in other ways that are 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 Q3 and Q4, 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 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. That's as a non-operator; that's the hardest thing for us to predict. Based on public comments we've seen from operators and early results in the third quarter, we're very encouraged. But it's early to tell, especially given how tenuous the recovery in oil prices is. 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. That can have a dramatic impact on those numbers. We've really just taken stock of what we know. As you all know, we live and die by our engineering analysis. We have to take the most cautious approach, but the range is purposely wide because the number of outcomes is equally wide, and 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 spend next year sets you up for 2022 and 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 lower activity levels, our maintenance capital call is declining from where it was. 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. 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. As I mentioned in my prepared comments, if you spend towards the higher end of the range, it would likely mean 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. That ultimately will then somewhat reduce 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. With the curtailments coming back off towards the end of the year, with three net wells in process, we think that's enough wells 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 a three or four-year outlook. 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. 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 is spent, you're talking somewhere between $200 million and $240 million as a consistent maintenance number for the years beyond that, perhaps less. It just depends on 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 or commodity stability level that you 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 entity is strong and we make every move to ensure the company remains solid. The question for the dividend is that our goal has been to make this company a dividend-paying company, but however, we want that dividend to be sustainable. Rather than picking an exact time to resume, the condition at which we want to reintroduce the 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. A combination of these dynamic factors 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. This management team and the executive members of the board have done an exceptional job with this company as seen right now. I expect it could be early next year when we might be ready to resume some form of a dividend. But it's really a function of the conditions coming together, allowing us to run an 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. For my follow-up, it sounded like you guys were maybe a little bit more constructive on out-of-basin opportunities than you’ve been in the past, which is kind of curious. How you 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, 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. What I would tell you is that we're just driven by economics. So if we can look at our entry costs, full-cycle return, and have full confidence in underwriting, it shouldn't matter what basin you're in. But what I would tell you on that point is that confidence in that data that we have is really hard to match. It's made for a very high bar. I'd say in a lot of the active basins in the country, you've had a lot of funding money going around, which has meant that, regardless of how good wells are in any given basin, when you add it all up, it didn't earn a return on capital employed. What I was suggesting is that maybe we are entering a time now where it's really just whether it makes money or not, and the bloom is off the rose. In that case, these deals may start to compete. 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 box because our appetite for risk is about zero. 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. 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 are not going to do that. We're going to make sure that every deal we do adds value day one, not just for some symbol; we're about making money here. I'll leave it at that.

Got it. Appreciate it, 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, 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 uncertain in terms of its return, we will not consent because we know we have 10 deals behind it that will earn our cost of capital, 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. So we look at ground game and the organic AFE as a little bit one in the same, and we’re taking a look at what we're getting on an inbound basis on a daily basis, 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. We kind of put all those together, high-grade everything, and that's what we've been able to do. We've been able to pick up a handful of ground game deals in the third quarter and 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 wells in process with the best operators and best rocks. So I'm 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, dictate our capital and what our outlook is going to look like. 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. What our moves in the last few months show you is that if the economic returns are there, we can 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 in process to a near record. Anyone who thinks they can look at other companies' activities as a barometer for how Northern is going to perform over time are wrong. If you look at our own growth in the last several years, it has had almost no correlation with those of our 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 them 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 that would actually benefit potentially the company even quicker and more materially than buying 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 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 want to emphasize that I think 2021 can be an incredibly amazing banner year for Northern Oil and Gas in the sense that while we have been producing positive cash flow this year—and unfortunate for me, being on any sort of call as CEO or Chairman of a company, I hate to see any misses of any kind. We're very competitive; we want to ensure everything is a win, but I have to look at it from 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 is not producing right now. In 2021, as these wells begin coming up, we have a significant amount of production. If oil prices come up through the $55 or $60 range, operators will open the faucets and start letting the oil flow. 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 we think we can come into 2021 where spending is moderate, but the production, the returns, and cash flow will be significant. Patience is the virtue here. Unlike many other companies, we don't have guns to our head. We're still going to be in a positive cash flow situation under any circumstance. We have the staying power to wait and see when that moment turns around. All of that oil that is being saved in the ground right now will come up at prices that would be more lucrative for us. I’m very, very, very bullish on this company, probably more than I’ve ever been.

Very good. Thanks, Bahram. Thanks, team.

Thank you. 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 about the idea of a 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, I would say that to be intelligent, you have to be willing to change your mind. I think I have shown some skepticism about that in the past. What I'd say is that I saw what Pioneer announced, and I think it's interesting. I think it's something to take into consideration, especially given that it's been quite volatile over the last several—it feels like forever now—but certainly since 2014, there has been constant volatility in the oil and gas sector. I do think that idea of a small base dividend and then an ability to go through has merit. I certainly think that, as Pioneer alluded to, we get pressure to buy back stock. 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 the most important thing we can do is deliver a total return. I think that adds flexibility. My skepticism in the past has been whether the market would ever credit you for that variable dividend. Would it give you consistent value and things like that when it would vary from quarter-to-quarter and could it create more volatility? I think we need to do some more work on that, but I certainly think we are open-minded to the concept.

And I want to add, 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 the future cost of capital will continue to decrease for almost any business, returns are going to be challenging for most businesses. It's important to not end up in a situation where you must borrow extensively. So we're going to chip away as long as we can at this—it’s kind of an 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 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 variable based on the cash flow of the company, but Nick and I and the rest of the board will come up with strategies. Know for a fact that we are already thinking about when and how we can resume the dividend for our shareholders.

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

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 are being a little bit more disciplined with CapEx, at least that's the intent right now, and obviously the potential risks over DAPL and whatnot—how does that change your strategy? Does that change your strategy? Does that make you beef up your ground game a little bit more? And certainly, then you talked about the appetite or at least evaluating other opportunities outside of the basin 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 observation in the sense that it'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. In times we've seen recently where there's almost no activity and we have additional funds available to us, those hurdle rates popup and we can execute on them. I do think that 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’ve never had so many—I would say very varied opportunities in front of us. So from a risk to being able to reinvest our capital into return to things that earn our returns, I would see it as a risk that we're not terribly worried about.

Yes. I mean the only other thing I would add is that the capital discipline push has limited the number of rigs that are running. What operators are doing now rather than running around and HBP-ing acreage in order to most efficiently develop their units is that they're developing a significant majority of them all at once. What that translates into from a development standpoint is significantly more AFEs validated and that cash call going significantly higher. That has created an opportunity that we've seen both in North Dakota and elsewhere, creating an opportunity where we potentially have the ability to step into these units that are being developed in totality. The optionality in terms of deal structure gets wider, and whether you're picking it up on a wellbore-only basis or acreage, it doesn't necessarily matter as much because you're developing the entire unit.

And so for the listeners who may not understand implicitly what happens here when you receive additional AFEs: For example, in a maturity market where just about everything is safe, you could see a number of AFEs coming in associated with wells with acceptable returns. However, you could also see very many of the operators selectively going, 'We like the marginal projects.' What we're benefitting from is that single maturity at which they decide to allocate capital to is optimal for us and supporting those operators at that specific moment. I would point out that the same can be seen across many different asset classes. We can afford to be particularly discerning during this time and ensure clear returns when it comes to our decision-making.

Great. Appreciate that answer. On your view on hedging going forward, to keep leverage at, I think you all stated at 1x kind of range and maybe even lower—that's certainly a pretty high bar for E&P companies, especially with a lot of your peers. Would you envision becoming much more active on the hedge front, maybe even get as much as being more than 100% hedged as you go in 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've got to get there first, obviously, and 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 have already 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 durations. One of the reasons we're so well hedged next year. 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 generated from some of the moves we've made in the last three to six months. What I would say is that, at least for—as it pertains to my policy, to the extent that you underwrite something at a return that meets your hurdle rates and you can hedge that, you should. 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 said, you never are going to really be able to hedge 100%; maybe you can for the first year or so, but at a PDP level, there is some risk you create for yourself as you go too far out. You also, obviously, from a development perspective, if you're hedging future development yet you cannot hedge those costs, the well costs may change. If you hedge at $60 in 2022 and oil winds up being $80, and you hedge wells you thought you were going to be drilling that have a cost significantly higher from inflation, so you've got to be somewhat careful. But I think our strategy will be to continue to add duration and consistency to those hedges, particularly when you're paying fixed obligations.

I 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 for today's call. Have a great weekend.

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