Northern Oil & Gas, Inc. Q3 FY2020 Earnings Call

Greetings, and welcome to Northern Oil and Gas Third Quarter 2020 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mike Kelly, Executive Vice President-Finance.

Thank you, Brock, and good morning, everybody. We're happy to have you here for Northern's third quarter 2020 earnings call. In the room with me this morning, spaced a minimum of six feet apart, is Northern's 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. We will proceed as follows this morning. Bahram will get us started with his perspective on how Northern is positioned in the current environment. Then we'll turn the call over to Nick and the rest of the team to provide details on the quarter and to touch on our forward guidance and strategy. After that, we'll open it up for 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, it’s my pleasure to hand the call over to Northern's Chairman, Bahram Akradi. Bahram?

Thank you, Mike. I'm very excited to be on this conference call today to update you on the performance of NOG. We have a very interesting dichotomy between our strong financial performance and the performance of our stock price. Northern Oil and Gas is in a very enviable position. We entered 2020 expecting approximately 60% to 70% of our projected production hedged at $58 a barrel. However, with the convergence of the Saudi-Russia price war followed by a massive demand hit stemming from COVID, our oil prices plummeted, and our production slowed abruptly. We became almost completely hedged on every barrel of production. The positive impact of this situation for Northern Oil and Gas is that we collected $58 a barrel produced and stored our deferred production in the ground for free until oil prices recover. We have paid down $160 million of our debt year-to-date, and we will pay off our $65 million 5L note with free cash flow in early 2021. Our banks, led by Wells Fargo, recently left our borrowing base unchanged at $660 million, due to the stability of Northern Oil and Gas. 2021 will also be a great year for Northern Oil and Gas. Next year, we will remain in the same enviable position. If oil is under $35, we could spend as little as $15 million, but our free cash flow will be well in excess of $100 million. If oil is around $45 or higher, we spend a little more on CapEx and we’ll see higher production and cash flow while our free cash flow would still be approximately $100 million. Under any circumstance, you can envision for 2021, Northern Oil and Gas will generate material free cash flow. Our track record, if you reflect on the track record of Northern Oil and Gas over the last couple of years, nearly every quarter, we have been very busy. We have accretively grown the business, reduced debt-to-EBITDA, and made the company stronger. This course of action will continue, and it will be done accretively and precisely. We will continue to make the company stronger and reduce our debt position. We will position the company to be a very strong, publicly held, cash flow generating business. Opportunities in the Shale 3.0 era: our high return non-op business model has a major competitive advantage in the Shale 3.0 era. As operated budgets take precedence over non-op budgets for traditional E&P, Northern Oil and Gas pipeline of drill-ready, non-op prospects stands at an all-time high. We target less than a three-year payback on these deals. Thus, these investments are accretive to our already industry-leading return on capital metrics. Alignment and like-minded management, the board, and approximately 40% of our investors are like-minded. I am committed to take NOG to a strong cash flow generating entity with very low levels of debt. I'm grateful for this amazing management group; they have done and are doing every day. I'm thankful for the alignment from TRT, Angelo Gordon, and other large partners as they’re committed to building upon what we have done so far in the last couple of years and reaching the levels they just established earlier. Thank you again.

Thanks, Bahram. All right. Let's get down to it in nine points. Number one, it was a solid quarter. Production was up, costs were down, and our conservative outlook has paid dividends. Cost savings have really started to flow through in the form of lower operating drilling costs. Number two, our focus on continuing to work on the balance sheet has a meaningful impact for our equity investors. Our interest expense was down 32% year-over-year; we retired $17.1 million of bonds and preferred stock this quarter through negotiated exchanges. With these deals, we captured $4.4 million of discount and an additional $1 million in annual fixed charge savings. This is real cash and real accretion to our enterprise value comprising over $30 million per year in run rate interest savings versus last year, which flows directly to the bottom line. We should see another significant sequential drop in interest expense in the fourth quarter and first quarter of 2021. Number three, we continue to be well-protected, despite the challenging environment. It's important to understand that the company remains well-insulated in the coming 18-plus months. The world may, in fact, get worse in the near term. And we're okay with that. Our hedge book still has a gross value of nearly $150 million, and our cash flows will remain stable. As I have said in each of the last three quarters, the hedges and the cash flow they provide means that we do not have to waste our volumes in a low price environment to generate cash flow. As Bahram stated, they are simply being stored for free, and we will save them for better days ahead. Number four, the setup for 2021 is strong. While as a non-operator, timing is always the most challenging thing to forecast, we have built-in momentum through our large wells and process list. We expect to end the year with a record number, and these wells are of the highest quality, as you'd expect in the downturn. This simply means that as we look out the next year, we may be facing some of the best capital productivity in our history. As we've shown in our guidance sensitivities, we're not throwing away our inventory in a low price environment. We'll curtail and throttle back spending in a poor pricing scenario. None of these outcomes is a bad one, given the number of wells and processes we are carrying. Every $10 move in oil is roughly $2 million in revenue and free cash flow for a new well on an annualized basis. With 30 net wells in process, we don't want $60 million of additional revenue and free cash, potentially frittered away at low prices. As noted in our guidance, we will govern our activity levels based upon common sense, spending driven by the oil pricing strip. There is no losing scenario given our hedge profile. If prices aren't supportive of development activity, we'll simply produce more cash flow and preserve that development for the future. Number five, we are expanding. We closed on our first out-of-basin acquisition this quarter, and the Permian has become front and center over the past two years, simply because of its high levels of activity. We continue to look in the Permian and other basins where we can build inventory, drilling prospects, or producing cash flows that are either deeply discounted or meet or exceed our full cycle hurdle rates and preferably both. There will be more to come. Number six, cash is king. We produced over $50 million of free cash flow year-to-date, reduced our working capital deficit dramatically. As our cash flow accelerates in the fourth quarter, it will continue to free up additional liquidity throughout 2021. I have personally been observing almost every independent producer’s balance sheet. I continue to believe that Wall Street does not carefully monitor those carrying large working capital deficits, which is effectively shadow debt, and are misconstruing the company's debt reduction with the fact that they are simply deferring paying their bills; we have not done that. Our working capital deficit is the lowest in years, which means the cash coming in the door can service debt, not past accruals. Number seven, every dollar matters. We continue to remain within our $200 million capital budget this year; the variance in our fourth quarter spend will be any incremental success in the ground game or if we see higher prices and accelerated completions. Many investors ask us about transformational deals, and my response is we're looking at everything. Our backlog today stands at over $750 million in active M&A opportunities we're working through, but we focus on assets that make money. The key is to measure the benefits, costs, and risks of every deal. Risk is a factor for these transactions that is not always appreciated, but something we spend an enormous amount of time analyzing. We continue to be on the hunt for big and small deals, but we will not sacrifice our standards. Number eight, as you've seen, we actively manage our business through the ground game and larger M&A program. We are not just a passive ETF to the operators on our organic acreage. Anyone forecasting our business based on Bakken operators, the rig count, or our organic footprint has been wrong over the past few years and will be wrong for the foreseeable future; opportunities are everywhere. Our current backlog of producing assets and drilling prospects we’re evaluating right now is nearly $1 billion. What does low activity in the Williston mean for our business? The answer is nothing. As long as we're doing our jobs, rest assured that we control that, not our operators and not the activity in the basin. The key managerial linchpin of this non-operated strategy is that we focus on quality and we focus on cost of entry. Based on deals signed or closed, we should have our first Permian production online this quarter, and the basin already makes up nearly 5% of our wells in process. So focusing on just the net acres we've acquired is a key misunderstanding of what creates value. Acres only have value when they're converting into cash flow. Adam will provide further color on some of our progress there. Number nine, watch what we do, not what we say. Since this management team rebuilt this company two and a half years ago, we've done $1 billion in equity-centric cash flowing acquisitions and over $1.7 billion in gross financings to continue to improve the balance sheet and cut our cost of debt. We have taken many often painful steps to improve the balance sheet and cash flows of the business. We are not even close to done, and we will do whatever it takes to ensure that Northern thrives on the other side of COVID. We cannot control the stock market or what it wants to ascribe to a smaller producer in the marketplace today. But as our results show, we're still here, we're still making money. The model we've created is generating cash; and we're not going anywhere. While we firmly believe that the market will improve in the next year, hope is not a strategy. We'll take every step just as we have done in the past two plus years, regardless of what the market may say today. You don't have to believe what we say today, but you can trust in what we've done and what we will continue to do. Thank you for your time. Adam?

Thanks, Nick. In the third quarter, our active management resumed during the second quarter left off. In North Dakota, the rig count continued to languish, but our ground game acquisitions picked up the slack. Targeting our best-in-class operators, we acquired 4.6 net wells in process and picked up around 650 net acres and 140 net royalty acres. This has continued to bolster our wells in process with some of the most productive wells in the basin and in the quarter at a recent high of 28.3 net wells. As previously announced, we closed on our initial acquisition in the Permian during the third quarter and continue to screen more opportunities than ever before. Now more than ever, our operating and non-operating partners in the Bakken and Permian value the certainty to close that we can provide, and it has enabled us to continue to bolt on additional assets at attractive prices. We upped our hurdle rates significantly over a year ago, and our evaluation process remains unchanged, despite the lower strip. We'll continue to adhere to our strict underwriting and return requirements to maintain our best-in-class return on capital employed. While there are myriad opportunities that we are evaluating, if commodity pricing or the quality of assets will not generate an acceptable rate of return, we will deploy that capital where it is better suited. Through the end of October, we have continued to maintain our ground game momentum and have committed to or closed on an additional 100 barrels a day, 3.2 net wells in process, 670 net acres, and 420 net royalty acres. In total for the year, that accounts for roughly two net wells turned to production, 10.4 net wells in process, 2,400 net acres, and 630 net royalty acres. To be clear, all of this active management through our ground game is embedded within our stated CapEx guidance. At an operational level, we have been encouraged by our operators' ability to respond to this environment with effective reductions in well costs. Our average proposed well in the third quarter, inclusive of facilities, came in at just under $7 million, down from $7.7 million in the second quarter. As of late, we have seen well proposals from some of our operators in the $5 million to $6 million range, with some close to the bottom of that range. This will have a material impact on the embedded rate of return for these developments, despite the lower oil prices. Third quarter well proposals remain consistent with second quarter's activity levels, but with our operators retreating to the core, we are only seeing the best of the best areas get developed. Combined with the reduction in estimated well costs, about 80% of the net wells proposed to Northern met our hurdle rates, and we elected to it. Production curtailments continued to pay during the third quarter with 3,500 barrels on average brought back online from the second. Heading into the fourth quarter, we expect similar levels of curtailments, with roughly 11,000 barrels a day either still curtailed or attributed to delayed IPs, given the current price environment. We are supportive of this move, particularly given the recent downdraft in prices. We are effectively storing high-quality barrels in the ground for free while our hedge profile allows us to preserve that value for a stronger environment. Regardless of the curtailments, we continue to expect to produce between 30,000 and 40,000 BOE per day during the fourth quarter. With that, I'll turn it over to our CFO, Chad Allen.

Thanks, Adam. I have a few highlights to go over this quarter, starting with a quick summary on Northern’s financial performance. Our production averaged 29,051 barrels of oil equivalent per day, a 22% increase over the second quarter, and came in at the high end of our guidance. Production was significantly impacted by curtailments, shut-in production, and delayed development plans by our operating partners, which we estimate reduced our third quarter production by approximately 11,000 barrels of oil equivalent per day. In our earnings release this morning, we've given 2021 production and CapEx guidance based on sensitivities to oil price decks. Our base case for 2021 is based on oil averaging at least $40 per barrel, but in scenarios where WTI is below $40, we actually expect we’ll generate significantly higher free cash flow due to lower CapEx spent. Oil differentials were $6.54 during the quarter, which was an improvement of approximately 40% over the second quarter. Gas realizations continue to impact our revenues during the third quarter; however, recent upward moves in the natural gas strip should lead to higher realizations as a percentage of NYMEX in the fourth quarter due to fixed cost absorption. Lease operating expenses for the third quarter came in at $24.2 million, down 9% of that total basis and down 27% on a per unit basis from the second quarter. We expect to continue to see basin-wide cost savings during the remainder of the year and into 2021. Cash G&A came in at $1.39 per BOE this quarter and continues to be one of the lowest in the industry, even with significant impacts to our production volumes from curtailments, shut-in production, and delayed development plans. We significantly improved our leverage profile since the end of the year, and our focus continues to be on debt reduction in these challenging times. As we speak here today, we've reduced our total debt by approximately $160 million, or 14% since year-end. This reduction alone has reduced our run rate interest expense by over 45% compared to last year. We finalized our fall borrowing base redetermination this week, maintaining our borrowing base at the existing $660 million level, with 100% approval from our lenders and our bank group. This is a testament to our hedging strategy, high quality PDP asset base, and healthy leverage metrics. We expect to have ample liquidity and will expand our liquidity profile through free cash flow generation over the next 12 to 18 months, inclusive of the near-term maturity. We ended the quarter with $571 million outstanding on our revolving credit facility and have since further reduced that balance to $550 million, inclusive of our $8 million of interest coupon payments that were made on October 1. On the working capital front, we continue to work down our operating current liabilities, which were down 45% since the beginning of the year, and we expect to reduce several revolving credit balances by another $15 million to $30 million by the end of the year from its current levels. Capital spending in the third quarter was $43.8 million, which consisted of $27.7 million of organic D&C capital and $16.1 million of total discretionary acquisition capital, inclusive of acquisition D&C capital. As you saw in our earnings release this morning, Northern is reiterating its 2020 capital spending guidance to be in a range between $175 million to $200 million, a reduction of over 50% compared to our actual development capital expenditures in 2019. With that, I’ll turn the call back over to Mike.

Great. Thanks, Chad. Brock, let's open up for Q&A.

Thank you, sir. Our first question today comes from Duncan McIntosh of Johnson Rice. Please proceed with your question.

Sorry, I was on mute. Good morning, Nick. First question comes off the SHALE 3.0 side. You all highlighted a pipeline of a lot of drill-ready prospects, and I guess is that where we should kind of expect the majority of development beyond the organic D&C to go to kind of flow more towards drill-ready prospects going forward?

I think that we talk about being an active manager all the time. The organic base – we built a company three years ago to generate generally larger cash flow than necessarily the organic asset would ever pull. We moderate and throttle our activity based on that. Obviously, in an environment like this, the frank answer is that operators simply can barely fund their own drilling obligations, let alone their non-operated obligations, where their cash flow is cramped even if they wanted to. We are inundated with those offers, and we sift through them. They go through our engineering and land processes, and if the best ones can pass muster and we can agree on terms, we can buy the acreage and the development all in one. We view that as no different than an organic prospect. But it goes to my point; anyone who's thinking about just sitting here waiting to get an AFE in the mail is going to be sorely disappointed.

Yes. And Duncan, this is Adam. Maybe just to give you some context, in Q3, we had about 45 well proposals sent our way, and when I look at October, we're looking at 22, so you've already got 50% of Q3’s activity in kind of the first month. It's a process that our engineering and land team are reviewing on a day-to-day, real-time basis. So we're taking a look at the economics based on what’s coming in the door from our organic footprint and then comparing that to the active management and the ground game to get the right mix of the economics and opportunity sets.

All right, great. Thanks. I guess just to dovetail off a little bit, jumping over to Slide 11. The production on your new wells exceeding the type curve at 30%. What are some of the drivers? Is this more of a high grading of locations? Is it a high grading operator? Or maybe just some color around what you've seen, and I'd imagine you are pretty pleased with what you've got so far this year, and I'd have to imagine there's more on the come for next year.

Yes. Hey, Duncan, this is Jim. So what we're looking at here is we always take a pretty conservative view of well performance in the area. We've always been one where we like to see enough history before we make the assumption that bigger completions will generate bigger EURs. What we're seeing here is really just optimization by the operators, kind of coring up in certain areas and then optimizing their completions, optimizing the way that they produce these wells. So not necessarily generating bigger EURs per se, but getting that oil out faster than what we expected, which helps drive some of those rates of return. So that's really kind of what's driving this. We would expect this to continue in this environment, as operators really focus more on their operations of current wells and near-term wells rather than just trying to run 10 rigs out there. So we would expect this kind of optimization to continue across our portfolio.

All right. Thank you.

The next question is from Jordan Levy of Truist. Please proceed with your question.

Good morning. The pipeline out of the Permian that you guys pointed to is really impressive. Just wanted to see if you guys could compare kind of what the deal flow looks like in the Permian versus the Williston, if there's any kind of contrasting dynamics at play that you're seeing over that?

Yes. I'll give a little color, and then I'll let Adam probably elaborate further. What I would say from my observation is that the Permian is all over the map. We find ourselves very competitive in certain situations, and then other times we're seeing bids that are quadruple what we would be willing to pay. We do still see some – we've been looking for a long time, candidly. There was, like anything else, whether it be any hot commodity in oil and gas at the moment, minerals, the Permian basin. When capital is being thrown into an area, people are relatively undisciplined. But definitely see the discipline coming, I would say it's spottier. From a batting average perspective, our batting average has been relatively low, although we continue to grind away. We’ve had some really good success even since we did our initial deal. In the Bakken, we really are the clearinghouse, and so generally when we don't win something, usually the person says I can't accept that price and I'm just not going to sell it at all. So, that being said, the difference in the Bakken is, frankly, we know it so well at this point that much of this stuff doesn't even pass the smell test and things wouldn't be interesting at any price. I don't know if you want to add to that.

Yes. I mean, I guess if we're talking about rig up opportunities, looking at the Permian, you've got 10 times as many rigs. You can just extrapolate in terms of the deals that are walking themselves in the door. That being said, you have a much wider disbursement on the overall economics. To Nick's point, you've got a handful of sellers that are still living in the rearview mirror. So, it's a matter of swinging the bat and getting the volume in order to ensure that we're deploying our capital towards the appropriate projects with the right operators at the right hurdle rates, and those sets of things. In North Dakota, with 15 rigs running in the basin, they've all effectively retreated to the core. When we're seeing opportunities there, by and large, it’s stuff that's going to be penciling in this particular price environment. We have been really encouraged on the economics that we’re seeing there. Just the stuff we've effectively closed in Q4 is largely Williston basin opportunities, sprinkled in with a handful of Permian stuff that we're looking at. So, we are encouraged on both fronts; just different dynamics, and we continue to proactively look at things in both basins.

Yes. And it's not every day that we announce a small acquisition that's like 66 acres, right. I’m sure there are plenty in the peanut gallery with snarky comments about that. But the reality is that as much as we want our investors to understand that we're expanding, that's not just for the investors, but for deal flow purposes to understand that we're actually active; we've been looking for some time, and we're actually prosecuting on it. I would tell you that the number of new prospects that came our way after that announcement probably quadrupled overnight. Jim and Adam also got lots of resumes for else worth, tough times in the oil and gas space. But, I would just tell you that in alone we are active now. One thing I just want to end with is, if you look at what we do generally, we're very careful. In the Permian basin, there is a lot of Tier 1 and Tier 2 stuff for sale. We have really zoomed in on the areas that we think are high quality and are very resilient in pricing. There is a lot of stuff in the outskirts of the Delaware basin and then the Northern and Southern Midland basin that gets a bit sketchy. You're not going to see us transact there. One of the reasons that we do it at a small ground game level deal-by-deal is, we’re in the middle of an election, and there is risk over federal acreage; you're buying wells that are already permitted right in federal areas. That takes the risk out; we could go buy 10,000 acres in the Permian right now in Lea or Eddy County, and if something changes in the regulatory environment in a year, you would have destroyed a lot of value.

Makes sense. I really appreciate the color. Thanks, guys.

The next question is from Jeff Grampp of Northland Capital Markets. Please proceed with your question.

Good morning, guys. Hey, Nick, just kind of a strategic one for you. Can you talk about kind of the balancing act you guys want to thread the needle with in terms of, I should say, using your free cash flow to delever the balance sheet versus some great buying opportunities that are out there? Maybe you could discuss the possibility of equity or, I don't know, maybe even preferred equity as a source to fund deals in order to preserve the liquidity, which I know is important for you guys.

Yes, I think for anything transformational, you've got to be sensitive to your balance sheet, right. So anything upscale, we build our base capital budget to provide roughly a third of that budget in this day and age for these acquisitions. We have plenty of firepower within that to do a really healthy amount of them, especially we're aided by the fact that the organic activity in the Williston is relatively low. It allows us to throw that up some. What I would tell you is that people ask me all the time, well, the stocks keep going down, doesn't that preclude you from doing M&A? My answer is, if the stocks are going down, so are private valuations, and that doesn’t preclude anything. We are extremely balance sheet sensitive. A third of this company is owned by the founders, and we always talk about the fact, something that I think is oftentimes lost on investors, do you want to own 100% of nothing or 80% of something? I think a lot of companies that have overly focused on not diluting their shareholders, I can think of a number of them that are in Chapter 11 right now, or on their way for that matter. If we can do things that are a win-win for the existing holders, and we can structure something there, we will do that, especially anything upscale. I don't think you're going to see us do a Sanchez and lever up when we're already levered up. That's just not my style, and I don’t think that we're going to do that. But what that means sort of as a default is anything that involves any form of equity security, whether it be preferred or common, is going to have to be net beneficial to every holder right now, where they're going to be happy that we're doing it. I think that that's easy for us to tell you that because our Board of Directors are the owners of this business.

Yes, good to hear. That's what I was looking for. Thank you. And for my follow-up, just on the cost side, I don't pick a big drop down in the AFEs, and I think in the prepared remarks, you guys talked about things heading even lower. How sustainable do you guys think that is? As we think into the 2021 budget, can you tell us what’s kind of assumed there in terms of where well costs are headed?

We don’t assume many of those well costs, but I think we're still running like $7 million to $7.5 million in that budget. The reason that you're seeing this drop is that, for whatever reason, if the God speaks in oil prices, rallies really hard, there may be a scramble. We may see the vast majority of the costs are in completion. What you're seeing now is disposal costs, water costs are all falling, and obviously both rig rates and pressure pumping rates are at significant lows. Those can fluctuate. I think some of this stuff is going to be – every time we've had a downturn, it feels like we have a downturn every two years in this space over the last decade. Every time you have one of these downturns, there's going to be a portion of it that’s structural and a portion that is sensitive to price. What I’d tell you is, I don’t personally see in this environment that you’re going to see a lot of inflation. There’s so much slack in the service system; it’s going to be very hard to push pricing. I would expect that if you have a real scramble of oil, if the oil strip goes above $50 and you start to have people forced to put completion crews to work, you could have some of that cost come back. Simply because most of these people have been furloughed and laid off, and you're going to have to pay people to come back to actually join frac crews. So I think caution is of the order, but I do think most likely in most scenarios, we're going to be able to keep most of those savings over the next several years.

All right, that makes sense. Appreciate the time, guys.

Our next question is from John White of Roth Capital. Please proceed with your question.

Good morning. Thanks for taking my question. Looking at Slide 9, the map of the Permian and Delaware, Midland and Delaware basins, and reflecting back on your previous comments, regarding this region? Did I hear you correct about you're going to be focused on the Delaware basin and not really focused on the Midland basin?

No, not at all. We've looked at several deals in the Midland. I would say particularly in the core of the Midland, it's pretty blocked up, right. You have four operators that control a vast majority of it. So we don't see as much stuff in the Midland. When we do see it, it tends to be in the outskirts. We have seen a handful of some really good non-operated properties in good areas in the Midland. I think what I would tell you is we're snobs, and so we're going to be focused on the places where the wells are the most economic and the most resilient. So that could be in the Midland. It could be anywhere, frankly. We're just economic creatures. It's about focusing on rate of return and your cost of entry that affects that rate of return, which is sometimes forgotten by people. We run different price decks and see how resilient those assets are because there are assets that can have very similar rate of returns at $60 oil; however, when you run it at $30, that answer can be very different. We try to focus on things that can make, so it’s easier for us today, frankly, because the strip is so low. It defaults to kicking out a good portion of stuff that would otherwise work in a normal environment.

Thanks. And I believe you just answered my follow up, and that is what you just said. You're not necessarily focused on the New Mexico side of the Delaware; you're looking all over the basin.

We're looking everywhere, but I would tell you that what we have to zero in on is that there is sort of a football-shaped area, and Lea and Eddy, and then some Loving County. It does spread out in some other areas. But you have to go area by area. There are H2S issues in parts of the Delaware that have good properties; but can be a major problem from a development perspective. It’s a complicated analysis as we go through it. We're looking...

Yes, it's no different than the North Dakota, right. We're triangulating the areas and the operators and then ultimately the economics. We're looking at Texas on both sides of the fence, looking at New Mexico. It just so happens that we've gotten a handful of things done in New Mexico. That's not to say that we have submitted bids in Midland or the Texas side of the Delaware.

Okay. It sounds like the fragmentation in the Delaware is suited to your operating style, to your advantage?

That's right. I think also, frankly from an NRI perspective, given that some of those things are federal acres, it really helps the economics that the royalty rates are lower. That can have a material impact on those wells. But obviously, you also get that federal risk with it. So we focused on buying acres that are being developed and permitted, not going and buying 10,000 acres that could be thrown away if something materially changes at an administrative level.

Thanks very much for all the detail and congratulations on your continued progress.

Thanks, John.

There are no additional questions at this time. I'd like to turn the call back to Mike Kelly for closing remarks.

Yes, Brock, and thanks to all our investors for dialing in this morning during a busy and eventful week. Please give us a call if you have any further questions. Thank you.

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