Greetings and welcome to the Second Quarter 2021 Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. Please note, this conference is being recorded. I will now turn the conference over to your host, Mike Kelly, Chief Strategy Officer. You may begin.

Good morning and thank you for joining us for a discussion of Northern's second quarter 2021 earnings release. This morning before the market open, we released our financial results for the first quarter. You can access our earnings release on our Investor Relations website and our Form 10-Q will be filed within the next few days with the SEC. We also posted a new investor deck on the website this morning as well. I am joined here this morning with Northern's CEO, Nick O'Grady; our COO, Adam Dirlam; CFO, Chad Allen; and our Chief Engineer, James Evans. Our agenda for today is as follows. Nick will start off with his comments regarding Q2 strategy. After Nick, Adam will give you an overview of our operations and then, Chad will review NOG's Q2 financials and updated 2021 guidance. Finally, our executive team will be available to answer any questions. 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 the risks and uncertainties that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements. Those risks include, amongst others, matters that we've 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 EBITDA and free cash flow. A reconciliation of these measures to the closest GAAP measure can be found in the earnings release that we issued this morning. With that taken care of, I will now hand the call over to Northern's CEO, Nick O'Grady.

Good morning. I would like to thank everyone for joining us this morning. We've had a very productive first half of 2021, expanding significantly into two new basins and we've continued to improve our balance sheet. Our disciplined investment approach has been paying off handsomely as the results show today. I would like to focus on four key points. Number one, we had a monster quarter and one that truly highlights the flexibility and benefit of our differentiated and actively managed business model. In a quarter where the overall Williston basin volumes decreased, Northern Oil's volumes increased by 14%. Because of our ground game playbook and ownership of core rock in the Bakken, augmented by an increasing Permian presence, Northern's outlook is never tied solely to basin-wide activity levels. Strong well performance, an accelerated pace of completions, and robust realized pricing for both oil and gas resulted in us being able to exceed both internal and external forecasts. All of our key financial metrics, including production, EBITDA, cash flow, free cash flow, and earnings per share were above forecast across the board, and in most cases, it’s a new record for the company. Our capital expenditures were less than forecast. Our production costs fell on a unit basis as we integrated our low-cost Marcellus assets and as workover expenses in the Bakken began to tail off. Number two, our free cash flow outlook and our balance sheet projections continue to improve. We expect to meaningfully exceed our initial and recently updated free cash flow estimates for 2021. We now expect to end the year with a run rate leverage ratio of less than 1.5 times and to fall below one times by the end of the second quarter in 2022. During our conference call in June related to the Permian acquisition, we highlighted that we expected to produce more than $150 million of free cash in 2021 and cumulatively more than $800 million through 2025. We now estimate over $160 million of free cash flow in 2021 and cumulatively more than $900 million through 2025. I would also like to point out that if the current pricing strip holds, we expect to be able to retire all of our bank debt by late 2022, leaving only $550 million of 2028 notes as our sole piece of debt. Number three, Northern's M&A pipeline continues to grow. The M&A landscape continues to remain strong even as we work down last quarter’s M&A backlog. While we could have transacted on many more deals than we have year to date, we will not just do “Wall Street accretive deals” because we value transactions as any cash buyer would, which is on return on capital employed and rate of return. It's money in money out. We want to buy assets with discipline, not because we can. Number four, dividends and returns to our shareholders. Our Board of Directors has declared a 50% increase to our next quarterly common stock dividend for a total dividend of $0.045 per share. Successful M&A could accelerate our dividend strategy and with the Permian acquisitions and the associated financing, we expect to continue to increase dividends over the coming years. In conclusion, the outlook continues to improve as we have steadily exceeded our targets. We are ahead of our free cash flow forecasts and production outlook. We continue to grow our shareholder returns while improving our balance sheet. We have lowered our unit costs through scale and high-quality property acquisitions. The quality of assets testing the market is impressive and the possibilities for value creation continue to excite us. We are a company run by investors for investors and I truly want to thank each and every one of you for joining us today. With that, let me turn it over to Adam Dirlam.

Thanks, Nick. Our operational plans for the year remain on track and continue to play out largely as we've expected. In the Bakken, activity levels have started to pick up as we brought online 10.5 net wells during the quarter, a 55% increase quarter-over-quarter. Drilling activity continues to pick up steam too. Operators have been steadily working down their drilled but uncompleted well inventory, and they’ve started to reload their pipeline of new drills. We've seen a ratable increase in new well proposals and more notably, we've seen an outsized percentage of those well proposals across our acreage footprint. During the quarter, we elected to 50 AFEs, more than double from Q1. As encouraging, if not more, we have yet to see any sort of material inflation to overall well cost. During the quarter, new proposals averaged less than $6.5 million and we're actually down 7% versus our Q1 average. We've benefited in Q2 from having higher activity levels with some of our most efficient operators. As it stands right now, we continue to remain conservative with our internal assumptions, modeling well cost at an average of 7 million to 8 million depending on the operator and completion methodology which should buffer any potential for cost inflation. In the Marcellus, completions on our initial well pads commenced in early July and production to date has been right in line with our expectations. Cost savings with EQT have been a focus and we've been pleasantly surprised with the efficiencies we've seen and been able to generate. Turning to the Permian, our outlook for NOG's future in the basin gets stronger by the day. In less than one year since entering the play, we have now closed on over $100 million worth of deals and we have responsibly built up a scale position across more than 3000 net acres. Our playbook in the Permian is the same successful playbook we've historically used in the Bakken; build out a top tier position partnering with the best operators in the basin. Activity levels remain elevated in the play, which continues to present compelling opportunities for Northern. As it pertains to overall deal flow for NOG, we are extremely busy both at a ground game and package level. On the ground game front, we closed on 11 transactions in the quarter, almost double from what we signed up in the first quarter; high grading the opportunity set between the Bakken and the Permian, the number of transactions were evenly split between the two basins. In total, we picked up 2.8 net wells and over 600 net acres. This barbell approach has enabled us to diversify across operators and regions while adhering to our hurdle rates, even as we run sensitivities for lower commodity prices. If the bid-ask spreads start to widen out in various areas, the ability to pivot will certainly be a competitive advantage for us. Given where we are in the calendar, it's worth noting that typically, we see smaller competitors exhaust their budgets mid-year, and we expect we'll see even more opportunities as the year progresses. As it pertains to potential for larger M&A during the quarter, we looked at over 10 new packages focusing on high-quality assets that will see activity levels regardless of the price environment. With the high volume of prospects available, the opportunities are force ranked, and our disciplined means that only a select few meet our return criteria. Consolidation has been a theme that is alive and well, and we will continue to evaluate multiple opportunities in the current market. Now I'll turn it over to our CFO Chad Allen.

Thanks, Adam. I have a few highlights to go over for this quarter. Starting with a quick summary on Northern's financial performance. Our Q2 production averaged 54,623 barrels of oil equivalent per day and 33,346 barrels of oil per day, up 42% and 14% sequentially over Q1. Our adjusted EBITDA for the quarter was $132.8 million and our free cash flow was $46.2 million, up 35% and 11% respectively over Q1 significantly ahead of Wall Street and internal expectations. Well differentials were $5.46 during the quarter, which was an improvement of approximately 17% over Q1. Operating costs also continue to trend down in the second quarter. Lease operating expenses decreased 30% over the first quarter on a per-unit basis. Cash, G&A excluding one-time acquisition-related costs to the Marcellus and Permian transactions came in at $0.77 per BOE this quarter, about 9% better than the midpoint of our previous guidance. Capital spending for the second quarter was also below Wall Street and internal estimates at $68.4 million excluding the Reliance acquisition. We continue to improve our balance sheet and liquidity profile since the end of last year through debt and equity offerings and free cash flow. In the first six months of 2021, we produced $87.9 million of free cash flow, which is more than in the entirety of 2020. This has allowed us to fully equitize the Marcellus and Permian transactions and extends our maturity wall by retiring the remaining $65 million of our VEN Bakken Note and our second lien notes. As of June 30, pro forma for the closing of the Permian transaction earlier this week, we had approximately $350 million outstanding in our revolving credit facility, leaving around $315 million of available liquidity including cash on hand. Moving on now to our updated full-year 2021 guidance that was included in our earnings release. We have increased our production guidance for the year, primarily driven by the integration of our premium properties and the acceleration of some planned Q3 development into Q2. That will likely translate into a somewhat flat production profile in Q3 before increasing again in Q4. Additionally, we expect to shift some of our planned natural gas development into 2022. Some of that CapEx will be reallocated to our oil properties as noted in our increased oil percentage guidance of 63% to 64% for 2021. That should be cash flow and free cash flow enhancing for 2021 at current pricing levels. Oil differential guidance has been lowered by over a dollar on the high end, a function of strong pricing in the Williston and Permian basins. Our updated guidance on gas realizations reflects a strong pricing year to date. This guidance implies high 70% realizations for the remainder of the year inclusive of our Marcellus properties. On the cost guidance, it's fairly universal reductions across the board, with reductions in G&A cost and LOE that is much lower than we experienced in Q1. While our LOE guidance is $8.60 to $8.90 per BOE, the run rate should be around the low end of this forecast for the remainder of the year because this guidance includes Q1 which was $9.92 per BOE. Do note that the benefit of higher NGL prices will have a modest impact on our LOE numbers as pop contracts are increasing some processing charges in our LOE. However, these will be more than offset by the additional revenue from higher gas and liquids prices and will be a net benefit to overall margins. We have also simplified our production tax guidance to account for being a three basin company at 9% to 10% of oil and gas sales. Finally, we reduced the high end of our capital expenditure forecast to $260 million, a $10 million reduction. While prices are higher and could certainly warrant higher spending, we're maintaining a disciplined approach and not chasing lower quality prospects as we focus on full cycle stress-tested returns. With that, I'll turn it over to the operator for Q&A.

At this time, we'll be conducting a question-and-answer session. Our first question is from an analyst with Bank of America. Please proceed with your question.

Hey, guys, thanks for having me on the call. So my first question is really just kind of on the breakdown between the Marcellus and the Bakken. Clearly, we saw some pretty impressive gas realizations. I mean, you guys elected to report things as consolidated. So just try to get any color there that you could offer as far as the split, and then on production as well.

Yes. As far as the split between the Bakken and Permian. I mean, we certainly saw very solid pricing in the Bakken north of call it 120% to 130% realizations there. And then that was offset by our Marcellus production that was in and around I think it's around 60% to 70% realizations there.

Yes, Alex, and in terms of production, we were about 80% in the Bakken, 20% in the Marcellus.

Got it, that's helpful. And then the other question I wanted to ask was just on hedging. It looks like you guys have layered in some more hedges for 2022. Obviously, you're not at your leverage target yet, but have an anticipation of getting there mid-year. So just kind of curious, are you happy with your hedge position right now? And then beyond when you're looking at getting to that target, should we expect any change in strategy? Thanks.

Yes. I think my first comment is that there's no question that as our balance sheet improves, our hedging needs to protect credit are reduced. As we noted in our earnings presentation due to the balance sheet improvements, our target percentage is down about 1,000 to 1,500 basis points on a rolling 18-month basis to about 60% to 65% from previous periods where we were typically at about three quarters. I would anticipate like our dividend, as our leverage continues to tick down, so too will our internal hedging requirements. But let’s also get real here. Oil is near $70 not because the world is out of oil or that demand is through the roof, but because the largest cartel in the world is holding back about 5% of the world's supply artificially. The cartel is beginning to ease those restrictions. You also have the Delta variant and massive government action trying to kill demand for our products. So the concept of being wildly bullish and riding the upside because of a feeling doesn’t exactly feel like prudent financial management to me. I was inundated with investors at the beginning of this year telling me we should be hedging everything in at $45 because oil is going to be dead forever. The strip has never been an accurate predictor, nor has short-term investor sentiment. Our view of hedges in general is that the long-term value of a hedge is zero, meaning you're going to win some, you're going to lose some. But importantly, you're live to fight another day and our hedging counterparties tell me consistently that 90% of their EMP clients only start hedging when in panic mode and oil is breaking down. We would much rather have discipline and be consistent. We talk all the time to our investors about the asymmetry of hedging. This quarter as an example, we had more net completions of nearly 2000 barrels a day of oil production more than we expected because oil prices are high. And we throttle our development and our operators naturally accelerate their plans to capture that. Compare that to a quarter or a year ago, where we wound up more than 100% hedged because activity was deferred and curtailed. In this environment with higher pricing, we will see more well proposals and more production, less downtime, and so naturally we become less hedged. In the second quarter of 20, we made $77 million on realized hedge gains. We forgone about $27 million in profits this quarter. And 2Q, 20 was an existential moment. It seems like a fair trade to me. For those investors that want to play the upside, my comment would be if you saw it on hedged versus hedge stocks coming into 2021 and you bet on the unhedged ones for performance, you would have lost by a mile. And I personally find it a bit incredulous given in 2019 and 2020 we realized over $220 million in hedging gains and there were over 250 bankruptcies in oil and gas in 2020 alone. No one knows what the future prices for oil are. But I can tell you what we know when we hedge if we are locking in good returns or not. And we have been. Our weighted average IRR of elected wells this year at $55 flat is about 50%. The hedges we've added since last quarter are well north of $60. So explain to me why that's necessary to gamble. We have a choice here which is candidly to be a sheep or a wolf. And last time I checked, sheep get slaughtered. It's the roll-the-dice mentality and wild optimism that has gotten this industry into so much trouble in the first place. So while our balance sheet will be strong enough to absorb any volatility, I'm going to be unapologetic when I say when Adam and my team commit capital to projects that earn enormous returns, we want to make sure we don't throw that away on false assumptions just because it's a rounding error on our balance sheet. That being said, as I alluded to in the beginning, I do think we will naturally leave more room for upside over time.

Yes. Appreciate the thorough and very powerful response Nick. That's all. Thanks.

Our next question is from Scott Hanold at RBC Capital Markets. Please proceed with your question.

Thanks and Nick, I'll just tell you this, I mirror your sentiment on that. I agree that I think the industry loses on hedges because they're more reactive and not proactive. So I appreciate your views. It's very insightful and fresh to hear. My first question is that Adam, I think you mentioned that there are some gas development projects that are getting moved into 2022 in that year, then moving some capital to oil properties. Can you just talk about that, give a little more detail that did EQT push out its development plan a little bit, and then for you guys to, I guess, move more capital to oil properties how does that logistically work with your elections? Do you just take a broader look at your opportunities there or just, it was just the nature of seeing more things come in that you could consent to?

Sure. As far as the Marcellus goes, we had roughly about 2.2 net wells added in early July. Initial plans for kind of a next pad were slated towards later in the year, call it Q4. We've since taken a look at plans there. And really, it's just a function of IRR and pricing realizations. And so we expect that pad effectively to be pushed into early next year. The Marcellus is effectively locked and loaded. We've got an annual work plan that we come to the table with every year, make tweaks based on the market rig availability, price realization. All those types of things and so that's effectively the plan for the foreseeable future from a Marcellus standpoint. As far as the activity levels, I mean, we've seen a significant increase both in the Bakken and the Permian, as operators are working on the DUCs. We've seen AFEs more than double in the second quarter. I was looking at just the third quarter to-date, and we've already got north of 40 AFEs in the door. And so I think we're going to continue to see that activity. Flex forward, I think our election rate during the quarter was north of 90%. And really focused towards our core operators we've got continental, plus all adding activity this quarter, and we received a slug of AFEs from Ovintiv, during the quarter as well, that we're expected to spot and start getting to work there. And that was acreage that we picked up from the flywheel acquisition and certainly encouraged by the results, I think they actually pointed out in their earnings release, talking about six months payout. So certainly one of our more efficient operators and love to see them kind of getting after things. As far as the ground game goes, that's going to obviously be a function of both the overall activity levels in the basin. But it's also going to be a function of overall competition and variability in overall returns. We’re going to continue to run sensitivities down commodity cycles and make sure that it's meeting our rate of returns.

And Scott, this is Mike, just want to clarify one thing with that Marcellus, while we're pushing out a little bit of activity, we're also pushing out that CapEx too. So it's going to be additive in terms of free cash flow for this year. And then also, it's just going to be additive from general economics and rate of return as you're bringing on first production in a period where you had higher basin realizations.

And Scott just the simplest way to think about it, is that we generally have a fixed amount of money we want to spend in any given period of time. And generally speaking, we have more opportunities than that capital. And so it's just a force ranking. And so with robust oil prices, obviously, the return profile for a lot of those properties is higher. And so we just shift some of the capital to that, and we move it from time to time.

That's right. It's the function of managing kind of inbound AFEs and ground game activity for deploying the capital as such.

Yes. And you can see that in our consent rate this quarter which is that we may have probably not consented or much of that stuff because it was unbudgeted. But when there's room in the budget for that, and the returns have increased markedly as they have, then it simply makes it a pretty simple mechanical.

Right. And again just Nick to that point on when you look at the Marcellus obviously, that we're talking EQT at this point. So the election to push into 2022 I'm assuming they made that versus you. Because, in fact, I mean, so the question would you not consent to this stuff that if you did want to push that forward this year?

I think given the fall period for differentials into the shoulder season, it wouldn’t have made sense for either of us. And we had numerous conversations about it and made all the sense in the world.

Yes. I mean, it's a true JV and so there's a much more collaborative approach. So we're having monthly and quarterly meetings discussing these things and making the decisions collectively. Yes. No, that's exactly I was looking for that.

Yes. I mean, if there was a disagreement on funding, it's been pure economics, right. So when you're doing something that's NPV and IRR enhancing? It's not a very difficult question. But certainly given the way that's structured, if we had some major disagreement, we, of course, could have expressed that, but we didn't.

Got it. No, that's great. I appreciate that. And then if I could ask a second question here and if I turned, I think it's page 7, you obviously show a very strong performance of wells so far year-to-date. And when you look at the mix of the wells you are consenting to, obviously, it said it stepped up pretty nicely. Where would you on this curve, kind of put that mix of wells where you'd expect based on where you're seeing some of those AFEs? Is it pretty consistent with that? Or should we expect just some minor degradation now that things are being, I guess, leveled across the base a little bit more now?

Yes. Hey Scott this is Jim. I think what the AFEs that we're seeing, the operators are still primarily focused in the core areas. I think they're taking a pretty conservative approach here. We have been any kind of the smaller operators add rigs to start drilling in tier two areas yet. So I think going for at least for the rest of this year, we would expect that well performance will continue kind of in line with what we've seen so far this year.

And I don't think you know, you're ever going to see well performance that equates to 2020 and probably any basin in the United States, just because so few were actually economic. So the wells that came online in 2020 were the best probably will be in U.S. history. But they're still well above our five-year average and pretty close to 2020.

Yes. I mean, I just point back to kind of the comments I just mentioned before. I mean, we would put a little bit higher probably than the top operator in the basin and they've got some of the most high well efficiencies that we've seen, and that activity will be able to flex going forward as well.

Our next question is from Jordan Levy with Truist Securities. Please proceed with your question.

Good morning guys and I appreciate the commentary. Just wanted to see if you could talk to the dynamics you're seeing in the bid-ask spread of both in the Bakken and in the Permian, and maybe the Marcellus as well, and how that's kind of evolved, as we've seen commodity prices move up?

Yes. I mean, it's, I guess, it's a little bit counterintuitive, but we've certainly seen folks chasing things. And it's a function of activity, as well as just opinion on oil pricing. So we've got competitors that are running $70 price decks, that's not something that we're going to be doing. But we've got quite a few swings at bat. And so really, it's just a function of managing the overall competitive landscape, the variability in economics and then being able to pivot between the different basins where we've got the exposure to. Obviously, there's a lot more activity and a lot more competition in the Permian. But based on the relationships and the contacts and overall activity levels, there's probably three or four deals that are walking in the door on a daily basis. Obviously, the Williston is a little bit suppressed in terms of activity levels relative to the Permian. But you're also having operators pick up rigs, and they're staying disciplined in the core of the basin. And it's not nearly as competitive and given our foothold there, as our backyard, our ability to gross up our working interests on well elections, all those types of things we just kind of forced rank the two of them amongst each other. And so that's kind of why you're seeing the barbell approach that we've taken.

Thanks. That's great color and kind of along similar lines, I just want to get your thoughts on what the pipeline looks like as it relates to deals where you can boost your interest in existing positions and also how you weight those when you're evaluating transactions versus new areas you're looking at?

Yes. I mean, I think we're pretty picky. There are a lot of assets testing the market. Some of them are appropriate, some are not. I'd say from a volume perspective, I thought our engineering team was going to die during the first half of the year and it has not let up. It's probably even more intense. And frankly, what that's meant is that for assets that are probably threshold, that maybe there is a good value, but they may not fit the bill, they are just getting passed on. But there are good prospects out there now than there were in the first half and we continue to work through each one. I think it's a fine line between the assets that make strategic sense and the things that you want, and also solving for relatively rigorous return thresholds. The one thing that we've highlighted last quarter and I would highlight again is that there are pockets of competition, and there are pockets where it becomes less competitive. And so as we continue to build size and scale, there are areas where we think we can get both high-quality assets and add good value, and that generally comes where the size of those prospects others can't be competitive on. And so I think we've mentioned as you get towards that $100 million mark, there are few of the wherewithal to write those kinds of checks today. And so I think that that's where we see our ability to create a lot of value. There are a lot of assets out to the market that we'd love to have, and it really just comes down to solving for price because at the end of the day, we don’t want to follow the path that many public companies have, which is that they have higher multiples. And so they pay those multiples to the sellers. At the end of the day, we want to buy them just like they would buy them in the market on a cash on cash basis.

Great, thanks. Thanks for taking my questions.

Our next question is from Nick Pope, who is a private investor. Please proceed with your question.

Morning everyone.

Nicholas, how are you?

Great. Hey, I was hoping you could talk a little bit about, I guess where things are from a working interest standpoint in the Williston specifically? And just I guess what the comfort level is on creeping up working interest versus where you guys operate now?

Yes. No. I mean I think like anything else, it's a risk-adjusted factor. Being in four out of every 10 wells that were drilled means that we have a large database. And so there are periods where we can get comfortable with higher-than-normal working interests, and there are places where we would not be. So we have units in which we have upwards of 50% working interest. And we're very comfortable in that, because these are core areas with core operators. And then there are parts where we would not take that risk. Smaller operators that may have midstream issues, or development risks, or their own balance sheet risks, and you want to make sure, but I do think that alignment is important. If you're taking a disproportionate amount of the risk, ultimately, depending on that operator to do, to be motivated to do the best job becomes a little bit riskier. And so we have many units, some of our units that came online towards the end of the second quarter are ones that we have worked with operators where we have upwards of 30% working interest. And I think it really just depends, but I think that that's a risk that goes into the underwriting factor, because the larger the working interest, the larger the single well risk, the larger the development risk is, frankly.

Sure. I think a corporate average is around year-to-date our wells added to production is around 9% in total, and the Williston may be a little bit higher. The Delaware. And to Nick's point, all we're doing is running sensitivities at different price decks. The other thing that plays into it, we want to flex up activity is the whole 3.0 kind of paradigm and reinvestment rates and obviously, a lot of these operators have chunky non-working interests and for a lot of our competitors having that type of exposure in one particular unit regardless of the overall well quality is something that they're not necessarily willing to take. And it could be a circumstance where it's more of a drop in the bucket based on our overall asset base. And so it provides an opportunity for us to pick up things that at more competitive prices as well. So really just running sensitivities and deploying capital as such.

Got it. I mean, I think that really kind of answers my question there. I mean, it was, it seems like a higher working interest. I wasn't sure what kind of participation level was for you guys here recently, and it definitely sounds like it's crept up. So that's helpful. Thank you.

Our next question is from Jim at Partners. Please proceed with your question.

Yes. I found it curious that you're not seeing any material inflation increase, just because I've been on a lot of calls and there seems to be a little bit of a creep with your competitors and various basins. Is that a function of productivity that you're seeing? Or is that just that you’re have a lot of competition for oil services and it's keeping the price low?

Some of it just has to do with think of it as the statistical average in the bell curve, which is that some of our operators who are active in development have worked really hard to work down their cost structures. And so our average has fallen as they become a bigger slice of the pie. The other factor is just that we never really budgeted for the downturn that was really experienced late last year. And so as Adam mentioned, in his call, we've been budgeting $7 million to $8 million in those numbers, and experiencing significantly less than that. So to the extent that there is inflation, that won't really affect our numbers because we never really set that bar at those levels.

Yes and then it's just a fun of the active management of the overall portfolio flexing to the most efficient operators. And so that's what you're seeing in this quarter.

Great. All right, thank you.

It is worth noting that we have effectively cut our budget three times this year, as we realized the delta between those two pieces. And so, in summary we got asked that question, last call. And obviously when we made the Permian acquisition, we reduced the base CapEx, alongside that, and obviously doing it again today.

Our next question is from Scott Hanold with RBC Capital Markets. Please proceed with your question.

Yes. I just got a follow up. You talked about seeing some opportunities across a number of basins. And certainly your focus has been Bakken, Permian so far, but like, can you give a little bit of color on other opportunities or areas you're seeing as the Eagle Ford popped up in there, has there been other basins that are of interest and can you remind us places that you wouldn't expect to see Northern pursue?

Yes. I mean I think we have seen a number of Eagle Ford transactions, and unfortunately none of them have really passed muster. And I think the issues with the Eagle Ford we really want the trifecta, which is we want assets that have solid base production, have a bunch of upside, and obviously have good economics. And so, in the Eagle Ford, generally, we've seen assets that are either in the tier two or tier three areas that are going to be very vulnerable to any price volatility or in the core areas, we've seen them; or they’ve had limited remaining inventory. And so that's really made it difficult to find the one that's in the right spot. But it is a play we've done a lot of work on and we have looked at them. Obviously, the Permian being the most active basin is dominant in terms of the actual deal flow of the Bakken and it's been surprisingly much busier than we've thought coming into this year, given the overall rig count. But obviously, that's been slowly but surely changing. And then I'd say there are basins that are a struggle and what I would say is that, like, if it was pure economics or rock alone, I think the DJ basin would be an area of focus. I think the political concerns make it difficult. I think the geologic and performance issues in the Anadarko basin make it largely a non-starter. That being said, sometimes these packages have assets in these basins that kind of come along with it. So to the extent we can value it at zero, I think we're fine with doing that, or at a deep, deep discount. But I don't think we would ever pursue assets based on those basins themselves.

Yes and we've taken a look at a handful of additional Marcellus packages as well, and you haven't been able to get them across the finish line. But there certainly they’re as well.

Yes. And so I don't want to make it seem like we're distracted. We're pretty focused on the basin of interest. Sometimes some of these portfolios might happenstance have assets in other places, and to the extent that they came along with it, so be it, but I don't think it would be an area of focus.

Got it. Thanks, Nick.

And we have reached the end of the question and answer session and this does conclude today's conference. To access the digital replay, please dial 877-660-6853 or 201-612-7415 and enter the access code 1372-1948. You may not disconnect your line at this time. Thank you for your participation.