Greetings and welcome to the Northern Oil Fourth Quarter and Year End 2022 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Evelyn Infurna, Vice President of Investor Relations. Thank you, Evelyn. Please go ahead.

Thank you, Paul. Good morning and welcome to our fourth quarter 2022 earnings conference call. Yesterday after the market closed, we released our financial results for the fourth quarter and fiscal 2022. You can access our earnings release and presentation on our Investor Relations website and our Form 10-K will be filed with the SEC within a few days. I'm joined here this morning by NOG's Chief Executive Officer, Nick O'Grady; our President, Adam Dirlam; and our Chief Financial Officer, Chad Allen; and our EVP and Chief Engineer, Jim Evans. Our agenda for today's call is as follows: Nick will provide his remarks on the quarter and on our recent accomplishments, then Adam will discuss an overview of operations. And Chad will review our fourth quarter financials and walk through our 2023 guidance. After our prepared remarks, the executive team will be available to answer any questions. 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 our forward-looking statements. Those risks include, among others, matters that we have discussed 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 today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA, adjusted net income and free cash flow. Reconciliations of these measures to the closest GAAP measures can be found in our earnings release. With that, I will turn the call over to Nick.

Thank you, Evelyn. I'd like to take a few moments to welcome Evelyn to the NOG team. Evelyn comes to NOG with tremendous amounts of capital markets and investor relations experience, and we're excited to have her on board. All right, I'll get down to it with five key points. Number one, business fundamentals are strong. We delivered strong results in the fourth quarter and the full year. Despite lower commodity prices and severe weather, we generated approximately $90 million of cash in the fourth quarter, and still we're within annual production guidance. As we entered Q1, the business is back online and building momentum driven by strong turn-in line activity in December. Number two, growth. The fourth quarter was incredibly busy for the company. We closed on three Permian acquisitions and in the first week of January, we closed on our Midland Petro transaction. In total, these represented over 750 million of closings and over 900 million in acquisitions announced in 2022, which should translate into more than 20% growth in our year-over-year production on a reduced diluted share account. This is following roughly 40% growth in 2022, all the more impressive given we are in a low growth era for most public energy companies. As the largest, best capitalized non-operator with superior data insight and an unmatched track record, we are proud to be the preferred partner to the public and private upstream community. NOGs differentiated positioning sets the stage for significant [Audio Gap] relative and absolute outperformance in 2023. We have transformed the company by diversifying and growing our footprint, enhancing the quality of our portfolio and meaningfully improving the strength of our balance sheet. Despite inflationary pressures, and lower current commodity strips, we expect to generate significant cash flow and production growth in 2023. Our disciplined…

Thanks, Nick. On both the operational and business development fronts, we finished off another transformational year and look to continue our growth trajectory into '23. In the fourth quarter turn-in lines beat our internal forecasts as we added nearly 20 net wells and completions return to a relatively balanced mix as the Williston and Permian accounted for a 60:40 split. While initial production results were outperforming internal estimates, winter weather in December impacted production by approximately 10,000 barrels a day. As normal operations return, we expect to receive much of the benefit of our fourth quarter adds moving into the first quarter. Looking further ahead, we anticipate a typical turn-in line schedule, with spuds front-end loaded and completions weighted toward the back half of the year. Given the pull forward in well completions during the back half of '22, our wells in process finished the year totaling 55.4 net wells, with the Williston accounting for roughly 80% of our WIPs, excluding our Marcellus ducts. That said, we added 6.8 net wells in process with the closing of our mascot project in January. And accordingly, we now expect new drilling activity levels to be equally weighted across the Permian and Williston for 2023. In the Marcellus, we have deferred most activity to 2024 as we focus on higher margin oil properties, but continue to look for ways through acreage trades, and other means to potentially add exposure in the back half of the year. Q4 well proposals on our organic acreage remained healthy as we received over 125 AFEs during the quarter, which accounted for roughly 10 net wells. The combination of our operators staying disciplined, and our acquisitions focused on the core of our respective basins led to a consent rate of approximately 95%. Economics also continued to improve as…

Thanks, Adam. I'll start by reviewing key fourth quarter results, which were solid across the board despite the impact of the recent winter storms. Our Q4 average daily production was 78,854 BOE per day, a 23% increase compared to Q4 of 2021. Well volumes were up 4% sequentially over Q3 and have normalized after the winter storms. Our adjusted EBITDA was 264.8 million in Q4, and top 1 billion for the year, a record for our company. Our fourth quarter free cash flow was robust at 87 million despite growing activity. And we generated almost 460 million of free cash flow in 2022, which has more than doubled the prior year. Our adjusted EPS was $1.43 per share in Q4, up roughly 35% year-over-year. Oil differentials were again better than internally expected in Q4 and came in at $2.42 per barrel, due to continued strong in basin pricing and have more barrels weighted towards the Permian, which are typically priced tighter. For the year, our differentials were $2.73 off WTI, a record low for the company, driven by improvements in North Dakota and the diversification of our business over the last several years. Natural gas differentials were 92% of benchmark prices for the fourth quarter, lower sequentially but better than our internal expectations. Lower natural gas and NGL prices drove the reduction a function of lower gathering cost absorption and lower NGL uplift, for the yearly average 113% of NYMEX. On the CapEx front, we invested 142.9 million during the quarter evenly split between the Williston and Permian basins. Activity has been robust. As Adam mentioned, before turn lines were up dramatically from the third quarter and provide strong momentum as we enter 2023. This has resulted in a D&C List of 62.2 net wells inclusive of the mascot project…

Thank you. [Operator Instructions]. Thank you. Our first question is from Neal Dingmann with Truist Security. Please proceed with your question.

Nick, my first question, for your Chad, this is on capital spend maybe specifically, we're modeling how should we think about your '23 CapEx sort of pre and post potential transactions or maybe asked another way, do you all assume there'll be at least a minimum amount of ground game additions that we should put in the model and just really trying to speak to CapEx versus production expectations this year?

We always leave room in our CapEx guidance or flex capital. So the ground game is in there. And that's so we can actively manage the portfolio throughout the year. Whether we use it or not, it depends on the [indiscernible] proposals that come in the door, what they're expected spudder sales times are in, compare that to the ground game opportunities that we're seeing day in, day out, so meaning we really wait of returns against one another. And so we may have the opportunity to high grade our drilling program and modify it, and we'll definitely take advantage if we do. I'd say, like any other year, it'll depend on what we're able to get done. And if they're compelling opportunities to flex forward, you know, through the ground game, but again, as I reiterate, we budgeted a pretty hefty amount in our base budget every year for that amount.

Okay, because you haven't upgraded the add, so I thought you all did, okay. And then just second really on Bakken activity. I'm just basically wondering, maybe for Adam, how stable -- more recently have no [indiscernible] plans have become and if you all receiving what I'd call more or less proposals, than a year ago, I asked that because obviously, a lot of the gas is getting -- gas guys are becoming very volatile. And some other plans are volatile. I'm just wondering if you're seeing a bit more stability, and maybe Bakken versus Permian and just wondering how the proposals have become more recently. Thank you.

Yes. I think you nailed that. And I think in the fourth quarter out 125 plus AFEs, we received about 100 of those were in the Williston. And so, looking at the end of the year, if we're looking at our oily basin, kind of makeup, that's about 80% of kind of the wells that are in process right now. And so we see that kind of humming along. They continue to add rigs and the operator makeup is certainly compelling as well. And we're partnering with the likes of [indiscernible] and Conoco. So we've been encouraged by the activity phase.

Yes, I would just say Neal, based on our guidance that we put forth today are, whether or not the Williston Basin grows as a whole or not, I would probably say it probably remains pretty stable. We're going to have record volumes in the Williston by a big measure this year.

That's right. And I think it's a function of the working interests and the concentration with some of our operators, we've got significantly larger working interests that we're stepping into here at the beginning of the year.

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

I think, one, maybe underappreciated factors is this new AI system that you all have? And it sounds like they are going to be coming, going more full bore on it now? Can you just give us some context on, what do you think this does to your pace? And maybe if, I don't know the right way to say, but quality of sort of your ground game and your potential acquisition activity, where do you see upside, like, when you do, back looks at what you did versus what now, with this system. Would have you made a change in strategic advantages to having this in place?

Yes. I mean, from a strategic standpoint, especially if we branched out into multiple different basins that the volume of opportunities coming at us is at an all-time high. And so we've got to be able to prosecute these evaluations and do it with conviction. And when you've got the volatility that you have from a commodity standpoint, as well as the inflationary pressures that ebb and flow, the fact that we've got north of 100 plus operators, all that information needs to be socialized, and it needs to be done quickly, in order for us to -- truly high grade and allocate capital appropriately. And so by instituting the AI program, we're able to take that real-time data and truly harness all the information that we have coming through the [indiscernible] and the revenue checks, as well as all the public data and do that with one source of truth. And so that's going to be the key to our success, as well, as you know, taking the look backs on the various transactions. I think we did one just recently, in terms of kind of the recent major acquisitions, and we were within about 2% to 3% of original underwriting.

Yes. The only color I would add to that is, we got 9000 gross wellbores at this point in the business. And the database has always been massive, it's always been the secret to our success, right? Being in half of every Williston well drilled means you have full bore of knowledge, but the speed of what you can access that data and harness it can take minutes now what would take our engineering team a week to come through in the past.

Okay. That's good to hear. And so, my next question is, just if you can be patient with me for a second because there's a couple pieces to it. But like, if I think about where natural gas prices are today, and obviously the entrance you all made into Appalachia, the first thing that stands out to me as if I look back, when you guys announced that acquisition, gas prices were about 250. And then they went to 910. And now back to 250. So yearly, they're kind of back to where it was when you made that acquisition. Two things on it. Do you think that this environment does it make it more ripe for opportunities? A new gas plays from a competitive sort of ability to make an acquisition. And number two, when you do your look back at the Marcellus scale you did. Do you like the returns in economics? I mean, there definitely was a step down in production versus where you originally expected. But do you think the all in returns still justified that move?

Yes. So I mean, to the latter point, Scott, that transaction, even net of all the hedging we did paid out in one year, meaning we got all our money back in one year of owning it, and it has 20 years of inventory on it. So the pace at which it goes, I would say, the pace has been slightly slower than we thought, but at the same time, the cost structure and well performance has been 20% or 30% better than what we underwrote. So net-net, we've done a lot better. And so, we're thrilled to have it is truly a call option. We were also thrilled that we're not developing it this year that development really is in 2024. And that's really important to us, because I don't, while it is economic today, I don't really think we want to develop our gas properties at $2 gas. But going back to the more there's a larger M&A question. I said we are basin and fuel agnostic, but convexity of returns does matter. For example, buying assets at $100 oil has a lot more risk, even if you're hedging it versus buying it at 50. And buying gas last year was pretty unattractive to us on a risk adjusted return because ultimately, there's a lot more that can go wrong than go right. And that goes back to when we bought the properties in early 2021. And so I would say as it pertains to gas, it appears to us at current that the longer term convexity on gas assets is very attractive. And that would play a role and we're certainly actively looking at gas properties day in day out.

Our next question is from Philip Johnson with Capital One.

Question for Chad. You mentioned the weak gas realizations that you're expecting for '23. That's pretty similar to what we saw yesterday from one of your Williston operators. You guys are obviously on a two-stream report here. But, obviously the big driver, there's weak NGL prices. And of course, realize there's a fixed component that's coming into play relative to lower NYMEX prices. But I guess the 75% to 85% of NYMEX seems pretty low. So I'm just wondering if you can maybe give us a little more insight as to what the driver is on there. And what's different about, this year versus last year, in addition to lower NGO prices?

Yes. I think what we're currently seeing right now is in -- we're probably down in even below that we're seeing some pickups from past months that kind of creeped us up to that 92%. But we're currently realizing at or below those, I guess, with respect to where we currently sit. I think, some of the struggles in the Permian, obviously, with gas takeaway is going to also kind of creep into, I guess 2023. And that's kind of where we're being a bit more conservative, I think, with respect to realizations of gas prices.

Yes. I mean, so there's like, it's kind of four-dimensional chess, right? You have your fixed gathering cost, getting it from wellhead to pipe that doesn't move. But as the price of gas goes down, that becomes a larger percentage. And then you have the price of the NGL basket, which swings wildly, because the actual yields from the plants changes depending on where the what the plants want to do, meaning, whether ethane is economic or not to extract it. And some people do it anyway. We will leave them nameless, but some people do it whether it is or not. You get more volumes, obviously. But you then -- if you're a three-stream reporter, but you're losing money. And I think the thing to think about, though, is that although NGL, prices came down in in the fourth quarter, gas prices really came down in the first quarter. And so actually, from a ratio perspective, the propane is an example it was about one and a quarter to one versus gas in the fourth quarter, but it's over two today. So that actually helps the percentage. And so really, the absolute price of the gas versus the NGL impacts that as much and so we tried to be really conservative, because we're not -- we don't have a crystal ball here in terms of where natural gas is going. I wouldn't say we're internally particularly bullish. But we tried to run it. And if you look at our track record in the past, we've historically been very conservative in this because these are non-controllable costs that we don't really want that there's no benefit to us by doing anything by taking a conservative run at it. But I do think there as Chad mentioned in his prepared comments, there are some -- there is some room for improvement throughout the year. And we'll update you accordingly.

Yes. Okay. That's helpful. On the reserve report, and just wondering if you can maybe share what your next 12-month PDP decline rate is, I guess, for both oil and gas. And, for us how that's changed relative to where you are in the past couple of years? I'm assuming it's come down a little bit, but just looking for the approximate magnitude or so.

Yes. So our base PDP decline is going to be in the low 30s to 32% to 34%. Obviously, as we go through the year, and we start bringing on some of these acquisitions, MPDC projects, those sorts of things are declining, right will increase throughout the year. So as we exit the year, we're probably going to be closer to mid-30s to high 30s and that kind of range, but that's kind of where we're starting out today.

[Operator Instructions]. Our next question is from John Abbott with Bank of America.

First question. Cascading DD&A came a little bit high for the fourth quarter with the mergers closing. How do you think about inappropriate DD&A rate, just sort of going forward?

Yes, John, we were just looking at that this morning. And I think, when we roll in PDC, and I think we're sitting right around 10.50 for kind of exit DD&A. I think MPDC will likely add a buck or two to it. So I think once we get that rolled in, are probably somewhere in the 11.50 to 12.50 range, I would guess.

Appreciate it. And then, the second questions on the acquisitions that you just sort of -- you're just closed on here. Any, you just got them in the door? Any pleasant surprises? Any changes in activity levels versus what you originally assumed?

Yes. I mean, I think maybe a few anecdotes to start first, like, a small anecdote like our first Midland acquisition that we closed in October performing exceptionally well. And we actually just did this look back this morning, and in aggregate, we are ahead of schedule and the assets are performing really well. As a non-operator, you just have to say like anything, this will change and pivot, depending on the environment. But we underwrite conservatively and focus on good geology. And so they should be relatively resilient. And so ultimately, while drilling schedules move around here and there, I don't think we expect any major surprises in 2023.

Our next question is from Donovan Schafer with Northland Capital Markets.

The first one I want to ask is, I know it is definitely way too early to get specific at all on guidance or any type of an outlook for 2024. Obviously, but I'm just wondering if you can talk about this at a much higher level, just broadly in terms of given the high level of M&A activity, that you've had including this quarter and the preceding four quarters? Is there any kind of in embedded growth in that that you would expect to translate into 2024 in terms of the cadence. Did you see rigs moving through that acreage? Yes, I know, maybe we assume -- if we assume something like an $80 oil price, roughly, just when you're looking at all that acquisition activity that you did, and you kind of hold things constant? Do you see that as something leading to incremental growth in 24 over 23? Or would growth in 24 over 23 need some additional kind of proactive activity on your guys' part?

Yes. I mean, I think the simplest way to say this and assuming, obviously, keeping costs constant for a second Donovan, if we spent the same levels of activity this year that we -- next year, we would certainly see growth. We do highlight this in our earnings presentation, but the effective roll off of some of that MPDC activity, and we what we try to highlight is, obviously, the guidance is for 91,000 and 96,000 barrels a day, you're obviously going to exceed that at some point as that project completes. And as Jim pointed out earlier, your decline rate is going to be a little bit higher as you kind of reach that zenith. But you need about [70] [ph] to that wells a year to kind of hold above 90,000 barrels a day flat, public wrote a little bit from that base over time. And so you're talking about $600 million to $700 million of sort of sustaining capital underneath that those levels. But obviously, our guidance is more like 750-ish this year. So if you continue to at those levels, you're going to grow, I will say, when you talk about one year to one year that the cadence of that spending really matters, too, right? So because you're going to carry forward those barrels into a year. So not all dollars are equal, but that should be some good goalposts for you.

Okay, great. Yes, that's very helpful. And then, if I could get another -- for second question, I know that it might seem a little bit like a bit of an oddball question. And when you probably haven't gotten in a while, but I am curious to know if you would ever consider taking non-op positions outside of these U.S. shale plays. There are still some conventional onshore opportunities in there. And then, you have things like Gulf of Mexico or Canada or moving somewhere international. And I know you don't -- certainly wouldn't fit into a core competency, or you have this real differentiated knowledge base. But of course, building yet to start somewhere to build that knowledge. And so I'm just curious if you think about stepping out into some of these other areas, doing a little like a small degree of dabbling to build that knowledge base. I'm just curious to know just how you think about that.

Well, I will agree, that is an oddball question. But the answer is, I don't think so. I mean, I think we've seen a handful of Canadian opportunities on our way, and they've never made it past the email inbox. I think, we take great pride, and we take this really seriously about having technical knowledge. We spent over two years in the Permian before we bought 60 acres, right? And so if you're going to do something, you need to do it well, and I think that, we've seen this one, we've been shopped conventional opportunities in the United States which is within this country. And those are just simply, our technical team is focused elsewhere. And so we want to focus on what we're good at. So I'd say that's a relatively low probability outcome for us.

Yes. I guess to frame it up a little bit differently. In terms of the M&A landscape, I think the most interesting opportunities that we're seeing currently are within the basins that we're already in. And that's not to say that we're not canvassing different basins within the lower 48. Because we look at the Eagle Ford, we look at the Haynesville, we've looked at the DJ, we've looked in other basins in that regard, but I think even stepping out into any of those basins, you're going to have to have a hurdle rate that's going to need to be compelling in order for us to dedicate significant resources to that. And so I think we'll continue to keep our ear to the ground and take a look at these other basins from a shale standpoint, but even then, it's going to have to be a higher bar.

Okay. Thank you. That's very helpful. Just a good touch point for me, kind of driving that point home, so thank you. Good to know. And that's it for me. Thanks, guys.

Our next question is from Noel Parks with Tuohy Brothers.

Start with couple of things, was interesting to hear you say that the longer-term outlook is making you see gas assets as very attractive with this pullback and you're certainly looking at those properties. So I'm just wondering, as you do your evaluation process, how do you sort of weight the issue of getting more concentrated and saying gassy assets incrementally versus infrastructure uncertainty? How do you sort of fit that into your model?

I mean, I think it all goes in there. I mean, the number one we don't -- we certainly don't pick some esoteric gas price that we think it should go to, to underwrite these things. You have to underwrite them by based on the world you're living in now, and then stress that further. I'd say that infrastructure is really important. Just using the example, when we underwrote our Appalachian properties. We certainly never model in growth, just given the infrastructure constraints within that base. And then, we ran pretty punitive differential analysis, when we went through that. I'd say basins that were not in, use the Haynesville as an example where, we've observed, as it's grown materially, in the last few years, that infrastructure has gotten really tight. We also did the same thing when we were looking in the Permian, recognizing the same thing. And so our internal analysis factor in sometimes differentiated views on those things. We've suffered through infrastructure constraints and every basin we operate in. And the key thing is to understand what short-term and what's long-term and what's going to have a meaningful impact on the actual value of the properties.

Got you. Fair enough. And just wondering, apologies if you've touched on this before. Are you --on the path to maybe going non-consent on more of what gets refers to you in for example, Appalachia or other places weight a little bit gassier.

Yes. I mean, in Appalachia, the good news is that we have a multi-year program with [indiscernible]. And it's more happenstance than a function of the gas environment, but there are no completions this year. So there'll be minimal CapEx, we may expend some drilling CapEx as we prepare for the 24 plan at the end of the year, but not a ton.

Yes, it's much longer term planning. I think we're going to see the non-consent lever getting pulled or not getting pulled is going to really depend on inflation and how that interacts with commodity prices. And then obviously, depending on who the operators are, because at the end of the day, we're an IRR, driven shop, right? And so if you have a gap down and commodity pricing, but inflation stays stickies, and there's going to be things that, may or may not meet our hurdle rate. The good news is that most operators think relatively disciplined in terms of sticking to the core. And so I think you've got some buffer in that regard, versus a lot of the science experiments that we've seen in cycles past.

Yes. And just to elaborate on that, Noel, like, as an example. We came into the Permian later where the delineation has been largely made. And so we don't have a ton of acres in areas that are non-core, we're going to be really subject to some of those things to my advice, as you see now. And the Williston well because we have a large legacy position, we own a lot of non-core properties to [indiscernible]. They're just not being developed. And so it allows the operators in some ways are doing the work for us.

Thank you. Ladies and gentlemen, we have reached the end of our question-and-answer session. I'd now like to turn the call back to Nick O'Grady, CEO for closing remarks. Over to you sir.

Thanks, everyone, for joining us today. We'll work really hard to execute on the 2023 plan and we'll see you on the next quarter.

Thank you. To access the digital replay, please dial 877-660-6853 or 201-612-7415 and enter access code 13736011. I repeat 13736011. Ladies and gentlemen, this concludes today's conference. You may disconnect your lines at this time and thank you for your participation.