Greetings, and welcome to the Northern Oil Q4 and Year-End 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star 0 on your telephone keypad. 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, welcome to our Q4 2022 earnings conference call. Yesterday, after the market closed, we released our financial results for the Q4 and fiscal 2022. You can access our earnings release and presentation on our investor relations website. Our Form 10-K will be filed with the SEC within a few days. I'm joined here this morning by Energy's Chief Executive Officer, Nick O'Grady, our President, Adam Dirlam, 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. 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've 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'll 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. 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 Q4 and the full year. Despite lower commodity prices and severe weather, we generated approximately $90 million of cash in the Q4 and still were within our annual production guidance. As we enter Q1, the business is back online and building momentum, driven by strong turn-in-line activity in December. Number two, growth. The Q4 was incredibly busy for the company. We closed on three Permian acquisitions. 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 count. 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. NOG's differentiated positioning sets the stage for significant 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 and efficient transaction underwriting, prudent and sophisticated capital formation, and superior data insights have driven, and we expect will continue to drive, consistent multi-year equity outperformance. Number three, the 2023 outlook. Our 2023 guidance, which Chad will delve into later, reflects capital efficient growth, conservative cost inflation assumptions, and as I just mentioned, significant and differentiated volume and cash flow growth throughout the year. At our new elevated level of baseline production, we expect to generate significant levels of free cash flow in 2023. As the Mascot Project reaches completion, it sets the stage for a substantial increase in free cash flow in the coming years, enabling us to further accelerate the company's growth and enhance shareholder returns. Number 4, competitive advantage. We believe our competitive advantage has expanded in 2022. Over the last 4 years, we've not only rebuilt our infrastructure, augmented the financial strength, and improved the asset positions of the company, but have also invested in data science to continuously improve our technical analysis. With the launch of our purpose-built AI-powered system in January, we expect to further enhance the power of our proprietary data and the accuracy and efficiency of our decision making. More specifically, we believe our enhanced analytics will enable us to efficiently find differentiated value in properties and further enhance our risk management tools. Our team does not rest on its laurels, and we believe we are unmatched in the non-operated sphere given our scale, data analytics and underwriting advantages. We believe that few can compete with us for the high-quality properties that we target daily, and our scale allows us to play in a field largely on our own. As the breadth of opportunities has expanded for us, both from a basin and structural basis, our competitive advantage has only widened. Number five, shareholder returns. Our goal is to provide our shareholders with the highest possible total return over the long term. We have implemented a multi-pronged approach, including share repurchase programs, repurchasing high cost debt, and increasing the cash dividends for our common shareholders. During the Q4, we continued to tactically repurchase our common stock and senior notes. As market opportunities allow, we will continue opportunistic common buybacks and debt repurchases throughout 2023 and beyond. A few weeks ago, we announced a 13% increase in our quarterly common stock dividend to $0.34 per share for the first quarter, and introduced a plan to accelerate the dividend further to our target of $0.37 per share about two quarters ahead of schedule. We continue to have the goal of providing an attractive yield for our investors. We strongly believe that the consistency of a stable and growing quarterly dividend is more valuable to our shareholders and our equity value over the long term. Our Goldilocks strategy should give us the ability to both pay healthy, growing current income to our shareholders, and also allow for our significant excess retained cash flow to provide for value-added bolt-on acquisitions and growth opportunities. Going forward, we will remain focused on driving the highest total return to shareholders, focusing on optimal yield, tax and capital efficiency, and management of our overall leverage levels. The good news is, with the business positioned for strength, we anticipate being able to deliver continued growth to our returns while still leaving room for flexibility and the ability to scale the business responsibly over time. 2022 was another evolutionary leap forward for NOG, and I want to recognize the NOG team from top to bottom for their hard work and dedication to all we've accomplished. In closing, I'll remind you, as I always do, that we are a company run by investors for investors, and I wanna thank you all for taking the time to listen to us today. With that, I'll turn the call over to Adam. Thanks, Nick. On both the operational and business development fronts, we finished off another transformational year and look to continue our growth trajectory into 2023. In the fourth quar, turn-in-lines beat our internal forecasts as we added nearly 20- net wells, and completions returned 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 Q4 adds moving into the Q1. 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 2022, 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 DUCs. 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 we saw estimated IRRs increase by over 25% relative to our Q3 well proposals. As we think about well costs going forward, it has been encouraging to see a deceleration in inflation, which broadly aligns with the conversations that we've had with our operators. We do expect, and have seen, some creep from some of our lowest cost operators in the Williston as long-dated service contracts roll off. This has been offset by a steadier state in the Permian, which has kept our overall AFE inflation modest. We anticipate those minimal increases from leading edge indicators at year-end to carry over into 2023, which results in an estimated 7.5% inflationary increase at the midpoint. As Nick alluded to earlier, the Q4 was extremely busy for the business development team as we worked to close some of the most impactful acquisitions in company history. The $750 million of M&A completed in Q4 and Q1 has deepened our exposure to top-tier inventory with the addition of approximately 8,000 net acres in the Permian. Overall, our 2022 closed acquisitions and ground game activity added approximately 125 high quality, low break-even net future locations to our inventory, and 15% to our proven reserves, which increased to an estimated net 330 million barrels of oil equivalent. Note that our year-end reserves exclude the impact of the recently closed Midland Petro acquisition. Midland Petro represents an important evolution in our M&A strategy. The transaction showcased Northern's scale and ability to provide creative capital solutions for our operating partners while generating best-in-class returns. On the heels of our announced joint development agreement, we have been approached by multiple operators trying to find solutions for existing assets and desired development plans, as well as partnership opportunities to co-bid and acquire operated assets. Not only are we one of the few non-operators with scale and a balance sheet to help move the needle pursuing large-scale acquisitions, we also have the data insights to underwrite with conviction and participate alongside our operators as a low maintenance partner. These competitive advantages have established NOG as a partner of choice in pursuing operated assets and at the same time broadened the opportunity set available to us. As we move into 2023, the M&A backlog is spooling, and we are reviewing more than $5 billion in non-operated packages, operated packages, and joint development opportunities. While there are more prospects than ever available to us, our colors have not changed. We remain laser focused on our consistent approach to capital allocation and our ground game. In the fourth quarter, we closed on 1.2 net wells and 127 net acres, finishing our 2022 ground game efforts, acquiring 8.7 net wells and over 1,400 net acres across 24 transactions. As we look ahead to 2023, we are seeing a variety of compelling opportunities across our respective basins. We will actively manage the portfolio in order to build on an already high-graded drilling program and maintain our superior return on capital employed. With that, I'll turn it over to Chad. 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. Oil volumes were up 4% sequentially over Q3 and have normalized after the winter storms. Our adjusted EBITDA was $264.8 million in Q4 and topped $1 billion for the year, a record for our company. Our fourth Q4 free cash flow was robust at $87 million despite growing activity, we generated almost $460 million of free cash flow in 2022, which is more than double the prior year. Our adjusted EPS was at $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, with a continued strong in-basin pricing and having 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 year, they averaged 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, Q4 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 and has contributed to the pull forward of our capital spending, along with the continued success of our high return ground game investments. The balance sheet remains strong. We closed the $500 million convertible notes offering in the Q4 to fund, in part, our recent acquisitions. As you may recall, due to the features we selected, there will be minimal to potentially zero dilution to our existing holders. To the extent there is, the company has options to manage this over time. In addition to the convertible notes offering, we're able to expand the capacity of our revolving credit facility to $1 billion from $850 million, reflecting the growth in our borrowing base to $1.6 billion from $1.3 billion. As a result of our M&A activity, we flexed our balance sheet for the announced transactions in the Q4, and our leverage will be modestly higher over the next couple quarters, but well within our comfort zone. Our net- leverage- ratio should return to normal levels by the end of 2023 as our acquisitions contribute to our operations and we're able to organically de-lever. Liquidity remains strong, and we still have over $1 billion of dry powder in the form of unused revolver and borrowing base capacity. In 2022, we retired $25.8 million of our 2028 notes, and we'll continue to look for ways to efficiently reduce leverage if market opportunity arises. With respect to hedging, since our last report, we opportunistically added volumes in the form of attractive costless collars that provide downside protection with the optionality of participating in the upside if prices rally. We continue to hedge volumes from each closed and pending acquisition based on our conservative hedging strategy of 55%-65% of expected production on a rolling 18-month basis. As it pertains to our 2023 guidance, with our run rate CapEx from 2022 of approximately $500 million largely carrying over, capital plans from our 2022 acquisitions of approximately $220 million layered in, and $25-$50 million of in-service cost inflation. This translates to a range of $737 million-$778 million total CapEx guidance for 2023. From a cadence perspective, we expect approximately 60% of our annual spend will occur in the H1 of the year. We wanna point out that only approximately $25 million-$60 million that is specifically associated with the build-out of our Mascot Project is expected to reoccur in 2024. We do expect to see continued inflation in the first half of 2023, the decline in natural gas prices and subsequently, what appears to be the beginnings of a reduction in overall rig count, which is down approximately 25 from the peak in the United States, could lead to cost savings in six to nine months if the current trend stays in place. Additionally, we've seen de-bottlenecking in sand tubulars and added pressure pumping capacity, all green shoots towards stabilization or reduction in cost as the year progresses. Regarding our 2023 production guidance, we expect to start the year at a range of 84,000-86,000 BOE per day in Q1, improving each quarter with a target Q4 exit rate of 96,000-100,000 BOE per day. Overall, the quarterly production should translate to an average range of 91,000-96,000 BOE per day for the full year. With respect to the Q1, we typically see seasonal organic declines and accordingly guide conservative given the end of winter in the Williston. We do expect strong activity throughout the year to drive that higher exit. On differentials, we're taking a conservative view given the recent downtick in natural gas prices and typical volatility of in-basin oil pricing. We believe that there's room for improvement potentially as the year goes on. LOE and G&A should be largely consistent with 2022, adjusted for inflation in operating and public company costs. I'll turn the call over to the operator for Q&A. Thank you. We'll now be conducting a question-and-answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. One moment please, while we poll for questions. Thank you. Our first question is from Neal Dingmann with Truist Securities. Please proceed with your question. Morning, all. Thanks for all the details. Nick, my first question, for you to address is on capital spend or maybe specifically, you know, we're modeling, how should we think about your 2023 CapEx sort of pre and post potential transactions? 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, you know, just really trying to speak to CapEx versus production expectations this year. You know, 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 cadence of well proposals that come in the door, what their expected sputter sales times are and, you know, compare that to the to the ground game opportunities that we're seeing day in, day out. Meaning we really weight the returns against one another. And so we may have the opportunity to high grade our drilling program and modify it, you know, and we'll definitely take advantage if we do. I'd say, you know, like any other year, it'll depend on what we're able to get done, and if there are compelling opportunities to flex forward, you know, through the ground game. You know, again, as I reiterate, you know, we budget a pretty hefty amount, in our base budget every year for that amount. Okay. Yeah, great. Yeah. I thought you all did. Okay. Then just second, really on Bakken activity. I'm just specifically wondering, maybe for Adam, how stable more recently have most of your operator plans have become? You know, if you all are receiving, you know, what I'd call more or less proposals than a year ago. You know, I ask that because obviously a lot of the gas guys are becoming very volatile and, you know, some other plans are volatile. I'm just wondering if you're seeing a bit more stability in maybe Bakken versus Permian and, you know, just wondering how the proposals have become more recently. Thank you. Yeah, I think you nailed it. I think in the Q4, out of the, you know, 125 plus AFEs we received, about 100 of those were in the Williston. You know, looking at the end of the year, if we're looking at our oily basin, kinda makeup, that's about 80% of kind of the wells that are in process right now. We see that kinda humming along, they continue to add rigs and the operator makeup is certainly compelling as well when we're partnering with, you know, the likes of Ovintiv and Continental and Conoco. We've been encouraged by the activity pace. Yeah. I would just say, Neal, based on our guidance that we put forth today, our, you know, whether or not the Williston Basin grows as a whole or not, I would probably say it probably remains pretty stable. We're gonna have record volumes in the Williston by a big measure this year. That's right. I think it's a function of the you know the working interest 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. Great to hear. Thanks, boys. Thanks, Neal. Thank you. Our next question is from Scott Hanold with RBC Capital Markets. Please proceed with your question. Hey, thanks. You know, I think one, you know, maybe underappreciated factor is this new AI system that you all have, and it sounds like you're gonna be going more full bore on it now. Can you just give us some context on, you know, what do you think this does to your pace and, you know, maybe if... I don't know if it's the right way to say it, but quality of sort of your ground game and your potential acquisition activity? Where do you see upside? Like, when you do, you know, back looks at what you did versus what you know now with this system, you know, would have you made a change in, you know, are there strategic, you know, advantages to having this in place? Yeah. I mean, I think from a strategic standpoint, especially as we've branched out into multiple different basins, the volume of opportunities coming at us is at an all-time high. So we've gotta be able to prosecute these evaluations and do it with conviction. When you've got the volatility that you have from a commodity standpoint, as well as, you know, the inflationary pressures that ebb and flow, the fact that we've got north of, you know, 100+ operators, all of that information needs to be socialized, and it needs to be done quickly in order for us to, you know, truly high grade it, you know, and allocate capital appropriately. By instituting, you know, the AI program, we're able to take that real-time data and truly harness all the information that we have coming through, you know, the jibs and the revenue checks, as well as all the public data, and do that with one source of truth. That's gonna be, you know, 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 you know, major acquisitions, and I think we were within about 2%-3% of original underwriting. Yeah. The only color I would add to that is, you know, you got 9,000 gross wellbores at this point in the business. 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 which you can access that data and harness it, you know, can take minutes now, what would take our engineering team a week to comb through in the past. Okay. That's, that's good to hear. My next question is, you know, just if you could be patient with me a second 'cause there's a couple pieces to it. 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 is if I look back when you guys announced that acquisition, gas prices were about $2.50, then they went to $9, $10, and now back to $2.50. Eerily, they're kinda back to where it was when you made that acquisition. Do you think, you know, two things on it? Do you think that this environment, does it make it more ripe for opportunities on new gas plays, from a competitive sort of ability to make an acquisition? Number two, when you do your look back at the Marcellus deal you did, you know, do you like the returns on economics? I mean, there definitely was a step down in, you know, production versus where you originally expected, but do you think the all-in return still justified that move? Yeah. 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. The pace at which it goes, I would say, you know, the pace has been slightly slower than we thought. At the same time, the cost structure and well performance has been 20% or 30% better than what we underwrote. Net-net, we've done a lot better. You know, we're thrilled to have it. It is truly a call option. We're also, you know, thrilled that we're not developing it this year, that development really is in 2024. That's really important to us 'cause I don't, you know, while it is economic today, I don't really think we want to develop our gas properties at $2 gas. You know, going back to the larger M&A question, I said, you know, we are basin and fuel agnostic, but convexity of returns does matter. You know, for example, buying assets at $100 oil has a lot more risk, even if you're hedging it versus buying it at $50. 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 that can go right, and that goes back to when we bought the properties in early 2021. 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. Thanks for all that. Thank you. Our next question is from Philip Johnston with Capital One. Please proceed with your question. Johnston, is your line on mute? Yeah, sorry about that. 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 know, you guys are obviously on a two-stream report here, but, and, you know, obviously a big driver there is weak NGL prices. I, of course, realize there's a fixed component that's coming into play relative to lower NYMEX prices. I guess the 75%-85% of NYMEX seems pretty low. I'm just wondering if you can maybe give us a little more insight as to what the drivers are there and what's different about, you know, this year versus last year, you know, in addition to lower NGL prices? I think what we're currently seeing right now is in. You know, we're probably down in the even below that. We're seeing some pickups from past months that kinda creeped us up to that 92%. You know, we're currently realizing, you know, at or below those, I guess, with respect to where we currently sit. I think, you know, some of the struggles in the Permian, obviously with gas takeaway is gonna also kinda creep into, you know, I guess 2023, and that's kinda where we're being a bit more conservative, I think, with respect to realization of gas prices. I mean, Johnston, there's like. It's kinda four-dimensional chess, right? You have your fixed gathering cost, getting it from wellhead, you know, to pipe. That doesn't move. As the price of gas goes down, that becomes a larger percentage. Then you have the price of the NGL basket, which swings wildly because the actual yields from the plants changes depending on what the plants wanna do, meaning whether ethane is economic or not to extract it. Some people do it anyway. We'll leave them nameless, but some people do it whether it is or not. You get more volumes obviously, but then you, if you're a three-stream reporter, but you're losing money. I think the thing to think about though is that although NGL prices came down in the fourth quarter, gas prices really came down in the first quarter. Actually from a ratio perspective, you know, use propane as an example, it was about 1.25 to 1 versus gas in the fourth quarter, but it's over 2 today. That actually helps the percentage. Really the absolute price of the gas, versus the NGL impacts that as much. We try 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 try to run it. 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. There's no benefit to us by doing anything but taking a conservative run at it. I do think there, as Chad mentioned in his prepared comments, there is some room for improvement throughout the year, and we'll update you accordingly. Yeah. Okay. That's helpful. On the reserve report, I'm just wondering if you could maybe share what your next 12-month PDP decline rate is, for, I guess, for both oil and gas. You know, perhaps, you know, how that's changed relative to where you were 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. Our base PDP decline is gonna be in the low thirties, you know, 32% to 34%. You know, obviously as we go through the year and we start bringing on some of these acquisitions, the MPDC projects, those sorts of things, our decline rate will increase throughout the year. As we exit the year, you know, we're probably gonna be closer to mid-thirties to high thirties in that kinda range. That's kinda where we're starting out today. Okay. Makes sense. Thanks, guys. As a reminder, if you would like to ask a question, please press star one on your telephone keypad. The confirmation tone will indicate your line is in the question queue. Our next question is from John Abbott with Bank of America. Please proceed with your question. Hey, good morning. Thank you for taking our questions. First question's a bit of housekeeping. You know, DD&A came in a little bit high for the Q4 with the mergers closing. How do you think about an appropriate DD&A rate just sort of going forward? Yeah, John, we were just looking at that this morning. I think, you know, when we roll MPDC in, I think we're sitting right around $10.50 for kind of exit DD&A. I think MPDC will likely add $1 or $2 to it. I think, you know, once we get that rolled in, it will probably be somewhere in the $11.50 to $12.50 range, I would guess. Appreciate it. The second question's on the acquisitions that you just closed on here. You know, you just got them in the door. Any pleasant surprises? Any changes in activity levels versus what you originally assumed? Yeah, I mean, I think, you know, you know, maybe a few anecdotes to start first, like, you know, a small anecdote like our, our first Midland acquisition that we closed in October is performing exceptionally well. We actually just did this look back this morning in an aggregate. You know, we are ahead of schedule, and the assets are performing really well. You know, as a non-operator, you know, you just have to say, you know, like anything, this will, you know, change and pivot depending on the environment. We underwrite conservatively and, you know, focus on good geology. You know, they should be relatively resilient. Ultimately, while drilling schedules move around here and there, I don't think we expect any major surprises in 2023. I appreciate it. Thank you for taking our questions. Thanks, John. Thank you. Our next question is from Donovan Schafer with Northland Capital Markets. Please proceed with your question. Hey, guys. Thanks for taking the questions. The first one I wanna ask is, you know, I know it is, you know, definitely way too early to get specific at all on guidance or any type of an outlook for 2024, you know, obviously. I'm just wondering if you can talk about this at a much higher level, just broadly in terms of, you know, given the high level of M&A activity, that you've had, you know, a lot, you know, including this quarter and the preceding four quarters, is there any kind of, you know, embedded growth in that that you would expect to translate into 2024 in terms of, you know, the cadence you see rigs moving through that acreage? You know, I know, you 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 kinda hold things constant, do you see that as something leading to incremental growth in 2024 over 2023? Would growth in 2024 over 2023 need some, you know, additional kind of proactive activity on your guys' part? Yeah, I mean, I think the simplest say, and, you know, way to say this and assuming obviously, you know, keeping costs constant for a second, Donovan, if we spent the same levels of activity this year next year, we would certainly see growth. You know, we do highlight this in our earnings presentation, but the effective roll-off of some of that MPDC activity, you know, what we try to highlight is, you know, obviously the guidance is for 91,000 to 96,000 barrels a day. You're obviously gonna, you know, exceed that at some point as that project completes. And as Jim pointed out earlier, your decline rate is gonna be a little bit higher, as you kinda reach that zenith. They'll... You know, you need about 70 net wells a year to kinda hold above 90,000 barrels a day flat and probably grow it a little bit from that base over time. You're talking about $600 million to $700 million of sort of sustaining capital underneath at those levels. Obviously, we're, you know, our guidance is more like, you know, $750-ish this year. If you continued at those levels, you're gonna grow. I will say when you talk about, you know, 1 year to 1 year, the cadence of that spending really matters too, right? You know, 'cause you're gonna carry forward those barrels into a year, so not all dollars are equal, but that should be some good, you know, good goalposts for you. Okay, great. Yeah, that's very helpful. If I could get another for a second question. I know this, it might seem a little bit like a bit of an oddball question, and one you probably haven't gotten in a while. I am curious to know if you would ever consider taking non-op positions outside of these U.S. shale plays. You know, there are still some conventional onshore, you know, opportunities here and there. You know, you have things like, you know, Gulf of Mexico or Canada or, you know, moving somewhere international. I know you don't, that certainly wouldn't fit into a core competency where you have this real differentiated knowledge base. Of course, you know, you have to start somewhere to build that knowledge. 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. The answer is I, I don't think so. I mean, I think, you know, I think we've seen a handful of Canadian opportunities on our way, and they've never, you know, never made it past the email inbox. I, 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? So you gotta do if you're gonna do something, you need to do it well. I think that, you know, we've seen this when we've been shopped conventional opportunities in the United States which is within this country, those are just simply our technical team is focused elsewhere, so we wanna focus on what we're good at. I'd say that's a relatively low probability outcome for us. Yeah. I guess to frame it up a little bit differently in terms of an M&A landscape, I think, you know, the most interesting opportunities that we're seeing currently are within the basins that we're already in. 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, you know, in other basins in that regard. I think even stepping out into any of those basins, you're gonna have to have a hurdle rate that's gonna need to be compelling in order for us to dedicate, you know, significant resources to that. I think we'll continue to keep our ear to the ground and take a look at, you know, these other basins, you know, from a shale standpoint, but even then, it's gonna have to be a higher bar. Okay. Thank you. That's very helpful. Just a good touchpoint for me, kind of, you know, driving that point home. Thank you. Good to know. That's it for me. Thanks, guys. Thanks, Donovan. Thank you. Our next question is from Noel Parks with Tuohy Brothers. Please proceed with your question. Hi, good morning. Morning, Noel. Just a couple things. Was interesting to hear you say that the longer-term outlook is making you see gas assets as very attractive, you know, with this pullback, and that you're certainly looking at those properties. I'm just wondering, as you do your evaluation process, how do you sort of weight the issue of, you know, getting more concentrated, say, in gassy assets incrementally, versus infrastructure uncertainty? How do you sort of fit that into your model? Well, I mean, I think it all goes in there. I mean, number one, we don't, you know, we certainly don't pick some, you know, esoteric gas price that we think it should go 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, you know, infrastructure's really important. You know, just using an example, when we underwrote our Appalachian properties, we certainly never model in growth just given the infrastructure constraints within that basin, and we ran pretty punitive differential analyses when we went through that. I'd say in, you know, basins that we're not in, use the Haynesville as an example where, you know, we've observed, you know, as it's grown materially in the last few years, that infrastructure's gotten really tight. We also did the same thing when we were looking in the Permian, recognizing the same thing. Our internal analyses factor in sometimes differentiated views on those things. You know, we've suffered through in-infrastructure constraints in every basin we operate in. The key thing is to understand what's short term and what's long term and what's gonna have a meaningful impact on the actual value of the properties. Gotcha. Fair enough. Just wondering. Apologies if you touched on this before. Are you on the path to maybe going non-consent on more of what gets proposed to you in, for example, Appalachia, you know, or other places that weight a little bit gassier? Yeah. I mean, in Appalachia, the good news is that, you know, we have a multiyear, you know, program with EQT, and it's more happenstance than a function of the gas environment. There are no completions this year, so there'll be minimal CapEx. We may spend some drilling CapEx as we prepare for the 2024 plan at the end of the year, but not a ton. Yeah, it's much longer term planning. I think where you're gonna see, you know, the non-consent- lever getting pulled or not getting pulled is gonna really depend on inflation and how that interacts with commodity prices. Then obviously depending on, you know, who the operators are, 'cause at the end of the day, we're in a IRR-driven shop, right? If you have a gap down in commodity pricing but inflation stays sticky, then there's gonna be things that, you know, may or may not meet our hurdle rate. I think the good news is that most operators are staying relatively disciplined in terms of sticking to the core. I think you've got some buffer in that regard versus a lot of the science experiments that we've seen in cycles past. Yeah. And just to elaborate on that, Noel Parks, like, as an example, we came into the Permian later, where the delineation had been largely, you know, made. So we don't have a ton of acres in areas that are non-core or gonna be really subject to some of the swings in commodity prices you see now. In the Williston, well, because we have a large legacy position, we own a lot of non-core properties to Evan's point. They're just not being developed. The operators in some ways are doing the work for us. That's right. Great. Thanks a lot. Yep. Thank you. 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. 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.