Greetings, and welcome to the NOG's fourth quarter and full year 2023 earnings conference call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If you would like to ask a question during this time, simply press the star key followed by the number one on your telephone keypad. If you would like to withdraw your question, press star one again. As a reminder, this conference is being recorded. It's now my pleasure to introduce your host, Evelyn Infurna, Vice President, Investor Relations. Thank you. You may begin. Good morning. Welcome to NOG's fourth quarter and year-end 2023 earnings conference call. Yesterday, after the close, we released our financial results for the fourth quarter and full year. You can access our earnings release and presentation on our investor relations website at noginc.com. Our Form 10-K will be filed with the SEC within the next several days. I'm joined this morning by our Chief Executive Officer, Nick O'Grady, our President, Adam Dirlam, our Chief Financial Officer, Chad Allen, and our Chief Technical Officer, Jim Evans. Our agenda for today's call is as follows: Nick will provide his remarks on the quarter and our recent accomplishments. Then Adam will give you an overview of operations and business development activities, and Chad will review our financial results and walk through our 2024 guidance. After our prepared remarks, the team will be available to answer any questions. Before we begin, let me go over 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 described in our earnings release as well as 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. Welcome, and good morning, everyone, and thank you for your interest in our company. I'll get right to it with four key points to start the year. Number one, scoreboard: execution, delivering growth and profits. On our second quarter call, I spoke about the importance of delivering growth and profitability year-over-year. I'd like to use that framework today to put the results from the fourth quarter into context. Our fourth quarter Adjusted EBITDA was up 52% year-over-year, and our quarterly cash flow from operations, excluding working capital, was up 55% year-over-year. Over this same period, our weighted average, fully diluted share count was up about 17%, significantly less, reflecting the impact from our October offering, but not the impact of our fourth quarter bolt-on deals. We achieved outsized growth in profits despite a more challenging commodity backdrop than the prior year. Oil prices were down over 5%, and natural gas prices were down 52% versus the prior period a year ago. Even more impressive is the fact that our LQA debt ratio was 1.1 times this quarter, down about 17% versus the prior year. So in summary, our leverage was down, our per share profits up markedly, even as commodity prices were down. The point I continue to make is that our company is focused on the same simple philosophy: finding ways to grow profits per share through cycle and over time for our investors. We believe that is the path to driving sustainable share price outperformance. While oil and gas prices go through down periods that can and will affect our profits, again, it is our job to find ways to grow the business through such times. The scoreboard we share with you is something that keeps us honest. Being a cyclical business does not afford us a perfectly linear path, and we will have our ups and downs, but we are actively investing, hedging, and looking to drive consistent long-term growth to profits and cash returns. This has and will drive dividend growth and share performance. I'm pleased to say, as Chad will highlight in a bit, that our guidance for 2024 reflects 20% production growth on a budget that is very similar to last year's. Look across the upstream sector, and you'll find very few companies offering that. Once again, we stand out, and I believe we have a lot more levers to pull, which brings me to my next point. Number two, be greedy when others are fearful. The fourth quarter was Ground Game 101, highlighted by what happens when people run out of money. We saw operators pull forward activity even as budgets were exhausted. We chose to turn the ship directly into the storm and take on some of the best-returning small-scale acquisitions we've seen in some time, and these should help capital efficiency as we head into 2024 and beyond. We are diligently chipping away, one opportunity at a time, and Adam and his team continue to innovate with creative structures of every kind to solve for our operators' needs. This does mean we will spend money countercyclically at times, but spending money is what provides longer-term growth opportunities for our investors. Growth isn't free, and as a non-operator, sometimes our capital commitments will accelerate and come sooner, and the timing of our projects can vary somewhat, as we saw in the fourth quarter, but it doesn't change the soundness of these investment decisions. As we track well performance through our look-back analysis and review our return parameters internally, we continue to see excellent results across the board. Number three, shareholder returns. I typically leave this category for last, but I'm gonna address it sooner this quarter, particularly as I've observed weaker, relative, and absolute performance for our equity out of the gate for the start of this year. We talk a lot at NOG about dynamic capital allocation, and we get asked about share repurchases and where they rank in the stack. As I have said before, and I'll say again, we try to seize on opportunities and allocate capital accordingly. Our valuation has compressed in recent months, so in 2024, our stock may well be front and center in our capital allocation stack. We don't buy back stock with reckless abandon, only when flush with cash, when times are good, and when our valuation is high. Instead, stock repurchases legitimately compete as a use of capital to maximize the long-term returns on the capital we employ, which by nature means focusing on the point of entry and being discerning on when we do so. You've seen us be aggressive in repurchasing equity during times of value compression, like in early 2022. We try to allocate capital efficiently and seize on the opportunity when the time is right. From this vantage point, it certainly seems as though this is the moment when the macro outlook has been more in flux and commodities have been more range-bound and volatile, and our own value has compressed. If the market gives us lemons for the first time in a while, we're more than happy to make some lemonade. Number four: I have not yet begun to fight. Sailor John Paul Jones immortalized that defiant phrase during the American Revolutionary War when asked to surrender by the British in a naval battle. My use of it here is meant to convey that while our team has grown our business tremendously over the past six years, you'd be mistaken if you think our growth story is over. Far from it. We've worked hard to claim the mantle of the non-operating partner of choice. Given the opportunities and landscape in front of us, I believe we can, with thoughtful execution, double the size of our company again, if not more, over the next five years. And this time, I believe we can do it more creatively. It's an enormous goal and will pose a tremendous challenge, but I believe the opportunity is there for the taking. We will stay humble to our roots as a small company, but we have great ambition to grow the business to the benefit of our stakeholders, and our board has incentivized us and aligned us with our investors to do so for the long term and to do it the right way. Done right, it will add tremendous per share value, grow dividends significantly, and drive market outperformance, all while continuing to lower the business risk. It would be stating the obvious to point out that it's been an active time in the M&A sphere in oil and gas of late, as we've seen many mega merger transactions, as well as many private to public transactions in 2023. The fallout from these mega transactions is likely to create even more opportunity for our company over time, providing both improved cost efficiencies on our properties and a broad variety of potential acquisitions as combined portfolios are rationalized. We're already seeing signs of significant cost benefits on our properties from some of these mergers. While I just spoke about our dedication and focus on shareholder returns, I also want to highlight that Energy's path to growth through acquisition also remains very, very strong. We are involved in as many, if not more, conversations today than at any point in my history at the company, and the quality of these counterparties is very different, as are the nature of these discussions. That is largely because our company today has become de facto, the only viable entity for complex solutions for our partners that is truly of scale and commercial. We believe we've built a reputation as creative problem solvers. Our balance sheet is locked and loaded with capacity for deals in 2024. While we remain selective, I have no doubt there will be a myriad of opportunities in front of us this year. It should go without saying that our main goal is to grow our business the right way. One of the first questions we always ask ourselves when we look at an opportunity is: Will this make our company not just bigger, but will it make it better? We pass on a lot of things that would certainly make us a lot bigger, but we question whether they'll make us a better company. Asset quality, governance, if needed, value, operatorship, inventory, and commodity price resilience are all factors that go into driving these transactions. These questions have driven us to where we are today and will continue to drive us as we move forward. Adam will fill you in further on the deal front, but expect an active 2024. I'll close out, as I always do, by thanking the NOG engineering, land, BD, finance, and planning teams and everyone else on board, our investors and covering analysts for listening, and our operators and contractors for all the hard work they do in the field that actually creates what you see in NOG's results quarter after quarter. We enter 2024 formidably positioned with our strongest balance sheet, the highest level of liquidity, and largest size and scale since our formation. As always, our team is ready to pounce on the opportunities to drive the best possible outcome for our investors, whether that's growth through our ground game, through our organic assets, through M&A, or through share repurchases in our quest to deliver the optimal total return. That's because we're a company run by investors for investors. With that, I'll turn it over to Adam. Thanks, Nick. As usual, I will kick things off with a review of our operational highlights and then turn to our business development efforts in the current M&A landscape. ... During the fourth quarter, we saw production increase to over 114,000 BOE per day, driven by the closing of Novo in the middle of Q3, as well as an acceleration of wells turned in line during the quarter. We turned in line 27.6 net wells, evenly split between the Williston and Permian, which included roughly half the net wells in process acquired through our ground game in Q4. While well performance has been in line with expectations, we have been encouraged by the outperformance of our Mascot assets, the new wells completed since closing Forge, and the New Mexico results from our Novo assets. As we navigate the rest of the winter, we expect to see a typical seasonal deferral on IPs from the Williston in the first quarter, with a re-acceleration in completion activity as we move into the spring and summer. Overall, we expect a relatively balanced completion cadence in 2024, as activity is more heavily weighted towards the Permian, which accounts for about two-thirds of the estimated TILs. Our drilling program has remained consistent over the last three quarters as we spud an additional 20.8 net wells in Q4, with our organic acreage seeing continued focus from our operating partners. Our Permian position pulled roughly 60% of the organic net well additions, and if we include the contribution from our ground game, we saw three-quarters of our activity come from the Delaware and Midland Basins. Our acquisitions over the past few years are driving growth in the Permian as locations are converted and we head into 2024. At the end of the year, the Permian wells in process were sitting at all-time highs of 35.7 net wells and now account for more than 50% of our total wells in process and over two-thirds of our oil-weighted wells in process. We expect this trend to continue as the Permian accounts for the majority of expected new drills in 2024. As our drilling program has remained consistent, so have our inbound well proposals. During the quarter, we evaluated over 180 AFEs, with our Williston footprint contributing over 100 proposals in every quarter of 2023. Our net well consent rate remained at over 95% in Q4. However, we continue to actively manage the portfolio by comparing what's in the market at a ground game level and what is being proposed. For example, given the commodity market volatility, we non-consented approximately 16% of gross AFEs, which collectively accounted for just half a net well in the Williston during the quarter. As certain operators have stepped out, we have redeployed that capital into our ground game at higher expected returns. This highlights our flexibility with capital allocation and our ability to quickly react to changing environments, in contrast to operators that have to stick with their drill schedules. With that said, our acreage footprint continues to produce some of the highest quality opportunities available as our 2023 well proposals have expected rates of return north of 50% based on the current strip. Looking ahead, we have seen cost reductions come through with our operating partners, yet we remain conservative with our budgeting process for 2024. Through 2023, well costs were relatively flat. However, as of late, we have seen some of our larger operators coming in below their cost estimates from original well proposals. Notably, we have seen evidence from our planning sessions and recent AFEs of a potential 5%-10% reduction in well costs related to our Mascot, Novo, and Forge properties. As gas prices remain under pressure, some drilling and completing resources may also be reallocated to our oily basins, where we could then expect some additional tailwinds. Shifting gears to business development in the M&A landscape, the fourth quarter capped off another banner year for NOG, both on our ground game and in larger M&A. As Nick alluded to earlier, we were able to take advantage of the dislocations we were seeing during the fourth quarter, executing on a number of short-cycle ground game acquisitions. While competitors' budgets were running dry, we were able to step in and deploy meaningful capital consistent with our return requirements. During the quarter, roughly half of the locations we closed on were also turned in line, which will contribute to our 2024 plans and growth profile. Our small ball focus was almost entirely in the Permian during the fourth quarter and caps off a record year for our ground game, where we picked up roughly 30 net wells and 2,500 net acres. While we buy non-op interest day in and day out, we've also used our co-buying structures, joint development programs, and have acquired operated positions with our ground game to generate these results. During the quarter, we expanded our footprint as we signed and closed our Utica transaction. Similar to our approach in building scale in the Permian, we've elected to walk before we run, deploying a modest amount of capital in the core of a new play under some of the top operators. Since the Utica announcement, we've been inundated with additional opportunities, and we will methodically review each of those as we think about our footprint in Ohio and Appalachia in general. In January, we closed our previously announced non-operated package in the Delaware, where we have significant overlap with our current position and grossed up many of our working interests in New Mexico. With Mewbourne as the operator on 80% of the position, we've aligned ourselves with one of the most cost-efficient and active private operators in the basin, which should drive future growth for NOG. The scale that we've been able to achieve over the past few years has opened doors for us that were previously unavailable, and the creative structures that we've been able to implement have created mutually beneficial outcomes, with alignment for both NOG and our operators. Given the ongoing consolidation in the industry, we have been engaging in more frequent and substantial conversations with our operators. To put the landscape in perspective, there are currently $4 billion-$6 billion of assets that we are reviewing, both on and off market. Even more than that, we've been in discussions with some of our large, independent, and mid-cap operators about how we can be helpful, whether they are pursuing assets or digesting recent acquisitions. As consolidation continues, we can provide capital to help rationalize, combine portfolios, accelerate high quality, longer dated inventory, or facilitate debt reduction initiatives through sales to NOG. These off-market transactions can be tailor-made for both parties, and with our growth in size and liquidity, could be as large or larger than any of our recent transactions. Simply put, the options to deploy capital on top-tier assets is in no way slowing down for NOG. Depending on the needs and wants of the operator, the solutions could include simple non-op portfolio cleanups, joint development agreements, co-buying operated properties, minority interest carve-outs of operated positions, or any combination thereof. At NOG, we pride ourselves on finding win-win solutions through creativity and alignment. Our priority is not to chase growth for growth's sake, but to remain returns focused over the long term and doing right by our stakeholders. With that, I'll turn it over to Chad. Thanks, Adam. I'll start by reviewing our fourth quarter results and provide additional color on the operated update we released on February fifteenth. Average daily production in the quarter was more than 114,000 BOE per day, up 12% compared to Q3, and up 45% compared to Q4 of 2022, marking another NOG record. Oil production mix of our total volumes was lower in the quarter at 60%, driven primarily by gas outperformance. Adjusted EBITDA in the quarter was $402 million, up 52% over the same period last year, while our full year EBITDA was $1.4 billion, up 32% year-over-year. Free cash flow of approximately $104 million in the quarter was up 19% over the same period last year, despite lower oil volumes, CapEx pull forward to fund accretive 2024 investments, as well as commodity price volatility and widening oil differentials. Adjusted EPS was $1.61 per diluted share. Oil realizations were wider as expected in Q4, with the increased production and other seasonal factors in the Williston driving wider overall pricing. Permian differentials, particularly in the Delaware, were modestly wider. Natural gas realizations were 97% of benchmark prices for the fourth quarter, a bit better than we expected, given better winter NGL prices and in-season Appalachian differentials. LOE came in at $9.70 per BOE, which was driven by a few factors. We had highlighted in the third quarter, we expected more normalized workovers in the fourth quarter after a lighter quarter in the prior period. We also incurred approximately $4 million of firm transport expense as a result of refining our accrual process based off historical data, and with some curtailments in our Mascot Project that had the effect of artificially inflating the per BOE numbers. As we reach mid-year 2024, we expect our LOE per BOE to trend down as production ramps. On the CapEx front, we invested $260 million in drilling, development, and ground game capital in the fourth quarter, with roughly two-thirds allocated to the Permian and one-third to the Williston. As a result of having access to high-quality opportunities, success on the ground game, along with a pull forward of organic activity, we shifted more investment into the fourth quarter from 2024. The pull forward in activity is most apparent as we are seeing a 5%-10% decline in expected spud-to-sales development timelines. We end the year with over $1 billion of liquidity, comprised of $8.2 million cash on hand and $1.1 billion available on a revolver. Our net debt to LQA EBITDA was 1.15 times, and we expect that ratio to remain relatively flat throughout 2024. ... I want to point out that we did build our working capital significantly in the fourth quarter and expect that trend to continue through the first quarter of the year, and then begin to ease for the rest of the year as we convert the tremendous amount of capital that is currently in the ground into revenue-producing wells. We have remained disciplined on the hedging front and have been adding significant oil and natural gas hedges for this year through 2026, given the increased commodity price volatility we've seen over the past several months. The oil portfolio consists of over 40% collars in 2024, maintaining material upside exposure while providing a strong floor near $70 per barrel. With respect to shareholder returns in 2024, everything's on the table. As we've shared in the past, we adhere to a dynamic approach with the objective of achieving optimal returns for our shareholders. While Nick alluded to potentially an active year for NOG, those activities may include share buybacks if there's a dislocation in our share price, and if returns are competitive with other alternatives we are evaluating. Turning now to our 2024 guidance. We are guiding to 115,000-120,000 BOE per day, with 72,000-73,000 barrels of oil per day. You will see typical seasonal declines in the Williston in the first quarter, exacerbated by some freeze loss in January, but our production cadence will build throughout the year. We anticipate adding about 90 TILs and 70 spuds, reflecting the midpoint of our guidance. After a significant build in our D&C list in 2023, the conversion of IP wells in 2024 should materially help our capital efficiency as the D&C cadence returns to more normalized levels. This will bring some large amounts of working capital that we have drawn back on the balance sheet starting in the second quarter. On the CapEx front, the 2023 pull forward lowered our 2024 CapEx from our prior internal estimates, so we are making the assumption that the pull forwards are likely to continue, given the acceleration and pace of drilling that we're seeing across our core basins. Our CapEx expectations this year are in the $825 million-$900 million range. This level of CapEx will be driven by ground game success, commodity price-driven activity levels throughout the year, and overall well costs, which, for the time being, are forecasted to stay flat despite recent evidence of savings in AFEs, particularly from our larger JV interests. We have significant capital in the ground right now and expect our larger ventures, specifically Mascot and Novo, to ramp materially in the first half of the year, so the capital will be first half weighted around 58%-60%. On the LOE side, our guidance is purposely wide, at $9.25-$10 per BOE. This is due to the inclusion of our firm transport charge on a quarterly basis, as well as the anticipated ramp we just discussed. We expect LOE to start on the higher side before trending down throughout the year. We believe there will be room for improvement. We want to be conservative out of the gate. With the firm transport charges being accrued for quarterly, our LOE expense runway will be less lumpy than in the last several years. On the cash G&A front, we've seen a modest tick down in average cost per BOE, driven by increased production volumes year-over-year, offset by some inflation in costs and services. On the pricing front, given the low overall price of natural gas, we expect lower gas realizations year-over-year, even as NGL prices have thus far been better than we expected due to seasonal demand for propane use for heating in the winter months. We would expect higher realizations of 85%-90% in Q1, benefiting from winter NGL prices and differentials. However, we remain cautious based on the typical patterns for pricing as we enter the spring and summer. If we were to see material curtailments from natural gas producers to benefit the overall NYMEX price in 2024, obviously, this could help guidance throughout the year. As a reminder, our two stream reporting embeds transport costs and pricing instead of a separate GP&T line item, and the fixed costs that are absorbed make realizations go down when the absolute price is so low. To the extent gas prices rise materially or if flat prices and NGL stick around, there is room to the upside, but for now, this is where we're starting. Thankfully, we are well hedged on the gas front, which offsets much of the weakness in the near term. On the oil front, while we're guiding wider on differentials to start at $4-$4.50, we will reevaluate this in the second half of the year. Williston volume growth has widened differentials materially over the past five months versus what we've enjoyed over most of 2023, but we believe the Canadian TMX pipeline may pull away some demand from Canadian crude as it comes online in the coming months. We'll remain conservative until then, but this could lift pricing in the back half of the year. Overall, Midland Cushing differentials have been solid, so in the Delaware, realized deducts are slightly wider. I'd like to touch on some other items related to guidance. Our production taxes will be tracking an estimated 50 basis points higher in 2024, given the shift in production volumes towards the Permian, where production taxes are generally higher than our other basins. Our DD&A rate per BOE will also be higher in 2024, reflecting over $1 billion of bolt-on and ground game acquisitions completed in 2023. This, of course, does not impact free cash flow, as it's a non-cash item, but it does impact EPS and is provided to help with analyst modeling. Before I turn the call over to the operator for our Q&A session, I'd like to provide an update on cash taxes. Given the volume of acquisitions and organic growth completed in 2023, our oil and natural gas properties balance has grown by $1.9 billion year-over-year, which in turn impacts the magnitude of our tax cost depletion deductions, which reduces our taxable income. We are now anticipating becoming a cash taxpayer in 2025, with a potential tax expense of less than $5 million over the following two to three years, which is a significant reduction from our prior forecast. This is a material improvement for our shareholders, with potential of over $150 million in additional free cash flow over the next several years. With over 20% growth in year-over-year production, a broad opportunity set available in front of us, and a strong balance sheet, NOG is well positioned to execute in 2024 and beyond. With that, I'll turn the call back over to the operator for Q&A. Thank you. At this time, I would like to remind everyone, in order to ask a question, press star, then number one on your telephone keypad. We'll go to our first question from Neal Dingman n at Truist. Morning, guys. Thanks for the time. Nick, my question is really just on timing. Could you just go over, I guess, timing or cadence, that is? Can you talk about maybe just, you know, looking what fourth Q CapEx and, you know, maybe why that doesn't translate into, you know, call it immediate production? Maybe just talk about timing, if you would. Sure. Sure. Morning, Neal. I definitely think I'm the one to answer this because, you know, like a lot of the buy- and sell-side analysts, I'm not an accountant. I'm a former, you know, buy-side analyst. And, you know, I can read a financial statement, but, the nuances of accrual accounting versus, you know, cash CapEx accounting and... You know, I should be clear, you know, a lot of operated companies like a Diamondback or, you know, a lot of the operators, follow cash CapEx. You know, we're an accrual CapEx company. And so that means we're gonna account for our wells by well status and percentage of completion. And just to be clear, you know, 70% of the cost of a well is in the completion. So as the wells become more complete, the cost of a well we account for goes way up. So in the fourth quarter, as an example, if we have, say, 30 wells that we budgeted to go from, say, 25% in the third quarter to go to 50% in the fourth quarter, and instead they went to 75%-90% complete, that's a lot of capital. And it doesn't necessarily translate into any incremental production in that quarter. And it's just an accounting exercise. It's not any more capital over the long run. It's just you have to account for that capital in a given quarter. So it's not that we choose to outspend it, you just have to account for that in that period. So in Excel, you might think, "Well, why did you choose to spend that?" It's—and that's why we, you know, we put this in our release. Our, our TIL count didn't really change that much. Now, the Ground Game spending, that was elected, the $25 million, and we capitalized on that, and some of those did turn to sales towards the end of the quarter. But when they come online in December, they're obviously not gonna contribute much. You know, they will help in Q1 somewhat, but of course, you know, seasonally, that's one of our slower quarters. If you look at the overall midpoint of our 2024 guidance, you know, you will see a partial benefit to the midpoint. You know, clearly, it's about a $25 million benefit from the pull forward, but from that sort of overrun. But the reason it's not the full sort of $50 million is because our assumptions are that the shorter spud to sales times that we've been seeing, you know, on average in our total portfolio, you're talking about a full 7% acceleration of spud to sales times, is that we're assuming that that continues sort of in perpetuity. So that means that all of the capital in perpetuity is pulling forward. So you've got 2025 capital that we would have assumed is also coming into 2024. So there's sort of a half cycle effect to that. So, I would also just say, you know, for all the listeners out there, we have sort of a mock accrual model that we can make available for anyone with that can walk through how a D&C list and a percentage of completion will actually drive CapEx versus the TIL list and model this better. So if anyone would like to reach out to Evelyn, she'd be happy to walk them through it. What I can assure you is that over time, these are just moments in time, and the overall spending won't change a ton over it. It's really just a function of timing. You know, in the fourth quarter, our TIL cadence was right on track, and we can't really control how we account for well status. We can, of course, control our capital decisions. You know, we made the decision to spend the $25 million on the ground game because those were great economic decisions and relatively modest dollars, but the $50 million plus is not really incremental. The timing of the production and cadence of this stuff, frankly, we're more focused on making sound investment decisions with our budget than the optics of the timing on a 3-month time horizon, when on a 12- to 18-month, you know, for the longer-term investors, it'll come out in the wash. You know, number of the wells are the same, the cost is roughly the same. The amount you're accounting for in a given quarter is different. That's about it. You know, we're not and also, you know, I just say we're not cherry-picking single-well IRR plots. You know, we did publish in our earnings presentation, the cum of all our well plots year-over-year. And if you look at the data in aggregate, in our earnings presentation, 2023 was among our best well performance years in history. So, you know, optically, I recognize it's a bit noisy, but it's just noise and I want to reassure people. I'm sympathetic because I don't like the optics of it any more than anyone else. And I can understand why you might draw the wrong conclusions, but they, they'd be the wrong conclusions, because the well performance is a testament to everything that's going according to plan. You know, so over the long term, everything's going great. So it does sound like that capital on the ground is going to really pay dividends. So, I'm glad to hear about the timing. And then my just follow-up. Could you just talk a little bit about, you know, opportunities that you and Adam are seeing out there right now, Permian versus Bakken? Is it pretty split, or could you just talk about, is there one region that you're seeing predominantly more, more potentials? Hey, Neal, this is Adam. I would say that the opportunities that we're seeing right now are generally weighted towards the Permian. And in the Permian, most, most of that's in the Delaware, so I don't think anything's necessarily changed. I think one emerging theme that we've seen kind of evolve has been around Appalachia and kind of the, commodity price volatility there. You've obviously seen the pain, you know, ongoing for the last 12-18 months. Some of those conversations that, you know, were tabled, you know, a couple of years ago or a year ago when, you know, you're seeing $7 an N, and now you're obviously on, on the inverse of that. And I think with things settling out and, you know, having some of these operators truly feel the pain, I think there's some, you know, ability for us to potentially capitalize there. But I think it's across the board in terms of the conversations that we're having. We're certainly seeing things in the Bakken that are interesting. Looking at our deal tracker right now, I think we've executed about 10 NDAs. There's about 17 different you know, immediate processes that are either in market or coming to market shortly, and so I think we'll obviously parse through that. A lot of that might just go immediately into the garbage. So I don't think we're necessarily changing our stripes in terms of underwriting or any of that. But I think you've got a few different dynamics that are going on that are interesting, especially on the consolidation front with operators, and then having to kinda wrap their head around their new assets and then, you know, potentially rationalizing those assets, and whether or not those are core assets to them, regardless of the economics. Yeah, the only thing I would add to that would be on the Williston front. I think you're not seeing as much small-scale activity, but I think there's the opportunity for bigger, chunkier transactions over time. I think there are bigger things that could move over time there, which does give us some excitement. I think it's... You know, we did hit record volumes in the fourth quarter. You know, it's been amazing how resilient. It's frankly surprised even us, how our Williston asset just keeps growing, both organically and frankly, inorganically. We've continued to find ways to grow our footprint. You know, our small foray into the Utica, we have been inundated with Utica opportunities, and we've actually, you know, even in the last month or two, we've probably gotten another half a dozen shopped to us. So, we've been building up our technical expertise, and we're evaluating through those. We would view that, to Adam's point, as an extension of Appalachia. It is technically the Appalachian Basin, but that's clearly a distinct play. And obviously, the Utica is a broader play in the sense that it, you know, it's, there's a dry gas, wet gas, and oil part of it, so it's a couple different plays in some ways. But just having planted our flag there, to some degree, by doing so, we've suddenly found ourselves in another set of deal flow. Thanks, guys. Congrats. We'll move to our next question from Charles Meade at Johnson Rice. Morning, Charles. Good morning, Nick. Good morning, Nick, Adam, and Chad. Nick, I want to go back to this question about the 4Q capex, and I know you've already spent a lot of time on it, but I wanted to maybe take a slightly different angle. I think I understand the dynamic of the opportunity set with the ground game was looking good at year-end, and I think I understand the dynamic of your accrual accounting. What I don't get is the magnitude of it, particularly with respect to kind of what you knew on November one, when you reported 3Q. And so, you know, I'm wondering if there's something that, that I don't understand, like maybe that, that what you call your Ground Game D&C, if that, that what gets loaded into that line item is, is everything you've done from the Ground Game year to date? I don't know. Maybe you could just, just address it from that angle. Well, well, Charles, I mean, as a non-operator, well status updates come from the operators on delay, and so we're only as good as the information that is provided to us, right? So oftentimes it can, you know, we're provided this stuff sometimes months on delay, right? So we can be told that a well hasn't been even spudded, and then you'll get a report that it's been completed. And so I don't have any answer beyond that. Same thing could be said with the ground game, right? Depending on the complexity and the due diligence that's going around that, some of these deals can get closed within weeks, and some of them take months. And then you get up into year-end, and there's different, you know, from a seller standpoint, different tax consequences, and so different levels of urgency there. And so we're trying to be as accommodating and commercial as we can without, you know, obviously sacrificing any of the protection, you know, from a due diligence standpoint. But these things ebb and flow on a real-time basis. Got it. So if I understand correctly, it's got—you've got both volatility and also maybe would be fair to characterize this one as out-of-period adjustment catch-ups? Charles, this is Chad. I don't think it's necessarily out-of-period adjustments. Like we mentioned earlier, it's the pull forward. I think, look, we had record D&C levels at Q3, and the timing of when those come off, really depends on, like Nick mentioned, the, you know, the well status and where it's at. I think, look, we went from a typical D&C list percentage of completion of 40% ... all the way up, excuse me, all the way up to, you know, just over 60%. So I think you're gonna see, you see that build, and that kind of ebbs and flows each quarter as we, as we receive well status from operators. Got it. Charles, maybe just to put it into perspective in terms of, you know, the accrual accounting. An operator is collecting all of the service invoices and everything else, and they have to aggregate all of that, and then bill it out to the various non-ops. And every operator does that at a different cadence, right? And so you have these accruals out there until we're confident that all of the costs that have been incurred from actuals have been appropriately billed. And so those accruals, depending on the operator, can hang out there in a few months, however long, you know, relative to the IP date, because we need to make sure that we've got the coverage that we need. Yeah. But at the end of the day, it doesn't really change the aggregate dollars. It's not any more wells, it's just a factor of time. You're looking at it on a 3-month basis, when you need to be looking at it on a 12 to- So what I can tell you is, we're not electing to any more. We're not making any different capital decisions. We're electing to the same number of wells. We're electing. We're, we're tiling the same number of wells. It's just a matter of how much money is being spent. It's not a matter of these wells costing more or performing worse. It's a matter of truncating the amount of capital, and when you're accruing for it when. I mean, optically, I'm not any happier about it than anybody else. But Well, and it dovetails into 2024, right? And what the projected well costs are. We've had some great conversations with our operators, and what we're seeing in field estimates, and we alluded to as much, right? I think we expect 5%-10% kind of underrun from these AFEs, but we're gonna take these AFEs at face value. And depending on the operator, those AFEs might be, you know, three months old. They might be 12 months old. Yeah. But we're not gonna change our accounting practices based on what that mix looks like. Yeah. And let me walk you through how that works, Charles. So let's just say Midland Petro sends us an AFE, a gross AFE, for $12 million in November. So they sent us that, and we're accruing for that $12 million on a percentage of completion, starting in November through the completion of that well, let's just say it's in April. And we'll continue, and then, that accrual is held until probably. And then there's a period where it's held out until the final billing, which is probably at least 90 days until after the well is on sales. And then, if there's no more billing after that, that accrual falls out and it's finalized. We're getting field reports along the way that well, maybe it's costing $10 billion, right? But... So there's a $2 million savings, but only at some point later in 2024 will you see in our results that reduction to the capital. So there's a lot of conservatism built into this. If your typical cash operator, when they guide to you and they say, "We're gonna spend $12 million in this quarter," and then they actually spend $10 million, they're giving you the immediacy of that benefit. We're not. And so what I would tell you is there's inherent conservatism in how we're doing this, but over time, you will see the benefits of those. And so while it obviously is the inverse, certainly in the fourth quarter, over time, I think you'll see it doesn't really change the outcome in the long run. And in some ways, I think throughout 2024, and certainly into next year, you will see the benefits of our accounting. And it—like I said, it will all come out in the wash. Got it. I thank you for all that added detail. And if I can transition away from accounting and more towards pictures, which I'm better at. I very much... Yeah, I like pretty pictures. Slide 10. I appreciate that you guys put this gun barrel view of your Mascot Project. One short question, one bigger question. So the first question is: The first question is, those yellow circles, I'm interpreting that as kind of completion batches, is what it looks like, or, you know, is that right? And then the second thing I wanna ask you guys, a little more open-ended. I really like this picture. It helps fill in the, you know, the dynamics for me. But what... I guess when you guys first looked at this, and, you know, I recognize it may be as much as a year ago, but what are the lessons there? You know, what insights did you generate, or what insights came to you when you first looked at this? Yeah. Hey, Charles, this is Jim. Yeah, what you're looking at there, the kind of the yellow amoeba, those are completion batches. So they'll do them in, you know, two, three, four wells at a time. And then what we're showing is, you know, you've got several rows where you need to shut wells in behind it, whether it's due to the drilling or fracking, to protect yourself. So when we looked at this about a year ago, really all you saw in here, in terms of wells that we're producing, was the Charger unit. And so the Mustang, Rebel, and Bulldog units were all undeveloped at that time. Discussions around, you know, development timing, completion with MPDC at that time, was that we were gonna do smaller batches. So where you see the yellow dots, we'd maybe do three wells at a time. Complete those wells, turn them online, go another six months, complete the next three to four wells. What we saw with the first batches is that we started to see some interference issues, some frac hits, because we were drilling and fracking all at the same time as we moved from west to east across this project. So the decision was made, let's do bigger batches. So what that did is it, it obviously causes delays, and when we thought, you know, the project was gonna peak in terms of production, but what we're seeing is that because we're doing that, we're getting better well performance overall. The project is outperforming by 5%-10% versus our original estimates. Obviously, there's delays, but we think in the long run, it's actually gonna benefit from a return on investment ROI- ... overall project economics. And so what we're learning is that obviously things change over time, and this is a big working interest project, so it's more impactful than our typical non-op package would be. So our learning is just make sure we're in full communication with the operator at all times, and that we're all in agreement on how the development plan is gonna go forward. And like I said, we're acceptable to the changes. Obviously, that, you know, hurts us from a guidance standpoint and trying to understand when these wells are gonna be coming online. But overall, we're very happy with the project, and we're comfortable with how things have changed. Yeah. What you can see in this, Charles, is that you're pretty much almost all the way there, right? You're down to your last, pretty much eight wells to be drilled. Yep. Your frack schedule, you're really all in and what you can see is where the Charger and Mustangs, which are really the ones that are remaining, you know, there, you're gonna have fewer shut-ins on the back end. You're gonna have to, in terms of... You will have to shut some in when you go to frack those wells later on. But in the last wave of shut-ins, which will be sort of towards the end of this year into 2025, it'll be reduced. So the one thing I can tell you about this project is it, while it won't produce that peak rate that it would have, it will produce, it will cum way more barrels and a much flatter production profile than it ever would have before. And so the total ROI on the project will be significantly, you know, much more superior to what it would have been originally. And we've obviously, we're also saving. Because you're doing much more continuous drilling and fracking, we're saving a lot of money. I mean, that's still to be determined until we finish the project, and I think we wanna be a bit tight-lipped and conservative on that until we're done. But I think we feel very confident at this point that it's gone swimmingly. And obviously, you know, it doesn't feel that way, but the strip was about $70 this year when we underwrote this program, and obviously, we're in the mid- to high $70s today, so we're earning higher returns than we would have otherwise underwritten. Great detail. Thank you. Yep. We'll go next to Scott Hanold at RBC Capital Markets. In your prepared comments, you mentioned about wanting to, you know, creatively double the company in five years. Can you give us a sense of, you know, how you achieve that? I mean, since you kinda came on, you first pivoted out of the Bakken into other basins, and, you know, obviously, your next significant move was doing JVs. You know, what's next? Is there other basins you're looking at? Would you consider being an operator? Like, you know, how do you double a company from here? I'm curious, what's that wonderful music in the background? Oh, sorry. Lots of calls going on today. I think what you see is what you get. I think what I would tell you is, you know, we still see the same. I think we still see a lot of the same stuff. We still see a lot of regular way, you know, the ground game. Look, we did almost $300 million with the ground game. It was a record year. I mean, I think we did, you know, several thousand acres over thir-- which included over 30 locations, which is, you know, frankly, a monstrous record, and we're doing it in a different way. We're solving- we're doing it in-- We've moved out of the sort of fractional, small scale stuff into much larger. We're solving major operator problems, and it's mostly dealing with our mega operators. Obviously, we have moved into the JVs, but that's more a function that we can actually do that. They were dealing with private equity groups that were non-commercial in the past because they were the only ones that had the capital, and they'd much prefer to work with an actual true oil and gas concern that's a permanent owner of the assets. And so we've really become the first oil and gas concern that can actually do that. And so I do think that that will be an avenue that goes there. I think there are still, we know of a half a dozen, regular way, non-op transactions that are gonna come to market, either on or off market, within this year, and so obviously, we will be looking at those. But I can tell you, to Adam's point, he said, "We've, you know, we've signed 10 nondisclosure agreements this year." It just keeps coming. We continue to be contacted of people coming to see us saying, "I have this problem," or, "I need to buy this," or, "I want to do this. Can you help us do this?" And we are trying to solve solutions, whether it be rationalize their assets, whether they have an asset that cannot be sold, and they would like to sell a portion of it, like what we did with Midland Petro. There are all sorts of solutions that we're trying to provide, and with that, we can create the scale that I'm describing, but I am extremely confident that we can grow it and create a return for our investors. As for other basins, there are other great economic basins. There are certainly ones that I would very much like to avoid, but I think we can solve for the risks around them. We certainly have technical expertise. We've looked at a handful of other basins that we would be interested in. There are some that I think are gonna be a challenge. I think there are some that we would, of course, for the right opportunity, go to. I think there are some that we would have to, frankly, create governance or other things to get around those risks. And I don't know, Adam, if you wanna add to that. Yeah, I mean, I just feel like a broken record quarter after quarter, but it's the scale that we have now, it's the optionality and the deal structures and the blueprint that we've created, and then frankly, it comes down to reputation and our ability to execute and our ability to be commercial. And so we've got, you know, more than we can shake a stick at in terms of the inbounds and how can we solve a problem together, and so those are the conversations that we're having. And, you know, I've talked about the stuff that's in the market, and that's everything from the non-op packages to the, you know, DrillCo like joint development agreements, as well as the co-buying. ... But now you've got this different theme emerging with the operators merging and the rationalization coming in there. And so you can add another kind of arrow to the quiver in terms of how Northern can be helpful. And so if you've got all of those options, and you've got the balance sheet, and you've got the reputation, then you can use all of those to your advantage in order to execute. Okay, appreciate that color. And my follow-up question is on shareholder return. You know, you mentioned that you'd be willing to kind of step in and, you know, lean to buybacks with market dislocations. Can you give us a sense of, like, how aggressive are you willing to get there? And, you know, how do you think about intrinsic value? I mean, it seems like you think the stock price is attractive today, but, like, you know, where is that sort of point where you really get aggressive and how deep can you go? Yeah, I mean, I think that would, I can't give away too much of our playbook, Scott. And, you know, obviously, it's a board decision. We've been in discussions with the board. We are watching... You know, I would say, as an ex-hedge fund manager, we have a fairly sophisticated internal modeling of this, and we try to use it, and we model it internally and compete, and compare it, and compete it versus generic M&A and all that stuff. When we run all of these things versus, you know, we, we effectively mock it against where that capital could go elsewhere, right? Because it is... You know, you have to sit there and say to yourself, "If I spend this money today, where could it go elsewhere?" But frankly, you know, as we look to the first quarter, this represents the, you know, the worst relative performance we've seen in about three years, and we view it as relatively inexplicable. Given the fact that, you know, our growth profile, as we look this year, is one of the best in the space. You know, perhaps it's because, I mean, I can come up with, you know, a hare-brained, long-short thesis of some sort or whatever, but regardless, that generally, like I said, life gives you lemons, you make lemonade. That creates opportunities for us, and that's how you allocate capital when you see that. So, we'll be watching and if the opportunity presents it, we're ready to act. We certainly have availability in our buyback authorization. We can always create more and go to the board if necessary. And so, you know, that, you know, I think we have over $80 million today available. We can always ask for more if the board's willing, and that, that's a board-level decision. Thanks. We'll go next to John Freeman at Raymond James. Good morning, guys. Just following up on the last comment there, where you said that y'all would consider looking at... I guess there's a handful of other basins that y'all have looked at or considered. I would assume that for y'all to do anything outside of the three basins that you're in, that it would require a pretty substantial position. I mean, not something that y'all would sort of build into, right? You would need enough scale for it to be you know, make sense to add a fourth kind of leg to the stool. Is that correct? Yeah. Yeah, I think that's a fair point. I think there's a handful of different dynamics that kind of come into play. Obviously, the land and the regulation around that, and what that means, you know, for a non-operator. And then, you know, when you think about co-buying or buying down, you know, a minority interest in an operator position, you're kind of linking arms with an operator that likely already has that expertise in that basin, to the extent that it, you know, we need to have two sets of eyes taking a look at things. And so I think that's an interesting dynamic in terms of taking a look outside of, you know, our own backyard and being able to link up with some of the best-in-class operators that we want to partner with. Yeah. I think there are some basins that would be a real challenge, John, but I think there are some basins that may have some risks to them that could be solved if you had the right operator that might have the right rock, but have other risks associated with them that could be solved if you had the right operating partner. That makes sense. And then my, my follow-up question, obviously, we spent a lot of time on the, the accrual aspects on the CapEx, and it, it looks pretty clear that, you know, whether it's late this year or next year, that, you know, the, the cost improvements that you're seeing at some of those major properties, eventually that'll, that'll show up. If I shift gears and, and think about the guidance as it relates to production, you know, you've got a slide in there that shows the, the productivity y'all are seeing in the Permian and the Williston. And I think the Williston, in particular, was pretty surprising for me, just, you know, you think of it as a, as a mature, one of the older basins. You know, it looks like, obviously, still early here, but 2024 results look like they're meaningfully outperforming. Is your guidance on production related to the Williston, does it assume more like a 2023 type well results? Yeah. Hey, John, this is Jim. You know, we always go into a year, you know, kind of assuming there's gonna be some well performance degradation. Obviously, we've got about nine months of wells in process. We already have a pretty good idea of what we think the performance of those wells will be, but we do always assume there's gonna be some degradation. But really that plays into our, you know, our portfolio management, right? As we're thinking about which wells we want to participate in, which operators we think are, you know, the best performers, where we're gonna target our activity levels. And so that's really how we kind of manage our activity and our well performance to make sure that year-over-year, we're doing a good job on participating in the best wells. Obviously, you know, 2024 is off to a great start, you know, but it's pretty early on. We'll keep an eye on that and see how it changes over time. But we're obviously very encouraged. You know, we're happy with the Permian. 2023 outperformed a little bit, versus 2022, even as we move more into the Midland, which is less productive than the Delaware side. So we're very happy there as well. And again, 2024 is off to a great start. Overall, well performance has been as good or better than expected. But we'll stay, you know, true to our roots and, you know, expect some well degradation, which is what we build into our guidance and our forecast. So, you know, potentially some upside there, but, we'll wait until we get more information as we go farther into the year. If you're looking for optimism from a non-operator, you're not gonna get it, John. Yeah, maybe to give you a little different perspective, I think, you know, from our PDP adds, from a Williston standpoint, it was generally concentrated with Continental, Marathon, and Slawson, so some of our best operators in 2023. And if I'm looking at the D&C list as well as some of the near-term, you know, AFEs, you've got a similar setup with Conoco and Slawson, you know, and Continental all kind of leading the pack in terms of, you know, what that makeup is. So encouraged by where these guys are operating and how they're performing. Appreciate it, guys. Thanks a lot. It's done. Our next question comes from Phillips Johnston at Capital One. Hey, guys. Thanks. Chad, you gave some pretty good color on LOE in your prepared remarks. You mentioned the run rate should start to fall in mid 2024 as production ramps, and obviously, you've got the FT charges tapering off by the middle of next year. So wondering where we might be by Q4, and as you look out into 2025, would $9 a barrel be a good placeholder for our models, or would you steer us to something above that or below that? Yeah, I mean, I think, I think that, that sounds in the ballpark, Phillips. Yeah, like I mentioned, you know, we're gonna be- we're gonna be running a little, little hot as we kind of catch up the FT charge. We only have, instead of a year to accrue for, we only have six months, so that'll be a little bit heavier in the first quarter. But yeah, then as, as I mentioned, we will trend down, probably towards the bottom end of our guidance range, maybe even a little bit lower as we, as we close out the back half of the year. Okay. Sounds good. And then maybe just a question for Adam. It looks like the plan involves, 70 net spuds and 90 turning lines. Can you talk about maybe what's driving that 20 well gap and, and what that might mean for the trajectory of production and capital efficiency into 2025? Yeah, you've got obviously the Midland Petro project that, you know, kind of finishing up. That's a 40% working interest, so you've got concentration there. And then, it, you know, well, as we proceed throughout the year, we're gonna be getting these well proposals coming in the door, and so what that looks like. And so I think it'll depend on, obviously, that working interest mix, as well as kind of the cadence and activity levels of kind of the Permian as well as the Bakken. Yeah. So I think it's a function of both Novo and some of the other larger transactions that we had and, you know, where that activity level is concentrated. We're having these conversations on a quarterly basis with our operating partners, and so that can change. I mean, Phillips, for a normal course, our D&C list should usually roughly equate to about half of our TIL count, and obviously, it's been elevated. We've been building it because we've been growing organically, so over time, with a normalized line, it should be about half, and that's partly why our cap has been elevated. So it masks some of the capital efficiency of the business, and so that's why you will see our capital efficiency markedly improve. And if you go back to, say, 2021, where our D&C list was declining, you would see, you know, material improvements to free cash flow yield and other things, and that's because you were running a leaner D&C list, and so it's more just a normalization of it. So I wouldn't make the assumption that it leads to material declines or something like that. It's just more a normalization of the D&C list, because obviously, we've been going through... I mean, think about it, last quarter, our production grew, like, 5,300—our oil production grew 5,300 barrels, and not all of that was just Novo, that a lot of that was organic. So you've been seeing volume growth material, right? So you're just really flattening out that growth production effectively as you exit the year to some degree. Sounds good, guys. Thank you. Yeah. Yeah. We'll move next to Donovan Schafer at Northland Capital Markets. Hey, guys. Thanks for taking the question. So, first, I want to talk about the reserve. So, I was a reservoir engineer in my first job out of college, so I might be a bit biased on this, but I do, I do think, you know, you can make a lot of-- you can draw a lot of meaningful conclusions or, or pull out some insights from reserve, if you, you know, if you know how to make some adjustments, because obviously, there are, there are a lot of adjustments to make in order to show real, a true sort of economic reality. But so, the PV-10 was $5 billion, which is almost exactly in line with where you're trading in terms of enterprise value. And, you know, that's on an SEC pricing basis, and, and that can cause crazy distortions. You know, this time around, it does, at least, you know, in my view, look like the SEC pricing happens to not look too crazy and be, you know, kind of, sort of close to what we might could expect going forward. But there are a lot of other things for where you are right now as a company, where the reserve reports, you know, may not be accurate and need more adjustment. So, you know, one is Utica and Delaware acquisitions. You know, I don't think those would be, you know, included. So, you know, if you can confirm that. Donovan, we don't, we don't really book PUDs in our... As a non-op, we don't book our PUDs, right? So we have- Yeah. Unlike an operator, an operator can book a full PUD booking for five years. Yeah. I mean, would you-- how many PUDs do we book in our? ... We generally book about 2-2.5 years of activity, right? As a non-operator, we still need to show that we're converting more than 20% of our PUDs every single year. And so in the projects that we've been doing, you know, the Novo and Forge, we have a more definitive drill schedule, so we can book more PUDs there. But on your typical non-op, where the operators aren't providing us with their actual drill schedules, it's hard for us to show that high level of confidence that certain locations will get drilled over the next 5 years. Now, we're obviously gonna have the activity that, you know, as we showed this last year, almost 80 net TILs, but we can't book those specific locations because we need to make sure that we're converting those locations. So we have a lot more locations than what we're booking in our reserves. And so it's a very conservative reserve set that you're seeing there. Right. And then another thing is just, this is coming from kind of my recollection of how things work, so I'm looking for what your thoughts are on kind of the relative impact of this. Is that, you know, the other thing about how the way you have to do it for the, with the SEC, the pricing gets locked in on a historical basis, and so, like, in this case, with the current reserve report that you just put out, or the numbers you just shared, you know, you're kind of stuck with the current commodity price, the 2023 commodity prices, and then they do the same thing on D and C prices or, you know, D and C costs. But D and C costs follow commodity prices on kind of a lagged basis. Like, you're only just now—you know, it sounds like the more material decline in D and C costs, you're kind of only just now starting to see that, yet you're sort of, you know, locked in at a level of D and C costs that honestly may have been more reflective of commodity prices in 2022, right? So that also kind of creates... Is, like, am I right in that? Am I remembering that correctly? Yeah, you're correct there, right? We have to use trailing twelve-month prices, so that's locked in. We have to hold that constant going forward. Same thing for LOE. If you think about where we were last year, SEC prices were in the mid-$90s, now we're in the high 70s. So that has an impact on our reserves. You know, we lose a lot of reserves just cutting off the tail end. So those are reserves that we had to replace. It was about 30 million barrels that we lost just due to pricing. And then also on the well cost, because we're not an operator, we look back at historical AFEs that we've gotten over the last year, which is more of an $80-$90 kind of price environment, and that's what we have to bake in going forward. Versus an operator, they can model their current costs going forward because they have the AFEs, they have the actual well costs to model that. So we're... Again, we're being kind of double conservative there because we're holding a lower price from a commodity standpoint, but then we have to use higher well costs, higher LOE than what we're kind of expecting on a go-forward basis. Yeah. Okay, okay. All right, and then moving on, just I may have some more follow-ups on that afterwards, but for now, the other one, just as a quick modeling question: with Q1, with the freeze in the Williston in Q1, you know, having an impact on production there, is that going to have an impact on the oil mix? You know, when I kind of triangulate that with full year guidance, is that something where we could see oil mix come down a bit or higher, like, in a way that would material- be material at all? I'm just trying to think. I want to avoid a situation where, you know, somebody just models a slight production, you know, dip in Q1, but you end up underestimating the impact because it, you know, is more weighted towards oil or, you know, it's a change in the oil mix or something. And then does that mean, you know, in Q2, Q3, Q4, you could have a higher oil mix than what is necessarily in the guidance for the full year? I mean, I think I would... I mean, from a guidance standpoint, we feel pretty confident in the numbers that we put out there. We put out both total production and oil. So you can kind of infer an annual, you know, oil cut there. Yes, in Q1, most of the shut-ins were in the Williston, which is a higher oil cut, so you could potentially see lower oil cut in Q1, and then it rise as we go throughout the year. And obviously, our Midland Petro project is a very high oil cut, and so that will also improve your oil cut throughout the year there. But I don't think, I mean, I don't think it's gonna, I mean, I don't think it's gonna be, you know- Material ... material. I don't think it's gonna be material because there were also some mild curtailments in the Permian as well. So I don't... I mean, on the margins of it, I don't think it's gonna be... You know, you're talking about a 10-point difference between, or 7-point difference between the Permian and the rest of our oil basin. So I don't think it's gonna be, you know, massive in any material way. We'll move to our next question from Paul Diamond at Citi. Good morning, all. Thanks for taking my call. Just a couple of quick ones. Talking about some of performance on Forge, can you just talk a bit more about that? You know, if you guys are seeing that as an establishment of a trend or I guess, what you're expecting out of that this year? Yeah, thanks, Paul. This is Jim. Yeah, we're seeing the same thing. You know, Vital announced yesterday they're seeing about 30%-35% outperformance on, on the new wells versus kind of the legacy Forge assets. We're seeing the, you know, something similar versus what we underwrote. It's around 30% outperformance. I think it's around, you know, optimization on, on spacing, completion design, you know, production uptime on artificial lift. That is now baked into our go-forward plan. You know, we're still modeling based on what we originally underwrote for the acquisition. So we do see, you know, potential upside there. As we continue to go throughout the year, we think we'll see that, and we'll adjust as we get more data. Typically, we like to see 6-9 months of history before we feel confident in adjusting our assumptions. But so far, we're very encouraged with what we're seeing out there. Yeah. They've also just done, you know, one of their main initiatives when they bought the asset was really to work on the PDP itself, was really to work on lowering costs of the actual OP on the existing assets, and I think they've done a good job cleaning that up. Got it. Understood. And, just a quick follow-up. You guys talked about having a lot of conversations with the small mid-cap operators. You talked about, you know, scale being similar to prior deals. But can you just dig down a bit more on that? Is there a pretty wide range to that scale you're seeing, or is it all pretty much locked in, you know, similar to, you know, Mascot, Forge, Novo, things of that sort? Or can we go a bit smaller, a bit larger? What are you guys seeing? You mean just in terms of the partners? Or deal size? Yeah. It's all- Or deal size and partners ... I mean, I think, I mean, I think a lot of the, a lot of the stuff, you know, from, from the mega transactions, we have a lot of conversations with the, the largest of the large. Certainly, we have a lot of interest from small scale people as well, who, because they always need money just like everybody else. But I think in terms of the asset rationalization, we're also seeing the conversations from very large and, and mid-cap and upper mid-cap companies as well. So I think it, it runs the gamut. I think what I would tell you from our perspective, and I'd rather let Adam talk about this than me, is that from our perspective, it's not a, it's not a one, you know, not one, one size fits all. Our methodology is going to change depending on what type of counterparty it is, meaning that we're going to adjust our structure based on what type of party it is. It's probably gonna become more mean-spirited, depending on who we're dealing with. That's right. And just to, I guess, put it in perspective in terms of deal size and partners, I mean, on a ground game level, we're doing this on a unit-by-unit basis. We've also got, you know, for example, private equity groups that have just raised capital that are looking to, you know, participate in both the $100 million-$200 million transaction size levels, that are looking for a partner, so that they can use some of their dry powder for development on a go-forward basis. And then you've got, obviously, the ones that we prosecuted last year, that were, you know, significantly larger than that. So it runs, it runs the gamut, like Nick was saying. Understood. Thanks for your time, and I'll be there. We'll go next to John Abbott at Bank of America. Hey, good morning, and thank you for taking our questions. Sticking with the four to six billion dollars of opportunities that you're seeing out there, and you look at the balance sheet, you look at your share price. I mean, what are your thoughts on potentially financing transactions at this point in time? Yeah, I mean, John, we raised $290 million last fall, you know, for a reason, which was that we felt that we saw a great opportunity in front of us, and we wanted to be prepared to act. We've got over $1 billion of liquidity. Frankly, with all of the transactions that have happened, I think something like 10% of the revolvers have been recalled across the board. Chad is the most popular girl at the prom right now. He is, has banks begging him to take money. And so, we certainly have capital available to us. I don't think that's the case for everybody, but I think for scaled companies like ourselves, the ability to raise additional capital is there. Certainly, we've so my point being that I think we have the capacity, you know, on balance sheet to, you know, for upwards of $1 billion without raising any additional capital, and I think that would satiate us quite, quite easily, you know, for the time being. Obviously, you know, beyond that, you know, we'll see, but as you do those and, you know, we, we haven't really done much more than $1 billion in a year, so I think we're, we're, we're in pretty good shape for 2024. Very, very helpful. And I mean, there was a lot of conversations earlier on accrual accounting, but I guess the real question here is, you know, looking beyond the noise, as you sort of think about the exit rate for this year, you know- Yeah ... nothing necessarily specific, where do you kind of see the exit rate for 2024 in terms of production? Yeah, I mean, as a non-operator, Jim Evans will stab me with a large knife if I talk about that because, you know, we just talked about how the timing can really vary. And the truth is that if we see acceleration of projects and we see everything come on early in the third quarter, we'll produce a lot more barrels, and our guidance will be raised for the year. And so if we see our production peak in the third quarter, that would be a great thing. And so theoretically, we'd see peak production in the third quarter, and your, quote-unquote, "exit rate" would be lower. Of course, we would find ways to redeploy capital and exit higher, so I'd be hesitant to see that. But I would say, as we described in our release, you know, we obviously believe we'll be, we'll be down modestly in the first quarter. We would expect a material jump in the second quarter, another jump in the third quarter, and then, you know, a mild jump in the, in the fourth quarter. So I think, you know, that I would just leave it at that, for now. But I would say that obviously, based on our guidance, that that is substantial, and I'm, I'm sorry to, to punt on that, but I- Well, it's February. It's February, but- Things can change in the commodity market. Yeah. So I'm sorry, but as a non-operator, that's just—that's the best I can do for you. But I would say this, that, like, we're in the business to grow our company. And you know, there's a reason in our business... Look, there are great things about being a non-operator, a lot of great things. But the timing of it, we know, is the part of it, and honestly, to the extent that it gets accelerated, we're gonna produce a lot more barrels this year. So that, that's a good thing. But you know, the exit rate is... We're not a laundromat, right? So you know, this is something, right, that the—it's not a machine. The exit rate is sort of one of those things that people like to hang on to, but it's really about, it's not about a moment in time, it's about the number of barrels you produce over the life. And so I just say this, that we are in the business to grow the business over time, and I think that that's the most important thing. Very helpful. Thank you for taking our questions. Yep. ... We'll take our final question from Noel Parks at Tuohy Brothers. Hi, good morning. Just had a couple. You know, you talked a little earlier about you can't really do one size fits all in terms of just how you look at different acquisitions. But, is it fair to say that you're pretty agnostic between private, operated versus publicly traded, operated, non-op interests right now, either for the ground game or for larger A&D? I wouldn't say that. I mean, I think it depends, it depends on the quality of the operator. I mean, there are great privates, but it's a, you know, the largest. You know, there are really large operators that are bad. I mean, I think it just really goes operator specific. There are really good operators, and there are really bad operators that are big and small, right, Adam? I mean- Yeah, and I think you need to differentiate what private means. Are you talking about private equity, or are you talking about true private? Yeah. Right? And those business models are run very, very differently. Yeah. You know, you've got one that's renting an asset and one that's had it and will continue to have it for a very, very long time. And so their viewpoint on a short-term or a long-term basis could be very, very different. Yeah. I mean, Mewbourne is a private company, and it's one of the finest operators in the world. You know, and I can think of many private equity-backed operators that are, you know, renting the asset and looking to flip it. Yeah. I mean, I would say typically we're looking at people who have a similar view as us in terms of the long term, but that's not to say that there aren't great private equity operators that are out there as well that we'd be willing to partner with. Absolutely. Oh, great. Well, thanks for the clarification. And, I guess, I was wondering a bit, talking about the Williston, and we have seen a deal there, the first one maybe in quite a while of any size. And, just wondering, I have not paid a lot of attention to the state of, sort of the land management out there. You know, leases, some of those leases are probably 15 years old, if not longer at this point. So I just wonder, you know, you, you've been there so long, are things pretty cleaned up there, or is there still stuff to do just in terms of, I don't know, you know, neglected books or, you know, absent non-op positions that you've— you can still, you know, still- It's pretty blocked up, Noel, but there are still, you know, there are still things to do. I mean, you know, it's just gonna be more about people when they're ready. There are things that are owned that when people are ready to sell, will be sold. But I don't think it's like the Wild West, where there's lots of open land ready to be sold. Is that fair, Adam? Yeah, I think that's fair. I... The other thing that I would add to that is just the evolution of the completion methodology, right? You've seen a lot of operators, you know, refine those techniques and step out, and so the rate of return and the economics on some of those projects that you wouldn't even look at, you know, call it two, three years ago, are things that are certainly viable now. And then that changes the landscape from a land standpoint. So you can do some of the blocking and tackling in terms of picking up some white space acreage and bringing in appropriate operators that you know are gonna do a good job. And as a non-operator, it, you know, we're not beholden to one particular area, right? So we can get into the core day in and day out and continue to gross up our working interest as we get, you know, 100 AFEs a quarter, as we did in 2023. So there's always wood to chop. It's just, it's a different dynamic. That concludes the question and answer session. I would like to turn the conference over to Nick O'Grady for closing remarks. Thanks, everyone, for joining us today. We'll see you on the next one. Appreciate your time. This is the way. This concludes today's conference call. Thank you for your participation. You may now disconnect.