Greetings and welcome to NOG's Fourth Quarter and Full Year 2023 Earnings Conference Call. At this time all participants are in listen-only mode. The question-and-answer session will follow the formal presentation. Operator instructions were provided. 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. But 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've 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 in 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 the 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, 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 one-on-one, 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. 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 counter-cyclically at times. But spending money is what provides longer term growth opportunities for our investors; growth isn't free. 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 loopback 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 going to 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 talked a lot about dynamic capital allocation, and we get asked about share repurchases and where they rank in the stack. As I've 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 and when we believe the valuation presents an attractive entry point. 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, 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 phrase during the American Revolutionary War, when asked to surrender by the British in the 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. 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. Our board has incentivized this 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 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 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 NOG's path to grow 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 of the company. 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 scaleable and commercial. We believe we 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. But 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, operator fit, 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, business development, finance and planning teams and everyone else on board — our investors and covering analysts for listening, 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 entered 2024 positioned with our strongest balance sheet, the highest level of liquidity and largest size and scale since our formation. And 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'll kick things off with a review of operational highlights, and then turn to our business development efforts and 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 in 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 initial production rates from the Williston in the first quarter with a reacceleration 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 turns in line. 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 stepped back, we 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% to 10% reduction in well costs related to our Mascot, Novo and Forge properties. As gas prices remain under pressure, some drilling and completion resources may also be reallocated to our oilier basins, where we could then expect some additional tailwinds. Shifting gears to business development and the M&A landscape, the fourth quarter kept up 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 capped 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 interests 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 Newburn 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 will 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. 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 $46 billion of assets that we're reviewing, both on and off market. 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 combined 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 can be as large or larger than any of our recent transactions. Simply put, the option 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 operating 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 focus on returns 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 operator update we released on February 15. Average daily production for 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 90% 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. For these differentials, particularly in the Delaware, realized differentials 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 and 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 on historical data. And with the 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, the investment of $260 million in drilling, development and ground game capital in the fourth quarter had roughly two thirds allocated to the Permian and one third to Williston. As a result of having access to high quality opportunities, success on the ground game along with a pull forward of organic activity has shifted more investment into the fourth quarter from 2024. The pull-forward activity is most apparent because we are seeing a 5% to 10% decline in expected spud-to-sales development timelines. With over a billion dollars of liquidity comprised of $82 million cash on hand and $1.1 billion available on our 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 hedge front and have been adding significant oil and natural gas hedges to 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. And while Nick alluded to potentially an active year for NOG, those activities may include share buybacks if there's a dislocation in the 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 to 120,000 BOE per day, with 72,000 to 73,000 barrels of oil per day. You'll see typical seasonal declines in the Williston in the first quarter, exacerbated by some freeze-offs in January, but our production cadence will build throughout the year. We anticipate adding about 90 turns in line 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 to $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 run materially in the first half of the year. So the capital will be first-half weighted around 58% to 60%. On the LOE side, our guidance is purposely wide, at $9.25 to $10 per BOE. This is due to the inclusion of our firm transport charge on a quarterly basis, as well as the anticipated items we just discussed. We expect LOE to start on the higher side before trending down throughout the year. I believe there will be room for improvement. We want to be conservative out of the gate. And with the firm transport charges being accrued 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 decline 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 used for heating in the winter months; we would expect higher realizations of 85% to 90% in Q1 benefiting from winter NGL prices and differentials. However, we remain cautious based on the typical pattern 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 Q3 reporting embeds transport costs and pricing instead of a separate GP&T line item, and the fixed costs that are absorbed cause realizations to go down when the absolute price is so low. To the extent gas prices rise materially or NGL prices stay elevated, there's room to the upside. But for now, this is where we're starting. Thankfully, we're well hedged on the gas front, which offsets much of the weakness in the near term. On the oil front, regarding wider differentials to start at $4 to $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 on the Delaware realized deducts have been 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; production taxes are generally higher there than our other basins. Our DD&A rate per BOE will also be higher in 2024, reflecting over $1 billion of both 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 analysts' 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 to depletion deductions, which reduces our taxable income. We're now anticipating becoming a cash taxpayer in 2025, with a potential cash 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 of additional free cash flow over the next several years. With over 20% growth in year-over-year production and the opportunities that are 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. Operator instructions were provided. We'll go to our first question from Neal Dingmann at Truist.

Good morning, guys. Thanks for the time. Nick, it's really just on timing. Could you just go over your capital cadence? Can you talk about maybe looking at what the fourth quarter CapEx was and why that doesn't translate into immediate production? Maybe just talk about timing, if you would?

Sure. Good morning, Neal. I think I'm the one to answer this, because, like a lot of buy-side and sell-side analysts, I'm not an accountant, I'm a former buy-side analyst and I can read a financial statement, but the nuances of accrual accounting versus cash CapEx accounting are important. We are an accrual CapEx company. So we account for our wells by well status and percentage of completion. Just to be clear, about 70% of the cost of a well is in the completion. So as wells become more complete, the amount of capital we account for goes way up. For example, in the fourth quarter, we may have had wells that moved from 25% complete in Q3 to 75% or 90% complete in Q4. That's a lot of capital accounted for, and it doesn't necessarily translate into incremental production in that same quarter. It's an accounting exercise; it's not additional capital over the long run, it's just that you have to allocate that capital to the quarter when the work was done. So it's not that we chose to spend differently; you just have to account for that in that period. Regarding the ground game spending that was elective — the roughly $25 million we capitalized on that — some of those did turn to sales toward the end of the quarter, but when they come online in December, they're obviously not going to contribute materially in that quarter; they will help in Q1 somewhat, but seasonally Q1 is one of our slower quarters. If you look at the overall midpoint of our 2024 guidance, you'll see a partial benefit to the midpoint — roughly a $25 million benefit from the pull-forward. The reason it's not the full $50 million is because our assumptions include the shorter spud-to-sales times we've been seeing on average across our portfolio. We're assuming that continues. That means capital that might have been spent in 2025 is effectively moving into 2024, so there's a half-cycle effect. For those interested, we have a mock accrual model that we can make available that walks through how a D&C list and percentage of completion will actually drive CapEx versus the turns in line model. 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; it's really just a function of timing. In the fourth quarter our turns in line count was right on track. We can't really control how operators provide accounting status; we can control capital decisions. We made the decision to spend $25 million on the ground game because those were great economic decisions and relatively modest dollars. The $50 million-plus variance is not really incremental capital — it's timing. Also, if you look at our published well IRR plots in the earnings presentation, 2023 was among our best well performance years in history. So optically I recognize it's a bit noisy, but it's just noise. Over the long term, everything's going according to plan.

So it does sound like capital on the ground is going to really pay dividends. I'm glad to hear about the timing. As a follow-up, could you talk a little about what opportunities you're seeing out there right now — Permian versus Bakken? Is it pretty split? Or are you seeing predominantly more potential spend in one basin?

Hey Neal, this is Adam. I would say the opportunities we're seeing right now are generally weighted towards the Permian, and most of that's in the Delaware. One emerging theme we've seen evolve is around Appalachia and the commodity price volatility there. You've obviously seen pain ongoing for the last 12 to 18 months. Some conversations were tabled a year or two ago when natural gas prices were higher, and now you're on the inverse of that. Things are settling out and some operators truly feel pain. There may be ability for us to potentially capitalize there. But I think it's across the board in terms of the conversations 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 and there are about 17 different immediate processes either in-market or coming to market shortly. We'll parse through that; a lot of that will not be pursued. I don't think we're changing our underwriting; it's just that you have a few different dynamics, especially on consolidation, with operators having to wrap their head around new assets and potentially rationalizing those assets regardless of the economics.

The only thing I'd add is on the Williston front, you're not seeing as much small-scale activity, but I think there's opportunity for bigger, chunkier transactions over time. We've hit record volumes in the fourth quarter. It's been impressive how resilient our Williston assets have been — they've surprised even us in how they keep growing both organically and via small acquisitions. Our small foray into the Utica has generated a lot of inbound opportunities; we've gotten another half dozen opportunities in the last month or two. We're building technical expertise there and evaluating those opportunities. The Utica is effectively an extension of Appalachia but has distinct dry gas, wet gas and oil parts, so evaluating it gives us incremental deal flow.

Thanks, guys. Congrats.

We'll move to our next question from Charles Meade at Johnson Rice.

Good morning, Nick, Adam and Chad. Nick, I want to go back to the fourth quarter CapEx. I know you've already spent a lot of time on it, but I wanted to take a slightly different angle. I think I understand the dynamic of opportunities out of the ground game and accrual accounting. What I don't get is the magnitude of it, particularly with respect to what you knew on November 1 when you reported Q3. I'm wondering if there's something I don't understand, for example, does the ground game D&C activity get loaded into that line item? Is everything you've done from the ground game year-to-date included? Maybe you could address it from that angle.

Charles, as a non-operator we receive well status updates from operators with some delay. We're only as good as the information provided to us. Oftentimes, we get updates months after the fact. We can be told a well hasn't been spud and then receive a report that it's been completed. So there's timing delay in the information flow.

Same answer could be said for the ground game. Depending on complexity and diligence, some deals close within weeks and some take months, and year-end introduces different tax consequences and urgency from the seller side. We're trying to be accommodating and commercial without sacrificing due diligence protection, but these things ebb and flow in real time.

Charles, I don't think it's necessarily out-of-period adjustments. As we mentioned earlier, it's the pull forward. We had record D&C levels in Q3 and the timing of when those come off really depends on well status. We went from a typical D&C percentage of completion of around 40% up to just over 60%. So you'll see that bill and that ebbs and flows each quarter as we receive well status from operators.

Got it.

To put it in perspective on accrual accounting: an operator collects all service invoices and then aggregates and bills the non-ops. Every operator does that at a different cadence, so you have accruals out there until we're confident costs incurred have been appropriately billed. Those accruals can hang out for a few months depending on the operator relative to the initial production day because we need coverage.

At the end of the day, it doesn't change the aggregate dollars. It's a factor of timing. We're not electing any different well counts or making different capital decisions; it's how much money is being spent in a given quarter. Optically, I understand the concern — I don't like the optics any more than anyone else — but over time it comes out in the wash.

On well tails in 2024 and projected well costs, we've had great conversations with our operators. Field estimates suggest a 5% to 10% underrun from AFEs, but we take AFEs at face value. AFEs can be three months old or 12 months old depending on the operator, and we won't change accounting practices based on that mix.

To illustrate, if an operator sent a gross AFE of $12 million in November and the well is completed in April, we accrue that $12 million starting in November through completion. The accrual is held until final billing, which could be 90 days after the well is on sales. Field reports may later indicate the well cost was $10 million, but you'll only see that $2 million reduction show up later in 2024 when final billing is complete. There's conservatism built in compared to a cash operator that can immediately reflect lower costs. Over time, you'll see the benefits; it will come out in the wash.

Got it. Thanks for all that added detail. If I can transition to a question about visuals — I liked slide 10 showing a gun-barrel view of the Mascot project. A quick question: those yellow circles, I interpret them as completion batches — is that right? And, more open-ended, when you first looked at this a year ago, what lessons or insights did you generate?

Hey Charles, those yellow shapes are completion batches. Operators will do two, three, or four wells at a time. What we're showing is several rows where you need to sequence wells due to drilling and fracing operations. When we looked at this about a year ago, only the Charger unit was producing and several units like Mudbank, Rebel and Bulldog were undeveloped. Early development planned smaller batches of three wells, but with the first batches we started seeing interference issues and frac hits because drilling and fracing were happening simultaneously across the project. The decision was made to do bigger batches. That caused some delays and shifted the expected peak, but the bigger batches improved well performance overall. The project is outperforming by about 5% to 10% versus our original estimates. While delays hurt guidance timing, the long-term economics look better — higher cumulative production and a flatter profile. We're learning that plans change over time and strong communication with the operator is essential. As a working interest project, it's more impactful than our typical non-op packages. We're comfortable with how things have changed.

Charles, you're almost at the finish line on that project — you're down to your last roughly eight wells to be drilled. The Charger and Mustang areas are among the remaining zones. You'll have fewer shut-ins on the back end and the last wave of shut-ins will be reduced into late 2024 and into 2025. While it won't produce the peak rate originally expected in the same timing, it will cumulatively produce more barrels with a much flatter profile and likely better IRR. Continuous drilling and fracing also provides cost savings. Underwriting assumed about $70 per barrel strip when we structured the program; today's mid-to-high $70s strip means we're earning higher returns than originally underwritten.

Great detail. Thank you.

We'll go next to Scott Hanold at RBC Capital Markets.

In your prepared comments, you mentioned wanting to accretively double the company in five years. Can you give us a sense of how you achieve that? Since you pivoted out of the Bakken into other basins and moved into JVs, what's next? Would you consider being an operator? How do you double the company from here?

I'm curious what's that music in the background? I think what you see is what you get. We still see a lot of the same opportunities: the ground game has expanded — we did almost $300 million with the ground game, a record year with several thousand acres and over 30 locations. We've moved from fractional small-scale deals into larger problem-solving transactions for major operators. We've moved into JVs, which were only possible because we have the permanent capital profile and the industry reputation to be a long-term owner. That's an avenue for growth. We know of a half dozen regular non-op transactions that will come to market this year. We've signed 10 NDAs recently; deal flow keeps coming. We're contacted with problems to solve — rationalizing assets, carving out portions of positions, etc. Those are ways to create the scale I'm describing. Regarding new basins, there are other economic basins we might consider, though some present challenges we may avoid. We have the technical expertise and have reviewed a handful of other basins. For some, governance or other structures would be necessary to mitigate risks. Adam, want to add?

A broken record answer: scale, optionality in deal structures, our blueprint, and reputation are the differentiators. We have the balance sheet and execution capability. We're having the kinds of conversations that range from non-op packages to drill-co JVs and co-buying. With ongoing operator consolidation, we can add another arrow to the quiver in how Northern can be helpful. With all of those options, balance sheet, reputation and execution, we can use them to accelerate growth.

Appreciate the color. My follow-up is on shareholder return: you mentioned stepping in with buybacks during market dislocations. How aggressive might you get? How do you think about intrinsic value — where is the point you get really aggressive, and how deep can you go?

I can't give away too much of our playbook and it's a board decision; we've discussed this with the board. As an ex-hedge fund manager, we model these choices internally and compare buybacks versus M&A and other alternatives. If we spend on buybacks today, that capital can't go elsewhere. As we look into Q1, this is the worst relative performance we've seen in about three years given the company fundamentals, which we view as inexplicable. Life gives you lemons and we make lemonade; compressed valuation creates buyback opportunity. We're watching and ready to activate. We have availability under our current authorization — over $80 million is available — and we can always request more from the board if warranted.

We'll go next to John Freeman at Raymond James.

Good morning. Following up on potential new basins: I assume that for you to do anything outside the three basins you're in, it would require a substantial position — not something you could build incrementally. You need scale for a fourth leg, correct?

Yes, that's fair. A few dynamics come into play: land, regulation and how that affects non-operators. When co-buying or buying down a minority interest in an operator position, you often link arms with an operator who already has basin expertise, which helps mitigate risk. We would likely partner with best-in-class operators if we moved into a new basin and add two sets of technical eyes where needed.

There are basics that could be a real challenge; some basins have risks that can be solved with the right operator. If you add the right operator, some of those basin-level risks become manageable.

That makes sense. On guidance related to production: you have a slide showing productivity in the Permian and Williston and the wells are meaningfully outperforming. Does your Williston guidance assume something like 2023-type well results?

John, we always assume some well performance degradation in the year ahead. We already have about nine months of wells in process and a pretty good idea of expected performance for those. We build some degradation into guidance as a conservative assumption. That plays into portfolio management and which wells we participate in. 2024 is off to a great start, but it's early. Overall well performance has been as good as or better than expected; we'll stay conservative in our modeling but there is potential upside.

If you're looking for optimism from an operator, you're not going to get it, but we are encouraged. We try to be conservative in guidance.

From a PDP perspective, our Williston PDP was concentrated with Continental, Marathon and Slawson — some of our best operators in 2023. Looking at our D&C list and near-term AFEs, Conoco, Slawson and Continental are leading the pack, so we're encouraged by where these operators are performing.

Our next question comes from Phillips Johnston at Capital One.

Thanks. Chad, you gave good color on LOE in prepared remarks. You mentioned the run rate should start to fall in mid-2024 as production ramps and AFEs taper. Where might LOE be by Q4? Looking into 2025, would $9 per BOE be a good placeholder or should we model higher or lower?

Phillips, that sounds in the ballpark. We'll run a little hot as we catch up the AFE charge through the first half. We have about six months to catch up rather than a year, so Q1 will be heavier. Then we'll trend down probably toward the bottom end of our guidance range, maybe a bit lower as we close out the back half of the year. For 2025, mid-to-high single digits like $9 per BOE could be reasonable, but lot depends on production mix and transport accruals.

Thanks. One for Adam: the plan involves 70 net spuds and 90 turns in line. You talked about a 20-well gap. What's driving that gap and what does it mean for production trajectory and capital efficiency into 2025?

You've got concentration in some larger projects — for example the Midland Petro project completing work where we have a 40% working interest. As we proceed through the year we'll receive well proposals and the working interest mix and regional concentration will determine the split between spuds and turns. We review activity levels with operating partners quarterly, and that can change the cadence. It's a function of larger transactions like Novo, and where activity is concentrated.

Typically our D&C list equates to about half of our total count; it's been elevated as we've built organically. Over time it should normalize to about half. That normalization masks some capital efficiency benefits. If you go back to 2021 where our D&C list was declining, you saw material improvements in free cash flow yield; this is a normal cycle. Don't assume it leads to material declines — it's more normalization of the D&C list. We've been growing production materially and the D&C list is just reflecting that growth.

We'll move next to Donovan Schafer at Northland Capital Markets.

Thanks for taking the questions. First, on reserves: the PV-10 was $5 billion, which is almost exactly in line with your trading enterprise value, and that's on an SEC pricing basis. I'm trying to understand adjustments. One question: do your Utica and Delaware acquisitions get included in the reserves?

We don't book spuds in the same way an operator does. As a non-operator, we generally book about two to two-and-a-half years of activity where we have the confidence to do so. On typical non-op assets where operators are not providing definitive drill schedules, it's harder for us to show that level of confidence over five years. So many of the locations we have are not fully booked in reserves; our reserve set is conservative.

Another modeling point: the SEC pricing requirement uses trailing 12-month prices, and D&C costs follow commodity prices with a lag. It sounds like you're only now starting to reflect the material declines in D&C costs, yet you're locked into D&C cost assumptions that may reflect 2022 dynamics. Is that right?

Yes, you're correct. We use trailing 12-month prices, which are locked in, and that affects reserves. SEC prices last year were in the mid-90s; now they're in the high 70s, which reduced reserves — we lost some reserves just due to pricing, roughly 30 million barrels cut off the tail. As a non-operator, we also look back at historical AFEs that reflected a higher price environment, so we have to bake in higher well costs and LOE in our reserve calculations. We're being double conservative: lower prices for commodity but higher costs based on historical AFEs.

Understood. One modeling follow-up: with the Williston freeze-offs in Q1, will that materially impact oil mix such that a simple Q1 production dip underestimates the oil mix effect? Could Q2–Q4 oil mix be higher than current full-year guidance implies?

From a guidance standpoint, we're confident in the numbers we put out; we provided both total production and oil volumes so you can infer an annual oil cut. Yes, in Q1 most shutdowns were in the Williston, which is higher oil cut, so you could see a lower oil cut in Q1 and then it rise through the year. The Midland Petro project is very high oil-cut and will improve oil mix throughout the year.

I don't think it'll be materially different because there were also some modest curtailments in the Permian. On the margin it shouldn't be a large swing — perhaps a few percentage points — but not material.

We'll move to our next question from Paul Diamond at Citi.

Good morning. Can you talk more about performance on Forge and what you're assuming out of that trend this year?

Paul, we're seeing similar outperformance to what others have reported. Tide Oil announced 30% to 35% outperformance on new wells versus legacy Forge assets; we're seeing about 30% outperformance versus our underwriting. The drivers are optimization in spacing, completion design and production uptime on artificial lift. We're still modeling based on original acquisition assumptions but we see potential upside and typically like to see six to nine months of history before adjusting our assumptions. So far we're encouraged.

One of the operator's main initiatives was to work on the base assets and reduce operating inefficiencies; we've done a good job cleaning that up.

Got it. Quick follow-up: you mentioned many conversations with small and midcap operators. Are the deal sizes similar to prior deals like Mascot, Forge and Novo, or is there a wide range?

It runs the gamut. We have conversations with very large, mid-cap and smaller counterparties. From our perspective it's not one-size-fits-all; our methodology adjusts depending on the counterparty. We'll structure deals differently depending on who we're dealing with.

To put it in perspective on deal size: ground game transactions can be unit-by-unit; private equity groups have raised capital and are looking at $100 million to $200 million transaction levels for partnering; and we had larger transactions last year that were significantly bigger. It runs the gamut.

We'll go next to John Abbott at Bank of America.

Hey, good morning. You mentioned $4 billion to $6 billion of assets under review. Looking at the balance sheet and share price, what are your thoughts on financing transactions at this point in time?

We've already raised $290 million last fall because we expected great opportunities and wanted to be prepared. We have over a billion dollars of liquidity on the balance sheet; we can finance substantial transactions without raising equity. With recent market developments, many revolvers remain available for scaled companies like ours. We have capacity on the balance sheet for upwards of a billion dollars without additional capital, which should be sufficient for 2024 activity.

Helpful. Regarding exit rate for 2024 production, ignoring noise of accrual accounting, what do you see as a reasonable exit rate?

As a non-operator, small changes in timing can move exit rate materially. If projects accelerate and come on early, we'll produce more barrels and guidance would be raised. We expect a modest Q1 decline, a material jump in Q2, another jump in Q3 and a mild increase in Q4 based on our guidance. Peak production could be in Q3 if activity accelerates. Exit rate is a single point in time — what's most important is cumulative production over the period. We're focused on growing the company and delivering barrels over the long term.

And we'll take our final question from Noel Parks at Tuohy Brothers.

Hi, good morning. First, are you agnostic between private-operated versus publicly traded operators for the ground game or larger A&D? Does it depend on the situation?

I wouldn't say we're agnostic. It depends on the quality of the operator. There are great private operators and some large public operators that underperform. It's operator-specific: great and bad operators exist in both public and private spheres.

Differentiate what you mean by private: private equity-backed operators versus owner-operated private companies have very different business models and time horizons. Their incentives differ. Generally we seek partners with a similar long-term view as us, but we would also partner with quality private equity operators where appropriate.

Thanks for clarifying. One more on the Williston: we've seen a deal there recently, the first in quite a while of size. Some leases are 15 years old or longer — is the land base pretty cleaned up or is there still work to do on neglected books or absent non-op positions?

It's pretty consolidated, but there are still opportunities. It's not the Wild West of open land; deals happen when sellers are ready. There are still assets that will be sold when the timing and price are right.

Another dynamic is evolving completion methodology. Operators have refined techniques and stepped out, improving economics on projects that might not have been viable two or three years ago. You can pick up some whitespace with appropriate operators. As a non-op, we're not beholden to one area, so we can participate in core opportunities wherever they arise. We evaluated about 100 AFEs a quarter in 2023 — there's always more to do.

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.