Earnings call: NOG reports robust growth and strategic expansion plans

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Earnings call: NOG reports robust growth and strategic expansion plans
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Northern Oil and Gas, Inc. (NOG) has announced significant growth in its profitability and outlined ambitious plans for expansion in its Fourth Quarter and Full Year 2023 Earnings Conference Call.

CEO Nick O'Grady reported a 52% increase in adjusted EBITDA and a 55% rise in quarterly cash flow from operations year-over-year. The company plans to double in size within five years, leveraging mergers and acquisitions, and is actively engaged in discussions for potential deals.

NOG also aims to maximize shareholder returns, with share repurchases on the table. The call revealed a strong liquidity position and guidance for increased production and reduced lease operating expenses (LOE) in 2024.

Key Takeaways

  • NOG reported a 52% increase in adjusted EBITDA and a 55% increase in cash flow from operations year-over-year.
  • The company plans to double in size within the next five years through mergers and acquisitions.
  • NOG is considering share repurchases as part of its dynamic capital allocation strategy.
  • Production increased to over 114,000 barrels of oil equivalent (BOE) per day in the fourth quarter.
  • Guidance for 2024 includes 115,000 to 120,000 BOE per day with capital expenditures between $825 million and $900 million.
  • The company expects to become a cash taxpayer in 2025, which could lead to tax expense reductions and increased free cash flow for shareholders.

Company Outlook

  • NOG anticipates a typical seasonal deferral on IPs from the Williston basin in Q1, with a reacceleration in completion activity expected in spring and summer.
  • The company is guiding to 115,000 to 120,000 BOE per day for 2024, with a focus on the Delaware and Midland basins in the Permian.
  • Capital expenditures for 2024 are projected to be $825 million to $900 million, driven by ground game success and commodity prices.

Bearish Highlights

  • The company expressed disappointment with its first-quarter performance.
  • There are potential concerns regarding degradation in well performance.
  • SEC pricing has impacted reserve calculations due to its reliance on historical prices.

Bullish Highlights

  • NOG's Mascot project is outperforming original estimates by 5% to 10%.
  • The company has a strong liquidity position with over $1 billion available on a revolver.
  • NOG is actively reviewing $46 billion worth of assets for potential M&A opportunities.

Misses

  • The company has non-consented approximately 16% of gross Authorization for Expenditure (AFE), reallocating capital into the ground game.
  • There is a noted discrepancy between current well costs and historical pricing due to D&C costs following commodity prices on a lag basis.

Q&A Highlights

  • NOG discussed the differences between private equity operators and true private operators, acknowledging the value of long-term partnerships with reputable operators like Mewbourne.
  • The company is open to expanding into new basins with the right operating partner.
  • NOG has over $80 million available for buybacks and can request more from the board if necessary.

Throughout the call, NOG's management conveyed confidence in the company's strategic direction, emphasizing their commitment to growth and shareholder value. The company's ticker, NOG, may be one to watch as they execute on their vision for expansion and capital efficiency.

InvestingPro Insights

Northern Oil and Gas, Inc. (NOG) has demonstrated a robust financial performance in the last twelve months as of Q1 2023, which is reflected in several key metrics from InvestingPro. The company's market capitalization stands at a solid $3.48 billion, and the adjusted P/E ratio is attractively low at 3.8, suggesting that the stock could be undervalued relative to its earnings. Additionally, NOG has shown impressive revenue growth of 18.53% over the last twelve months, indicating strong business momentum.

From an operational standpoint, NOG has maintained a high gross profit margin of 76.59%, which is a testament to its effective cost management and operational efficiency. This is further supported by a robust operating income margin of 49.61%, underscoring the company's profitability.

Investors may also take note of the company's dividend track record. An InvestingPro Tip highlights that NOG has raised its dividend for 3 consecutive years, which could be a sign of confidence from management in the company's financial health and commitment to returning value to shareholders. Additionally, with analysts predicting that the company will be profitable this year, this could provide further support for the company's expansion plans and capital allocation strategy.

For those looking for more in-depth analysis and additional insights, there are 7 more InvestingPro Tips available for NOG at https://www.investing.com/pro/NOG. To access these insights and more, readers can use the coupon code PRONEWS24 to get an additional 10% off a yearly or biyearly Pro and Pro+ subscription.

Full transcript - Northern Oil and Gas Inc (NOG) Q4 2023:

Operator: Greetings and welcome to the 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] 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.

Evelyn Infurna: 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 that these measures to the closest GAAP measures can be found in our earnings release. With that, I will turn the call over to Nick.

Nick O'Grady: 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 overtime 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 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. 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 counter-cyclically 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 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 of energy about dynamic capital allocation, and we get asked about share repurchases and where they rank in the stacks. 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 stacks. We don't buy back stock with reckless abandon only one flush with cash and 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 and repurchasing equity during times of value compression, like in early 2022. We tried 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 influx, 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 defined phrase during the American Revolutionary War, when asked to surrender by the British and 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. 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 had great ambition to grow the business to the benefit of our stakeholders. And 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. And done right it will add tremendous per share value row dividend 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 overtime, 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 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. 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 upscale 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, 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 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 formatively 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.

Adam Dirlam: 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 IPs from the Williston in the first quarter with the 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 tails. Our drilling program has remained consistent over the last three quarters as we spun 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 in 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 have 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 completing resources may also be reallocated to our oily 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 grounding 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 grounded in 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 in 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 Appalachian 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 [ph] 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 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 $46 billion of assets that we're 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 rationalized 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 interests 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 three main returns focused over the long term and doing right by our stakeholders. With that, I'll turn it over to Chad.

Chad Allen: 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 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 on 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 is 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 the curtailments in our Mascot project that had the effect of artificially inflated 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 getting capital the fourth quarter, with roughly two thirds allocated 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 forwarding activity is most apparent because we are seeing a 5% to 10% decline in expected spot to sales development timelines. And we with over a billion dollars 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 can we expect that ratio remained 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 discipline on the heavy front and has 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 or 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 fruit in January, but our production cadence will build throughout the year. We anticipate adding about 90 tills 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 returned to more normalized levels. This will bring some large amounts of working capital that we have drawn back on the balance sheet started 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. Or 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 wall costs with for the time being, are forecasted to say flat despite recent evidence of savings and 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 rent 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 for a 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 tech done an average cost per BOE driven by increased production volumes year-over-year, offset by some inflation and 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 to the seasonal demand for propane used for heating in the winter months, 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 and 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 like realizations go down when the absolute price is so low. To the extent gas prices rise materially or a flat prices and NGL stick around. There's room to the upside. But for now, this is where we're starting. Thankfully, we're well ahead on the gas front, which offsets much of the weakness in the near term. On the oil front, while regarding wider on 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 has 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 than our other basins. And 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 policemen deductions, which reduces our taxable income. We're now anticipating becoming a cash taxpayer in 2025, with a potential tax expense of less than $5 million over the following two-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 abroad 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.

Operator: Thank you. [Operator Instructions] We'll go to our first question from Neal Dingmann at Truist.

Neal Dingmann: Good morning, guys. Thanks for the time, Nick is really just on timing. Could you just go over I guess time your cadence that is, can you talk about maybe just looking what's the 4Q CapEx and maybe why that doesn't translate into call it immediate production? Maybe just talk about timing, if you would?

Nick O'Grady: Sure. Good morning, Neal, I definitely think I'm the one to answer this, because, like a lot of the buy 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. And I should be clear, a lot of operated companies like a Diamondback (NASDAQ: FANG ), or a lot of the operators follow cash CapEx, we're an accrual CapEx company. And so that means we're going to account for our wells by well status and percentage of completion. And just to be clear, 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 is an example 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% to 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 our spend, 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, we put this in our release, our till count didn't really change that much. Now, the ground game spending that was elective that $25 million, and we capitalize 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 going to contribute much. They will help in Q1 somewhat, but of course, seasonally, that's one of our slower quarters. If you look at the overall midpoint of our '24 guidance, you will see a partial benefit to the midpoint, clearly we 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 spot, the sales times that we've been seeing, 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 going 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 tillies and model does 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 overtime, 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. In the first fourth quarter or till games is right on track. And we can't really control how we account for wealth status, we can, of course control our capital decisions. 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 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 three month time horizon, when on a 12 to 18 month, for the longer term investors that will come out in the wash. 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, we're not sure. And also, just say, we're not cherry picking single IRR, well, IRR plots we did publish in our earnings presentation, the cube of all our wealth plots year-over-year. And if you look at the data in aggregate, in our earnings presentation, 2023 was amongst our best well performance years in history. So, 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'd be the wrong conclusions. Because the well performance is a testament to everything's going according to plan. So over the long term, everything's going great.

Neal Dingmann: So it does sound like a capital on the ground is going to really pay dividends. So I'm glad to hear about the timing. And then might, just follow up, could you just talk a little bit about, what opportunities that unanimous seeing out there right now Permian versus Bakken? Is it pretty split? Or could you just talk about there is one reason that you're seeing predominantly more potential spends.

Adam Dirlam: Hey Neal, this is Adam, I would say that the opportunities that we're seeing right now are generally weighted towards the Permian, in the Permian, 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 ongoing for the last 12 to 18 months. Some of those conversations are tabled a couple years ago, or a year ago, when you're seeing $7 and now you're obviously on the inverse of that. And they would things settling out. And having some of these operators truly feel a pain. I think there's some 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 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 in interesting, especially on the consolidation front with operators, and then having to kind of wrap their head around their new assets and then potentially rationalizing those assets, whether or not those are core assets to them, regardless of the economics.

Nick O'Grady: 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 overtime. I think there's there are bigger things that couldn't move overtime there, which does give us some excitement. I think it's -- we did hit record volumes in the fourth quarter. It's been amazing how resilient it's frankly surprised even us how our Williston asset just keeps growing both organically and frankly and organically. We've continued to find ways to grow our footprint. Our small foray into the Utica, we have been inundated with Utica opportunities. And we've actually, even in the last month or two, we've probably gotten another half a dozen shot to us. So we've been building up our technical expertise and we're evaluating through those we would use view at this point as an extension of Appalachia. It is technically the Appalachian Basin but that's a really a distinct play. And obviously, the Utica is a broader play in the sense that, there's a dry gas, white gas and oil part of it. So it's a couple of 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.

Neal Dingmann: Thanks, guys. Congrats.

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

Charles Meade: Good morning, Nick, Adam and in Chad. And, Nick, I want to go back to this this question of 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 opportunities out of the ground games 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 1, when you report it 3Q. And so I'm wondering if there's something that I don't understand, like, maybe that that you what you call your ground game, D&C, if that would get loaded into that line item? Is everything you've done from the ground game, year-to-date? I don't know, maybe you could just address it from that angle.

Nick O'Grady: 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 be, we can provide this stuff, sometimes months on delay, right. So we can be told that it well is hasn't been even spud, and then you'll get a report that has been completed. And so I don't have any answer beyond that.

Adam Dirlam: 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 get closed within weeks, and some of them take months. And then you get up into year end. And there's different 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 obviously sacrificing any other protection from a due diligence standpoint, but these things ebb and flow on a real time basis.

Charles Meade: Got it. So if I understand correctly, if you've got both volatility, and also maybe would be fair to characterize the song as is out a period of adjustment catch ups?

Chad Allen: So 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 out come off, really depends on like, Nick mentioned that the well status and where it's at. I think we 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 just over 60%. So I think you're going to see you see that bill, and that's kind of ebbs and flows each quarter as we receive well status from operators.

Charles Meade: Got it.

Adam Dirlam: Charles, maybe just to put it into perspective, in terms of the accrual accounting, and operator is collecting all of the service invoices and everything else. And they have to aggregate all of that and then bill it up 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 actual have been appropriately billed. And so those accruals, depending on the operator can hang out there a few months far long relative to the IP day, because we need to make sure that we've got the coverage that we need.

Nick O'Grady: Yeah. But at the end of the day, it doesn't really change the aggregate dollars. It's not anymore. Well, it's just a factor of time.

Adam Dirlam: Looking at it on a three month basis. I mean you need to be looking at it 12 --

Nick O'Grady: So what I can tell you is we're not electing day anymore. We're not making any different capital decisions, we're looking to the same number of wells. We're electing, we're tilling 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 women, I mean, optically, I'm not any happier about it than anybody else.

Adam Dirlam: On a dog tails in the '24. 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% to 10% kind of under run from these AFEs. But we're going to take these AFEs at face value. And depending on the operator and build AFEs might be three months old, they might be 12 months old. But we're not going to change our accounting practices based on what that mix looks like.

Nick O'Grady: Yeah, and let me walk you through worse, Charles. So let's just say Midland Petro send a AFE, 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 an 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 that, well, maybe it's costing $10 million, right? But so there's a $2 million savings, but only at some point later in 2024, will you see in our results, that that reduction to the capital. So there's a lot of conservatism built into this. If you're typical cash operator, when they tell you when they guide to you, and they say we're going to spend $12 million in this quarter, and then they actually spend 10, they're giving you the immediacy of that benefit, we're not. And so what I would tell you is there's inherent conservatism and how we're doing this, but overtime, you will see the benefits of those. And so while it obviously is the inverse, certainly in the fourth quarter overtime, 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's like I said it will all come out in the wash.

Charles Meade: Got it. And thank you for all that that added detail. And if I can transition away from accounting, and more towards pictures.

Adam Dirlam: Thank you very much.

Charles Meade: Yeah, I like pretty pictures. Slide 10. I appreciate that you guys put this this gun barrel view of your Mascot -- of your Mascot project in one short question, one bigger question. So the first question is, it doesn't look at -- the first question is those yellow circles, I'm interpreting that as kind of completion batches is what it looks like, is that right? And then the second thing I want to ask you guys are more open ended. I really liked this picture. It helps fill in the, the dynamics for me. But what, I guess when you guys first looked at this, you recognize it maybe as much as a year ago. But what are the lessons there? What insights did you generate? Or what insights came to you when you first looked at this?

Jim Evans: 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 will do a min two, three, four wells at a time. And then what we're showing is, you've got several rows where you need to shove wells in behind it, whether it's due to the drilling or, or fracing to protect yourself. So when we looked at this about a year ago, really all you saw on here, in terms of the wells that were we're producing was the charger unit. And so the Mudbank, Rebel [ph] and Bulldog units were all undeveloped at that time. Discussions around development time and completion with MPDC at that time was that we're going to do smaller batches. And so we're you see the yellow dots, we maybe do three wells at a time. We build wells, turn them online, go another six months to 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 heads, because we were drilling and fracing all the same time as we moved from west to east across this project. And so the decision was made, let's do bigger batches. And so what that did is it obviously causes delays. And when we thought the project was going to 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% to 10% versus our original estimates. Obviously, there's delays, but we think in the long run, it's actually going to benefit from a return on investment IRR, overall project economics. And so what we're learning is that obviously, things change overtime. And this is a big working interest project. So it's more impactful than our typical Novo 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 going to go forward. And like say we're acceptable to the changes, obviously, that hurts us from a guidance standpoint and trying to understand when these wells are going to be coming online. But overall, we're very happy with the project and we're comfortable with how things have changed.

Nick O'Grady: And 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 at pretty much eight wells to be drilled. Your frac schedule, you're really all -- and when you can see is where the Charger [ph] and Mustangs which are really the ones that are remaining, there, you're going to have fewer shut ins on the back end you're going to have to in terms of you will have to shut some in when you go to frac 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 will 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 cume way more barrels and a much flatter production profile than ever would have before. And so the total ROI on the project will be 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 fracing, we're saving a lot of money. I mean, that's still be to be determined until we finished the project. And I think we want to be a bit tight lipped and conservative on that, and we're done. But I think we feel very confident at this point that it's gone swimmingly. And obviously, 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.

Charles Meade: Great detail. Thank you.

Nick O'Grady: Yeah.

Operator: We'll call next to Scott Hanold at RBC Capital Markets.

Scott Hanold: In your prepared comments, you mentioned about wanting to accretively double the company in five years. Can you give us a sense of how you achieve that? I mean, since you kind of came on you, you first pivot out of the Bakken into other basins. And, obviously, your next significant move was doing JVs. What's next? Is there other basins you're looking at? Would you consider being an operator like, how do you double a company from here?

Nick O'Grady: I'm curious, what's that wonderful music in the background?

Scott Hanold: Sorry. Lot of the calls going on today?

Nick O'Grady: I think what you see is what you get, I think what I would tell you is we still see the same, I think, we still see a lot of the same stuff. We still see a lot of regular way, the ground game blew up. We did almost $300 million with the ground game that was a record year. I mean, I think we did, several thousand acres over a third -- which included over 30 locations, which is 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 their 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 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 going to come to market, either on or off market in the next -- within this year. And so obviously, we will be looking at those. But I can tell you, to Adam's point, we've signed 10 non-disclosure 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'm 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 going to be a challenge, I think there are some that we would have pushed for the right opportunity to 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 want to add to that.

Adam Dirlam: 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 in 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 that 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 I've talked about the stuff that's in the market. And that's everything from the non-op packages to the drill co 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 you got a reputation, then you can use all of those to your advantage in order to execute.

Scott Hanold: Okay, appreciate that color. And my follow up question is on shareholder return. You mentioned that you'd be willing to kind of step in and, laying the buybacks with market dislocations? Can you give us a sense of like, how aggressive are you willing to get there? And, how do you think about intrinsic value. I mean, it seems like you think the stock price is attractive today, but like, where is -- can you give a sense of where's that sort of point where you really get aggressive? And, and how deep can you go?

Nick O'Grady: Yeah, I mean, I think that would I can't give away too much of our playbook, Scott. And, obviously, it's a board decision, we've been in discussions with the board. We are watching. I'd 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 competed versus generic M&A, and all that stuff. When we run all these things, versus we effectively mock it against where that capital to go elsewhere. Because it is, you have to sit there and say to yourself, if I spend this money today, workers go elsewhere. But frankly, as we look to the first quarter, this represents the worst relative performance we've seen in about three years. And we view it as relatively inexplicable, given the fact that our growth profiles, we look this year as one of the best in the space. Perhaps it's because I can come up with, harebrained 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 presented, we're ready to activate we certainly have availability and our buyback authorization, we can always create more and go to the board if necessary. And so, that, I think we have over $80 million today available, we can always ask for more if the board's willing. And that's a board level decision.

Scott Hanold: Thanks.

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

John Freeman: Good morning, guys. Just following up on the last comment, there where you said that you would consider looking at I guess there's a handful of other basins that you all have looked at or considered. I would assume that for you 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 they all sort of build into, right. You need enough scale, for it to be make sense to add a fourth kind of leg to the stool, right, correct?

Nick O'Grady: Yeah, yeah, I think that's a fair point. And 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, for non-operator. And then, when you think about co-buying or buying down of 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, 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 our own backyard and being able to link up with some of the best in class operators that we want to partner with.

Adam Dirlam: I think there are some basics that would be a real challenge John. I think there's some basins that may have some risks to them that could be solved if you add 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.

John Freeman: That makes sense. And then my follow up question, obviously, we spent a lot of time on the accrual aspects on the CapEx. And it looks pretty clear that whether it's late this year, next year that the cost improvements that you're seeing that some of those major properties eventually that'll show up. If I shift gears and think about the guidance as it relates to production. You've got a slide in there that shows the productivity you're seeing in the Permian and the Williston. And I think the well in particular was pretty surprising for me just you think of it as a mature one of the older basins. And, it looks like obviously still early here, but '24 results look like they're meaningfully outperforming. Is your guidance on production related to the Williston, does it assume we're like a 2023-type well results?

Jim Evans: Yeah, Hey, John, this is Jim. We always go into the year kind of assuming there's going to be some well performance degradation. Obviously we've got about nine months of wells in process, we already have a pretty good idea what we think the performance of those wells will be. But we do always assume there's going to be some degradation. But really, that plays into our portfolio management, right, as we're thinking about which wells we want to participate in which operators we think are the best performers where we're going to target our activity levels. And so that's really how we kind of manage our activity and our wealth performance and make sure that year-over-year we're doing a good job and participating in the in the best well. Obviously, 2024 is off to a great start, but it's pretty early on, we'll keep an eye on that and see how it changes overtime. But we're obviously very encouraged, 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. So overall well performance has been as good are better than expected. But we'll stay true to our roots and expect some well degradation, which is what we build into our guidance and our forecasts. So, potentially some upside there. But we'll wait until we get more information as we go farther into the year.

Nick O'Grady: If you're looking for optimism from an operator, you're not going to get it done.

Adam Dirlam: I'm going to give you a little different perspective, I think, from our PDPs from a Williston standpoint, it was generally concentrated with Continental Marathon and Slawson. So some of our best operators and '23 If I'm looking at the D&C list, as well as some of the near term AFEs, you've got a similar setup with Conoco and Slawson and Continental, all kind of leading the pack in terms of what that makeup is. So encouraged by where these guys are operating and how they're performing.

John Freeman: Appreciate it, guys. Thanks a lot.

Nick O'Grady: Thanks, John.

Operator: Our next question comes from Phillips Johnston at Capital One.

Phillips Johnston: I got it. 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-'24 as production ramps and obviously, you've got the AFE charges tapering off by the middle of next year. So wondering where we might be by Q4. And as you look out into '25, would $9 a barrel be a good place holder for our models? Or would you steer us to something above that or below that?

Chad Allen: Yeah, I mean, I think I think that that sounds in the ballpark. Phillips. Yeah, like I mentioned, we're going to be running a little hot. As we kind of catch up the AFE charge. We only have instead of a year to a group, well, we only have six months. So that'll be a little bit heavier in the first quarter. But yeah, then, as I mentioned, we will trend down probably towards the bottom end of our guidance range, maybe even a little bit lower as we close out the back half of the year.

Phillips Johnston: Okay, sounds good. And then maybe just a question for Adam. Looks like the plan involves 70, net spuds and 90 till in lines. You talked about maybe what's driving that 20 well gap and what that might mean for the trajectory of production, capital efficiency in to 2025.

Adam Dirlam: You've got, obviously the Midland Petro project, kind of finishing up, that's a 40% working interest. So you've got concentration there. And then, well, as we proceed throughout the year, we're going to 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 interests mix, as well as kind of the cadence and activity levels of kind of the Permian as well as the Bakken. So I think it's a function of both Novo and some of the other larger transactions that we had, and where that activity levels concentrated. We're having these conversations on a quarterly basis with our operating partners. And so that can change.

Nick O'Grady: I mean, so as for our normal course, or D&C list, usually roughly equate to about half of our total count. And obviously, it's been elevated. We've been building it, because we've been growing organically. So overtime, it should be about half. And that's partly why I'm elevated. So it masks some of the capital efficiency in the business. And so that's why you will see our capital efficiency markedly improved. And if you go back to say, 2021, where our D&C list was declining, you would see material improvements, the free cash flow, yield and other things, and that's because you were, you're 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 for I mean, think about it last quarter, our production grew like 53 -- our oil production grew to 5,300 barrels, and not all that was just Novo that a lot of that was organic. So you've been seeing volume growth and material, right? So you're, you're just really flattening out that growth production effectively as you as you exit the year to some degree.

Phillips Johnston: Sounds good guys, thank you.

Nick O'Grady: Yeah.

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

Donovan Schafer: Hey, guys, thanks for taking the questions. So, first, I want to talk about the reserves. So I was a reservoir engineer, my first job at a college so I might be biased on this. But I do think, you can make a lot of you can draw a lot of meaningful conclusions, or pull out some insights from if you know how to make some adjustments. Because obviously, there are a lot of adjustments to make in order to show real a truce or economic reality. But so the TV 10 was $5 billion, which is almost exactly in line for your trading terms of enterprise value. And, that's on an SEC pricing basis. And that can cause crazy distortions, this time around, it does, at least, in my view look like the SEC pricing happens to not look too crazy, and be kind of sort of close to what we could expect going forward. But there are a lot of other things for where you are right now as a company, where the reserve work may not be accurate and need more adjustments. So one is Utica and Delaware acquisitions. I don't think those of you included, so if you can confirm that.

Nick O'Grady: We don't really book spuds in our -- as a non-op, we don't book our spuds, right? So we have, unlike an operator an operator can book a full spud booking for five years. I mean, how many spuds do we book in there. We generally book about two to two and a half years of activity, right. As a non-operator, we still need to show that we're converting more than 20% of our spuds every single year. And so in the projects that we've been doing the Midland forward, we have a more definitive drill schedule so we can book more spuds 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 five years. Now, we're obviously going to have the activity that we showed last year almost 80 net till's, but we can 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.

Donovan Schafer: 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, the other thing about how the way to do affiliate 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're kind of stuck with the current commodity price, the 2023 commodity prices, and then they do the same thing on D&C prices, or D&C costs. But D&C costs follow commodity prices on kind of a lag basis. Like you're only just now, it sounds like the more material decline in D&C costs, you're kind of only just now starting to see that yet, you're sort of locked in at a level of D&C costs that honestly may have been more reflective of commodity prices in 2022. So that also kind of creates, like, am I right in that? Am I remembering that correctly?

Nick O'Grady: Yeah, you're correct there, right. We have to use trailing 12-month prices. So that's locked in, we have to hold that constant going forward. Similarly, for elderly. And so if you think about where we were last year, SEC prices were in in the mid-90s. Now we're in the high 70s. So that has an impact on reserves. And we lose a lot of reserves, just cutting off the tail end, those reserves that we had to replace those about 30 million barrels that we lost just due to pricing. And then also on the well costs. 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 AFE, 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 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.

Donovan Schafer: Yeah, okay. Okay. Moving on, just a mess and more follow up on that afterwards, but for now, the other one, just as a quick modeling question, With Q1 with a freeze and the Williston in Q1 having an impact on production there. Is that going to have an impact on the oil mix? When I kind of triangulate that with full year guidance, is that something where we can see oil mix come down a bit or higher, like, in a way that would material at all? I'm just trying to think I want to avoid a situation where, somebody just models a slight production dip in Q1. But you end up under estimating the impact because it is that more weighted towards oil or change in the oil mix or something? And then does that mean, in Q2 Q3 Q4, you could have a higher oil mix and what isn't necessarily in the guidance for the full year?

Adam Dirlam: I mean, I think I would expect -- I think 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 oil cut there. Yes, in the in Q1, most of the shutdowns 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 so Midland Petrol project is a very high oil cut. And so that will also improve your oil cut throughout the year there.

Nick O'Grady: And I don't think I mean, I don't think it's I mean, I don't think it's going to be materially -- I don't think it's going to be material. Because there were also some mild curtailments in the Permian as well. So I don't -- I mean, on the margin, none of that I don't think it's going to be. You're talking about a 10 point difference between the -- 7 point difference between the Permian and the rest of our oil base. And so I don't think it's going to be massive in any material way.

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

Paul Diamond: Good morning. Thanks for taking my call. Just a couple of quick ones. Talking about some of performance on Forge and you just talk a bit more about that. You guys assuming that as an assumption of the trend, I guess what you're expecting out of that this year?

Jim Evans: Yeah, thanks, Paul. This is Jim. Yeah, we're seeing the same thing, Tide Oil [ph] announced yesterday. They're seeing about 30% to 35% outperformance on the new wells versus kind of the legacy Forge assets. We're seeing the something similar versus what we underwrote? It's around 30% outperformance. I think it's around optimization on spacing completion design, production uptime on artificial lift that is now baked into our go forward plan. We're still modeling based on what we originally underwrote for the acquisition. So we do see 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 six to nine months of, of history before we feel confident in adjusting our assumptions. But so far, we're very encouraged with what we're seeing out there.

Nick O'Grady: Yeah. And then also just on one of their main initiatives, when they bought the asset was really to work on the BVP [ph] itself, was really the work on lowering costs at the actual LP on the existing assets. And I think we've done a good job cleaning that up.

Paul Diamond: Got it understood. And I just do have a quick follow up. You guys talked about having a lot of conversations with the small and midcap operators. You talked about scale being similar to prior deals, but just dig down a bit more on that because there pretty wide range to that scale you're seeing or is that pretty much locked in similar to Mascot, Forge, Novo thing of that sort, where it could be bit smaller, a bit larger? What do you guys seeing?

Nick O'Grady: You mean, just in terms of the partners?

Paul Diamond: Yeah, historically.

Nick O'Grady: [Multiple speakers]. Yeah, I mean, I think a lot of the stuff from the mega transactions, we have a lot of conversations with the largest of the large. Certainly, we have a lot of interest from small scale people as well, 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 midcap and upper midcap companies as well. So I think it runs the gamut. I think what I would tell you from our perspective, and I'd rather lead out and talk about this than me is that from our perspective, it's not a one, not 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 going to become more mean spirited depending on who we're dealing with.

Adam Dirlam: That's right. But I'm just, 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 for example, private equity groups that have just raised capital that are looking to participate in both $100 million to $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 significantly larger than that. So it runs, it runs the gamut, like Nick was saying.

Paul Diamond: Understood. Thanks for your time. And I'll leave there.

Operator: We'll go next to John Abbott at Bank of America (NYSE: BAC ).

John Abbott: Hey, good morning, and thank you for taking our questions. Sticking with the $4 billion to $6 billion 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?

Nick O'Grady: Yeah, I mean, John, we've raised $290 million last fall 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 a billion dollars of liquidity. Frankly, with all of them 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, on balance sheet for upwards of a billion dollars without raising any additional capital. And I think that would say she is quite easily, you know, for the time being. Obviously, beyond that, we'll see. But as you do those that and, we haven't really done much more than a billion dollars in a year. So I think we're in pretty good shape for 2024.

John Abbott: Very, very helpful. And, I mean, there was a lot of conversations earlier on accrual accounting. But I guess the real question here is, looking beyond the noise as you sort of think about the exit rate for this year. Nothing that's super specific. What do you kind of see the exit rate for 2024 in terms of production?

Nick O'Grady: Yeah, I mean, I, as a non-operator, Jim Evans will stab me with a large knife. If I talked about that. Because, 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, we obviously, believe we'll be down modestly in the first quarter, we would expect the material jump in the second quarter and other jump in the third quarter, and then a mild jump in the in the fourth quarter. So I think that I would just leave it at that for now. But I would say that, obviously, based on our guidance that is substantial, and I'm sorry, to plan on that --

Jim Evans: It's February.

Nick O'Grady: It's February, but --

Jim Evans: But things can change --

Nick O'Grady: Yeah. So I'm sorry, but as an 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 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, you know, is the part of it. And honestly, to the extent that it gets accelerated, we're going to produce a lot more barrels this year. So that's a good thing. But the exit rate is, we're not a laundromat, right? So this is something, right, that 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 overtime. And I think that that's the most important thing.

John Abbott: Very helpful. Thank you for taking our questions.

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

Noel Parks: Hi, good morning. Just had a couple. 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 interest right now either for the ground game or for larger A&D?

Nick O'Grady: 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 the largest, there are really large operators that are bad. I mean, I think it just, it really goes operator specific. There are really good operators, and they're really bad operators that are big and small, right out of my meter.

Adam Dirlam: You need to differentiate what private means? Are you talking about private equity or you're talking about true private, right? And those business models are run very, very differently. You've got one that's renting an asset, one that's had it and will continue to have it for a very, very long time. And so their viewpoint short term or long term basis can be very, very different.

Nick O'Grady: Yeah. I mean, Mewbourne is a private company. And it's one of the finest operators in the world. And I can think of many private equity backed operators that are renting the asset and looking to flip it.

Adam Dirlam: Yeah. So I'd 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.

Nick O'Grady: Absolutely.

Noel Parks: Great. Well, thanks for clarification. And I guess, I was wondering a bit, talking about the Williston and we have seen a deal there, the first one may be 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. Leases some of those leases, probably 15 years old, if not longer at this point. So as wonder 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 neglected books or absent non-op positions that you can still --

Nick O'Grady: It's pretty blocked. It's pretty blocked up, Noel. But there are still things to do. I mean it's just going to 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?

Adam Dirlam: Yeah, I think that's fair. 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, 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, 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 whitespace acreage and bringing in appropriate operators that you know are going to do a good job. And as a non-operator, you know, we're not beholden to one particular area, right. So we can get in to the core day in and day out and continue to grow so far working interest as we get 100 AFEs a quarter, as we did in 2023. So there's always more to chop. It's a different dynamic.

Operator: And that concludes the question-and-answer session. I would like to turn the conference over to Nick O'Grady for closing remarks.

Nick O'Grady: Thanks, everyone, for joining us today. We'll see you on the next one. Appreciate your time. This is the way.

Operator: And this concludes today's conference call. Thank you for your participation. You may now disconnect.

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