Hello, everyone. Thank you for joining us, and welcome to the Q4 2025 SandRidge Energy Conference Call. [Operator Instructions] I will now hand the call over to Scott Prestridge, Senior Vice President of Finance and Strategy. Please go ahead.

Thank you, and welcome, everyone. With me today are Grayson Pranin, our CEO; Jonathan Frates, our CFO; Brandon Brown, our CAO; as well as Dean Parrish, our COO. We would like to remind you that today's call contains forward-looking statements and assumptions, which are subject to risks and uncertainties, and actual results may differ materially from those projected in these forward-looking statements. These statements are not guarantees of future performance, and our actual results may differ materially due to known and unknown risks and uncertainties as discussed in greater detail in our earnings release in our SEC filings. We may also refer to adjusted EBITDA and adjusted G&A and other non-GAAP financial measures. Reconciliations of these measures can be found on our website. With that, I'll turn the call over to Grayson.

Thank you, and good afternoon. I'm pleased to report on a strong quarter and the year for the company. Production averaged 18.5 MBoe per day during the full year, an increase of 12% on a Boe basis and 32% on oil versus 2024, benefited by our operated development program in the Cherokee Play and production for the fourth quarter averaged 19.5 MBoe per day. Before getting into this and other highlights, I will turn things over to Jonathan for details on financial results.

Thank you, Grayson. Compared to the third quarter of 2025, the company continued to see higher natural gas prices, partially offset by lower WTI. We continue to grow production, generating revenues of approximately $156 million for the year, which represents a 25% increase compared to 2024. Adjusted EBITDA was roughly $25 million in the quarter and $101 million (sic) [ $101.1 million ] for the year compared to $24 million and $69 million in the prior year period. As always, we continue to manage the business within cash flow while growing production and utilizing our NOLs to shield us from federal income taxes. At the end of the quarter, cash, including restricted cash, was approximately $112 million (sic) [ $112.3 million ], which represents over $3 per common share outstanding. The company paid $4.4 million in dividends during the quarter, which includes $0.6 million of dividends paid in shares under our Dividend Reinvestment Plan, including special dividends, SandRidge has now paid $4.60 per share in dividends since the beginning of 2023. On March 3, 2026, the Board of Directors declared a $0.12 per share dividend payable on March 31 to shareholders of record on March 20, 2026. Shareholders may elect to receive cash or additional shares of common stock through the company's noted Dividend Reinvestment Plan. During the year, the company repurchased approximately 600,000 or $6.4 million worth of common shares at a weighted average price of $10.72 per share. Our share repurchase program remains in place with $68.3 million remaining authorized. Capital expenditures during the quarter were approximately $18 million, including drilling and completions and new leasehold acquisitions. The company has no debt outstanding and continues to fund all capital expenditures and capital returns with cash flows from operations. Commodity price realization for the quarter before considering the impact…

Thank you, Jonathan. Let's start with a brief review of a very successful year in 2025, then discuss recent results in 2026 drilling and completions. Average production in 2025 was 18.5 MBoe per day, which was 4% above the midpoint of guidance. This was driven by strong well results on new wells in the Cherokee Play as well as continued focus of our operations team on optimizing base production. Total capital spend for the year, including leasehold, was $76.2 million, which falls in line with midpoint of guidance A rigorous bidding process focused on driving drilling and completion costs down in the Cherokee Play and low artificial lift failure rates from previous years of improvements kept us on budget. Lease operating expenses for the year were $36.2 million or 14% below the low point of guidance. That includes $4.3 million but nonrecurring, noncash adjustments of operating accruals that benefited LOE. Excluding those, LOE still came in below the low point, driven by the team's focus on reducing expense mark overs, LOE efficiencies implemented on recent acquisitions and utility costs. During the year, the company successfully completed and brought 6 wells online from our operated one-rig Cherokee drilling program. We recently brought online well 7 and 8 in the program and are drilling the 9. We are pleased with the results of the first 6 operated wells which had a per well average peak 30-day production rate of approximately 2,000 Boe per day, made up of 44% oil. Moving to our 2026 capital program. We plan to drill 10 operated Cherokee wells with one-rig this year and complete 8 wells. The remaining 2 completions are anticipated to carry over to next year. A majority of the remaining wells in our development program this year directly offset proven or in progress wells in the area. These new wells and the results in the area give further confidence in reservoir quality and expectations in the area. Gross well costs vary by depth, but are estimated to be between approximately $9 million to $11 million. We intend to spend between $76 million and $97 million in our 2026 capital program, which is made up of $62 million to $80 million in drilling and completions activity and between $14 million and $17 million in capital markovers, production optimization and selective leasing in the Cherokee Play. Our high-grade leasing is focused to further bolster our interest, consolidate our position, and extend development into future years. With that, I will turn things back over to Grayson.

Thank you, Dean. I'd like to look back at 2025 for a moment. 12 months ago, we initiated our operated development program in the Cherokee, which, among other factors, has contributed to reaching a multiyear high with production averaging 19.5 BOE per day in the fourth quarter. In addition, something for which we are very proud, we set a new record of over 4 years without a recordable safety incident. I'm very proud of our team for these accomplishments and other value-adding contributions this year. They stood up the Cherokee development program from scratch, have implemented several cost efficiency initiatives, and have done all this while championing safety, resulting in 0 incidents. In addition, these achievements were done with a lean, but very engaged and experienced staff which have proven to be capable operators with peer-leading operating and administrative cost efficiencies. Given the promising initial results achieved in 2025 and the attractive returns for these Cherokee wells, we plan to continue our Cherokee development with one-rig throughout 2026. As we look forward to developing these high-return assets, we anticipate growing oil production volumes another approximately 20% this year. In addition, we plan to sustain our ground game by opportunistically securing new leases at attractive metrics to further increase our interest in wells that we plan to operate or that will further extend our development option. We're hopeful that our approximately 24,000 net acres in the Cherokee Play as well as our continued leasing efforts will translate to a meaningful multiyear runway as we look beyond 2026. Our operated Cherokee wells have a robust return with breakevens for our planned wells down at $35 WTI. Our baseline economics were set earlier this year and recent increases in commodity price would only enhance these returns. In addition, while these returns are durable…

Thank you, Grayson. As we approach the conclusion of our prepared remarks, I will point out our fourth quarter adjusted G&A of $2.7 million or $1.53 per Boe continues to compare favorably to our peers. The continued efficiency of our organization reflects our core value to remain cost disciplined as well as prior initiatives, which have tailored our organization be fit for purpose. We will maintain our efficiency and low-cost operation mindset and continue to balance the weighting of field versus corporate personnel to reflect where we create value. Outsourcing necessary but for [indiscernible] and less core functions such as operations accounting, land administration, IT, tax and HR has allowed us to operate with total personnel of just over 100 people while retaining key technical skill sets that have both the experience and institutional knowledge of our business. In summary, at the end of the fourth quarter, the company had approximately $112 million in cash and cash equivalents, which represents over $3 per share of our common stock outstanding and inventory of high rate of return, low breakeven projects, low overhead, top-tier adjusted G&A, no debt, negative leverage, a flattening production profile, double-digit reserve life and approximately $1.6 billion of federal NOLs. This concludes our prepared remarks. Thank you for your time today. We will now open the call to questions.

[Operator Instructions] Your first question comes from Christopher Dowd of Third Avenue Management.

Your 2026 production guidance of 6.4 million to 7.7 million Boe and CapEx of $76 million to $97 million. has got a bit of a range to it, for the benefit of everyone on the call, could you just give a little more context on what scenarios might lead to the higher and lower end of that guidance? And then I've got a follow-up.

Sure. Yes. Thank you for the interest and the questions. Things that we're watching for that range is timing is a big part of it. So right now, we're planning on drilling 10 wells and completing 8, if the timing of the shift due to the availability of crews or weather or anything like that, that could shift wells later in the year or into next year potentially that could affect the range as well as working interest. A lot of the wells that we're developing this year, their pooling hasn't been finalized in Oklahoma, as you pool the well and sometimes you can achieve higher working interest through that pooling process. And so while we budgeted for some potential net increases, additional could -- add additional capital, but it also adds additional production with that as well. And so we tend to like to make sure that we're budgeting at appropriate achievable levels. And so we're not accounting for all of that potential upside that could occur through the normal planning and development process throughout the year.

Very helpful. And then just as my follow-up question, can you comment on how you're viewing what seems to be a fairly supportive spot market today relative to how that might influence your hedging positions going forward? I know you mentioned, I think, about 23% hedged today. But how should we think about the opportunity to kind of lock in more certainty on the cash flows going forward?

Sure. No, it's a great question, one that we're watching literally by the mid year even as we're on the call now, I'm going to say a few words and then hand this off to our CFO, Jonathan Frates, to say more. But I think a big piece of this is, one, we do not have the debt, so we don't have any bank-mandated hedging requirements. Maybe we're not required to hedge in the down side and could be more opportunistic in nature. It has -- prices have increased this year. We've just -- we've done that and taken in additional options. You can probably see a lot of speculation in the marketplace on where oil prices could go to. So we're mindful to layer in additional contracts. We want to do so that we also have some opportunities for the potential upside. And with that, I'll hand things over to Jonathan.

Yes. I think you said it well, Grayson. We're very opportunistic with this program. I'll point out that majority of these oil hedges came very recently. So if you look at the balance of the year, I know I mentioned in the commentary that we had up 27% of guided production hedged on the oil side, but that -- due to the fact that we put a lot of these very recently, and we're 2 months into the year. The balance is going to look a little higher than that, which you can calculate based on your own estimates. But we're very optimistic as these prices continue to rise up. We're watching it every day, and we'll layer on more as the year goes on, assuming things continue in this direction.

[Operator Instructions] Your next question comes from the line of Sergey Pigarev of Freedom Broker.

I think everyone had this question on guidance, '26 with production and CapEx. And so actually, I want to ask about the guidance too, I say that you have this higher range of price differentials guidance for NGLs. And actually in Q4, we were a bit surprised because of actually higher differentials that we expected for Q4 yes, so do you see some temporary things here or it's like something structural, and we will see higher differentials from here.

Sure, Sergey. I appreciate your question. As we obviously, there's different differential depending on the commodity. I think if you look at oil, that's been relatively tight, I think you may be referencing gas. As we talk to gas and we've talked about this directionally, as we benefit from higher commodity prices and when compared to the Henry Hub benchmark, the fixed deducts within our gas stream are reduced, so you kind of have an expanded realization. So if you look into an environment where we have $4 gas, you'll see us towards the higher end of our guidance range. If you're looking at $2 gas, it's going to be near that lower range, and that's why we provided that range of 50% to 70% to try to accommodate different gas environment. I think if you look at the whole year, we're really close to that center of 60%, and we're averaging that -- I think that average just over $3 for a benchmark perspective. Relative to Q4, in particular, you had a widening of a regional basis, a lot of our gas is sold through Panhandle Eastern and [ NGL PL ] markets. I think that is localized and temporal. I think as we look in structurally, we're wanting to make sure that we're selling as much gas as we can at higher commodity prices because that's when we see the highest realization.

There are no further questions at this time. This concludes today's call. Thank you for attending. You may now disconnect.