SandRidge Energy, Inc. (NYSE:SD) Q4 2025 Earnings Call Transcript

SandRidge Energy, Inc. (NYSE:SD) Q4 2025 Earnings Call Transcript March 5, 2026

Operator: 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.

Scott Prestridge: 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.

Grayson Pranin: 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.

Jonathan Frates: 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 of hedges were $57.56 per barrel of oil, $2.20 per Mcf of gas, and $14.92 per barrel of NGL. This compares to third quarter realizations of $65.23 per barrel of oil, $1.71 per Mcf of gas, and $15.61 per barrel of NGL. Our commitment to cost discipline continues to result with adjusted G&A for the quarter of approximately $2.7 million or $1.53 per Boe and $10.2 million or $1.50 per Boe for the full year.

This compares to $2.4 million or $1.39 per Boe and $9.3 million or $1.54 per Boe in the same period last year. Net income was $21.6 million for the quarter or $0.59 per diluted share, and adjusted net income was $12.5 million or $0.34 per diluted share. This compares to $17.6 million or $0.47 per share and $12.7 million or $0.34 per share, respectively, during the same period last year. Net income for the full year was $70.2 million or $1.90 per diluted share and adjusted net income was $54.7 million or $1.48 per share. The company generated adjusted operating cash flow of approximately $108 million for the year compared to $77 million in 2024 and despite the ramp-up in our capital program, free cash flow before acquisitions of roughly $44 million compared to $48 million last year.

Lastly, our production is hedged with a combination of swaps and collars representing approximately 23% of the midpoint of our 2026 guidance. This includes approximately 37% of natural gas production and 27% of oil production. These hedges will help secure a portion of our cash flows and support our drilling program through the rest of the year. We continue to monitor the market and we’ll take advantage of further opportunities to lock in favorable prices as volatility continues. Before shifting to our outlook, we should note that our earnings release and 10-K will provide further details on our financial and operational performance during the quarter. Now I will turn it over to Dean for an update on operations.

Dean Parrish: 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.

Grayson Pranin: 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 and the program is attractive in a range of commodity environments. Our team will continue to be diligent about prioritizing full-cycle returns, monitoring reasonable reinvestment rates and when needed, exercise drill schedule flexibility to make prudent adjustments to our development plans in different economic environments. Also, we do not have significant near-term leasehold expirations and have the flexibility to defer these projects if needed for a period of time. I’d like to pause here to highlight the optionality we have across our asset base, coupled with the strength of our balance sheet, which sets us up to leverage commodity price cycles.

The combination of our oil-weighted and Cherokee gas-weighted legacy assets as well as a robust net cash position give us a multifaceted options to maneuver and take advantage of different commodity cycles. Put simply, we have a strong balance sheet and a versatile kit bag, which makes the company more resilient, better poised to maneuver and adjust to matter the commodity environment. I will now revisit the company’s advantages. Our asset base is focused in the Mid-Continent region with a PDP well set that provides meaningful cash flow, which does not require any routine flaring of produced gas. These well-understood assets are almost fully held by production along history, shallowing and diversified production profile and double-digit reserve life.

Our incumbent assets include more than 1,000 miles each of owned and operated SWD and electric infrastructure over our footprint. This substantial owned and integrated infrastructure helps de-risk individual well profitability for a majority of our legacy producing wells down to roughly $40 WTI and $2 Henry Hub. Our assets continue to yield free cash flow. This cash generation potential provides several paths to increase shareholder value realization and is benefited by a low G&A burden. Sandridge’s value proposition is materially derisked from a financial perspective by our strengthened balance sheet, including negative net leverage, financial flexibility, and an advantaged tax position. Further, the company is not subject to MVCs or other significant off-balance sheet financial commitment.

We have bolstered our inventory to provide further organic growth opportunities in incremental oil diversification with low breakevens in the high-graded areas. Finally, it is worth highlighting that we take our ESG commitment seriously and have implemented disciplined processes around this. Not only do we continue to operate our existing assets extremely efficiently and execute on our Cherokee development in an efficient manner but we do so in a prudent and safe manner. Shifting to strategy. We remain committed to growing the value of our business in a safe, responsible, efficient manner while prudently allocating capital to high-return growth projects. We will also evaluate merger and acquisition opportunities in a disciplined manner, consideration of our balance sheet and commitment to our capital return program.

This strategy has 5 points: one, maximize the value of our incumbent Mid-Con PDP assets by extending and flattening our production profile with high rate of return production optimization projects as well as continuously pressing on operating and administrative costs. Two, exercise capital stewardship and invest in projects and opportunities that have high risk-adjusted fully burdened rate of return while being mindful and prudently targeting reasonable reinvestment rates that sustain our cash flow and prioritize a regular way dividend. An important part of this organic growth strategy is further progressing our Cherokee development and economically growing our production levels while providing further oil diversification. However, we will continue to exercise capital stewardship and maintain flexibility to respond to changes in commodity prices, costs, macroeconomic and other factors.

Three, maintain optionality to execute on value-accretive merger and acquisition opportunities that could bring synergies, leverage the company’s core competencies, complements its portfolio’s assets further utilized approximately $1.6 billion of federal net operating losses or otherwise yield attractive returns for its shareholders. Fourth, as we generate cash, we will continue to work with our Board to assess path to maximize shareholder value to include investment and strategic opportunities, advancement of our return of capital program and other uses. Our regular way quarterly dividend is an important aspect of our capital return program, which we plan to prioritize in capital allocation along with opportunistic share repurchases. The final staple is to uphold our ESG responsibilities.

Now shifting to administrative expenses, I will turn things over to Brandon.

Brandon Brown: 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.

Q&A Session

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

Christopher Dowd: 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.

Grayson Pranin: 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.

Christopher Dowd: 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?

Grayson Pranin: 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.

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

Sergey Pigarev: 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.

Grayson Pranin: 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.

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