SandRidge (SD) Q4 2025 Earnings Call Transcript

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Date

Thursday, March 5, 2026 at 2 p.m. ET

Call participants

• President & Chief Executive Officer — Grayson R. Pranin
• Chairman — Jonathan Frates
• Chief Operating Officer — Dean Parrish
• Chief Financial Officer — Brandon L. Brown

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Takeaways

• Production Volumes -- Average daily production reached 19.5 MBOE in the quarter and 18.5 MBOE for the year, reflecting a 12% increase on a BOE basis and 32% increase in oil output compared to 2024.
• Revenue -- Annual revenue totaled approximately $156,000,000, representing a 25% increase.
• Adjusted EBITDA -- Achieved $25,000,000 for the quarter and $101,000,000 for the year, compared to $24,000,000 and $69,000,000 in the prior-year periods.
• Net Income -- Recorded $21,600,000 for the quarter and $70,200,000 for the year, translating to $0.59 and $1.90 per diluted share, respectively.
• Adjusted Net Income -- Delivered $12,500,000 for the quarter ($0.34 per share) and $54,700,000 for the year ($1.48 per share).
• Operating Cash Flow -- Adjusted operating cash flow stood at approximately $108,000,000 for the year, up from $77,000,000.
• Free Cash Flow -- Generated roughly $44,000,000 before acquisitions, slightly down from roughly $48,000,000.
• Capital Expenditures -- Quarterly capital spend was approximately $18,000,000, with full-year capital expenditures at $76,200,000, aligning with the midpoint of guidance.
• Dividends -- Paid $4,400,000 during the quarter, including $600,000 in shares; total dividends per share since 2023 now $4.60.
• Share Repurchases -- Repurchased around 600,000 shares for $6,400,000 at a weighted average price of $10.72, leaving $68,300,000 authorization remaining.
• Balance Sheet -- Ended the quarter with no debt and $112,000,000 in cash, equating to over $3 per share.
• Commodity Price Realization -- Realized $57.56 per barrel for oil, $2.20 per Mcf for gas, and $14.92 per barrel for NGL in the quarter.
• Cherokee Play Development -- Completed eight operated wells; the first six had a per-well average peak 30-day rate of approximately 2,000 BOE/day (44% oil); commenced drilling the ninth.
• Cost Discipline -- Adjusted G&A for the quarter was $2,700,000 ($1.53 per BOE); annual adjusted G&A was $10,200,000 ($1.50 per BOE), reflecting continued efficiency initiatives.
• Lease Operating Expense (LOE) -- Full-year LOE was $36,200,000, reported as 14% below the low-point of guidance, aided by $4,300,000 in nonrecurring noncash accrual adjustments.
• Hedging -- Swaps and collars hedge approximately 23% of 2026 guided production midpoint, specifically approximately 37% of natural gas and 27% of oil production, to manage cash flow volatility.
• 2026 Production Guidance -- Management guided 2026 production between 6,400,000 and 7,700,000 BOE, with capital expenditure planned between $76,000,000 and $97,000,000.
• Cherokee Drilling Plan for 2026 -- Expect to drill 10 operated wells, complete eight this year, and defer two completions to the following year.
• Dividend Declaration -- Board declared a $0.12 per share dividend payable March 31, 2026, with an option for cash or stock via the dividend reinvestment plan.
• Breakeven Economics -- Management cited Cherokee wells with breakevens at $35 WTI and the majority of legacy wells profitable at $40 WTI and $2 Henry Hub.
• Federal Net Operating Losses (NOLs) -- The company maintains around $1,600,000,000 in federal NOLs, used to shield taxable income.
• Operational Safety -- Achieved over four years without a reportable safety incident, marking a new corporate record.
• Asset Positioning -- Approximately 24,000 net acres held in the Cherokee, supporting a potential multi-year drilling runway.
• M&A and Capital Allocation -- Management restated capital stewardship and openness to merger and acquisition opportunities consistent with balance sheet strength and capital return priorities.

Summary

SandRidge Energy (NYSE:SD) reported a quarter characterized by expanding production, rising revenues, and increased adjusted EBITDA, all underpinned by continued cash flow discipline and a debt-free balance sheet. The company executed on cost controls through lower operating expenses and peer-competitive administrative costs. Management articulated a forward plan to sustain Cherokee Play drilling with a focus on further oil volume growth, while keeping capital expenditures flexible according to market and operational timing. Strategic priorities include robust hedging practices, attentive capital allocation between dividends, share repurchases, and potential M&A, as well as leveraging its extensive NOL position for tax efficiency.

• The company specifically cited, "breakevens for our planned wells down to $35 WTI," positioning the portfolio for resilience across commodity cycles.
• Hedge coverage for 2026, described as "opportunistic," was recently increased in response to firming commodity prices and comprises both swaps and collars.
• Future production may benefit from additional working interest or development timing optimization, subject to factors including pooling process outcomes and operational logistics.
• Grayson R. Pranin noted the company does not have significant near-term leasehold expirations, providing schedule flexibility for deferring projects without risk of asset loss.
• Integrated water disposal (SWD) and electric infrastructure spanning over a thousand miles each reduce individual well risk and support stable development economics.

Industry glossary

• MBOE: Thousand barrels of oil equivalent, a combined unit used for expressing both oil and gas production on an energy-equivalent basis.
• Cherokee Play: A specific oil and gas producing region in Oklahoma targeted by the company's drilling and development activity.
• NOLs (Net Operating Losses): Tax losses that can be carried forward to offset future taxable income, reducing federal tax liabilities.
• SWD (Salt Water Disposal): Infrastructure enabling disposal of produced water from oil and gas operations, mitigating environmental and operational risks.
• LOE (Lease Operating Expense): Recurring costs of operating and maintaining productive oil and gas leases, excluding significant capital investments.

Full Conference Call Transcript

Grayson R. Pranin: Thank you. Good afternoon. I am pleased to report on a strong quarter and 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 2024, the company continued to see higher natural gas prices, partially offset by lower WTI. We continued to grow production, generating revenues of approximately $156,000,000 for the year, which represents a 25% increase compared to 2024. Adjusted EBITDA was roughly $25,000,000 in the quarter and $101,000,000 for the year, compared to $24,000,000 and $69,000,000 in the prior-year periods. 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 $112,000,000, which represents over $3 per common share outstanding.

The company paid $4,400,000 in dividends during the quarter, which includes $600,000 of dividends paid in shares under our dividend reinvestment plan. Including special dividends, SandRidge Energy, Inc. has now paid $4.60 per share in dividends since 2023. On 03/03/2026, the Board of Directors declared a $0.12 per share dividend payable on March 31 to shareholders of record on 03/20/2026. 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 shares, or $6,400,000 worth of common shares, at a weighted average price of $10.72 per share. Our share repurchase program remains in place, with $68,300,000 remaining authorized.

Capital expenditures during the quarter were approximately $18,000,000, including drilling and completions and newly sold 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, was $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 $5.23 per barrel of oil, $1.71 per Mcf of gas, and $15.61 per barrel of NGLs. Our commitment to cost discipline continues to yield results with adjusted G&A for the quarter of approximately $2,700,000, or $1.53 per BOE, and $10,200,000, or $1.50 per BOE for the full year.

This compares to $2,400,000, or $1.39 per BOE, and $9,300,000, or $1.54 per BOE in the same period last year. Net income was $21,600,000 for the quarter, or $0.59 per diluted share, and adjusted net income was $12,500,000, or $0.34 per diluted share. This compares to $17,600,000, or $0.047 per share, and $12,700,000, or $0.34 per share, respectively, during the same period last year. Net income for the full year was $70,200,000, or $1.90 per diluted share, and adjusted net income was $54,700,000, or $1.48 per share.

The company generated adjusted operating cash flow of approximately $108,000,000 for the year compared to $77,000,000 in 2024, and, despite the ramp up in our capital program, free cash flow before acquisitions of roughly $44,000,000 compared to $48,000,000 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 will 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-Ks 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 us start with a brief review of a very successful year in 2025, then discuss recent results and 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 $76,200,000, which falls in line with the 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 $36,200,000, or 14% below the low point of guidance. That includes $4,300,000 of 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 workovers, LOE efficiencies implemented on recent acquisitions, and utility costs. During the year, the company successfully completed and brought six wells online from our operated one-rig Cherokee drilling program. We recently brought online wells seven and eight in the program and are drilling the ninth.

We are pleased with the results of the first six 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 eight wells. The remaining two 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 $9,000,000 to $11,000,000. We intend to spend between $76,000,000 and $97,000,000 in our 2026 capital program, which is made up of $62,000,000 to $80,000,000 in drilling and completions activity and between $14,000,000 and $17,000,000 in capital workovers, 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 R. Pranin: Thank you, Dean. I would like to look back at 2025 for a moment. Twelve 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 four years without a reportable safety incident. I am very proud of our team for these accomplishments and other value-adding contributions this year. They set up a Cherokee development program from scratch, have implemented several cost-efficiency initiatives, and have done all this while championing safety, resulting in zero 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 are hopeful that our approximately 24,000 net acres in the Cherokee, 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 to $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, exercising 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 would 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 Cherokee and gas-weighted legacy assets, as well as our robust net cash position, give us 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 and better poised to maneuver and adjust no 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, have a long history, shallowing, and a diversified production profile, and double-digit reserve life. Our incumbent assets include more than a thousand miles each of owned and operated SWD and electric infrastructure over our footprint. This substantial owned and integrated infrastructure helps derisk individual well profitability for the 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 Energy, Inc.'s value proposition is materially derisked from a financial perspective: our strengthened balance sheet, including negative net leverage, financial flexibility, and advantaged tax position. Further, the company is not subject to MVCs or other significant off-balance-sheet financial commitments. We have bolstered our inventory to provide further organic growth opportunities and incremental oil diversification with low breakevens in high-graded areas. Finally, it is worth highlighting that we take our ESG commitment seriously and have implemented disciplined processes around it.

Not only will we continue to operate our existing assets extremely efficiently and execute on our Cherokee development in an efficient manner, but we will 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 the manner and consideration of our balance sheet and commitment to our capital return program. This strategy has five 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 rates of return while being mindful and prudently targeting reasonable reinvestment rates that sustain our cash flows 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, complement its portfolio of assets, further utilize approximately $1,600,000,000 of federal net operating losses, or otherwise yield attractive returns for its shareholders. Four, as we generate cash, we will continue to work with our Board to assess paths 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 L. Brown: Thank you, Grayson. As we approach the conclusion of our prepared remarks, I will point out our fourth-quarter adjusted G&A of $2,700,000, 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 to be fit for purpose. We will maintain our efficiency, low-cost operation mindset, and continue to balance the weighting of field versus corporate personnel to reflect where we create value.

Outsourcing necessary but perfunctory and less core functions such as operations accounting, land administration, IT, tax, and HR have allowed us to operate with total personnel of just over 100 people, while retaining key technical skill sets and both the experience and institutional knowledge of our business. In summary, at the end of the fourth quarter, the company had approximately $112,000,000 in cash and cash equivalents, which represents over $3 per share of our common stock outstanding, an 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 $1,600,000,000 of federal NOLs. This concludes our prepared remarks. Thank you for your time today.

We will now open the call to questions.

Operator: We will now begin the question and answer session. If you would like to ask a question, please press 1 on your telephone keypad. To withdraw your question, press 1 again. Please pick up your handset when asking a question. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from Christopher Dowd of Third Avenue Management. Your line is open. Please go ahead.

Christopher Dowd: Hi, guys. Thanks for taking the Q&A. Your 2026 production guidance of 6,400,000 to 7,700,000 BOE and CapEx of $76,000,000 to $97,000,000 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 ends of that guidance? And then I have a follow-up.

Grayson R. Pranin: Sure. Yes. Good afternoon. Thank you for the interest and the question. Things that we are watching for that range is timing is a big part of it. So right now, we are planning on drilling 10 wells and completing eight. If the timing shifts, 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 are developing this year, their pooling has been finalized in Oklahoma. You pool the wells, 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 are budgeting at appropriate achievable levels, and so we are 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. Thank you. And then just as my follow-up question, can you comment on how you are 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 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? Thank you.

Grayson R. Pranin: Sure. No. It is a great question, one that we are watching literally by the minute here, even as we are on the call now. I am 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 any debt, so we do not have any bank-mandated hedging requirements, meaning we are not required to hedge in the downside and could be more opportunistic in nature. As prices have increased this year, we have done that and taken in additional options.

You can probably see a lot of speculation in the marketplace of where oil prices could go to. So we are mindful to layer in additional contracts. We want to do so that we also have some opportunities of potential upside. And with that, I will hand things over to Jonathan.

Jonathan Frates: Yes, I think you said it well. We are very opportunistic with this program. I will point out that the 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 have about 27% of guided production hedged on the oil side, but due to the fact that we have put oil on very recently and we are only two 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, yes, we are very opportunistic.

As these prices continue to rise up, we are watching it every day, and we will layer on more as the year goes on, assuming things continue in this direction.

Operator: If you would like to ask a question, press 1 on your telephone keypad. To withdraw your question, press 1 again. Please pick up your handset when asking a question. If you are muted locally, please remember to unmute your device. Your next question comes from the line of Sergey Pigarev of Freedom Broker. Your line is open. Please go ahead.

Sergey Pigarev: Hi, everyone, and thank you for taking my question. I think everyone had this question on 2026 guidance with the production and CapEx, and so, actually, I want to ask about the guidance too. I see that you have this higher range of price differentials guidance for NGLs, and, actually, in Q4, we were a bit surprised because of higher differentials than we expected for Q4. So do you see some temporary things here, or is it something structural and we will see high differentials from here?

Grayson R. Pranin: Sure, Sergey. I appreciate your question. Obviously, there are different differentials depending on the commodity. I think if you look at oil, that has been relatively tight. I think you may be referencing gas, and we have talked about this directionally. As we benefit from higher commodity prices and we compare it to the Henry Hub benchmark, the fixed deduct within our gas stream are reduced, so you have an expanded realization. So if you look into an environment where we have $4 gas, you will see us towards the higher end of our guidance range.

If you are looking at $2 gas, it is going to be near that lower range, and that is why we provided that range of 50% to 70%—to try to accommodate different gas environments. I think if you look at the whole year, we are really close to that center of 60%, and we are averaging that. I think that averaged just over $3 from a benchmark perspective. Relative to Q4 in particular, you had a widening of the regional basis. A lot of our gas is sold through Continental, Eastern, and NGLTL market. I think that is localized and temporal.

I think, as we look at things structurally, we want to make sure that we are selling as much gas as we can at higher commodity prices because that is when we see the highest realization.

Sergey Pigarev: Thanks. Hello? That is very helpful.

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

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