SandRidge Energy, Inc. (NYSE:SD) Q1 2025 Earnings Call Transcript

SandRidge Energy, Inc. (NYSE:SD) Q1 2025 Earnings Call Transcript May 10, 2025

Operator: Good afternoon and welcome to SandRidge Energy’s First Quarter 2025 Earnings Conference Call. [Operator Instructions]. I would now like to turn the call over to Scott Prestridge, SVP 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 risk and uncertainty 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 and 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 positive quarter for the company. In the first quarter, total production averaged nearly 18 MBoe per day, an increase of approximately 17% on a BOE basis and 30% on an oil basis, as well as roughly 40% increase in revenue and EBITDA relative to the same period last year, benefited from a prior Cherokee acquisition and improved commodity price realizations. Before expanding on this, Jonathan will touch on a few key highlights.

Jonathan Frates: Thank you, Grayson. Compared to the first quarter of 2024, the company benefited from significantly improved natural gas prices, partially offset by headwinds in WTI. Combined with growing production, the company generated revenues of approximately $43 million, which represents a 41% increase compared to the same period last year and a 9% increase sequentially. Adjusted EBITDA was $25.5 million in the quarter compared to roughly $15 million in the prior year period. We continued to manage the business within cash flow, have no debt, and maintain a substantial NOL position that fuels us in federal income taxes. Cash, including restricted cash at the end of the quarter, was just over $100 million, which represents more than $2.75 per share of our common stock outstanding.

The company paid $4 million in dividends during the quarter, which, including special dividends, now represents $4.25 per share paid to shareholders since the beginning of 2023. On May 5, 2025, the Board of Directors declared an $0.11 per share cash dividend payable on June 2nd to shareholders of record on May 19th. Following the recent decline in oil prices, the company repurchased $452,000 or $5 million worth of common shares in the first quarter. Our share repurchase program remains in place with just under $70 million remaining authorized as a quarter end. As noted, the company has no term debt or revolving debt obligations and continues to live within cash flow, funding all capital expenditures and capital returns with cash flows from operations.

Q&A Session

Commodity price realization for the quarter, before considering the impact of hedges, were $69.88 per barrel of oil, $2.69 per MCF of gas, and $20.07 per barrel of NGL. This compares to fourth quarter 2024 realizations of $71.44 per barrel of oil, $1.47 per MCF of gas, and $18.19 per barrel of NGL. Our production remains meaningfully hedged through the remainder of the year with a combination of swaps and collars representing nearly 30% of guided production. This includes over 40% of natural gas production and roughly 15% of oil. These hedges will help secure a portion of our cash flows and support our drilling program during the recent downtrack and crisis. Despite growing production, our commitment to cost discipline continues to yield results with adjusted G&A for the quarter of approximately $2.9 million, or $1.83 per BOE, compared to $2.8 million, or $2.03 per BOE in the first quarter last year.

Net income was $13 million during the quarter, or $0.35 per basic share, and adjusted net income was $14.5 million, or $0.39 per basic share. This compares to $11 million, or $0.30 per basic share, and $8.4 million, or $0.23 per basic share, respectively, during the same period last year. Adjusted operating cash flow was roughly $26 million during the quarter. Finally, despite a higher CapEx program, the company generated free cash flow before acquisitions of roughly $14 million during the quarter, near that of the first quarter of 2024. Before shifting to our outlook, we should note that our earnings release in Q2 will provide further details on our financial and operational performance during the quarter.

Grayson Pranin: Thank you, Jonathan. I thought it would be useful to give a brief update on operations before touching on other company highlights. In the first quarter, the company successfully drilled the first well of our operated 1 rig Cherokee drilling program, with first production anticipated later this month. Dean will touch more on this later. While we are anticipating our first result later this month, four non-ops and industry wells directly offsetting this well and other DSUs we will be developing this year at initial average production rates of over 1,000 barrels of oil or 2,000 barrels of equivalent per day. These new wells give further confidence to reservoir quality, result consistency, and expectations in the area.

We hope to share more details on this and our operated results next quarter. As I mentioned previously, production for the quarter increased approximately 17% and 30% on a BOE and oil basis year-over-year. As we look forward to developing our high-return Cherokee assets this year, we anticipate growing oilier production volumes further. From a timing perspective, most of the production from our development program will occur in the second half of this year, with exit rates projected around 19 MBoe per day and increasing oil production rates estimated around another 30% relative to Q1. In addition, two completions will carry over into the next year, and should further drilling also continue, we will see production volumes, and specifically oil volumes, increase meaningfully above the year-end 25 exit rates level.

However, please keep in mind that we will continue to be mindful of results, commodity prices, costs, macroeconomics, and other factors which will shape our capital decisions this year and beyond. Shifting over to commodity prices, WTI prices have been around the low $60 range over the last several weeks and recently tested to high 50s. Although the forward-looking curve has been relatively flat, we will continue to vigilantly monitor WTI prices. Current commodity prices are operated Cherokee Wells, have a robust return, and break-evens for these new wells are down to $35 WTI. However, we could begin to moderate or curtail a portion of our capital program before we reach these levels if headwinds are more severe and present further pressure on returns.

Given that the program is weighted in the back half of the year, we have time to continue to monitor commodity prices. As we do not have significant leasehold expirations this year, we have the flexibility to defer these projects, if needed, for a period of time in order to better time the commodity environment and optimize both our cash flows and project returns. While our acreage is 95% held by production, we do have undeveloped leases to include leases in the Cherokee play that have expirations. So long and short, we have the flexibility to adjust our capital program this year to respond to commodity price challenges, and we’ll do so in a judicious manner while managing lease expirations and other considerations. Now, onto natural gas prices.

We’ve benefited during the with Henry Hub prices, which have been more robust and durable, rising to $4.30 per Mcf, a near doubling of that from 2024. While there has been some volatility in early Q2, the natural gas price outlook remains strong. The real so what here is the optionality we have across our asset base, coupled with the strength of our balance sheet that situates us well to navigate changing commodity environments. Combination of our Cherokee and legacy assets, as well as improvement in natural gas prices, give us multi-faceted options to maneuver and leverage different commodity cycles. Our Cherokee development adds value with WTI as constructive, and we can take advantage of our legacy properties through well reactivation, incremental production optimization projects, and possibly even as development at the appropriate natural gas and liquid prices, or potentially both when WTI and Henry Hub are both constructive.

Conversely, given the relatively low breakeven of our producing properties and our cash balance of just over $100 million, we’re also well positioned, not only the weather, but the right circumstances to take advantage of lower commodity environments by acquiring additional producing properties at attractive prices. Put more simply, we have a strong balance sheet and a more versatile kit bag, which makes the company more resilient and better poised to maneuver and adjust with the commodity environment. Now, I’ll turn things over to Dean to discuss operations in more detail.

Dean Parrish: Thank you, Grayson. Let’s start on our capital program. The first operated well in our program and two non-operated wells were drilled in the Cherokee Play last quarter. First production on the operated well is expected later this month. Early indications during drilling and completion are positive, and we anticipate having production results report next quarter. Our team successfully planned and executed drilling of the first operated well on budget with minimal operational issues. We are currently pad drilling wells number two and three and anticipate to complete and have production for these wells in the next quarter. We plan to drill eight operated Cherokee wells with one rig this year and complete six wells.

The remaining two completions are anticipated to carry over to next year. More than 80% of our planned wells are proved, undeveloped, or PUDs, with others projected to be converted to PUDs by year end. This means that our planned drilling locations this year will offset producing wells, which translates to higher relative confidence and well performance. Additionally, this could set up new PUD additions or extensions at the end of the year. Gross well costs vary by depth but are estimated to be between approximately $9 million and $11 million. While we have taken proactive steps to help mitigate these effects of inflation, further changes to tariffs or other factors could influence these costs in the future. From a timing standpoint, most of the production from this year’s capital program will occur in the second half of the year, with the benefit extending into next year.

We intend to spend between $66 million and $85 million in our 2025 capital program, which is made up of $47 million to $63 million in drilling and completions activity, and between $19 million and $22 million in capital workovers, production optimization, and selective leasing in the Cherokee play. Our high graded leasing is focused to further bolster our interest and consolidate our position and extend development into future years. We intend to fund capital expenditures and other commitments using cash flows from our operations and cash on hand. As Grayson discussed earlier, our operated Cherokee wells have robust returns at current commodity prices. However, we could moderate or curtail our capital program if headwinds persist or present further pressures on rates of return.

If we were to take these steps, we would likely begin by reducing non-D&C spend and if faced with more challenging commodity prices, followed by deferring certain completions, which would make up roughly 60% of new well costs. In this scenario, we would be positioned to more quickly take advantage of commodity price improvement, maintain current drilling efficiencies, manage lease expirations, and other factors. Under more extreme downside cases, we have the optionality to take further steps to defer projects, minimize spending, and optimize cash flows. Through the first quarter, 13 wells were converted to rod pumps and five wells were reactivated as we continue to focus on high return and value adding projects that provide benefits such as lowering forward-looking costs, enhancing production on existing wells, and further moderating our base decline profile.

The artificial lift systems we have and will be installing in our conversion program are tailored for the well’s current fluid production and will reduce the electrical demand from the current artificial lift system, which is key to decreasing future utility costs. The focused efforts over past quarters in optimizing our well’s production profile and costs have contributed to flattening the expected base asset level decline of our already producing assets to single-digit average over the next 10 years. Our legacy assets remain approximately 99% held by production, which cost-effectively maintains our development option over a reasonable tenor. These non-Cherokee assets have high relative gas content, but commodity price futures are not yet at preferred levels to resume further development or more well reactivations at this time.

Commodity prices firmly over $80 WCI and $4 Henry Hub over a confident tenor and/or reduction in well costs are needed before we would return to exercise the option value of further development or well reactivation. Now, shifting to lease operating expenses. Despite continued inflationary pressures and increased well count from our recent acquisition and prior capital programs, LOE and expense workovers for the quarter were held to approximately $10.9 million or $6.79 per BOE, which compares favorably to $7.92 per BOE in the first quarter last year. We will continue to actively press on operating costs through rigorous bidding processes, leveraging our significant infrastructure, operations center, and other company advantages. With that, I will turn things back over to Grayson.

Grayson Pranin: Thank you, Dean. I will now revisit the key highlights of SandRidge. Our asset base is focused in the mid-continent region with a primarily PDP well set, which does not require any routine flaring of produced gas. These well-understood assets are almost fully held by production with a long 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 electrical infrastructure over our footprint. This substantial owned and integrated infrastructure helps de-risk individual well profitability for a majority of our legacy producing wells under roughly $40 WTI and $2 Henry Hub. Our assets continue to yield free cash flow, and we have negative net leverage.

This cash generation potential provides several paths to increase shareholder value realization and is benefited by low G&A burden. SandRidge’s value proposition is materially de-risked from a financial perspective by our strength in balance sheets, financial flexibility, and advantaged tax decisions. Further, the company is not subject to NVCs or other significant off-balance sheet financial commitments. We have bolstered our inventory to provide further organic growth optionality and incremental oil diversification with low break-evens in high graded areas. We maintain financial flexibility that allows us to adjust our strategy to take advantage of commodity cycles. This flexibility provides advantages in strategic optionality to further grow our business and provide the buffer to commodity headwinds while protecting our capital return program.

Finally, it’s worth highlighting that we take our ESG commitments seriously and have implemented disciplined processes around them. We remain committed to our strategy in growing the value of our business in a safe, responsible, efficient manner while prudently allocating capital to high return organic growth projects. We’ll also evaluate merger and acquisition opportunities in a disciplined manner with consideration of our balance sheets and commitment to our capital return program. This strategy has five points. One, maximize the value of our incumbent MidCon 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. 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 $1.6 billion 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.

The final staple is to uphold our ESG responsibility. As we look forward to the year and beyond, we plan to further progress our Cherokee development while monitoring commodity prices, results, and other factors in order to realize high rates of returns as well as maintain our production levels while providing further oil diversification. With continued success in support of commodity prices, we are hopeful to expand to a multi-year development plan. Please keep in mind that our return of capital programs will continue to be our top priority, and given our financial flexibility, we will exercise capital stewardship to respond to changes in commodity prices, costs, macroeconomics, and/or other factors. Shifting to administrative expenses, I will turn things over to Brandon.

Brandon Brown: Thank you, Grayson. As we wind up our prepared remarks, I will point out our first quarter adjusted G&A of $2.9 million or $1.83 per BOE continues to compare favorably to our peers. The ongoing efficiency of our organization stems from our core values to remain cost-disciplined and prior initiatives which have tailored our organization to be fit for purpose. We will maintain our cost-conscious and efficiency-focused mindset moving forward and continue to balance the weighting of field versus corporate personnel to reflect where we create value. We have outsourced necessary but perfunctory and less core functions, such as operations accounting, land administration, IT, tax, and HR. Our efficient structure has allowed us to operate with total personnel and just over 100 people while retaining key technical skill sets to have both the experience and institutional knowledge of our business.

In summary, the company had free cash flow of approximately $14 million during the quarter, over $100 million in cash and cash equivalents at quarter end, which represents more than $2.75 per share of our common stock outstanding, an inventory of high rate of return, low break-even projects, and overall mid-composition that is approximately 95% held by production, which preserves the option value of future development potential of our legacy acreage in a cost-effective manner. Low overhead, top-tier adjusted D&A, no debt, negative leverage, 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: Q – Unidentified Analyst A – Unidentified Company Representative

Operator: We have no questions in queue. This will conclude today’s conference call. Thank you for your participation. You may now disconnect.