SD 10-K & 10-Q changes, risk factors and insider trading
Sandridge Energy Inc. · NYSE · Crude Petroleum & Natural Gas · CIK 1349436 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Failure to successfully identify, complete and integrate acquisitions of properties or business combinations, or the lack of development activity, could slow or even eliminate our growth due to the natural decline of our producing properties and adversely affect our results of operations.”
New heading “The declaration of dividends and any repurchases of our common stock are each within the discretion of the Board based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.”
New heading “The inability of our significant customers to meet their obligations to us may adversely affect our financial results.”
Largest changes
“◦Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control ◦Drilling for and producing oil and natural gas are high risk activities with many uncertainties ◦Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production ◦A financial downturn could negatively affect our business, results of operations, financial condition, cash flows and access to capital ◦Future drilling activities face substantial uncertainties ◦Certain of our undeveloped acreage is subject to leases that will expire …”see in full comparison
“We may not be able to complete acquisitions or do so on commercially acceptable terms, as our ability to complete acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. To the extent we incur indebtedness in connection with any acquisition, our leverage and debt service obligations may increase, which could adversely affect our liquidity, financial flexibility and balance sheet. Further, our future acquisitions may be in geographic regions in which we do not currently hold properties. …”see in full comparison
“•Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, the FTC or other regulators, we could be subject to substantial penalties and fines”see in full comparison
“The declaration of dividends and any repurchases of our common stock are each within the discretion of the Board based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.”see in full comparison
“Failure to successfully identify, complete and integrate acquisitions of properties or business combinations, or the lack of development activity, could slow or even eliminate our growth due to the natural decline of our producing properties and adversely affect our results of operations.”see in full comparison
“The inability of our significant customers to meet their obligations to us may adversely affect our financial results.”see in full comparison
Full comparison: every changed paragraph (68)
•Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control
•Drilling for and producing oil and natural gas are high risk activities with many uncertainties
•Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production
•A financial downturn could negatively affect our business, results of operations, financial condition, cash flows and access to capital
•Our producing properties are depleting assets, and the development or acquisition of additional reserves would be necessary to maintain or increase our production levels as the natural decline of our producing assets would result in a decrease in production levels. Failure to successfully identify, complete and integrate acquisitions of properties or business combinations, or the lack of development activity, could slow or even eliminate our growth or offset the natural decline of our producing properties and adversely affect our results of operations.
•Future drilling activities face substantial uncertainties
•Certain of our undeveloped acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or we renew the leases
•We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and our ability to offset the natural decline in our oil, natural gas and NGL reserves
•Future commodity price declines may result in reductions of the asset carrying values of our oil and natural gas properties
•Significant inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves
•The loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations
•We are subject to litigation and adverse outcomes in such litigation could have a material effect on our financial condition
•The present value of future net cash flows from our proved reserves are not the same as the current market value of our estimated oil, natural gas and NGL reserves
•We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible
•Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather
•Our business could be affected by macroeconomic risks
•Capital market volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets
•Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them
•All of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas
•The inability of our significant customers to meet their obligations to us may adversely affect our financial results
•Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured
•Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans
•Intense competition in the oil and natural gas industry may adversely affect our ability to succeed
•Seismic data may not accurately identify the presence of oil and natural gas, and the use of such technology requires greater predrilling expenditures
•Inflation may increase costs which can adversely impact cash flows and reserves value
•As we outsource functions, we are more dependent on the entities performing those functions. Disruptions or delays at our third-party service providers could adversely impact our operations
•Complex laws and regulations could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities
•Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, the FTC or other regulators, we could be subject to substantial penalties and fines
•Our operations are subject to environmental and occupational safety and health laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations
•Legislative or regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production
•Legislative or regulatory initiatives relating to seismic activity could limit our ability to produce oil and natural gas economically
•Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce
•Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results
•Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business
•Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations
•Conservation measures and technological advances could reduce demand for oil and natural gas
◦Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control ◦Drilling for and producing oil and natural gas are high risk activities with many uncertainties ◦Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production ◦A financial downturn could negatively affect our business, results of operations, financial condition, cash flows and access to capital ◦Future drilling activities face substantial uncertainties ◦Certain of our undeveloped acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or we renew the leases ◦We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and our ability to offset the natural decline in our oil, natural gas and NGL reserves ◦Future commodity price declines may result in reductions of the asset carrying values of our oil and natural gas properties ◦Significant inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves ◦The loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations ◦We are subject to litigation and adverse outcomes in such litigation could have a material effect on our financial condition ◦The present value of future net cash flows from our proved reserves are not the same as the current market value of our estimated oil, natural gas and NGL reserves ◦We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible ◦Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather ◦Our business could be affected by macroeconomic risks ◦Capital market volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets ◦Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them ◦All of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas ◦Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured ◦Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans ◦Intense competition in the oil and natural gas industry may adversely affect our ability to succeed ◦Seismic data may not accurately identify the presence of oil and natural gas, and the use of such technology requires greater predrilling expenditures ◦Inflation may increase costs which can adversely impact cash flows and reserves value ◦As we outsource functions, we are more dependent on the entities performing those functions. Disruptions or delays at our third-party service providers could adversely impact our operations ◦Complex laws and regulations could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities ◦Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, the FTC or other regulators, we could be subject to substantial penalties and fines ◦Our operations are subject to environmental and occupational safety and health laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations ◦Legislative or regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production ◦Legislative or regulatory initiatives relating to seismic activity could limit our ability to produce oil and natural gas economically ◦Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce ◦Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results ◦Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business ◦Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations ◦Repercussions from terrorist activities or armed conflict could harm our business ◦Conservation measures and technological advances could reduce demand for oil and natural gas ◦Events outside of our control, including an epidemic or outbreak of an infectious disease, may materially adversely affect our business
◦•Our ability to use our NOLs may be limited, and our Tax Benefits Preservation Plan may not prevent an ownership change resulting in loss of the Company’s NOLs
•We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover
◦We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover ◦•Anti-takeover provisions in our charter documents may make it more difficult to acquire us, even though such acquisitions may be beneficial to our stockholders For a more complete discussion of the material risk factors relevant to us, see below.
•There is no guarantee of future dividends or stock repurchases. The declaration of dividends and repurchases of our common stock are at the discretion of our Board of Directors, based on relevant considerations, with no assurance of future payments or repurchases at levels anticipated by stockholders.
For a more complete discussion of the material risk factors relevant to us, see below.
◦•the timing of planned United States' liquefied natural gas projects, data storage, electrification and other factors will impact demand for natural gas;
•U.S. and worldwide political and economic conditions, including armed conflict and related sanctions including, but not limited to, the conflicts in the Middle East, Ukraine and Iran, and political instability in Venezuela;
These factors and the volatility of the energy markets, which we expect will continue, make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For oil, from January 20201, 2021 through December 2024,31, 2025, the NYMEX West Texas Intermediate ("WTI") settled price fluctuated between a high of $123.64 per Bbl and a low of $(36.98)$47.47 per Bbl. For natural gas, from January 20201, 2021 through December 2024,31, 2025, the NYMEX Henry Hub spot prices fluctuated between a high of $24.77 per Mcf and a low of $1.26 per Mcf. In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season. For NGLs, prices exhibited similar volatility from January 20201, 2021 through December 2024.31, 2025.
Failure to successfully identify, complete and integrate acquisitions of properties or business combinations, or the lack of development activity, could slow or even eliminate our growth due to the natural decline of our producing properties and adversely affect our results of operations.
Our future success depends on the development or acquisition of additional oil, natural gas and NGL reserves that are economically recoverable, as our proved reserves will generally decline as reserves are depleted. To increase reserves and production, we would need to undertake replacement activities to undertake development, exploration and other replacement activities, requiring substantial capital expenditures. Such activities may not result in significant additional reserves and efforts to drill productive wells at low finding costs may be unsuccessful.
The successful acquisition of businesses and producing properties requires an assessment of several factors, including; recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review may not reveal all existing or potential problems including title defects or environmental issues, which, if material, could render an interest worthless, nor may it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Significant acquisitions and other strategic transactions may involve other risks that may cause our business to be adversely impacted, including diversion of our management’s attention to evaluating and negotiating such transactions and our failure to realize the full benefit that we expect in estimated proved reserves, production volume or other benefits anticipated therefrom, or to realize these benefits within the expected time frame.
We may not be able to complete acquisitions or do so on commercially acceptable terms, as our ability to complete acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. To the extent we incur indebtedness in connection with any acquisition, our leverage and debt service obligations may increase, which could adversely affect our liquidity, financial flexibility and balance sheet. Further, our future acquisitions may be in geographic regions in which we do not currently hold properties. If we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements and other unforeseen difficulties. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business or properties into our existing operations, the process of which may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. We may also need to hire additional personnel in connection with any such acquisition, which may not be readily available following an acquisition. Any of the unfavorable circumstances mentioned above could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth and results of operations.
The declaration of dividends and any repurchases of our common stock are each within the discretion of the Board based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
Dividends, whether fixed or variable, and stock repurchases are authorized and determined by the Board in its sole discretion and depend upon a number of factors, including our financial results, cash requirements and future prospects, potential restrictions in future debt agreements, as well as such other factors deemed relevant by the Board. In May 2023, the Board approved a share repurchase program of $75.0 million of our outstanding common stock, of which $68.3 million was available as of December 31, 2025. However, this share repurchase program may be suspended from time to time, modified, extended or discontinued by the Board at any time. Similarly, any dividends, whether fixed or variable, we may declare in the future will be determined by the Board in its sole discretion. Any elimination of, or downward revision in, our share repurchase program or dividend policy could have an adverse effect on the market price of our common stock.
Future commodity price declines may result in reductions of the asset carrying values of our oil and natural gas properties.
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this accounting method, all costs for both productive and nonproductive properties are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, the amount of these costs that can be carried as capitalized assets is subject to a ceiling, which limits such pooled costs to the aggregate of the present value of future net revenues of proved oil, natural gas and NGL reserves attributable to proved properties, discounted at 10%, plus the cost of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the SEC prices, adjusted for the impact of derivatives accounted for as cash flow hedges, if any. The Company did not recognize any full cost ceiling impairment charges for the years ended December 31, 20242025 or 2023.2024. Cumulative full cost ceiling impairment from the Emergence Date through December 31, 20242025 totaled $947.1 million. If oil, natural gas and NGL prices decline in the near term, and without other mitigating circumstances, we may experience additional losses of future net revenues, including losses attributable to quantities that cannot be economically produced at lower prices, which could cause us to record additional write-downs of capitalized costs of oil and natural gas properties and non-cash charges against future earnings. The amount of such future write-downs and non-cash charges could be substantial. In addition, reductions in commodity prices may cause certain wells to become uneconomic to operate, resulting in the curtailment of uneconomic wells, which could reduce our cashflows and potential reserves.
We base the estimated discounted future net cash flows from our proved reserves on 12-month average index prices and costs, as is required by SEC rules and regulations. Actual future net cash flows from our oil and natural gas properties will be affected by actual prices we receive for oil, natural gas and NGLs,NGLs to include derivative instruments, as well as other factors such as:
The timing of both our production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, we use athe 10% discount factor we use when calculating discounted future net cash flows,flow whichrequirements in compliance with ASC 932, “Extractive Activities — Oil and Gas,” may not be the most appropriate discount factor based on prevailing interest ratesrate, in effect from time to time andmarket, risks associated with the Company or theother oil and natural gas industry in general.factors.
With the divestment of our North Park Basin assets in February 2021, allAll of our production and reserves are located in the Mid-Continent region. This concentration could disproportionately expose us to operational and regulatory risk in this area. This relative lack of diversification in location of our key operations could expose us to adverse developments in the Mid-Continent or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production due to weather, electrical outages, treatment plant closures for scheduled maintenance, changes in the regulatory environment or other factors. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more diversified.
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
We are subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. During the year ended December 31, 2025, our three largest customers accounted for approximately 68% of our revenue, with our largest two customers representing 32.6% and 21.5% of our revenue. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. Furthermore, we cannot predict the extent to which our customers' businesses would be impacted if oil and natural gas prices decline, such prices remain depressed for a sustained period of time or other conditions in our industry were to deteriorate. If we were to lose one or more of our significant customers and were unable to sell our production to other customers on terms we consider acceptable, our business, financial condition, results of operations and cash flows could be adversely impacted. "Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements included in Item 8 of this Form 10-K for further discussion of significant customers and concentration of risk.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and natural gas production. We routinely have utilized hydraulic fracturing techniques in the majority of our drilling and completion programs. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAAthe finalQuad Oa regulations in 2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry under CAA, as described above; and in June 2016 issued final effluent limitations guidelines under the CWA that waste-waterwastewater from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant. The EPA also issued an Advance Notice of Proposed Rulemaking under TSCA in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing, but, to date, has taken no further action. Separately, the BLM published a final rule in March 2015 that establishes more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, the U.S. District Court of Wyoming struck down this rule in June 2016, and after various appeals and a presidential executive order directing it to review rules related to the energy industry, the BLM published a final rule rescinding the 2015 rule in December 2017.
The EPA previously published its findingsEndangerment Findings that emissions of GHGs present a danger to public health and the environment because such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes.changes, which the EPA has proposed rescinding. Based on theseits findings,Endangerment Findings, the EPA has adopted various rules to address GHG emissions under existing provisions of the CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis, which includes certain of our operations. In addition, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of an LDAR program to minimize methane emissions, under the CAA’s New Source Performance Standards Quad Oa. However, the EPA has taken several steps to delay implementation of the Quad Oa standards. The agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and in October 2018, the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain Quad Oa requirements is technically infeasible. In September 2020, the EPA finalized amendments to Quad Oa that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things. On June 30, 2021, Congress issued a joint resolution pursuant to the Congressional Review Act disapproving the September 2020 rule, and on November 15, 2021, EPA issued a proposed rule to revise the Quad Oa regulations. On November 8, 2022, EPA issued a supplemental notice of proposed rulemaking that would impose standards for certain sources that were not addressed in the November 2021 proposal, revise the previously proposed emissions standards, and establish a “super emitter response program” allowing local regulatory agencies and EPA-certified third parties to issue notices to owners and operators of regulated facilities when they detect a so-called “super-emitting event.” Additionally, as discussed above in the description of our business, various regulatory bodies have announced or are considering new rules and regulations impacting our operations and our business, including the EPA’s final rule under the CAA to reduce methane emissions from the oil and natural gas industry,industry under Subparts OOOOb/c, EPA and BLM methane emissions limitations, cap and trade programs launched by states and regions in which we operate, and, to the extent applicable, the Paris Agreement. See “Business—Environmental, Health, and Safety Regulations” in Item 1 of this report for information about climate change laws and regulations restricting emissions of GHGs that could impact our operations and business.
Management's Discussion & Analysis (MD&A)
Removed heading “Capital Expenditures.”
Largest changes
“Lease operating expenses decreased in total and per Boe versus the same period in 2024 primarily due to $4.3 million of out of period corrections which are non-recurring, non-cash, adjustments of operating accruals dating as far back as the Company’s emergence from bankruptcy (see “Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements included in Item 8 of this Form 10-K for further information), of which $2.1 million and $2.2 million were recorded in the second and fourth quarter of 2025, respectively. …”see in full comparison
However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves. Any such ceiling test impairments in the future could be material to our net earnings. Full cost pool impairments have no impact to our cash flow or liquidity.see in full comparison
“Full cost pool impairments have no impact to our cash flow or liquidity.”see in full comparison
We remain committed to growing the value of our asset base in a safe, responsible and efficient manner, while prudently allocating capital to high-return,see in full comparisonorganicgrowth projects. Currently, these projects include: (1)One rigone-rig development in the Cherokee ShalePlay, which consists of 9 wells to be spud, 8 wells to be drilled and 6 wells to be completed in 2025Play (2)ProductionevaluationOptimizationof accretive merger and acquisition opportunities, with consideration of our strong balance sheet and commitment to our capital return program (3) production optimization program through artificial lift conversions to more efficient and cost-effective systems andhigh-graded(4)recompletions (3)a leasing program that will bolster future development and extend development in our Cherokee assets.OurWe are developing our term acreage in the Cherokee Play, and our total leasehold position, inclusive of the Cherokee, NW Stack and legacynon-Cherokeeassets,leasehold remainsis approximately99%95% held by production, which cost-effectively maintains our development option over a reasonable tenor. We will continue to monitor forward-looking commodity prices, project results,costscosts, impacts of tariffs and other factors that could influence returns and cash flows, and will adjust our program accordingly, to include curtailment of capitalallocationsactivityaccordingly.and wells, if needed, or conversely, well reactivations in higher commodity price environments. These and other factors,to includeincluding reasonable reinvestment rates,sustainingmaintaining our cash flows and prioritizing our regular-way dividend, will continue to shape our development decisions for the remainder of the year and beyond.We also remain vigilant in evaluating further merger and acquisition opportunities, with consideration of our strong balance sheet and commitment to our capital return program.
“Depreciation and Depletion of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. See above discussion on the uncertainty of proved reserves estimates. …”see in full comparison
Full comparison: every changed paragraph (54)
During the year ended December 31, 2025, the Company operated one drilling rig and drilled seven operated wells, and completed six wells. As of December 31, 2025, one operated well was being drilled and another operated well was awaiting completion. Additionally, four non-operated wells were drilled and completed during 2025. For the year ended December 31, 2024 there were no operated wells drilled, while three operated and one non-operated wells were completed.
For the year ended December 31, 2024, there were no operated wells drilled, with three operated and one non-operated wells completed. For the year ended December 31, 2023 there were two operated wells drilled and four wells completed.
The Company's production last year benefited from our previous drilling program that concluded in 2023. Production in 2024 decreased slightly due to the natural decline of our producing assets, but benefited by our newly acquired wells beginning in September 2024, as well as periods of ethane recovery.
Total production by volume on a Boe basis for the years ended December 31, 2024 and 2023 was composed of the following:
•On August 5, 2025, the Board approved a dividend reinvestment plan (the “Dividend Reinvestment Plan”), pursuant to which the shareholders of the Company may, at their election, reinvest any dividends declared by the Board. During 2025, we issued 92,733 shares of common stock in lieu of cash dividends under the Dividend Reinvestment Plan.
•On July 18, 2025, the Board increased its size from five members to six members and appointed Mr. Brett Icahn to serve as a member of the Board, effective as of August 1, 2025. Mr. Icahn's current term as a member of the Board will run until the 2026 annual meeting of stockholders.
•Under our ongoing one-rig Cherokee development program we drilled seven operated wells, completed six operated wells during the year and turned six wells to sales during 2025.
•We paid cash dividends to stockholders totaling $15.9 million or $0.46 per share in 2025, excluding stockholders who elected to take shares in lieu of cash under the Dividend Reinvestment Plan.
•For the year ended December 31, 2025, we repurchased 595,635 shares of common stock for $6.4 million with a weighted average price of $10.72, under our share repurchase program.
•On August 30, 2024, the Company closed on its previously announced acquisition of certain producing oil and natural gas properties in the Cherokee Play of the Western Anadarko Basin for $121.9 million, after customary post-closing adjustments. On December 13, 2024, the Company closed a subsequent acquisition that exchanged and increased its ownership interest in certain proved and unproved oil and gas properties within the same area for $5.2 million, before customary post-closing adjustments of $0.5 million, paid in January 2025, and terminated the previously announced joint development agreement. The Company will operate the majority of its planned development in 2025.
•On September 30, 2024, and effective October 1, 2024, the Company announced the following changes (i) Jonathan Frates was appointed to serve as the Company's Executive Vice President and Chief Financial Officer and resigned as Chairman of the Board, (ii) the Board appointed Mr. Vincent Intrieri to serve as a Board member and as the Company’s Chairman of the Board to fill the vacancy following Jonathan Frates’ resignation from the Board; Mr. Intrieri also joined the Board’s Compensation and Nominating and Governance Committees, and (iii) Mr. Brandon Brown to serve as the Company’s Senior Vice President and Chief Accounting Officer, effective October 21, 2024. Mr. Brown no longer serves as Chief Financial Officer upon the commencement of Mr. Frates’ role as Chief Financial Officer on October 21, 2024.
•On April 3, 2024, the Company announced that the Board had appointed Mr. Dean Parrish, Senior Vice President, Operations, to serve as the Company’s Senior Vice President and Chief Operating Officer, effective April 1, 2024.
We remain committed to growing the value of our asset base in a safe, responsible and efficient manner, while prudently allocating capital to high-return, organic growth projects. Currently, these projects include: (1) One rigone-rig development in the Cherokee Shale Play, which consists of 9 wells to be spud, 8 wells to be drilled and 6 wells to be completed in 2025Play (2) Productionevaluation Optimizationof accretive merger and acquisition opportunities, with consideration of our strong balance sheet and commitment to our capital return program (3) production optimization program through artificial lift conversions to more efficient and cost-effective systems and high-graded(4) recompletions (3)a leasing program that will bolster future development and extend development in our Cherokee assets. OurWe are developing our term acreage in the Cherokee Play, and our total leasehold position, inclusive of the Cherokee, NW Stack and legacy non-Cherokeeassets, leasehold remainsis approximately 99%95% held by production, which cost-effectively maintains our development option over a reasonable tenor. We will continue to monitor forward-looking commodity prices, project results, costscosts, impacts of tariffs and other factors that could influence returns and cash flows, and will adjust our program accordingly, to include curtailment of capital allocationsactivity accordingly.and wells, if needed, or conversely, well reactivations in higher commodity price environments. These and other factors, to includeincluding reasonable reinvestment rates, sustainingmaintaining our cash flows and prioritizing our regular-way dividend, will continue to shape our development decisions for the remainder of the year and beyond. We also remain vigilant in evaluating further merger and acquisition opportunities, with consideration of our strong balance sheet and commitment to our capital return program.
The table below presents production and pricing information for the years ended December 31, 2024 and 2023.information.
Consolidated revenues for the years ended December 31, 2024 and 2023 are presented in the table below (in thousands).:
Oil, natural gas and NGL revenues increased during 2025 primarily due to new production volumes from our Cherokee play development program and higher natural gas price realizations partially offset by lower oil and NGL price realizations.
Oil, natural gas and NGL revenues decreased primarily due to lower commodity prices. The Company's production benefited from its prior drilling program, concluded in 2023, as well as production from our newly acquired wells beginning in September 2024, offset by the natural decline of our producing assets.
Operating expenses for the years ended December 31, 2024 and 2023 consisted of the following (in thousands):
Lease operating expenses decreased in total and per Boe versus the same period in 2024 primarily due to $4.3 million of out of period corrections which are non-recurring, non-cash, adjustments of operating accruals dating as far back as the Company’s emergence from bankruptcy (see “Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements included in Item 8 of this Form 10-K for further information), of which $2.1 million and $2.2 million were recorded in the second and fourth quarter of 2025, respectively. The removal of the operating accruals was partially offset by an increase in water hauling costs associated with increased activity from our 2025 development program.
Production, ad valorem, and other taxes increased due to higher average commodity prices, sales volumes, and related revenues. The increase in sales volumes was primarily the result of our one rig development program in the Cherokee Play of the Mid-Con. Production, ad valorem, and other taxes per Boe increased primarily due to higher average commodity prices.
The decrease in lease operating expenses was primarily due to a decrease in workover expense.
Production, ad valorem, and other taxes decreased primarily due to a $1.4 million ad valorem tax refund received in the fourth quarter of 2024 combined with a decrease in production taxes due to lower commodity prices and related revenues.
The increase in depreciation and depletion for oil and natural gas properties was primarily the result of ouran acquisitionincrease in the Cherokee Play of the Western Anadarko Basin in the third quarter of 2024, which increased the book value of our proved properties and subsequently our depletion rate.rate and higher production volumes.
Full cost pool impairment. We did not record a full cost ceiling limitation impairment for the years ended December 31, 20242025 orand 2023.2024.
However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves. Any such ceiling test impairments in the future could be material to our net earnings. Full cost pool impairments have no impact to our cash flow or liquidity.
Full cost pool impairments have no impact to our cash flow or liquidity.
Other operating expenses for the years ended December 31, 2024 and 2023 consisted of the following (in thousands):
General and administrative expenses increased for the year ended December 31, 20242025 primarily due to higher personnel costs and otherprofessional costs.fees.
Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filingfiling, the outsourcing of corporate functions and our exit from NPBNorth Park Basin in Colorado.
Other operating expense (income) increaseddecreased for the year ended December 31, 20242025 primarily due to a $1.3 millionan impairment in 2024 on our equipmentnon-full cost pool inventory.
The following table summarizes derivative activity for the years ended December 31, 2024 and 2023 (in thousands):
Interest income (incomeexpense) expense,, net for the years ended December 31, 2024 and 2023 consisted of the following (in thousands):
Interest income (incomeexpense) expense,, net during the years ended December 31, 20242025 and 20232024 is primarily comprised of interest income received from cash deposits. The decrease in interest income, net is due to the Company’s lower cash balance primarily as a result of our acquisitions,capital expenditures, dividend payments, acquisitions and toshare arepurchases lesseras extent,well capitalas expenditureslower andinterest dividend payments.rates.
We recorded income tax benefit and expense of $22.2$5.5 million and $14.0$22.2 million for the years ended December 31, 20242025 and 2023,2024, respectively, which directly relates to movement in our valuation allowance against our deferred tax assets. As the partial valuation allowance release as of December 31, 20242025 was higher than the partial valuation allowance release as of December 31, 20232024 of $50.6$72.8 million, we recognized $22.2$5.5 million of deferred federal and state income tax benefit for the year ended December 31, 2024.2025.
At December 31, 2024,2025, our cash and cash equivalents, including restricted cash, was $99.5$112.3 million. We expect our cash on hand and cash from operations to be adequate to meet our short and long-term liquidity needs. As of MarchFebruary 4,26, 2025,2026, the Company had no outstanding term or revolving debt obligations.
Our working capital increased to $79.8 million at December 31, 2025, compared to $67.1 million at December 31, 2024. The increase in working capital was primarily driven by cash flows provided by operating activities of $100.1 million and partially offset by $58.6 million in capital expenditures, dividend payments to stockholders of $15.9 million, $8.5 million in acquisitions and $6.4 million in share repurchases.
Dividend payments, excluding shares issued in lieu of cash dividends, for the year ended December 31, 2025 totaled $15.9 million, which included $0.2 million of dividends on vested stock awards. See Note 13 for further discussion of the Company’s dividends.
Our working capital decreased to $67.1 million at December 31, 2024, compared to $228.5 million at December 31, 2023. Cash paid for oil and gas property acquisitions of $129.7 million, dividend payments to shareholders of $72.3 million, and $26.4 million in capital expenditures were the primary drivers in the reduction of working capital. These cash outflows were offset by $73.9 million in cash provided by operating activities.
In January 2024, the Board approved a one-time cash dividend of $1.50 per share of the Company's common stock, which was paid on February 20, 2024 to shareholders of record as of the close of business on February 5, 2024. The aggregate total payout was approximately $55.6 million. Additionally, in March 2024, the Board increased the on-going quarterly dividend to $0.11 per share which was paid in March, May, August, and November 2024. The aggregate total payout was $16.3 million. The $0.11 per share dividend is subject to quarterly approval by the Board. Dividend payments for the year ended December 31, 2024 totaled $72.3 million, which included $0.5 million of dividends on vested stock awards. See Note 13 for further discussion of the Company’s dividends.
Our cash flows from operations are substantially dependent on current and future prices for oil, natural gas and NGL, which historically have been, and may continue to be, volatile. For example, during the period from January 20201, 2021 through December 2024,31, 2025, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98)$47.47 per Bbl, and the NYMEX Henry Hub spot prices for gas fluctuated between a high of $24.77 per Mcf and a low of $1.26 per Mcf.
Cash flows for the years ended December 31, 2024, and 2023 are presented in the following table and discussed below (in thousands):
The increase in cash flows from operations for the year ended December 31, 2025 compared to the same period in 2024 is primarily due to an increase in revenues from higher sales volumes from our 2025 development program in the Cherokee Play of the Mid-Continent region with our base production also benefiting from our 2024 acquisition and higher natural gas price realizations.
The $41.6 million decrease in operating cash flows for the year ended December 31, 2024 compared to 2023, is primarily due to a decrease in revenues from lower commodity prices. The changes in operating assets and liabilities do not include changes in accounts payable or accrued expenses attributable to capital expenditures noted in the capital expenditure table below.
During the year ended December 31, 2024, cash flows used in investing activities primarily reflects $129.7 million in cash paid for oil and gas property acquisitions and capital expenditures of $26.4 million. Cash outflows were partially offset by $1.4 million of proceeds from the sale of equipment related to our oil and gas assets.
During the year ended December 31, 2023, cash flows used in investing activities primarily reflects capital expenditures of $26.4 million made for drilling and completions, capital workovers, and well reactivations and $11.2 million related to an acquisition of proved reserves, which increased ownership interests in properties operated by the Company. Cash outflows were partially offset by $1.5 million of proceeds from the sale of equipment related to our oil and gas assets.
See "Note 3— Acquisitions of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for additional information.
Capital Expenditures.
Our capital expenditures forand theacquisitions yearsof ended December 31, 2024oil and 2023,gas properties are summarized below (in thousands):
Our financing activities used $73.7$23.3 million of cash for the year ended December 31, 2024,2025, consisting primarily of $72.3$15.9 million in cash dividends, $6.4 million in common stock repurchases, finance lease payments of $0.7 million, $0.4$0.3 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and $0.2 million in common stock repurchases.exercise. Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award, that equals the employee payroll tax obligation due. We then remit a cash payment to the relevant taxing authority on behalf of the employee for their payroll tax obligations resulting from the vesting of their stock award.
Our financing activities used $82.9$73.7 million of cash for the year ended December 31, 2023,2024, consisting primarily of $81.5$72.3 million in cash dividends, $0.9finance lease payments of $0.7 million, $0.4 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.6$0.2 million offsetin by $0.1 million of proceeds from the exercise ofcommon stock options.repurchases. See discussion in above paragraph for additional information on net exercises of stock awards.
In May 2023, the Board approved a share repurchase program (the “Program”) authorizing the Company to repurchase up to an aggregate of $75.0 million of the Company’s outstanding common stock with the Company’s cash on hand. The Program replaced the prior share repurchase program previously approved by the Board in August 2021. Purchases under the Program are intended to meet the requirements of Rule 10b5-1 of the Exchange Act. The Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. For the year ended December 31, 2025, the Company repurchased 595,635 shares for $6.4 million, or $10.72 per share. For the year ended December 31, 2024, the Company repurchased 21,308 shares for $0.2 million. The Company did not repurchase any common stock under the existing or prior Program during the year ended December 31, 2023.million
Depreciation and Depletion of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter. See above discussion on the uncertainty of proved reserves estimates. If we maintain the same level of production year over year, the depreciation and depletion of oil and natural gas properties may be significantly different if our estimate of remaining reserves or future development costs changes significantly. The average rates used for depreciation and depletion of oil and natural gas properties were $3.52 per Boe in 2024 and $1.82 per Boe in 2023.
Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes and electrical infrastructure costs, may not exceed an amount equal to the ceiling limitation. The Company calculates its full cost ceiling limitation using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. See above discussion on the uncertainty of proved reserves estimates. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Company did not record any impairment for the years ended December 31, 20242025 orand 2023.2024.
Asset Retirement Obligations. Asset retirement obligations represent the estimate of fair value of the cost to plug, abandon and remediate the Company’s wells at the end of their productive lives, in accordance with applicable federal and state laws. The Company estimates the fair value of an asset’s retirement obligation in the period in which the liability is incurred (at the time the wells are drilled or acquired). Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on current actual costs. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability. The Company did not have significant revisions to its asset retirement obligations for the years ended December 31, 20242025 orand 2023.2024.
What changed in the latest 10-Q
Risk Factors
Information regarding our risk factors appears in Item 1A. of our 2025 Form 10-K for the year ended December 31, 2025. These risk factors describe some of the assumptions, risks, uncertainties and other factors that could adversely affect our business or that could otherwise result in changes that differ materially from our expectations.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
Largest changes
“Lease operating expenses for the three and six months ended June 30, 2026 increased in total and per BOE compared to the three and six months ended June 30, 2025 primarily due to a $2.1 million one-time non-cash adjustment during the three and six months ended June 30, 2025 of an operating accrual dating back to the Company’s emergence from bankruptcy (see Note 1—Basis of Presentation to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report for further information).”see in full comparison
“Cash used in financing activities for the six months ended June 30, 2026 consisted of $14.5 million in cash dividends, $0.5 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.4 million. …”see in full comparison
“Cash used in financing activities for the three months ended March 31, 2026 consisted of $3.9 million in cash dividends, finance lease payments of $0.2 million, and $0.4 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise. …”see in full comparison
“•On June 26, 2026, the Company entered into a purchase and sale agreement for the acquisition of certain producing assets and leasehold interests in the Cherokee Play of the Mid-Continent region for $65.0 million, subject to customary purchase price adjustments, and three contingent earn-out payments of $2.0 million each, based on exceeding the average daily spot price for West Texas Intermediate crude oil at certain price thresholds beginning July 1, 2026 and ending December 31, 2027. The Company expects to fund the acquisition with cash on hand. …”see in full comparison
Production, ad valorem, and other taxes for the three and six months endedsee in full comparisonMarchJune31,30, 2026wereincreasedconsistentin total compared with the three and six months endedMarchJune31,30,2025.2025Theprimarilydecreasedueintoproduction,higher average commodity prices, sales volumes, and related revenues. Production, ad valorem, and other taxes perBoeBOEwasincreased for the three and six months ended June 30, 2026 compared with the three and six months ended June 30, 2025 primarily due toahigherdecreaseaverageincommodityad valorem taxes.prices.
Total MBoe production for the three months endedsee in full comparisonMarchJune31,30, 2026 was comprised of approximately21.1%18.3% oil, 49.6% natural gas and 32.1% NGL compared to 16.7% oil, 49.4% natural gas and 33.9% NGL in the second quarter of 2025. Total MBoe production for the six months ended June 30, 2026 was comprised of approximately 19.6% oil, 49.7% natural gas and29.2%30.7% NGL compared to16.8%16.7% oil,48.9%49.2% natural gas and34.3%34.1% NGL in the firstquarterhalf of 2025.
Full comparison: every changed paragraph (25)
The financial information with respect to the three and six months ended MarchJune 31,30, 2026 and 2025, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments unless otherwise disclosed, necessary to state fairly the accompanying unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.
The charts below show production by product and percent revenues for the three and six months ended MarchJune 31,30, 2026 and 2025:
Total MBoe production for the three months ended MarchJune 31,30, 2026 was comprised of approximately 21.1%18.3% oil, 49.6% natural gas and 32.1% NGL compared to 16.7% oil, 49.4% natural gas and 33.9% NGL in the second quarter of 2025. Total MBoe production for the six months ended June 30, 2026 was comprised of approximately 19.6% oil, 49.7% natural gas and 29.2%30.7% NGL compared to 16.8%16.7% oil, 48.9%49.2% natural gas and 34.3%34.1% NGL in the first quarterhalf of 2025.
Recent Events
•On June 26, 2026, the Company entered into a purchase and sale agreement for the acquisition of certain producing assets and leasehold interests in the Cherokee Play of the Mid-Continent region for $65.0 million, subject to customary purchase price adjustments, and three contingent earn-out payments of $2.0 million each, based on exceeding the average daily spot price for West Texas Intermediate crude oil at certain price thresholds beginning July 1, 2026 and ending December 31, 2027. The Company expects to fund the acquisition with cash on hand. The acquisition is expected to close during the third quarter of 2026 and will be effective May 1, 2026.
In order to reduce our exposure to price fluctuations, from time to time we may enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas and NGL production as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oiloil, natural gas and natural gas.NGL. Conversely, during periods of declining oil andoil, natural gas and NGL market prices, our commodity derivative contracts may partially offset declining revenues and cash flows to the extent strike prices for our contracts are above market prices at the time of settlement. See “Note 3 — Derivatives” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.
Lease operating expenses for the three and six months ended June 30, 2026 increased in total and per BOE compared to the three and six months ended June 30, 2025 primarily due to a $2.1 million one-time non-cash adjustment during the three and six months ended June 30, 2025 of an operating accrual dating back to the Company’s emergence from bankruptcy (see Note 1—Basis of Presentation to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report for further information).
Lease operating expenses for the three months ended March 31, 2026 were consistent with the three months ended March 31, 2025. The decrease in lease operating expenses per Boe was primarily driven by continued efficient operations and an increase in production volumes due to our ongoing drilling program in the Cherokee Play.
Production, ad valorem, and other taxes for the three and six months ended MarchJune 31,30, 2026 wereincreased consistentin total compared with the three and six months ended MarchJune 31,30, 2025.2025 Theprimarily decreasedue into production,higher average commodity prices, sales volumes, and related revenues. Production, ad valorem, and other taxes per BoeBOE wasincreased for the three and six months ended June 30, 2026 compared with the three and six months ended June 30, 2025 primarily due to ahigher decreaseaverage incommodity ad valorem taxes.prices.
The increase in depreciation and depletion for oil and natural gas properties for the three and six months ended MarchJune 31,30, 2026 versus the same period in 2025 was primarily the result of an increase in sales volumes and our depletion rate.
A ceiling limitation calculation is performed at the end of each quarter. If the full cost pool balance exceeds the ceiling limitation, an impairment of the full cost pool is required. Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month first-day-of-the-month index prices (“SEC prices”) as adjusted for price differentials and other contractual arrangements. The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at MarchJune 31,30, 2026 were $63.31$71.90 per barrel of oil and $3.72$3.64 per MMBtu of natural gas, before price differential adjustments.
The ceiling limitation was not exceeded; therefore, no full cost ceiling limitation impairments were recorded during the three or six months ended MarchJune 31,30, 2026 or 2025. Full cost pool ceiling limitation impairments have no impact to our cash flow or liquidity.
Based on the SEC prices over the trailing ten months ended AprilJuly 30,31, 2026, as well as two months of NYMEX strip pricing for MayAugust and JuneSeptember of 2026 as of AprilJuly 30, 2026, we estimate the SEC prices utilized in the JulySeptember 1,30, 2026 full cost ceiling test may be $72.15$75.25 per barrel of oil and $3.59$3.62 per MMBtu of natural gas (the "estimated secondthird quarter prices"). Applying these estimated secondthird quarter prices, and holding all other inputs constant to those used in the calculation of our MarchJune 31,30, 2026 ceiling test, we expect that no full cost ceiling limitation impairment is indicated for the secondthird quarter of 2026.
General and administrative expenses decreasedincreased for the three months ended MarchJune 31,30, 2026 versus the same periodsperiod in 20262025 primarily as a result of aincreased decreaseprofessional in personnelfees and other costs. General and administrative expenses for the six months ended June 30, 2026 were consistent with the same period in 2025.
Our derivative contracts were not designated as accounting hedges and, as a result, changes in their fair values were recorded each quarter as a component of operating expenses. Internally, management has historically viewed the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil, natural gas and NGL production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil andoil, natural gas and NGL prices at the time of settlement, compared to the contract price for our commodity derivative contracts; and, cash is paid on settlement of contracts due to higher oil, natural gas and NGL prices at the time of settlement, compared to the contract price for our commodity derivative contracts. See further discussion of derivative contracts in “Item 3. Quantitative and Qualitative Disclosures about Market Risk” included in Part I of this Quarterly Report.
Our other income (expense) areis presented in the table below (in thousands):
Interest income, net during the three and six month periods ended MarchJune 31,30, 2026 and 2025 is primarily comprised of interest income on cash deposits.
As of MarchJune 31,30, 2026, our cash and cash equivalents, including restricted cash, was $104.1$114.7 million. We expect our cash on hand and cash from operations to be adequate to meet our short and long-term liquidity needs. We had no outstanding term or revolving debt obligations as of MarchJune 31,30, 2026.
Decreases in accounts payable and accrued expenses are the primary driver of the increase in working capital to $83.5$93.9 million at MarchJune 31,30, 2026 compared to $79.8 million at December 31, 2025.
__________________ (1) Includes $3.9 million and $4.1 million in dividend payments for the three months ended March 31, 2026 and 2025, respectively.
The decreaseincrease in cash flows from operations for the threesix months ended MarchJune 31,30, 2026 compared to the same period in 2025 is primarily due to working capital changes partially offset by an increase in revenues from higher average commodityoil and NGL prices and higher sales volumes from our development program in the Cherokee Play of the Mid-Con.
Cash used in financing activities for the six months ended June 30, 2026 consisted of $14.5 million in cash dividends, $0.5 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.4 million. Since 2023, the Company has paid cash dividends totaling $184.2 million and issued 0.2 million shares in lieu of cash dividends under the Dividend Reinvestment Program, which represents $3.70 per share in special dividends and $1.35 per share in quarterly dividends for a total of $5.05 per share in total dividends. Cash used in financing activities for the six months ended June 30, 2025 consisted primarily of $8.2 million in cash dividends, $5.9 million in repurchases of common stock, finance lease payments of $0.4 million, and $0.2 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise. Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award that equals the employee payroll tax obligation due. We then remit a cash payment to the relevant taxing authority on behalf of the employee for their payroll tax obligations resulting from the vesting of their stock award.
Cash used in financing activities for the three months ended March 31, 2026 consisted of $3.9 million in cash dividends, finance lease payments of $0.2 million, and $0.4 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise. Since 2023, the Company has paid cash dividends totaling $173.6 million and 0.1 million in shares issued in lieu of cash dividends under the Dividend Reinvestment Program, which represents $3.50 per share in special dividends and $1.22 per share in quarterly dividends for a total of $4.72 per share in total dividends. Cash used in financing activities for the three months ended March 31, 2025 consisted primarily of $5.0 million in repurchases of common stock, $4.1 million in cash dividends, $0.1 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.2 million. Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award that equals the employee payroll tax obligation due. We then remit a cash payment to the relevant taxing authority on behalf of the employee for their payroll tax obligations resulting from the vesting of their stock award.
At MarchJune 31,30, 20262026, our contractual obligations included asset retirement obligations, leases and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the surety bonds or other instruments.
For a description of our critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2025 Form 10-K. For a discussion of recent accounting pronouncements, newly adopted and recent accounting pronouncements not yet adopted, see “Note 1—Basis of Presentation” to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report. We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the first threesix months of 2026.
SD insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-09-01 | Brown Brandon Louis Sr. |
Option exercise | 1,000 | — | — |
| 2026-09-01 | Brown Brandon Louis Sr. |
Shares withheld for tax | 244 | $14.37 | $3.5K |
| 2026-09-01 | Parrish Dean |
Option exercise | 1,000 | — | — |
| 2026-09-01 | Parrish Dean |
Shares withheld for tax | 289 | $14.37 | $4.2K |
| 2026-06-10 | Katz Jacob M |
Grant/award | 9,804 | $15.30 | $150.0K |
| 2026-06-10 | Icahn Brett |
Grant/award | 9,804 | $15.30 | $150.0K |
| 2026-06-10 | Firestone Jaffrey Adam |
Grant/award | 9,804 | $15.30 | $150.0K |
| 2026-06-10 | Dunlap Nancy Martori |
Grant/award | 9,804 | $15.30 | $150.0K |
| 2026-05-17 | Pranin Grayson R |
Shares withheld for tax | 1,378 | $15.27 | $21.0K |
| 2026-05-17 | Pranin Grayson R |
Option exercise | 3,138 | — | — |
| 2026-05-17 | Brown Brandon Louis Sr. |
Option exercise | 1,761 | — | — |
| 2026-05-17 | Brown Brandon Louis Sr. |
Shares withheld for tax | 429 | $15.27 | $6.6K |
| 2026-05-17 | Parrish Dean |
Option exercise | 1,891 | — | — |
| 2026-05-17 | Parrish Dean |
Shares withheld for tax | 546 | $15.27 | $8.3K |
Well-known investors holding SD (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Carl Icahn | 2026-06-30 | 5,054,907 | $69.3M | 0.84% | Added 2% |
| Renaissance Technologies | 2026-06-30 | 1,487,395 | $20.4M | 0.03% | Reduced 1% |
| Two Sigma Investments | 2026-06-30 | 504,494 | $6.9M | 0.01% | Added 2% |
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 489,909 | $6.7M | 0.0% | Added 7% |
| D. E. Shaw & Co. | 2026-06-30 | 149,924 | $2.1M | 0.0% | Added 145% |
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 123,840 | $1.7M | 0.0% | Added 7% |
| Millennium Management (Israel Englander) | 2026-06-30 | 120,136 | $1.6M | 0.0% | Added 419% |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 78,344 | $1.3M | — | Sold out |