SandRidge Energy Inc.
03/05/2026 | Press release | Distributed by Public on 03/05/2026 16:05
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: "Business" in Item 1 and "Financial Statements and Supplementary Data" in Item 8. Our discussion and analysis includes the following subjects:
•Overview;
•Consolidated Results of Operations;
•Liquidity and Capital Resources;
•Valuation Allowance; and
•Critical Accounting Policies and Estimates.
We have applied the Securities and Exchange Commission's adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent calendar years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for years ended December 31, 2025 and 2024. For the comparison of the years ended December 31, 2024 and 2023, see "Management's Discussion and Analysis of Consolidated Results of Operations" in Part II, Item 7 of our 2024 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 11, 2025.
Overview
We are an independent oil and natural gas company with a principal focus on acquisition, development and production activities in the U.S. Mid-Continent region ("Mid-Con").
Operational Activities
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.
The charts below show production and percent revenues by product for the years ended December 31, 2025 and 2024:
Total production by volume on a Boe basis was composed of the following:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Oil | 17.9 | % | 15.2 | % | |||||||
| Natural gas | 48.8 | % | 53.6 | % | |||||||
| NGL | 33.3 | % | 31.2 | % | |||||||
| Total | 100.0 | % | 100.0 | % | |||||||
Highlighted Events
•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.
Outlook
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, growth projects. Currently, these projects include: (1) one-rig development in the Cherokee Shale Play (2) evaluation of 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 (4) a leasing program that will bolster future development and extend development in our Cherokee assets. We are developing our term acreage in the Cherokee Play, and our total leasehold position, inclusive of the Cherokee, NW Stack and legacy assets, is approximately 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, costs, impacts of tariffs and other factors that could influence returns and cash flows, and will adjust our program accordingly, to include curtailment of capital activity and wells, if needed, or conversely, well reactivations in higher commodity price environments. These and other factors, including reasonable reinvestment rates, maintaining our cash flows and prioritizing our regular-way dividend, will continue to shape our development decisions for the remainder of the year and beyond.
Consolidated Results of Operations
The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs. Our revenues, profitability and future growth depend substantially on prevailing prices received for our production, the quantity of oil, natural gas and NGLs we produce, and our ability to find and economically develop and produce our reserves. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| NYMEX WTI Oil (per Bbl) | $ | 65.39 | $ | 76.63 | |||||||
| NYMEX Henry Hub Natural gas (per Mcf) | $ | 3.65 | $ | 2.27 | |||||||
In order to reduce our exposure to price fluctuations, from time to time we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in Item 7A. "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 oil, natural gas and NGLs. Conversely, during periods of declining market prices of oil, natural gas and NGL, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement.
Oil, Natural Gas and NGL Production and Pricing
The table below presents production and pricing information.
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | Change | |||||||||||||||
| Production data (in thousands) | |||||||||||||||||
| Oil (MBbls) | 1,214 | 918 | 296 | ||||||||||||||
| Natural gas (MMcf) | 19,802 | 19,488 | 314 | ||||||||||||||
| NGL (MBbls) | 2,254 | 1,889 | 365 | ||||||||||||||
| Total volumes (MBoe) | 6,768 | 6,056 | 712 | ||||||||||||||
| Average daily total volumes (MBoe/d) | 18.5 | 16.5 | 2.0 | ||||||||||||||
| Average prices-as reported (1) | |||||||||||||||||
| Oil (per Bbl) | $ | 63.64 | $ | 74.31 | $ | (10.67) | |||||||||||
| Natural gas (per Mcf) | $ | 2.10 | $ | 1.10 | $ | 1.00 | |||||||||||
| NGL (per Bbl) | $ | 16.64 | $ | 18.87 | $ | (2.23) | |||||||||||
| Total (per Boe) | $ | 23.10 | $ | 20.69 | $ | 2.41 | |||||||||||
| Average prices-including impact of derivative contract settlements | |||||||||||||||||
| Oil (per Bbl) | $ | 64.80 | $ | 74.88 | $ | (10.08) | |||||||||||
| Natural gas (per Mcf) | $ | 2.29 | $ | 1.10 | $ | 1.19 | |||||||||||
| NGL (per Bbl) | $ | 16.69 | $ | 18.89 | $ | (2.20) | |||||||||||
| Total (per Boe) | $ | 23.87 | $ | 20.78 | $ | 3.09 | |||||||||||
___________________
(1)Prices represent actual average realized prices for the periods presented and do not include the impact of derivative transactions.
Revenues
Consolidated revenues are presented in the table below (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | Change | |||||||||||||||
| Revenues | |||||||||||||||||
| Oil | $ | 77,270 | $ | 68,231 | $ | 9,039 | |||||||||||
| Natural gas | 41,587 | 21,397 | 20,190 | ||||||||||||||
| NGL | 37,500 | 35,662 | 1,838 | ||||||||||||||
| Total revenues | $ | 156,357 | $ | 125,290 | $ | 31,067 | |||||||||||
Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the years ended December 31, 2025 and 2024 are shown in the table below (in thousands):
| 2024 oil, natural gas and NGL revenues | $ | 125,290 | |||
| Change due to production volumes 2025 | 25,556 | ||||
| Change due to average prices 2025 | 5,511 | ||||
| 2025 oil, natural gas and NGL revenues | $ | 156,357 | |||
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.
Operating Expenses
Operating expenses consisted of the following (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | Change | |||||||||||||||
| Lease operating expenses | $ | 36,191 | $ | 40,012 | $ | (3,821) | |||||||||||
| Production, ad valorem, and other taxes | 9,846 | 6,780 | 3,066 | ||||||||||||||
| Depreciation and depletion-oil and natural gas | 36,439 | 25,976 | 10,463 | ||||||||||||||
| Depreciation and amortization-other | 6,433 | 6,503 | (70) | ||||||||||||||
| Total operating expenses | $ | 88,909 | $ | 79,271 | $ | 9,638 | |||||||||||
| Lease operating expenses ($/Boe) | $ | 5.35 | $ | 6.61 | $ | (1.26) | |||||||||||
| Production, ad valorem, and other taxes ($/Boe) | $ | 1.45 | $ | 1.12 | $ | 0.33 | |||||||||||
| Depreciation and amortization-oil and natural gas ($/Boe) | $ | 5.38 | $ | 4.29 | $ | 1.09 | |||||||||||
| Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) | 6.3 | % | 5.4 | % | 0.9 | % | |||||||||||
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 increase in depreciation and depletion for oil and natural gas properties was primarily the result of an increase in our depletion 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, 2025 and 2024.
Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month 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 December 31, 2025 were $65.34 per barrel of oil and $3.39 per MMBtu of natural gas, before price differential adjustments.
Based on the SEC prices over the eleven months ended February 1, 2026 and NYMEX strip pricing for March 2026 as of February 26, 2026, we anticipate the SEC prices utilized in the March 31, 2026 full cost ceiling test may be $63.16 per barrel of oil and $3.72 per MMBtu of natural gas, (the "estimated first quarter prices"). Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2025 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2026.
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.
Other Operating Expenses
Other operating expenses consisted of the following (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | Change | |||||||||||||||
| General and administrative | $ | 13,201 | $ | 11,695 | $ | 1,506 | |||||||||||
| Restructuring expenses | 1,060 | 474 | 586 | ||||||||||||||
| (Gain) loss on derivative contracts | (7,763) | (748) | (7,015) | ||||||||||||||
| Other operating expense (income) | - | 1,372 | (1,372) | ||||||||||||||
| Total other operating expenses | $ | 6,498 | $ | 12,793 | $ | (6,295) | |||||||||||
General and administrative expenses increased for the year ended December 31, 2025 primarily due to higher personnel costs and professional fees.
Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing, the outsourcing of corporate functions and our exit from North Park Basin in Colorado.
Other operating expense (income) decreased for the year ended December 31, 2025 primarily due to an impairment in 2024 on our non-full cost pool inventory.
The following table summarizes derivative activity (in thousands):
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (Gain) loss on derivative contracts | $ | (7,763) | $ | (748) | |||||||
| Realized settlement gains (losses) on derivative contracts | $ | 5,189 | $ | 548 | |||||||
Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded quarterly as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine "effective prices." In general, cash is received on settlement of contracts due to lower oil and natural gas 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 and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts. See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" of this report for additional discussion of our commodity derivatives.
Interest income (expense), net consisted of the following (in thousands):
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Interest income (expense), net | |||||||||||
| Interest income | $ | 4,149 | $ | 7,875 | |||||||
| Interest expense | |||||||||||
| Interest expense on right of use assets | (90) | (84) | |||||||||
| Interest expense on letters of credit | (30) | (40) | |||||||||
| Interest expense - other | (342) | (7) | |||||||||
| Total interest expense | (462) | (131) | |||||||||
| Total interest income (expense), net | $ | 3,687 | $ | 7,744 | |||||||
Interest income (expense), net during the years ended December 31, 2025 and 2024 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 capital expenditures, dividend payments, acquisitions and share repurchases as well as lower interest rates.
Income tax (benefit)
We recorded income tax benefit of $5.5 million and $22.2 million for the years ended December 31, 2025 and 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, 2025 was higher than the partial valuation allowance release as of December 31, 2024 of $72.8 million, we recognized $5.5 million of deferred federal and state income tax benefit for the year ended December 31, 2025.
Liquidity and Capital Resources
At December 31, 2025, our cash and cash equivalents, including restricted cash, was $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 February 26, 2026, the Company had no outstanding term or revolving debt obligations.
Working Capital and Sources and Uses of Cash
Our principal sources of liquidity for 2026 include cash flow from operations and cash on hand.
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.
Excluding any expenditures for acquisitions which may arise, we intend to spend between $76.0 million and $97.0 million in our 2026 capital budget plan. We intend to fund capital expenditures and other commitments for the next 12 months using cash flows from our operations and cash on hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.
Cash Flows
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 1, 2021 through December 31, 2025, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $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.
If oil, natural gas and NGL prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. Further, if our future capital expenditures are limited or deferred, or we are unsuccessful in developing reserves and adding production through our capital program, the value of our oil and natural gas properties, financial condition and results of operations could be adversely affected. Cash flows from operations are also affected by timing of cash receipts and disbursements and changes in other working capital assets and liabilities.
Cash flows are presented in the following table and discussed below (in thousands):
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Cash flows provided by operating activities | $ | 100,140 | $ | 73,933 | |||||||
| Cash flows used in investing activities | (64,011) | (154,696) | |||||||||
|
Cash flows used in financing activities(1)
|
(23,295) | (73,670) | |||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | $ | 12,834 | $ | (154,433) | |||||||
__________________
(1)Includes $15.9 million and $72.3 million in dividend payments for the year ended December 31, 2025 and 2024, respectively.
Cash Flows from Operating Activities
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.
See "Consolidated Results of Operations" for further analysis of the changes in revenues and operating expenses.
Cash Flows from Investing Activities
Our capital expenditures and acquisitions of oil and gas properties are summarized below (in thousands):
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Capital Expenditures | |||||||||||
| Drilling, completion, and capital workovers | $ | 63,970 | $ | 15,562 | |||||||
| Leasehold and geophysical | 5,016 | 11,246 | |||||||||
| Capital expenditures, excluding acquisitions (on an accrual basis) | 68,986 | 26,808 | |||||||||
| Acquisitions | 8,514 | 129,664 | |||||||||
| Capital expenditures, including acquisitions | 77,500 | 156,472 | |||||||||
| Changes in accounts payable and accrued expenses | (10,372) | (263) | |||||||||
| Inventory material transfers to oil and natural gas properties | (3) | (141) | |||||||||
| Total cash paid for capital expenditures, including acquisitions | $ | 67,125 | $ | 156,068 | |||||||
Cash Flows from Financing Activities
Our financing activities used $23.3 million of cash for the year ended December 31, 2025, consisting primarily of $15.9 million in cash dividends, $6.4 million in common stock repurchases, finance lease payments of $0.7 million, $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. 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 $73.7 million of cash for the year ended December 31, 2024, consisting primarily of $72.3 million in cash dividends, finance 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 $0.2 million in common stock repurchases. See discussion in above paragraph for additional information on net exercises of stock awards.
Share Repurchase Program
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
Contractual Obligations and Off-Balance Sheet Arrangements
At December 31, 2025, our contractual obligations included asset retirement obligations and short and long-term leases. 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.
As of December 31, 2025, we had future contractual commitments under various agreements, which are summarized below. The short-term leases are not recorded in the accompanying consolidated balance sheets.
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| Payments Due by Period | |||||||||||||||||||||||||||||
| Total |
Less than
1 year
|
1-3 years | 3-5 years |
More than
5 years
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| (In thousands) | |||||||||||||||||||||||||||||
| Asset retirement obligations (1) | $ | 72,391 | $ | 8,098 | $ | - | $ | - | $ | 64,293 | |||||||||||||||||||
| Operating lease | 161 | 161 | - | - | - | ||||||||||||||||||||||||
| Short-term leases | 7,817 | 7,817 | - | - | - | ||||||||||||||||||||||||
| Finance lease | 1,472 | 754 | 718 | - | - | ||||||||||||||||||||||||
| Total | $ | 81,841 | $ | 16,830 | $ | 718 | $ | - | $ | 64,293 | |||||||||||||||||||
(1)Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2025. These estimates and assumptions can be inherently unpredictable and may differ from actual results given the uncertainty of when we may be required to plug and abandon a well or retire an asset. As a result, we may not incur all or may incur more than the estimated costs for the current asset retirement obligation as depicted above. During the year ended December 31, 2025, plugging and abandonment costs incurred were $1.0 million.
Critical Accounting Estimates
The discussion and analysis of the Company's financial condition and results of operations are based upon the Company's consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company's financial statements requires management to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are based on historical experience and various other assumptions believed to be reasonable; however, actual results may differ significantly. The Company's critical accounting policies and additional information on significant estimates are discussed below. See "Note 1-Summary of Significant Accounting Policies" to the Company's accompanying consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies.
Proved Reserves.Approximately 97.9% of the Company's reserves were estimated by independent petroleum engineers as of December 31, 2025. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company's control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data. The accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. When excluding the effects of pricing and other commercial assumptions, the Company revised its proved reserves an average of approximately 5% over the past five years and the revisions for the year ended December 31, 2025 were approximately 2%. In the future, estimates of proved reserves could also be influenced by production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries among other factors. Estimates of proved reserves are key components of the Company's financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company's future depreciation, depletion and impairment expenses. See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail.
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, 2025 and 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, 2025 and 2024.
Income Taxes.Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax assets are recognized for temporary differences that will be deductible in future years' tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years' tax returns. In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. Upon emergence from bankruptcy and the application of fresh start accounting in 2016, our tax basis in oil and gas properties and property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had significant U.S. federal net operating losses remaining after the attribute reduction caused by the restructuring transactions. As such, the successor Company had significant deferred tax assets to consume upon emergence. In prior years, we determined that the deferred tax assets did not meet the more likely than not threshold of being utilized and thus recorded a valuation allowance. Our partial valuation allowance release of $72.8 million as of December 31, 2024 was increased by $5.5 million due to changes in expected future income, resulting in net deferred tax assets of $78.3 million as of December 31, 2025. We anticipate being able to utilize these deferred tax assets based on the generation of future income. A change in the estimate of future income could cause the valuation allowance to be adjusted in subsequent periods.
New Accounting Pronouncements. For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see "Note 1-Summary of Significant Accounting Policies" to the Company's accompanying consolidated financial statements in Item 8 of this report.
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