SANDRIDGE ENERGY INC (SD)

Item 7.    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, 2024 and 2023. For the comparison of the years ended December 31, 2023 and 2022, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2023 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 7, 2024.

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

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 charts below show production and percent revenues by product for the years ended December 31, 2024 and 2023:

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.

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Total production by volume on a Boe basis for the years ended December 31, 2024 and 2023 was composed of the following:

Highlighted Events

•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.

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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, organic growth projects. Currently, these projects include (1) One 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 2025 (2) Production Optimization program through artificial lift conversions to more efficient and cost-effective systems and high-graded recompletions (3) leasing program that will bolster future development and extend development in our Cherokee assets. Our legacy non-Cherokee leasehold remains approximately 99% 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 and other factors that could influence returns and adjust capital allocations accordingly. These and other factors, to include reasonable reinvestment rates, sustaining 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.

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:

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.

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Oil, Natural Gas and NGL Production and Pricing

The table below presents production and pricing information for the years ended December 31, 2024 and 2023.

___________________

(1)Prices represent actual average realized prices for the periods presented and do not include the impact of derivative transactions.

Revenues

Consolidated revenues for the years ended December 31, 2024 and 2023 are presented in the table below (in

thousands).

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, 2024 and 2023 are shown in the table below (in thousands):

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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

Operating expenses for the years ended December 31, 2024 and 2023 consisted of the following (in thousands):

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 our acquisition 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.

Full cost pool impairment.    We did not record a full cost ceiling limitation impairment for the years ended December 31, 2024 or 2023.

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, 2024 were $75.48 per barrel of oil and $2.13 per MMBtu of natural gas, before price differential adjustments.

Based on the SEC prices over the eleven months ended February 1, 2025 and NYMEX strip pricing for March 2025 as of February 28, 2025, we anticipate the SEC prices utilized in the March 31, 2025 full cost ceiling test may be $74.52 per barrel of oil and $2.44 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, 2024 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2025.

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.

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Other Operating Expenses

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, 2024 primarily due to higher personnel and other costs.

Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing and our exit from NPB in Colorado.

Other operating expense (income) increased for the year ended December 31, 2024 primarily due to a $1.3 million impairment on our equipment inventory.

The following table summarizes derivative activity for the years ended December 31, 2024 and 2023 (in thousands):

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.

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Interest (income) expense, net for the years ended December 31, 2024 and 2023 consisted of the following (in thousands):

Interest (income) expense, net during the years ended December 31, 2024 and 2023 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, and to a lesser extent, capital expenditures and dividend payments.

Income tax (benefit)

We recorded income tax benefit and expense of $22.2 million and $14.0 million for the years ended December 31, 2024 and 2023, 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, 2024 was higher than the partial valuation allowance release as of December 31, 2023 of $50.6 million, we recognized $22.2 million of deferred federal and state income tax benefit for the year ended December 31, 2024.

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Liquidity and Capital Resources

At December 31, 2024, our cash and cash equivalents, including restricted cash, was $99.5 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 March 4, 2025, the Company had no outstanding term or revolving debt obligations.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2025 include cash flow from operations and cash on hand.

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.

Excluding any expenditures for acquisitions which may arise, we intend to spend between $66 million and $85 million in our 2025 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 2020 through December 2024, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98) 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 for the years ended December 31, 2024, and 2023 are presented in the following table and discussed below (in thousands):

__________________

(1)     Includes $72.3 million and $81.5 million in dividend payments for the year ended December 31, 2024 and 2023, respectively.

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Cash Flows from Operating Activities

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.

See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.

Cash Flows from Investing Activities

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 for the years ended December 31, 2024 and 2023, are summarized below (in thousands):

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Cash Flows from Financing Activities

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. 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 million of cash for the year ended December 31, 2023, consisting primarily of $81.5 million in cash dividends, $0.9 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 million offset by $0.1 million of proceeds from the exercise of stock options. 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, 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.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2024, 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, 2024, 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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(1)Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2024. 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, 2024, plugging and abandonment costs incurred were $0.9 million.

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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 97.5% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2024. 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, 2024 were approximately 3%. 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.

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, 2024 or 2023.

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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, 2024 or 2023.

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 $50.6 million as of December 31, 2023 was increased by $22.2 million due to changes in expected future income, resulting in net deferred tax assets of $72.8 million as of December 31, 2024. 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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Item 7.    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, 2023 and 2022. For the comparison of the years ended December 31, 2022 and 2021, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 15, 2023.

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

For the year ended December 31, 2023, there were two operated wells drilled and four wells completed. For the year ended December 31, 2022 there were eight operated wells drilled, six wells completed, and 50 wells reactivated.

The charts below show production and percent revenues by product for the years ended December 31, 2023 and 2022:

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Total production for the years ended December 31, 2023 and 2022 was composed of the following:

The increase in oil production was primarily driven by the newly drilled wells as part of our capital development program. The decrease in total MBoe was primarily driven by a reduction of NGL production, as one of our purchasers elected to retain more ethane in the natural gas stream, which had more favorable market pricing at the time of sales, as well as natural decline of its producing assets. These factors were partially offset by production added during the third quarter from an acquisition that closed on July 11, 2023, which increased our ownership interest in twenty-six wells we operate.

Highlighted Events

•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 January 2024, the Board announced that it plans to increase its on-going quarterly dividend to $0.11 per share starting with the next quarterly payout, estimated to be first paid in March 2024, continuing every quarter thereafter until noticed, subject to quarterly approval by the Board.

•On July 11, 2023, the Company closed an acquisition that increased its ownership interest in twenty-six producing

wells operated by the Company within the Northwest Stack play for $10.6 million, after customary post-closing

adjustments, with an effective date of April 1, 2023. The Company used its cash on hand to fund the acquisition.

•In May 2023, the Board approved a one-time cash dividend of $2.00 per share of the Company’s common stock, which was paid on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023. Additionally, in May 2023, the Board announced a regular quarterly dividend of $0.10 per share of the Company’s common stock, subject to quarterly approval by the Board. Our dividend payment in May was $73.8 million and the $0.10 dividend payments made in August 2023 and November 2023 totaled $7.4 million.

•In May 2023, the Board approved a stock buyback program authorizing the repurchase of up to $75 million of the

Company’s outstanding common stock in open market transactions.

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Outlook

We will continue to focus on growing the value and cash generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment. These projects include (1) artificial lift conversions to more efficient and cost effective systems, (2) high-graded re-fracturing and recompletion and (3) limited opportunistic leasing in proven areas around or adjacent to our area of operations that could further bolster future development. While commodity price futures are not yet at preferred levels to resume drilling or further well reactivations at this time, we retain the development option over a reasonable tenor, since our assets are 99% held by production. We will continue to monitor forward-looking commodity prices, results, costs and other factors that could influence returns on investments, which will continue to shape our disciplined development decisions in 2024 and beyond. We will also continue to maintain optionality to execute on value accretive merger and acquisition opportunities that could bring synergies, leverage our core competencies, compliment our portfolio of assets, further utilize our NOLs or otherwise yield attractive returns for our shareholders.

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:

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.

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Oil, Natural Gas and NGL Production and Pricing

The table below presents production and pricing information for the years ended December 31, 2023 and 2022.

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(1)Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.

Revenues

Consolidated revenues for the years ended December 31, 2023 and 2022 are presented in the table below (in

thousands).

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, 2023 and 2022 are shown in the table below (in thousands):

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Oil, natural gas and NGL revenues decreased primarily due to lower commodity prices. Production volumes for the year ended December 31, 2023 decreased slightly due to the natural declines of our producing wells, which were partially offset from the production from our new wells and increased ownership interest from our July 2023 acquisition.

Operating Expenses

Operating expenses for the years ended December 31, 2023 and 2022 consisted of the following (in thousands):

The increase in lease operating expenses was primarily due to inflationary pressures and higher production costs associated with more producing wells from our prior well reactivations and development program as well as increased ownership interest from our July 2023 acquisition during the year ended December 31, 2023.

Production, ad valorem, and other taxes decreased primarily due to lower commodity prices and related revenues. However, production, ad valorem, and other taxes increased as a percentage of oil, natural gas and NGL revenue primarily due to higher oil and gas property valuation assessments by local jurisdictions who use historical commodity price averages that included prior periods that were higher than current commodity prices, when determining ad valorem tax assessments.

The increase in depreciation and depletion for oil and natural gas properties was primarily the result of capital expenditures for 2023 and a decrease in proved reserves at December 31, 2023, primarily as a result of lower SEC prices (as defined below), which increased our depletion rate.

Full cost pool impairment.    We did not record a full cost ceiling limitation impairment for the years ended December 31, 2023 or 2022.

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, 2023 were $78.22 per barrel of oil and $2.64 per MMBtu of natural gas, before price differential adjustments.

Based on the SEC prices over the eleven months ended February 1, 2024 and NYMEX strip pricing for March 2024 as of March 1, 2024, we anticipate the SEC prices utilized in the March 31, 2024 full cost ceiling test may be $77.48 per barrel of oil and $2.44 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, 2023 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 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 additional 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 2024 could be material to our net earnings.

Full cost pool impairments have no impact to our cash flow or liquidity.

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Other Operating Expenses

Other operating expenses for the years ended December 31, 2023 and 2022 consisted of the following (in thousands):

General and administrative expenses increased for the year ended December 31, 2023 primarily due to higher technology, service and personnel costs.

Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing and our exit from NPB in Colorado.

The following table summarizes derivative activity for the years ended December 31, 2023 and 2022 (in thousands):

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.

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Interest (income) expense, net for the years ended December 31, 2023 and 2022 consisted of the following (in thousands):

Interest (income) expense, net during the year ended December 31, 2023 is primarily comprised of interest income received from cash deposits. Interest (income) expense, net during the year ended December 31, 2022 is primarily comprised of interest income received from cash deposits partially offset by interest paid on royalty obligations of $0.1 million, interest on vehicle leases and letters of credit.

Other income (expense), net

The Other income (expense), net line item was not significant for the year ended December 31, 2023. For the year ended December 31, 2022, Other income (expense), net of $0.4 million is primarily comprised of gains on the sale of fleet vehicles and the removal of previously accrued liabilities due to a change in estimate.

Income tax (benefit)

We recorded income tax expense and benefit of $14.0 million and $64.5 million for the years ended December 31, 2023 and 2022, respectively, which directly relates to our partial valuation allowance release. As the partial valuation allowance release as of December 31, 2023 was lower than the partial valuation allowance release as of December 31, 2022 of $64.5 million, we recognized $14.0 million of deferred federal and state income tax expense for the year ended December 31, 2023.

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Liquidity and Capital Resources

At December 31, 2023, our cash and cash equivalents, including restricted cash, was $253.9 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 March 1, 2024, the Company had no outstanding term or revolving debt obligations.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2024 include cash flow from operations and cash on hand.

Our working capital decreased to $228.5 million at December 31, 2023, compared to $241.6 million at December 31, 2022. Dividend payments to shareholders of $81.5 million, $26.4 million in capital expenditures, and $11.2 million related to an acquisition of proved reserves were the primary drivers in the reduction of working capital. These cash outflows were offset by $115.6 million in cash provided by operating activities.

In May 2023, the Board approved a one-time cash dividend of $2.00 per share of the Company’s common stock, which was paid on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023. The aggregate total payout was $73.8 million. Additionally, in May 2023, the Board announced plans for a regular quarterly dividend of $0.10 per share, subject to quarterly approval by the Board. The Company paid quarterly dividends of $3.7 million each on August 28, 2023 and November 27, 2023, totaling $7.4 million, as well as dividends on vested stock awards of $0.3 million for the year. Total special and regular dividends for the year ended December 31, 2023 were $81.5 million. See Note 13 for further discussion of the Company’s dividends.

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 2019 through December 2023, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98) per Bbl, and the NYMEX Henry Hub spot prices for gas fluctuated between a high of $24.77 per Mcf and a low of $1.38 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 for the years ended December 31, 2023, and 2022 are presented in the following table and discussed below (in thousands):

Cash Flows from Operating Activities

The $49.1 million decrease in operating cash flows for the year ended December 31, 2023 compared to 2022, 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.

See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.

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Cash Flows from Investing Activities

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.

During the year ended December 31, 2022, cash flows used in investing activities primarily reflects capital expenditures of $44.1 million related to drilling and completions, capital workovers, well reactivations, and inventory purchases and $1.4 million related to an acquisition of proved reserves. Cash outflows were partially offset by $0.4 million of proceeds from the sale of assets.

See "Note 3— Acquisitions and Divestitures 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 for the years ended December 31, 2023 and 2022, are summarized below (in thousands):

Capital expenditures, excluding acquisitions, for development activities decreased for the year ended December 31, 2023 compared to 2022, primarily due to the conclusion of our drilling program in the second quarter of 2023.

Cash Flows from Financing Activities

Our financing activities used $82.9 million of cash for the year ended December 31, 2023, consisting primarily of $81.5 million in cash dividends, $0.9 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 million offset by $0.1 million of proceeds from the exercise of stock options. 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, t

hat 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 $1.6 million of cash for the year ended December 31, 2022, consisting primarily of $1.2 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.5 million offset by $0.1 million of proceeds from the exercise of stock options. 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. The Company did not repurchase any common stock under the existing or prior Program during the years ended December 31, 2023 and 2022.

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Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2023, 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, 2023, we had future contractual commitments under various agreements, which are summarized below. The short-term leases and operating lease are not recorded in the accompanying consolidated balance sheets.

____________________

(1)Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2023. 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 of the estimated costs for the current asset retirement obligation as depicted above. During the year ended December 31, 2023, plugging and abandonment costs incurred were $0.9 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.

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Proved Reserves. Approximately 95.2% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2023. 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, 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, 2023 were less than 3%. 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.

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 $1.82 per Boe in 2023 and $1.18 per Boe in 2022.

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, 2023 or 2022.

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. For the years ended December 31, 2023 and 2022, the Company revised its asset retirement obligations by approximately $0.9 million downwards and $2.7 million upwards, respectively, due primarily to changes in working interest and estimated well lives.

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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 release of $64.5 million as of December 31, 2022 was partially offset by $14.0 million due to changes in expected future income, resulting in net deferred tax assets of $50.6 million as of December 31, 2023. 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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Item 7.    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, 2022 and 2021. For the comparison of the years ended December 31, 2021 and 2020, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2021 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 10, 2022.

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. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.

Operational Activities

For the year ended December 31, 2022, there were eight operated wells drilled and six wells completed. There was no drilling activity on our operated acreage during the year ended December 31, 2021. However, we brought wells that were previously not producing on to production as part of our well reactivation program during the year ended December 31, 2021.

The chart below shows production by product for the years ended December 31, 2022 and 2021:

(1)For the year ended December 31, 2021, North Park Basin had 67 MBoe in oil production.

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Total production for the Company in 2022 was composed of approximately 14.7% oil, 54.4% natural gas and 30.9% NGLs compared to 14.1% oil, 52.5% natural gas and 33.4% NGLs in 2021.

Mid-Continent total production for the years ended December 31, 2022 and 2021 was composed of the following:

Highlighted Events

•Consistent with our 2022 capital development program, we drilled eight wells and completed six wells during the year ended December 31, 2022.

•On October 5, 2022 the Company’s Board of Directors appointed Ms. Nancy Dunlap to serve as a member of the Board. Ms. Dunlap also joined the Audit Committee.

•As part of our well reactivation program, we returned 50 wells to production for the year ended December 31, 2022.

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Outlook

We will continue to focus on growing the cash value and generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment. These projects include (1) a continuation of our well reactivation program, (2) artificial lift conversions to more efficient and cost effective systems and (3) focused drilling in high-graded areas. We will continue to monitor forward-looking commodity prices, results, costs and other factors that could influence returns on investments, which will continue to shape our disciplined development decisions in 2023 and beyond. We will also continue to maintain optionality to execute on value accretive merger and acquisition opportunities that could bring synergies, leverage our core competencies, compliment our portfolio of assets, further utilize our NOLs or otherwise yield attractive returns for our shareholders.

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:

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.

Acquisitions and Divestitures of Properties

2021 Acquisitions and Divestitures

On April 22, 2021, we announced the acquisition of all the overriding royalty interest assets of SandRidge Mississippian Trust I (the “Trust”). The gross purchase price was $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

On February 5, 2021, we sold all of our oil and natural gas properties and related assets of the North Park Basin ("NPB") in Colorado for a purchase price of $47 million in cash. Net proceeds were $39.7 million in cash as a result of customary effective to close date adjustments and a $0.8 million post-close adjustment made during the second half of the year. The sale resulted in an $18.9 million gain after the post-close adjustment.

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Oil, Natural Gas and NGL Production and Pricing

The table below presents production and pricing information for the years ended December 31, 2022 and 2021.

___________________

(1)Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.

The table below presents production by area of operation for the years ended December 31, 2022 and 2021.

Revenues

Consolidated revenues for the years ended December 31, 2022 and 2021 are presented in the table below (in

thousands).

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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, 2022 and 2021 are shown in the table below (in thousands):

Oil, natural gas and NGL revenues increased primarily due to improvements in realized commodity prices. Production volumes for the year ended December 31, 2022 decreased slightly due to the natural declines of our producing wells, which were partially offset from the production from our well reactivations and new well activity for the year.

Operating Expenses

Operating expenses for the years ended December 31, 2022 and 2021 consisted of the following (in thousands):

The increase in lease operating expenses was primarily due to inflationary pressures, a higher number of producing wells and higher workover expenses due to our well reactivation program during the year ended December 31, 2022.

Production, ad valorem, and other taxes increased primarily due to the increase in production taxes as a result of increased revenues.

The increase in depreciation and depletion for oil and natural gas properties was primarily the result of increased capital expenditures from higher drilling and completion activity which increased our depletion rate.

Full cost pool impairment.    We did not record a full cost ceiling limitation impairment for the years ended December 31, 2022 or 2021.

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, 2022 were $93.67 per barrel of oil and $6.36 per MMBtu of natural gas, before price differential adjustments.

Based on the SEC prices over the twelve months ended March 1, 2023, we anticipate the SEC prices utilized in the March 31, 2023 full cost ceiling test may be $90.97 per barrel of oil and $5.96 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

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calculation of our December 31, 2022 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2023.

However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2023 and in subsequent quarters based on the outcome of numerous other factors such as additional 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 2023 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 for the years ended December 31, 2022 and 2021 consisted of the following (in thousands):

General and administrative expenses decreased for the year ended December 31, 2022 compared to the year ended December 31, 2021 due to continued efforts of cost control initiatives.

Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing and our exit from NPB in Colorado.

The following table summarizes derivative activity for the years ended December 31, 2022 and 2021 (in thousands):

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.

Gain on sale of assets for the year ended December 31, 2021 relates to the sale of our NPB assets in Colorado in February 2021. See "Note 3-Acquisitions, Divestitures and Disposal of Assets and Oil and Gas Properties."

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Interest (income) expense, net for the years ended December 31, 2022 and 2021 consisted of the following (in thousands):

Interest (income) expense, net during the year ended December 31, 2022 is primarily comprised of interest income received from cash deposits partially offset by interest paid on royalty obligations of $0.1 million, interest on vehicle leases and letters of credit. Interest expense incurred during the year ended December 31, 2021 is primarily comprised of interest and fees paid on the 2020 Credit Facility. The 2020 Credit Facility has been fully repaid and terminated as of September 2, 2021. As a result of the termination of the 2020 Credit Facility, $0.2 million of deferred financing costs were expensed to Interest expense.

Other income (expense), net

Other income (expense), net for the years ended December 31, 2022 and 2021 is reflected in the table below (in thousands):

The Other income (expense), net line item for the year ended December 31, 2022 is primarily comprised of gains on the sale of fleet vehicles and the removal of previously accrued liabilities due to a change in estimate. For the year ended December 31, 2021, Other income (expense), net is primarily comprised of the removal of $2.4 million of an allowance for doubtful accounts as a result of the $2.4 million being collected in October 2021.

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Liquidity and Capital Resources

At December 31, 2022, our cash and cash equivalents, including restricted cash, was $257.5 million. For the next twelve months, we expect to have ample liquidity with cash on hand and cash from operations. As of March 8, 2023, the Company had no outstanding term or revolving debt obligations.

Our commodity derivative contracts are subject to credit risk of our counterparties being financially able to settle the transaction. We monitor the credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. However, any future failures by one or more counterparties could negatively impact our cash flow from operations.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2022 included cash flow from operations and cash on hand.

Our working capital increased to $241.6 million at December 31, 2022, compared to $97.7 million at December 31, 2021. The positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2022 as a result of cash flows from operations, partially offset by increased accrued liabilities driven largely by our increased capital expenditure activity in 2022.

We intend to spend between $26 million and $35 million in our 2023 capital budget plan, excluding any expenditures for acquisitions. 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 and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January 2018 through December 2022, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98) per Bbl, and the month-end NYMEX Henry Hub settled price for gas fluctuated between a high of $24.74 per Mcf and a low of $1.38 per Mcf.

If oil or natural gas 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 for the years ended December 31, 2022, and 2021 are presented in the following table and discussed below (in thousands):

Cash Flows from Operating Activities

The $54.4 million increase in operating cash flows for the year ended December 31, 2022 compared to 2021, is primarily due to increased revenues which is the result of improved commodity prices as discussed above, offset by a slight decrease in production. 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.

See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.

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Cash Flows from Investing Activities

During the year ended December 31, 2022, cash flows used in investing activities primarily reflects capital expenditures of $44.1 million related to drilling, capital workovers, well reactivations, and inventory purchases and $1.4 million related to an acquisition of proved reserves. Cash outflows were partially offset by $0.4 million of proceeds from the sale of assets.

During the year ended December 31, 2021, cash flows provided by investing activities primarily reflects $38.2 million of net cash proceeds primarily from the sale of the NPB assets partially offset by capital expenditures of $11.6 million and the acquisition of overriding royalty interests for $3.6 million.

See "Note 3— Acquisitions, Divestitures and Disposal 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 for the years ended December 31, 2022 and 2021, are summarized below (in thousands):

Capital expenditures, excluding acquisitions, for development activities increased for the year ended December 31, 2022 compared to 2021, which is in line with the planned drilling, completion, capital workover and well reactivation program.

Cash Flows from Financing Activities

Our financing activities used $1.6 million of cash for the year ended December 31, 2022, consisted primarily of $1.2 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.5 million offset by $0.1 million of proceeds from the exercise of stock options. 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 $22.0 million in of cash for the year ended December 31, 2021, consisting primarily of repayments of borrowings under the 2020 Credit Facility of $20.0 million, finance lease payments of $1.0 million and cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise of $0.9 million.

Share Repurchase Program

On August 16, 2021, our Board approved the initiation of a share repurchase program authorizing us to purchase up to an aggregate of $25.0 million of our common stock beginning as early as August 16, 2021. We did not repurchase any common stock under the Program during the year ended 2022.

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Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2022, 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, 2022, we had future contractual payment commitments under various agreements, which are summarized below. The short-term leases and operating lease are not recorded in the accompanying consolidated balance sheets.

____________________

(1)Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2022. 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 of the estimated costs for the current asset retirement obligation as depicted above. During the year ended December 31, 2022, plugging and abandonment costs incurred were $2.6 million.

Valuation Allowance

Upon emergence from bankruptcy and the application of fresh start accounting in 2016, our tax basis in 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 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. 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. As of December 31, 2022, we have partially released our valuation allowance on our deferred tax assets by $64.5 million. 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.

See “Note 13—Income Taxes” to the accompanying consolidated financial statements for additional discussion of income tax related matters.

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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 95.0% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2022. 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. For the years ended December 31, 2022 and 2021, the Company revised its proved reserves from prior years’ reports by approximately 8.1 MMBoe and 43.3 MMBoe, respectively, due to increases in SEC prices used to value reserves at the end of the applicable period, 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.

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.

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. 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, 2022 or 2021.

See “Consolidated Results of Operations” and “Note 9—Impairment” to the Company’s accompanying consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.

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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 third-party quotes and 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.

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. 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. As of December 31, 2022, we have partially released our valuation allowance on our deferred tax assets by $64.5 million. 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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Item 7.    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 2021 and 2020. For the comparison of years ended 2020 and 2019, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2020 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 4, 2021.

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. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.

Operational Activities

There was no drilling activity on our operated acreage during the years ended December 31, 2021 and 2020. However, we brought wells that were previously not producing on to production as part of our well reactivation program during the year ended December 31, 2021.

The chart below shows production by product for the years ended December 31, 2021 and 2020:

(1)For the year ended December 31, 2021, North Park Basin had 67 MBoe in oil production.

(2)For the year ended December 31, 2020, North Park Basin had 940 MBoe in oil production.

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Total production for 2021 was comprised of approximately 14.1% oil, 52.5% natural gas and 33.4% NGLs compared to 23.9% oil, 45.1% natural gas and 31.0% NGLs in 2020.

Mid-Continent total production for the year ended December 31, 2021 and 2020 was comprised of the following:

Highlighted Events

•On February 5, 2021, we sold all of our oil and natural gas properties and related assets of the North Park Basin ("NPB") in Colorado for a purchase price of $47 million in cash. Net proceeds were $39.7 million in cash as a result of customary effective date adjustments and a $0.8 million post-close adjustment made during the second half of the year. The sale resulted in a $18.9 million gain after the post-close adjustment.

•On March 3, 2021, we named Mr. Salah Gamoudi, our Chief Financial Officer and Chief Accounting Officer, as a Senior Vice President. We also named Mr. Dean Parrish, formerly our Director of Operations, as our Vice President of Operations.

•On April 22, 2021, we announced the acquisition of all the overriding royalty interest assets of SandRidge Mississippian Trust I (the “Trust”). The gross purchase price is $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

•On July 9, 2021, Carl F. Giesler, Jr. submitted his resignation from his positions as CEO, President and as a member of the Board of the Company, effective July 16, 2021 in order to pursue another career opportunity. Mr. Giesler did not resign as a result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

•The Board appointed Grayson Pranin as President and CEO effective July 16, 2021 and in addition will maintain his role as Chief Operating Officer. Mr. Pranin, age 41, held the role of Senior Vice President and Chief Operating Officer since March 3, 2021.

•In August 2021, our Board of Directors approved the initiation of a share repurchase program (the "Program") authorizing us to purchase up to an aggregate of $25.0 million of our common stock beginning as early as August 16, 2021. The Program is in accordance with Rule 10b-18 of the Exchange Act. Subject to applicable rules and regulations, repurchases under the Program can be made from time to time in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. 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. We did not repurchase any common stock under the Program during the year ended December 31, 2021.

•On September 2, 2021, we repaid our $20.0 million term loan in full and terminated all commitments and obligations under the 2020 Credit Facility. Our repayment of the term loan satisfied all of our remaining term debt and revolving debt obligations.

•On December 28, 2021, Patricia Agnello submitted her resignation from her positions as a member of the Board of Directors (the “Board”) our Company. Ms. Agnello did not resign as a result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

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Outlook

As discussed in “Business— Our Business Strategy” in Item 1 of this report, we will focus on growing the cash value and generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment. These projects include a continuation of our well reactivation program, artificial lift conversions to more efficient and cost effective systems, as well as focused drilling in high-graded areas, which will aide in partially offsetting the natural decline of our producing asset's. Forward looking commodity prices, results, costs and other factors will shape our development decisions in 2022 and beyond. We will also remain vigilant and maintain optionality for opportunistic, value-accretive acquisitions and business combinations.

As the impact of COVID-19 lessens, demand for commodities is continuing to rise to pre-pandemic levels within the United States. The resurging demand led to favorable commodity prices during the year ended December 31, 2021. However, the spread of COVID-19 variants and the effectiveness of the vaccines against these variants are significant risk factors to a full and sustained recovery. If the vaccines currently available are not effective against COVID-19 or its other variants, Governments and other regulatory bodies may have to rely on mobility and activity restrictions to mitigate the spread, which could lead to reduced demand for certain commodities. See “Item 1A. Risk Factors” included in Part I of this Annual Report for additional discussion of the potential impact these events may have on our future revenues.

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:

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 NGL. 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.

Acquisitions and Divestitures of Properties

2021 Acquisitions and Divestitures

On April 22, 2021, we announced the acquisition of all the overriding royalty interest assets of SandRidge Mississippian Trust I (the “Trust”). The gross purchase price is $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

On February 5, 2021, we sold all of our oil and natural gas properties and related assets of the North Park Basin ("NPB") in Colorado for a purchase price of $47 million in cash. Net proceeds were $39.7 million in cash as a result of customary effective date adjustments and a $0.8 million post-close adjustment made during the second half of the year. The sale resulted in a $18.9 million gain after the post-close adjustment.

2020 Acquisitions and Divestitures

On September 10, 2020, the Company acquired all of the overriding royalty interests held by SandRidge Mississippian Royalty Trust II ("the Trust") for a net purchase price of $3.28 million, given our 37.6% ownership of the Trust. The Company

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accounted for this transaction as an asset acquisition and allocated the purchase price of the acquisition plus the transactions costs to oil and gas properties.

On August 31, 2020, the Company closed on the previously announced sale of its corporate headquarters building located in Oklahoma City, OK, for net proceeds of approximately $35.4 million.

Oil, Natural Gas and NGL Production and Pricing

The table below presents production and pricing information for the years ended December 31, 2021 and 2020.

___________________

(1)Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.

The table below presents production by area of operation for the years ended December 31, 2021 and 2020.

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Revenues

Consolidated revenues for the years ended December 31, 2021 and 2020 are presented in the table below (in thousands).

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, 2021 and 2020 are shown in the table below (in thousands):

Oil, natural gas and NGL revenues increased by a combined $54.4 million, or 47.6% for the year ended December 31, 2021, compared to 2020. The average prices for oil, natural gas and NGL's increased primarily due to increased oil, natural gas and NGL realized prices primarily as a result of increased economic activity and recovery from the COVID-19 pandemic and the related increase in energy demand, in addition to a contraction of differentials on realized commodity prices. These increases were partially offset by an overall decline in production due to the natural declines in our existing producing wells and a decrease in oil production as a result of the sale of NPB. Midcon production declines were reduced as a result of our well reactivation program that employs low cost capital workovers to return wells to production.

Operating Expenses

Operating expenses for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):

Lease operating expenses for 2021 decreased $7.4 million from 2020. This decrease primarily resulted from field personnel reductions in force, the sale of NPB and other cost reduction efforts during the year ended December 31, 2021.

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Production, ad valorem, and other taxes has increased primarily due to higher commodity prices in 2021 partially offset by a decline in ad valorem taxes due to the sale of NPB in Colorado and a difference in our accrued estimate and the actual last ad valorem tax payment made for NPB. Production, ad valorem, and other taxes decreased as a percentage of oil, natural gas and NGL revenue for the year 2021 compared to 2020, primarily due to the difference between the estimate and actual payment for ad valorem taxes of NPB.

Depreciation and depletion for oil and natural gas properties decreased by $41.0 million for the year ended December 31, 2021 compared to 2020 due to a decrease in the average depreciation and depletion rate to $1.38 per Boe in 2021 compared to an average rate of $5.79 in 2020. These decreases are primarily due to the sale of the North Park Basin properties and full cost ceiling test impairments recorded during 2020, which lowered the net cost basis of our oil and gas properties significantly.

Impairment

Impairment expense for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):

Full cost pool impairment.    We did not record a full cost ceiling limitation impairment for the year ended December 31, 2021. Impairment for the year ended December 31, 2020 largely resulted from an impairment charge of $256.4 million, which included a full cost ceiling limitation impairment charge of $218.4 million, and an impairment charge of $38 million to write down the value of the Company's building headquarters to its estimated fair value less estimated costs to sell the building headquarters.

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, 2021 were $66.56 per barrel of oil and $3.60 per Mcf of natural gas, before price differential adjustments.

Based on the SEC prices over the twelve months ended March 1, 2022, we anticipate the SEC prices utilized in the March 31, 2022 full cost ceiling test may be $75.24 per barrel of oil and $4.09 per Mcf 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, 2021 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2022.

However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2022 and in subsequent quarters based on the outcome of numerous other factors such as additional 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 2022 could be material to our net earnings.

Full cost pool impairments have no impact to our cash flow or liquidity.

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Other Operating Expenses

Other operating expenses for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):

General and administrative expenses decreased $5.7 million, or 36.9%, for the year ended December 31, 2021 compared to 2020. These decreases resulted primarily from a reduction in compensation related costs after completing reductions in force during 2020, significant reductions in information technology and software costs and overhead expenses related to the Company's previously held corporate headquarters building. Part of the decrease is also due to reductions in professional costs such as legal expenses, audit fees and consulting services.

Restructuring expenses represent fees and costs associated with the 2016 bankruptcy and exit from NPB in Colorado. Restructuring expenses decreased by $1.9 million, or 71.0% for the year ended December 31, 2021, compared to 2020. These decreases are primarily related to previously accrued expenses for the 2016 Bankruptcy that were removed as a result of the notice of completion of final distribution being filed in the United States Bankruptcy Court for the Southern District of Texas on July 26, 2021. Further, 2020 expenses included the relocation of company headquarters and outsourcing of corporate functions. See "Note 13 - Commitments and Contingencies" in the accompanying consolidated financial statements in Item 8 of this report for additional discussion of these expenses.

Employee termination benefits for the years ended December 31, 2021 and 2020, includes cash and share-based severance costs incurred for reductions in force. The decrease from 2020 to 2021 is primarily the result of separations of employment for Company employees during 2020, that did not occur in 2021. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with the separations in 2020, with no recurrence of such costs in 2021. See "Note 13 - Employee Termination Benefits" in the accompanying consolidated financial statements in Item 8 of this report for additional discussion of these expenses.

Loss on derivative contracts of $2.3 million and a gain of $5.8 million for the years ended December 31, 2021 and 2020, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments upon settlement of $2.2 million, and net cash received upon settlement of $5.9 million, respectively.

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.

(Gain) loss on sale of assets increased by $18.9 million for the year ended December 31, 2021 compared to 2020. The increase is due to the gain on sale for the sale of NPB assets in Colorado in February 2021.

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Other Income (Expense)

Other income (expense) for the years ended December 31, 2021 and 2020 is reflected in the table below (in thousands):

Interest expense for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):