SANDRIDGE ENERGY INC (SD) FY 2022 MD&A

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.

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(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.

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(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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