SANDRIDGE ENERGY INC (SD) FY 2021 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 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):

Interest expense incurred during the year ended December 31, 2021 is primarily comprised of interest 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. Interest expense incurred during the year ended December 31, 2020 is primarily comprised of interest and fees paid on the 2017 Credit Facility that was terminated on November 30, 2020.

See “Note 11—Long-Term Debt” to the accompanying consolidated financial statements in Item 8 of this report for additional discussion of our long-term debt transactions.

The Other (expense) income, net line item for the year ended December 31, 2021 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 October 2021. For the year ended December 31, 2020, this line item includes an allowance for doubtful accounts of $2.5 million that was recorded as a result of conducting an assessment of governmental and other regulatory receivable balances, which we had previously deemed as potentially uncollectible.

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Liquidity and Capital Resources

At December 31, 2021, our cash and cash equivalents, including restricted cash, was $139.5 million. The 2020 Credit Facility was terminated, as discussed below. See "Note—11 Long-Term Debt" to the accompanying consolidated financial statements in Item 8 of this report for further discussion. For the next twelve months, we expect to have ample liquidity with cash on hand and cash from operations. As of March 9, 2022, 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 2021 included cash flow from operations and cash on hand.

Our working capital increased to $97.7 million at December 31, 2021, compared to $18.1 million at December 31, 2020, the positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2021 as a result of proceeds from the sale of NPB and cash flows from operations. In addition, accounts payable and accrued liabilities decreased due to our continuous cost reduction efforts, the sale of NPB and the timing of payments.

We intend to spend between $41 million and $50 million in our 2022 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 2017 through December 2021, the NYMEX settled price for oil fluctuated between a high of $85.64 per Bbl and a low of $(36.98) per Bbl, and the month-end NYMEX settled price for gas fluctuated between a high of $23.86 per MMBtu and a low of $1.33 per MMBtu.

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. This could result in full cost pool ceiling impairments. 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, 2021, and 2020 are presented in the following table and discussed below (in thousands):

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Cash Flows from Operating Activities

The $74.1 million increase in operating cash flows for the year ended December 31, 2021 compared to 2020, is primarily due to net income of $116.7 million which is the result of improved revenue due to increased commodity prices and improved differentials as well as the well reactivation program which reduced production declines. In addition, our cost reduction efforts resulted in decreases in lease operating expenses and general and administrative expenses. The increase in net income was partially offset by the addback of the gain on sale of assets primarily related to NPB and a reduction of accrued liabilities over and above an increase in our receivable and other working capital balances.

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

During the year ended December 31, 2020, cash flows provided by investing activities primarily reflects $35.4 million of net cash proceeds from the sale of the corporate office building, offset by cash payments made for capital expenditures coupled with the acquisition of $3.3 million primarily related to the purchase of overriding royalty interests.

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, 2021 and 2020, are summarized below (in thousands):

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(1)Excludes $3.9 million for the year ended December 31, 2020, related to non-monetary transactions.

Capital expenditures, excluding acquisitions, for development and production activities increased for the year ended December 31, 2021 compared to 2020, which is in line with the planned increase in costs as result of our well reactivation program.

Cash Flows from Financing Activities

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 paid for tax obligations on vested stock awards of $0.9 million.

Our financing activities used $39.0 million in cash for the year ended December 31, 2020, consisting primarily of repayments of borrowings under the 2017 Credit Facility of $96.5 million, finance lease payments of $1.2 million and cash paid for tax obligations on vested stock awards of $0.1 million partially offset by proceeds from borrowings of $59.0 million.

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Indebtedness

Credit Facility

On November 30, 2020, the Company entered into the $30 million 2020 Credit Facility with the lenders party thereto and Icahn Agency Services LLC, as administrative agent (the “New Administrative Agent”). The 2020 Credit Facility consisted of a $10 million revolving loan facility and a $20 million term loan facility. During the third quarter of 2021, the 2020 Credit Facility was terminated, as discussed below.

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, between us, as Borrower, IEP Energy Holding LLC, as Lender, and Icahn Agency Services LLC, as Administrative Agent. Our payment to the Lender under the Credit Agreement satisfied all of our term debt and revolving debt obligations. We did not incur any early termination penalties as a result of the repayment of indebtedness or termination of the Credit Agreement. See “Note 11—Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt during 2021 and 2020.

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 2021.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2021, our contractual obligations included asset retirement obligations, short and long-term leases and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the surety bonds or other instruments.

As of December 31, 2021, we had future contractual payment commitments under various agreements, which are summarized below. The operating 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, 2021. 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, 2021, plugging and abandonment costs incurred were $2.1 million.

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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. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be fully realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through December 31, 2021.

We continue to closely monitor all available evidence in considering whether to maintain a valuation allowance on our net deferred tax asset. Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, our historical earnings and the prospects of future earnings. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

In determining whether to maintain the valuation allowance at December 31, 2021, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ending December 31, 2021, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ending December 31, 2021.

See “Note 14—Income Taxes” to the accompanying consolidated financial statements for additional discussion of income tax related matters.

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Critical Accounting Policies and 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.  Over 96.0% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2021. 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, 2021 and 2020, the Company revised its proved reserves from prior years’ reports by approximately 43.3 MMBoe and (44.8) MMBoe, respectively, due to increases (or decreases) 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.

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 and electrical infrastructure costs, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, 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 recorded full cost ceiling did not record any impairment for the year ended December 31, 2021 and $218.4 million for the year ended December 31, 2020. See “—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.

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.

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

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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. As of December 31, 2021, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

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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