BATTALION OIL CORP 10-K

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Derivative Instruments and Hedging Activity We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil and natural gas prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we have designed a risk management policy which provides for the use of derivative instruments to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the affect it could have on our operations. The types of derivative instruments that we typically utilize include fixed-price swaps, costless collars, basis swaps and WTI NYMEX rolls. The total volumes that we hedge through the use of our derivative instruments varies from period to period, however, our requirement under our Term Loan Agreement, is to hedge approximately 50% to 85% of our anticipated oil and natural gas production, in varying percentages by year, on a rolling basis for the next four years, when derivative contracts are available at terms and prices acceptable to us. Our hedge policies and objectives may change significantly as our operational profile and contractual obligations change but remain consistent with the requirements in effect under our Term Loan Agreement. We do not enter into derivative contracts for speculative trading purposes. We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. As of December 31, 2021, we did not post collateral under any of our derivative contracts as they are secured under our Term Loan Agreement. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging , (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Item 8. Consolidated Financial Statements and Supplementary Data —Note 8, “Derivative and Hedging Activities,” for more details. Fair Market Value of Financial Instruments The estimated fair values for financial instruments under ASC 825, Financial Instruments , (ASC 825) are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. See Item 8. Consolidated Financial Statements and Supplementary Data —Note 7, “ Fair Value Measurements,” for additional information. Interest Rate Sensitivity We are also exposed to market risk related to adverse changes in interest rates. Our interest rate risk exposure results primarily from fluctuations in short-term rates, which are LIBOR based and may result in reductions of earnings or cash flows due to increases in the interest rates we pay on these obligations. At December 31, 2021, the principal amount of our debt was $200.1 million, of which less than 0.1% bears interest at a weighted average fixed interest rate of 1.0% per year. The remaining 99.9% of our total debt at December 31, 2021 bears interest at floating and variable interest rates that are tied to LIBOR. Fluctuations in market interest rates will cause our annual interest costs to fluctuate. At December 31, 2021, the weighted average interest rate on our variable rate debt was 7.22% per year. If the balance of our variable interest rate at December 31, 2021 were to remain constant, a 10% change in market interest rates would impact our cash flows by approximately $1.4 million per year. 54 Table of Contents ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS ​ ​ ​ ​ Page Management’s report on internal control over financial reporting ​ 56 Report of independent registered public accounting firm (PCAOB ID No. 34 ) ​ 57 Consolidated statements of operations ​ 60 Consolidated balance sheets ​ 61 Consolidated statements of stockholders’ equity ​ 62 Consolidated statements of cash flows ​ 63 Notes to the consolidated financial statements ​ 64 Supplemental oil and gas information (unaudited) ​ 93 ​ ​ ​ ​ ​ 55 Table of Contents MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Battalion Oil Corporation (the Company), including the Company’s Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonable assurance to the Company’s Management and Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this evaluation, Management concluded that Battalion Oil Corporation’s internal control over financial reporting was effective as of December 31, 2021. This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm regarding the effectiveness of the Company’s internal control over financial reporting. Management’s report was not subject to attestation by its independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit smaller reporting companies to provide only Management’s report in this Annual Report on Form 10-K. ​ /s/ RICHARD H. LITTLE /s/ R. KEVIN ANDREWS Richard H. Little ​ R. Kevin Andrews Chief Executive Officer ​ Executive Vice President, ​ ​ Chief Financial Officer and Treasurer Houston, Texas ​ ​ March 7, 2022 ​ ​ ​ ​ 56 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and the Board of Directors of Battalion Oil Corporation Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Battalion Oil Corporation and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows, for the years ended December 31, 2021 and 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years ended December 31, 2021 and 2020, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgements. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which they relate. ​ 57 Table of Contents Proved Oil and Natural Gas Property and Depletion — Oil and Natural Gas Reserve Quantities — Refer to Note 1 and 5 to the financial statements Critical Audit Matter Description The Company uses the full cost method of accounting for its investment in oil and natural gas properties. The Company’s proved oil and natural gas properties are depleted using the units of production method and are evaluated for impairment by the full cost ceiling impairment test utilizing the Company’s oil and natural gas reserves in accordance with accounting principles generally accepted in the United States and SEC guidelines. The development of the Company’s oil and natural gas reserve quantities and the related net present value of future cash flows from the related proved reserves requires management to make significant estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within a five-year development period, as prescribed by SEC guidelines, and the future development costs associated with these reserves. The Company engages an independent reservoir engineering firm, management’s specialist, to estimate oil and natural gas quantities using these estimates and assumptions and engineering data. Changes in these assumptions or engineering data could have a significant impact on the amount of depletion and impairment recorded for the Company’s proved oil and natural gas properties. The gross proved oil and natural gas properties balance was $569.9 million with an accumulated depletion balance of $339.8 million as of December 31, 2021. Depletion expense was $44.6 million for the year ended December 31, 2021. Given the significant judgments made by management and management’s specialist, performing audit procedures to evaluate the Company’s oil and natural gas reserve quantities and the related net cash flows, including management’s estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within the five-year development period and future development costs, requires a high degree of auditor judgment and an increased extent of effort. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures of management’s significant judgments and assumptions related to oil and natural gas reserves quantities and estimates of the future net cash flows included the following, among others: ● We evaluated the reasonableness of management’s five-year development plan by comparing the forecasts to: - Historical conversions of proved undeveloped oil and natural gas reserves into proved developed oil and natural gas reserves. - Internal communications to management and the Board of Directors. - Forecasted information included in Company press releases as well as in analyst and industry reports for the Company and certain of its peer companies. - The financial capability of the Company to execute its drilling program. ● We evaluated the reasonableness of management’s estimate of future development costs by comparing the estimate to: - Historical development of similar wells, including location of the well. - Future development costs to internal data. - Internal communications to management and the Board of Directors. - Approval for expenditures. ​ 58 Table of Contents ● We evaluated the reasonableness of management’s estimated reserve quantities by performing the following: - Evaluating the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm. - Performing analytical procedures on the reserve quantities developed by management’s specialist. ​ ​ ​ ​ /s/ DELOITTE & TOUCHE LLP ​ ​ ​ Houston, Texas ​ March 7, 2022 ​ ​ ​ We have served as the Company’s auditor since 2012. ​ ​ ​ 59 Table of Contents BATTALION OIL CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts) ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 Operating revenues: ​ ​ ​ ​ ​ ​ Oil, natural gas and natural gas liquids sales: ​ ​ ​ ​ ​ ​ Oil ​ $ 213,512 ​ $ 125,985 Natural gas ​ ​ 35,248 ​ ​ 5,818 Natural gas liquids ​ ​ 35,394 ​ ​ 14,972 Total oil, natural gas and natural gas liquids sales ​ ​ 284,154 ​ ​ 146,775 Other ​ ​ 1,051 ​ ​ 1,514 Total operating revenues ​ ​ 285,205 ​ ​ 148,289 ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ Production: ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 43,977 ​ ​ 42,106 Workover and other ​ ​ 3,224 ​ ​ 3,709 Taxes other than income ​ ​ 12,312 ​ ​ 10,056 Gathering and other ​ ​ 60,396 ​ ​ 56,016 Restructuring ​ ​ — ​ ​ 2,580 General and administrative ​ ​ 16,514 ​ ​ 18,456 Depletion, depreciation and accretion ​ ​ 45,408 ​ ​ 62,053 Full cost ceiling impairment ​ ​ — ​ ​ 215,145 Total operating expenses ​ ​ 181,831 ​ ​ 410,121 Income (loss) from operations ​ ​ 103,374 ​ ​ ( 261,832 ) ​ ​ ​ ​ ​ ​ ​ Other income (expenses): ​ ​ ​ ​ ​ ​ Net gain (loss) on derivative contracts ​ ​ ( 125,619 ) ​ ​ 38,759 Interest expense and other ​ ​ ( 8,018 ) ​ ​ ( 6,634 ) Gain (loss) on extinguishment of debt ​ ​ 1,946 ​ ​ — Total other income (expenses) ​ ​ ( 131,691 ) ​ ​ 32,125 Income (loss) before income taxes ​ ​ ( 28,317 ) ​ ​ ( 229,707 ) Income tax benefit (provision) ​ ​ — ​ ​ — Net income (loss) ​ $ ( 28,317 ) ​ $ ( 229,707 ) ​ ​ ​ ​ ​ ​ ​ Net income (loss) per share of common stock: ​ ​ ​ ​ ​ ​ Basic ​ $ ( 1.74 ) ​ $ ( 14.18 ) Diluted ​ $ ( 1.74 ) ​ $ ( 14.18 ) Weighted average common shares outstanding: ​ ​ ​ ​ ​ ​ Basic ​ ​ 16,261 ​ ​ 16,204 Diluted ​ ​ 16,261 ​ ​ 16,204 ​ The accompanying notes are an integral part of these consolidated financial statements. ​ 60 Table of Contents BATTALION OIL CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands, except share and per share amounts) ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 December 31, 2020 Current assets: ​ ​ ​ ​ ​ ​ Cash and cash equivalents ​ $ 46,864 ​ $ 4,295 Accounts receivable, net ​ ​ 36,806 ​ ​ 32,242 Assets from derivative contracts ​ ​ 1,383 ​ ​ 8,559 Restricted cash ​ ​ 1,495 ​ ​ — Prepaids and other ​ ​ 1,366 ​ ​ 2,740 Total current assets ​ ​ 87,914 ​ ​ 47,836 Oil and natural gas properties (full cost method): ​ ​ ​ ​ ​ ​ Evaluated ​ ​ 569,886 ​ ​ 509,274 Unevaluated ​ ​ 64,305 ​ ​ 75,494 Gross oil and natural gas properties ​ ​ 634,191 ​ ​ 584,768 Less - accumulated depletion ​ ​ ( 339,776 ) ​ ​ ( 295,163 ) Net oil and natural gas properties ​ ​ 294,415 ​ ​ 289,605 Other operating property and equipment: ​ ​ ​ ​ ​ ​ Other operating property and equipment ​ ​ 3,467 ​ ​ 3,535 Less - accumulated depreciation ​ ​ ( 1,035 ) ​ ​ ( 1,149 ) Net other operating property and equipment ​ ​ 2,432 ​ ​ 2,386 Other noncurrent assets: ​ ​ ​ ​ ​ ​ Assets from derivative contracts ​ ​ 2,515 ​ ​ 4,009 Operating lease right of use assets ​ ​ 721 ​ ​ 310 Funds in escrow and other ​ ​ 2,270 ​ ​ 2,351 Total assets ​ $ 390,267 ​ $ 346,497 ​ ​ ​ ​ ​ ​ ​ Current liabilities: ​ ​ ​ ​ ​ ​ Accounts payable and accrued liabilities ​ $ 62,826 ​ $ 58,928 Liabilities from derivative contracts ​ ​ 58,322 ​ ​ 22,125 Current portion of long-term debt ​ ​ 85 ​ ​ 1,720 Operating lease liabilities ​ ​ 369 ​ ​ 403 Total current liabilities ​ ​ 121,602 ​ ​ 83,176 Long-term debt, net ​ ​ 181,565 ​ ​ 158,489 Other noncurrent liabilities: ​ ​ ​ ​ ​ ​ Liabilities from derivative contracts ​ ​ 7,144 ​ ​ 4,291 Asset retirement obligations ​ ​ 11,896 ​ ​ 10,583 Operating lease liabilities ​ ​ 352 ​ ​ — Other ​ ​ 4,003 ​ ​ — Commitments and contingencies (Note 10) ​ ​ ​ ​ ​ ​ Stockholders' equity: ​ ​ ​ ​ ​ ​ Common stock: 100,000,000 shares of $ 0.0001 par value authorized; ​ ​ ​ ​ ​ ​ 16,273,913 and 16,203,979 shares issued and outstanding as of ​ ​ ​ ​ ​ ​ December 31, 2021 and 2020 , respectively ​ ​ 2 ​ ​ 2 Additional paid-in capital ​ ​ 332,187 ​ ​ 330,123 Retained earnings (accumulated deficit) ​ ​ ( 268,484 ) ​ ​ ( 240,167 ) Total stockholders' equity ​ ​ 63,705 ​ ​ 89,958 Total liabilities and stockholders' equity ​ $ 390,267 ​ $ 346,497 ​ The accompanying notes are an integral part of these consolidated financial statements. ​ 61 Table of Contents BATTALION OIL CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Retained ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additional ​ Earnings ​ ​ ​ ​ ​ Common Stock ​ Paid-In ​ (Accumulated ​ Stockholders' ​ Shares Amount Capital Deficit) Equity Balances at December 31, 2019 ​ 16,204 ​ $ 2 ​ $ 327,108 ​ $ ( 10,460 ) ​ $ 316,650 Net income (loss) ​ — ​ ​ — ​ ​ — ​ ​ ( 229,707 ) ​ ​ ( 229,707 ) Equity issuance costs and other ​ — ​ ​ — ​ ​ ( 14 ) ​ ​ — ​ ​ ( 14 ) Stock-based compensation ​ — ​ ​ — ​ ​ 3,029 ​ ​ — ​ ​ 3,029 Balances at December 31, 2020 ​ 16,204 ​ ​ 2 ​ ​ 330,123 ​ ​ ( 240,167 ) ​ ​ 89,958 Net income (loss) ​ — ​ ​ — ​ ​ — ​ ​ ( 28,317 ) ​ ​ ( 28,317 ) Long-term incentive plan vestings ​ 96 ​ ​ — ​ ​ — ​ ​ — ​ ​ — Reduction in shares to cover ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ individuals' tax withholding ​ ( 26 ) ​ ​ — ​ ​ ( 290 ) ​ ​ — ​ ​ ( 290 ) Stock-based compensation ​ — ​ ​ — ​ ​ 2,354 ​ ​ — ​ ​ 2,354 Balances at December 31, 2021 ​ 16,274 ​ $ 2 ​ $ 332,187 ​ $ ( 268,484 ) ​ $ 63,705 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The accompanying notes are an integral part of these consolidated financial statements. ​ 62 Table of Contents BATTALION OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 Cash flows from operating activities: ​ ​ ​ ​ ​ ​ Net income (loss) ​ $ ( 28,317 ) ​ $ ( 229,707 ) Adjustments to reconcile net income (loss) to net cash provided by (used ​ ​ ​ ​ ​ ​ in) operating activities: ​ ​ ​ ​ ​ ​ Depletion, depreciation and accretion ​ ​ 45,408 ​ ​ 62,053 Full cost ceiling impairment ​ ​ — ​ ​ 215,145 Stock-based compensation, net ​ ​ 2,010 ​ ​ 2,578 Unrealized loss (gain) on derivative contracts ​ ​ 47,721 ​ ​ 6,143 Amortization of debt issuance costs ​ ​ 379 ​ ​ — Reorganization items, net ​ ​ — ​ ​ ( 6,565 ) Loss (gain) on extinguishment of debt ​ ​ ( 1,946 ) ​ ​ — Accrued settlements on derivative contracts ​ ​ 7,030 ​ ​ 170 Other expense (income) ​ ​ ( 567 ) ​ ​ 142 Change in assets and liabilities: ​ ​ ​ ​ ​ ​ Accounts receivable ​ ​ ( 4,647 ) ​ ​ 13,513 Prepaids and other ​ ​ 636 ​ ​ 4,712 Accounts payable and accrued liabilities ​ ​ 865 ​ ​ ( 17,987 ) Net cash provided by (used in) operating activities ​ ​ 68,572 ​ ​ 50,197 ​ ​ ​ ​ ​ ​ ​ Cash flows from investing activities: ​ ​ ​ ​ ​ ​ Oil and natural gas capital expenditures ​ ​ ( 52,557 ) ​ ​ ( 101,788 ) Proceeds received from sales of oil and natural gas assets ​ ​ 947 ​ ​ 29,029 Acquisition of oil and natural gas properties ​ ​ — ​ ​ ( 23 ) Other operating property and equipment capital expenditures ​ ​ ( 371 ) ​ ​ ( 82 ) Funds held in escrow and other ​ ​ 68 ​ ​ 510 Net cash provided by (used in) investing activities ​ ​ ( 51,913 ) ​ ​ ( 72,354 ) ​ ​ ​ ​ ​ ​ ​ Cash flows from financing activities: ​ ​ ​ ​ ​ ​ Proceeds from borrowings ​ ​ 374,000 ​ ​ 148,209 Repayments of borrowings ​ ​ ( 332,085 ) ​ ​ ( 132,000 ) Debt issuance costs ​ ​ ( 14,220 ) ​ ​ — Equity issuance costs and other ​ ​ ( 290 ) ​ ​ ( 32 ) Net cash provided by (used in) financing activities ​ ​ 27,405 ​ ​ 16,177 ​ ​ ​ ​ ​ ​ ​ Net increase (decrease) in cash, cash equivalents and restricted cash ​ ​ 44,064 ​ ​ ( 5,980 ) ​ ​ ​ ​ ​ ​ ​ Cash, cash equivalents and restricted cash at beginning of period ​ ​ 4,295 ​ ​ 10,275 Cash, cash equivalents and restricted cash at end of period ​ $ 48,359 ​ $ 4,295 ​ ​ ​ ​ ​ ​ ​ Supplemental cash flow information: ​ ​ ​ ​ ​ ​ Cash paid (received) for interest ​ $ 8,485 ​ $ 7,577 Cash paid (refunded) for income taxes ​ ​ — ​ ​ ( 1,250 ) Cash paid for reorganization items ​ ​ — ​ ​ 6,565 ​ ​ ​ ​ ​ ​ ​ Disclosure of non-cash investing and financing activities: ​ ​ ​ ​ ​ ​ Asset retirement obligations ​ $ 836 ​ $ ( 592 ) Accrued equity issuance costs ​ ​ — ​ ​ ( 19 ) Accrued debt issuance costs ​ ​ 379 ​ ​ — ​ The accompanying notes are an integral part of these consolidated financial statements. ​ ​ 63 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES Basis of Presentation and Principles of Consolidation Battalion Oil Corporation (Battalion or the Company) is the successor reporting company to Halcón Resources Corporation (Halcón). On January 21, 2020, Battalion filed a Certificate of Amendment to the Company’s Amended and Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Halcón Resources Corporation to Battalion Oil Corporation. Battalion is an independent energy company focused on the acquisition, production, exploration and development of onshore liquids-rich oil and natural gas assets in the United States. The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. The Company operates in one segment which focuses on oil and natural gas acquisition, production, exploration and development. Allocation of capital is made across the Company’s entire portfolio without regard to operating area. All intercompany accounts and transactions have been eliminated. The Company has evaluated events and transactions through the date of issuance of this report in conjunction with the preparation of these consolidated financial statements . Risk and Uncertainties The Company is continuously monitoring the current and potential impacts of the novel coronavirus (COVID-19) pandemic on its business, including how it has and may continue to impact its operations, financial results, liquidity, contractors, customers, employees and vendors, and taking appropriate actions in response, including implementing various measures to ensure the continued operation of its business in a safe and secure manner. In 2020, COVID-19 and governmental actions to contain the pandemic contributed to an economic downturn, reduced demand for oil and natural gas and, together with a price war involving the Organization of Petroleum Exporting Countries (OPEC)/Saudi Arabia and Russia, depressed oil and natural gas prices to historically low levels. Although OPEC and Russia subsequently agreed to reduce production, downward pressure on prices continued for several months, particularly given concerns over the impacts of the economic downturn on demand. As a consequence, beginning in March 2020, the Company realized lower revenue as a result of commodity price declines, resulting in the Company temporarily shutting in producing wells in May and June 2020, which further contributed to lower revenues that year. Additionally in 2020, as discussed further in Note 5, “Oil and Natural Gas Properties,” the Company incurred ceiling test impairments, which were primarily driven by a decline in the average pricing required to be used in the valuation of the Company’s reserves for ceiling test purposes. During 2021, widespread availability of COVID-19 vaccines in the United States and elsewhere combined with accommodative governmental monetary and fiscal policies and other factors, led to a rebound in demand for oil and natural gas and increases in oil and natural gas prices. Further, at present, OPEC and Russia have been coordinating production increases to maintain supply and demand balance, stabilize prices and avoid market disruptions. However, there remains the potential for such cooperation to fail and for demand for oil and natural gas to be adversely impacted by the economic effects of the ongoing COVID-19 pandemic, including as a consequence of the circulation of more infectious “variants” of the disease, vaccine hesitancy, waning vaccine effectiveness or other factors. As a consequence, the Company is unable to predict whether oil and natural gas prices will remain at current levels or will be adversely impacted by the same sorts of factors that negatively impacted prices during 2020. Furthermore, the health of the Company’s employees, contractors and vendors, and its ability to meet staffing needs in its operations and critical functions remain concerns and cannot be predicted, nor can the impact on the Company’s customers, vendors and contractors. Any material effect on these parties could adversely impact the Company. These and other factors could affect the Company’s operations, earnings and cash flows and could cause its results to not be comparable to those of the same period in previous years. The results presented in this Form 10-K are not necessarily indicative of future operating results. For further information regarding the actual and potential impacts of COVID-19 on the Company, see “Risk Factors” in Item 1A of this Annual Report on Form 10-K. 64 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Use of Estimates The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Estimates and assumptions that, in the opinion of management of the Company, are significant include oil and natural gas revenue accruals, capital and operating expense accruals, oil and natural gas reserves, depletion relating to oil and natural gas properties, asset retirement obligations, and fair value estimates. The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements. Cash, Cash Equivalents and Restricted Cash The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. Amounts in the consolidated balance sheets included in “ Cash and cash equivalents ” and “ Restricted cash ” reconcile to the Company’s consolidated statements of cash flows as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 December 31, 2020 ​ ​ ​ ​ ​ ​ ​ Cash and cash equivalents ​ $ 46,864 ​ $ 4,295 Restricted cash ​ ​ 1,495 ​ ​ — Total cash, cash equivalents and restricted cash ​ $ 48,359 ​ $ 4,295 ​ Restricted cash consists primarily of funds to collateralize letters of credit outstanding. Accounts Receivable and Allowance for Doubtful Accounts The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. As of December 31, 2021 and 2020 allowances for doubtful accounts were approximately $ 0.2 million for both periods. Oil and Natural Gas Properties The Company uses the full cost method of accounting for its investment in oil and natural gas properties as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration and development of proved and unproved oil and natural gas properties, including the costs of abandoned properties, treating equipment and gathering support facilities, dry holes, geophysical costs, and annual lease rentals are capitalized. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on estimated proved reserves. The net capitalized costs of evaluated oil and natural gas properties are subject to a full cost ceiling 65 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company reviews its unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Investments in unevaluated oil and natural gas properties and exploration and development projects for which depletion expense is not currently recognized, and for which exploration or development activities are in progress, qualify for interest capitalization. The Company determines capitalized interest, when applicable, by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred that were excluded from the full cost pool; however, the amount of capitalized interest cannot exceed the amount of gross interest expense incurred in any given period. The Company’s accounting policy on the capitalization of interest establishes thresholds for the determination of a development project for the purpose of interest capitalization. Other Operating Property and Equipment Other operating property and equipment are recorded at cost. Depreciation is calculated using the straight-line method over the following estimated useful lives: buildings, twenty years ; automobiles and computers , three years ; computer software, fixtures, furniture and equipment , five years ; trailers, seven years ; heavy equipment, eight to ten years and leasehold improvements, lease term. Land and artwork are not depreciated. Upon disposition, the cost and accumulated depreciation are removed and any gains or losses are reflected in current operations. Maintenance and repair costs are charged to operating expense as incurred. Material expenditures which increase the life or productive capacity of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The Company reviews its other operating property and equipment for impairment in accordance with ASC 360, Property, Plant, and Equipment (ASC 360). ASC 360 requires the Company to evaluate other operating property and equipment for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. Further, the Company evaluates the remaining useful lives of its other operating property and equipment at each reporting period to determine whether events and circumstances warrant a revision to the remaining depreciation periods. Concentrations of Credit Risk The Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable and of nonperformance by counterparties under the Company’s derivative contracts. Each reporting period, the Company assesses the recoverability of material receivables using historical data, current market conditions and reasonable and supportable forecasts of future economic conditions to determine expected collectability of its material receivables. The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. The purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. Historically, the Company has not experienced any significant losses from uncollectible accounts from its oil and natural gas purchasers. In 2021, three individual purchasers of the Company’s production, Western Refining, Inc., Sunoco Inc. and Salt Creek Midstream, LLC, each accounted for more than 10 % of total sales, collectively representing 73 % of its total sales for the year. In 2020, two individual purchasers of the Company’s production, Western Refining Inc. and Sunoco Inc., each accounted for more than 10 % of total sales, collectively representing 57 % of its total sales for the year. 66 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. Joint operating agreements govern the operations of an oil or natural gas well and, in most instances, provide for offsetting of amounts payable or receivable between the Company and its joint interest owners. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company could be adversely affected. The Company’s exposure to credit risk under its derivative contracts is varied among major financial institutions with investment grade credit ratings, where it has master netting agreements which provide for offsetting of amounts payable or receivable between the Company and the counterparty. To manage counterparty risk associated with derivative contracts, the Company selects and monitors counterparties based on an assessment of their financial strength and/or credit ratings. At December 31, 2021, the Company’s derivative counterparties include two major financial institutions, both of which are secured lenders under the Term Loan Agreement. Employee Retention Credit ​ The Coronavirus Aid, Relief and Economic Security Act (the CARES Act) was enacted on March 27, 2020 and included, among other things, provisions relating to refundable payroll tax credits (the Employee Retention Credit or ERC). As provided for in the CARES Act and subsequent legislation which modified and extended the provisions included therein, the ERC allows for a refundable tax credit against certain employment taxes equal to 50% of the first $10,000 in qualified wages paid to each employee after March 12, 2020 and through December 31, 2020 and 70% of the first $10,000 in qualified wages paid to each employee, per calendar quarter, after December 31, 2020 through September 30, 2021. During the year ended December 31, 2021, the Company determined that the qualifications for the Employee Retention Credit were met and filed the corresponding applications for the applicable 2020 and 2021 periods. The Company recognized an approximate $ 0.7 million Employee Retention Credit during the year ended December 31, 2021, with approximately $ 0.5 million recorded to “General and administrative” and approximately $ 0.2 million recorded to “Lease operating” in the consolidated statements of operations. Risk Management Activities The Company follows ASC 815, Derivatives and Hedging (ASC 815). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil and natural gas production. The Company recognized all derivative instruments as either assets or liabilities in the consolidated balance sheets at fair value. The Company has elected to not designate any of its positions for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations. Income Taxes The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as noncurrent on the consolidated balance sheets. 67 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS The Company follows ASC 740, Income Taxes (ASC 740). ASC 740 creates a single model to address accounting for the uncertainty in income tax positions and prescribes a minimum recognition threshold a tax position must meet before recognition in the consolidated financial statements. The evaluation of a tax position in accordance with ASC 740 is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. The Company has no liability for unrecognized tax benefits as of December 31, 2021 and 2020. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2021 and 2020. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. The Company includes interest and penalties relating to uncertain tax positions within “Interest expense and other” on the Company’s consolidated statements of operations. Refer to Note 12, “Income Taxes,” for more details. Generally, the Company’s income tax years 2018 through 2021 remain open for federal purposes and are subject to examination by federal tax authorities. The Company’s income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes. Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. Asset Retirement Obligations ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records asset retirement obligations to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and natural gas wells, treating equipment and gathering support facilities. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, treating equipment and gathering support facilities as these obligations are incurred. 68 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 401(k) Plan The Company sponsors a 401(k) tax deferred savings plan, whereby the Company matches a portion of employees’ contributions in cash. Participation in the plan is voluntary and all employees of the Company who are 18 years of age are eligible to participate. The Company provided matching contributions of $ 0.8 million for each of the years ended December 31, 2021 and 2020. The Company matches employee contributions dollar-for-dollar on the first 10 % of an employee’s pre-tax earnings, subject to individual IRS limitations. Restructuring During 2020, the Company incurred approximately $ 2.6 million in restructuring charges related to the consolidation into one corporate office and reductions in its workforce due to efforts to improve efficiencies and reduce future costs. In May 2020, in furtherance of the consolidation into one corporate office, the Company exercised a one-time early termination option under the lease agreement for the Company’s office space in Denver, Colorado. These costs were recorded in “Restructuring” on the consolidated statements of operations. Refer to Note 2, “Leases , ” for further details. Change in Estimate In late March 2020, due to changes in market conditions and decreased commodity prices, the Company determined that previously accrued discretionary cash incentives related to 2019 would not be paid, causing a $ 1.6 million reduction to “General and administrative” on the condensed consolidated statement of operations for the year ended December 31, 2020. Recently Issued Accounting Pronouncements In March 2020, the FASB issued Accounting Standards Update (ASU) No. 2020-04, Reference Rate Reform (Topic 848) (ASU 2020-04), in response to the risk of cessation of the London Interbank Offered Rate (LIBOR). This amendment provides optional expedients and exceptions for applying generally accepted accounting principles to contracts, hedging arrangements, and other transactions that reference LIBOR. ASU 2020-04 will be in effect through December 31, 2022. The Company is currently evaluating ASU 2020-04 and the impact it may have on its operating results, financial position and disclosures. ​ In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of their simplification initiative. ASU 2019-12 simplifies the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. ASU 2019-12 is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. The Company adopted ASU 2019-12 effective January 1, 2021. The adoption of ASU 2019-12 did not have a material impact on the Company’s operating results, financial position or disclosures . ​ ​ 2. LEASES The Company determines if an arrangement is a lease at contract inception. A lease exists when a contract conveys to the customer the right to control the use of an identified asset for a period of time in exchange for consideration. The definition of a lease embodies two conditions: (1) there is an identified asset in the contract that is land or a depreciable asset, and (2) the customer has the right to control the use of the identified asset. The Company leases equipment and office space pursuant to net operating leases. Operating leases where the Company is the lessee are included in “Operating lease right of use assets” and “Operating lease liabilities” on the consolidated balance sheets. The lease liabilities are initially and subsequently measured at the present value of the 69 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS unpaid lease payments at the lease commencement date. The Company has no leases that meet the criteria for classification as a finance lease. Key estimates and judgments include how the Company determined (1) the discount rate used to discount the unpaid lease payments to present value, (2) lease term and (3) lease payments. ASC 842, Leases (ASC 842) requires a lessee to discount its unpaid lease payments using the interest rate implicit in the lease or, if that rate cannot be readily determined, its incremental borrowing rate. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date to determine the present value of lease payments. The incremental borrowing rate for a lease is the rate of interest the Company would have to pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. Additionally, the Company applies a portfolio approach to determine the discount rate (the incremental borrowing rate for leases with similar characteristics). The Company uses the implicit rate when readily determinable. The lease term includes the noncancellable period of the lease plus any additional periods covered by either a lessee option to extend (or not to terminate) the lease that the lessee is reasonably certain to exercise, or an option to extend (or not to terminate) the lease controlled by the lessor. Lease payments included in the measurement of the lease asset or liability comprise the following, when applicable: fixed payments (including in-substance fixed payments), variable payments that depend on an index or rate, and the exercise price of a lessee option to purchase the underlying asset if the lessee is reasonably certain to exercise. The right of use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For the Company’s operating leases, the right of use asset is subsequently measured throughout the lease term at the carrying amount of the lease liability, plus initial direct costs, plus (minus) any prepaid (accrued) lease payments, less the unamortized balance of lease incentives received. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Variable lease payments associated with the Company’s leases are recognized when the event, activity, or circumstance in the lease agreement on which those payments are assessed occurs. Variable lease payments, when applicable, are presented as “Gathering and other,” “Restructuring” or “General and administrative” in the consolidated statements of operations in the same line item as the expense arising from the fixed lease payments on the operating leases. The Company has lease agreements which include lease and nonlease components and the Company has elected to combine lease and nonlease components, when fixed, for all lease contracts. Nonlease components include common area maintenance charges on office leases and, when applicable, services associated with equipment leases. The Company determines whether the lease or nonlease component is the predominant component on a case-by-case basis. The Company reviews its right of use assets for impairment in accordance with ASC 360. ASC 360 requires the Company to evaluate right of use assets for impairment as events occur or circumstances change that would more likely than not reduce the fair value below the carrying amount. If the carrying amount is not recoverable from its undiscounted cash flows, then the Company would recognize an impairment loss for the difference between the carrying amount and the current fair value. The Company monitors for events or changes in circumstances that would require a reassessment of a lease. When a reassessment results in the remeasurement of a lease liability, an adjustment is made to the carrying amount of the corresponding right of use asset unless doing so would reduce the carrying amount of the right of use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right of use asset balance is recorded in the consolidated statements of operations. The Company elected not to recognize right of use assets and lease liabilities for all short-term leases that have a lease term of 12 months or less. The Company recognizes the lease payments associated with its short-term leases when 70 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS incurred. Variable lease payments associated with these leases are recognized and presented in the same manner as for all other leases. The “Operating lease right of use assets” outstanding on the consolidated balance sheets as of December 31, 2021 and 2020 have initial lease terms of 2.3 and 5.0 years, respectively. Payments due under the lease contracts include fixed payments plus, in some instances, variable payments. The table below summarizes the Company’s leases for the periods indicated (in thousands, except years and discount rate): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ ​ ​ 2021 2020 Lease cost ​ ​ ​ ​ ​ ​ ​ Operating lease costs ​ $ 444 ​ $ 1,986 ​ Short-term lease costs ​ ​ 3,152 ​ ​ 16,650 ​ Variable lease costs ​ ​ 375 ​ ​ 913 ​ Total lease costs ​ $ 3,971 ​ $ 19,549 ​ ​ ​ ​ ​ ​ ​ ​ ​ Other information ​ ​ ​ ​ ​ ​ ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases ​ $ 537 ​ $ 2,350 ​ Right-of-use assets obtained in exchange for new operating lease liabilities ​ ​ 841 ​ ​ — ​ Weighted-average remaining lease term - operating leases ​ ​ 1.9 years ​ 0.5 years Weighted-average discount rate - operating leases ​ ​ 4.29 % ​ 3.70 % As described in Note 1, “Summary of Significant Events and Accounting Policies , ” the Company exercised a one-time early termination option under the lease agreement for the Company’s office space in Denver, Colorado in May 2020 and paid a $ 1.3 million termination fee. The early termination option was deemed probable in May 2020 and was recognized in the Company’s operating lease right of use asset and operating lease liability during the three months ended June 30, 2020. This reduced the Company’s operating lease liability to $ 0.5 million, representing the remaining lease cost to be incurred from June 2020 through March 2021. The Company’s abandonment of its office lease in Denver resulted in a $ 0.5 million impairment to its operating lease right of use asset presented as “Restructuring” in the consolidated statement of operations for the year ended December 31, 2020. Future minimum lease payments associated with the Company’s non-cancellable operating leases for office space and equipment as of December 31, 2021, are presented in the table below (in thousands): ​ ​ ​ ​ ​ ​ December 31, 2021 2022 ​ $ 391 2023 ​ ​ 359 2024 ​ ​ — 2025 ​ ​ — 2026 ​ ​ — Thereafter ​ ​ — Total operating lease payments ​ ​ 750 Less: discount to present value ​ ​ 29 Total operating lease liabilities ​ ​ 721 Less: current operating lease liabilities ​ ​ 369 Noncurrent operating lease liabilities ​ $ 352 ​ 71 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Practical Expedients ​ The Company elected the following practical expedients for transition to, and ongoing accounting under, ASC 842: (i) the Company does not separate lease and non-lease components of a contract, (ii) the Company does not reassess whether expired or existing contracts contain leases, nor does it reassess the lease classification for expired or existing leases and does not reassess whether previously capitalized initial direct costs would qualify for capitalization under ASC 842, (iii) the Company applies a single discount rate to a portfolio of leases with reasonably similar characteristics and (iv) the Company does not assess whether existing or expired land easements that were previously accounted for as leases are or contain a lease under ASC 842. ​ ​ 3. OPERATING REVENUES Revenue Recognition Revenue is measured based on consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction that are collected by the Company from a customer are excluded from revenue. Revenues from the sale of crude oil, natural gas and natural gas liquids are recognized, at a point in time, when a performance obligation is satisfied by the transfer of control of the commodity to the customer. Because the Company’s performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with customers of $ 35.1 million and $ 24.5 million as of December 31, 2021 and 2020, respectively, as “Accounts receivable” and “Other assets” on the consolidated balance sheets. Substantially all of the Company’s revenues are derived from single basin operations, the Delaware Basin in Pecos, Reeves, Ward and Winkler Counties, Texas. The following table disaggregates the Company’s revenues by major product, in order to depict how the nature, timing, and uncertainty of revenue and cash flows are affected by economic factors in the Company’s single basin operations, for the periods indicated (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 Operating revenues: ​ ​ ​ ​ ​ ​ Oil, natural gas and natural gas liquids sales: ​ ​ ​ ​ ​ ​ Oil ​ $ 213,512 ​ $ 125,985 Natural gas ​ ​ 35,248 ​ ​ 5,818 Natural gas liquids ​ ​ 35,394 ​ ​ 14,972 Total oil, natural gas and natural gas liquids sales ​ ​ 284,154 ​ ​ 146,775 Other ​ ​ 1,051 ​ ​ 1,514 Total operating revenues ​ $ 285,205 ​ $ 148,289 ​ Oil Sales The Company generally markets its crude oil production directly to the customer using two methods. Under the first method, crude oil is sold at the wellhead at an index price, averaged over the daily settlement prices for a production month, and adjusted for pricing differentials and other deductions. Revenue is recognized at the wellhead, where control of the crude oil transfers to the customer, at the net price received. Under the second method, crude oil is delivered to the customer at a contractual delivery point at which the customer takes custody, title and risk of loss of the product. The Company receives a specified index price from the customer, averaged over the daily settlement prices for a production month, and net of applicable market-related adjustments. Revenue is recognized when control of the crude oil transfers at the delivery point at the net price received. 72 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Settlement statements for the Company’s crude oil production are typically received within the month following the date of production and therefore the amount of production delivered to the customer and the price that will be received for that production are known at the time the revenue is recorded. Payment under the Company’s crude oil contracts is typically due on or before the 20 th day of the month following the delivery month. Natural Gas and Natural Gas Liquids Sales The Company evaluates its natural gas gathering and processing arrangements in place with midstream companies to determine when control of the natural gas is transferred. Under contracts where it is determined that control of the natural gas transfers at the wellhead, any fees incurred to gather or process the unprocessed natural gas are treated as a reduction of the sales price of unprocessed natural gas, and therefore revenues from such transactions are presented on a net basis. Under contracts where it is determined that control of the natural gas transfers at the tailgate of the midstream entity’s processing plant, revenues are presented on a gross basis for amounts expected to be received from the midstream company or third party purchasers through the gathering and treating process and presented as “Natural gas” or “Natural gas liquids” and any fees incurred to gather or process the natural gas are presented separately as “Gathering and other” on the consolidated statements of operations. Under certain contracts, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant. The Company then sells the products to a customer at contractual delivery points at prices based on an index. In these instances, revenues are presented on a gross basis and any fees incurred to gather, process or transport the commodities are presented separately as “Gathering and other” on the consolidated statements of operations. Settlement statements for the Company’s natural gas and natural gas liquids production are typically received 30 days after the date of production and therefore the Company estimates the amount of production delivered to the customer and the price that will be received for that production. The majority of the Company’s natural gas and natural gas liquids prices are based on daily average pricing for the month. Historically, differences between the Company’s estimates and the actual revenue received have not been material. Payment under the Company’s natural gas gathering and processing contracts is typically due on or before the fifth day of the second month following the delivery month. ​ Practical Expedients The Company does not disclose the transaction price of unsatisfied performance obligations for i) contracts with an original expected duration of one year or less and ii) contracts where variable consideration is allocated entirely to a wholly unsatisfied performance obligation (each unit of product typically represents a separate performance obligation, and therefore, future volumes under the Company’s long-term contracts are wholly unsatisfied). ​ 4. DIVESTITURES Northern West Quito Assets On December 18, 2020, the Company sold certain oil and gas properties and related assets located in Ward County, Texas (the North West Quito Assets) to Point Energy Partners Operating, LLC for a total adjusted sales price of $ 25.9 million in cash. The effective date of the transaction was October 1, 2020. Proceeds from the sale were recorded as a reduction to the carrying value of the Company’s full cost pool with no gain or loss recorded. The Company used the net proceeds from the sale to repay amounts then outstanding under the Company’s Senior Credit Agreement and for general corporate purposes. ​ 73 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 5. OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties as of December 31, 2021 and 2020 consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ December 31, 2020 ​ ​ ​ ​ ​ ​ ​ Subject to depletion ​ $ 569,886 ​ $ 509,274 Not subject to depletion: ​ ​ ​ ​ ​ ​ Exploration and extension wells in progress ​ ​ — ​ ​ — Other capital costs: ​ ​ ​ ​ ​ Incurred in 2021 ​ ​ 1,427 ​ ​ — Incurred in 2020 ​ ​ 983 ​ ​ 983 Incurred in 2019 (1) ​ ​ 61,895 ​ ​ 74,511 Incurred in 2018 and prior ​ ​ — ​ ​ — Total not subject to depletion ​ ​ 64,305 ​ ​ 75,494 Gross oil and natural gas properties ​ ​ 634,191 ​ ​ 584,768 Less accumulated depletion ​ ​ ( 339,776 ) ​ ​ ( 295,163 ) Net oil and natural gas properties ​ $ 294,415 ​ $ 289,605 (1) In 2019, with the adoption of fresh-start accounting, the Company’s unevaluated properties were recorded at fair value. The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves (including such costs as leasehold acquisition costs, geological expenditures, treating equipment and gathering support facilities costs, dry hole costs, tangible and intangible development costs and direct internal costs) are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs are charged to expense. Depletion for oil and natural gas properties is calculated using the unit of production method, which depletes the capitalized costs of evaluated properties plus future development costs based on the ratio of production for the current period to total reserve volumes of evaluated properties as of the beginning of the period. Depletion expense was $ 44.6 million and $ 60.5 million for the year ended December 31, 2021 and 2020, respectively. Depletion expense is recorded in “Depletion, depreciation and accretion” in the Company’s consolidated statements of operations. Additionally, the Company assesses all properties classified as unevaluated property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation. For the three months ended September 30, 2020, the Company transferred approximately $ 23.6 million of unevaluated property costs to the full cost pool. These transfers of unevaluated property to the full cost pool in 2020 were the result of the Company’s intent to focus available capital on Monument Draw. 74 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS The ceiling test value of the Company’s reserves was calculated based on the following prices: ​ ​ ​ ​ ​ ​ ​ ​ ​ West Texas Intermediate (per barrel) (1) Henry Hub (per MMBtu) (1) December 31, 2021 ​ $ 66.55 ​ $ 3.60 December 31, 2020 ​ ​ 39.54 ​ ​ 1.99 (1) Unweighted average of the first day of the 12-months ended spot price, adjusted by lease or field for quality, transportation fees, and regional price differentials. The Company's net book value of oil and natural gas properties in 2021 did not exceed the ceiling amount. The Company’s net book value of oil and natural gas properties at June 30, September 30, and December 31, 2020 exceeded the ceiling amount and the Company recorded full cost ceiling test impairments before income taxes of $ 60.1 million, $ 128.3 million, and $ 26.7 million, respectively, for those periods, or $ 215.1 million for the year ended December 31, 2020. The ceiling test impairments during 2020 were primarily driven by decreases in the first-day-of-the-month 12-month average prices for crude oil used in the ceiling test calculation. Additionally, during the three months ended September 30, 2020, the transfer of unevaluated property costs to the full cost pool, as discussed above, also contributed to the impairment recorded for the period. During the three months ended December 31, 2020, proved undeveloped reserves additions as a result of changes to the Company’s five year development plan partially offset the impact on the impairment of the average price decline for the period. Full cost ceiling test impairments are recorded in “Full cost ceiling impairment” in the Company’s consolidated statements of operations and in “Accumulated depletion” in the Company’s consolidated balance sheets. Changes in commodity prices, production rates, levels of reserves, future development costs, transfers of unevaluated properties to the full cost pool, capital spending, and other factors will determine the Company’s ceiling test calculation and impairment analyses in future periods. ​ 6. DEBT As of December 31, 2021 and 2020, the Company’s debt consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 December 31, 2020 Term loan credit facility (1) ​ $ 181,565 ​ $ — Senior revolving credit facility ​ ​ — ​ ​ 158,000 Paycheck Protection Program loan ​ ​ 85 ​ ​ 2,209 Total debt, net ​ ​ 181,650 ​ ​ 160,209 Current portion of Paycheck Protection Program loan ​ ​ 85 ​ ​ 1,720 Total long-term debt, net ​ $ 181,565 ​ $ 158,489 (1) Amount is net of $ 14.2 million unamortized debt issuance costs at December 31, 2021. Amount also excludes $ 4.2 million allocated to the change of control call option embedded derivative. Refer to “Term Loan Credit Facility” below for further details . Term Loan Credit Facility ​ On November 24, 2021, the Company and its wholly owned subsidiary, Halcón Holdings, LLC (Borrower) entered into an Amended and Restated Senior Secured Credit Agreement (Term Loan Agreement) with Macquarie Bank 75 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Limited, as administrative agent, and certain other financial institutions party thereto, as lenders. The Term Loan Agreement amends and restates in its entirety the Senior Credit Agreement as discussed below. Pursuant to the Term Loan Agreement, the lenders have agreed to loan the Company (i) $ 200.0 million, which was funded on November 24, 2021 and was partially used to refinance all amounts owed under the Senior Credit Agreement; (ii) up to $ 20.0 million, available to be drawn up to 18 months from November 24, 2021, subject to the satisfaction of certain conditions; and (iii) up to $ 15.0 million, which amount will be available to be drawn from the date certain wells included in the approved plan of development (APOD) are deemed producing APOD wells until up to 18 months after November 24, 2021, subject to the satisfaction of certain conditions. An additional $ 5.0 million is available for the issuance of letters of credit. The maturity date of the Term Loan Agreement is November 24, 2025. Until such maturity date, borrowings under the Term Loan Agreement shall bear interest at a rate per annum equal to LIBOR (or another applicable reference rate, as determined pursuant to the provisions of the Term Loan Agreement) plus an applicable margin of 7.00 %. ​ The Company may elect, at its option, to prepay any borrowing outstanding under the Term Loan Agreement subject to the following prepayment premiums: ​ ​ ​ ​ ​ Period ​ ​ Premium Months 0 - 12 ​ ​ Make-whole amount equal to 12 months of interest plus 2.00 % Months 13 - 24 ​ ​ 2.00 % Months 25 - 36 ​ ​ 1.00 % Months 37 - 48 ​ ​ 0.00 % ​ The Company may be required to make mandatory prepayments of the loans under the Term Loan Agreement in connection with the incurrence of non-permitted debt, certain asset sales, and with excess cash on hand in excess of certain maximum levels. For each fiscal quarter after January 1, 2023, the Company shall make mandatory prepayments when the Consolidated Cash Balance, as defined in the Term Loan Agreement, exceeds $ 20.0 million. Until December 31, 2024, the forecasted APOD capital expenditures for the succeeding fiscal quarter are excluded for purposes of determining the Consolidated Cash Balance. ​ The Company is required to make scheduled amortization payments in the aggregate amount of $ 120.0 million from the fiscal quarter ending March 31, 2023 through the fiscal quarter ending September 30, 2025. Amounts outstanding under the Term Loan Agreement are guaranteed by certain of the Borrower’s direct and indirect subsidiaries and secured by a security interest in substantially all of the assets of the Borrower and such direct and indirect subsidiaries, and of the equity interests of the Borrower held by the Company. As part of the Term Loan Agreement there are certain restrictions on the transfer of assets, including cash, to Battalion from the guarantor subsidiaries. ​ The Term Loan Agreement also contains certain financial covenants, including the maintenance of (i) an Asset Coverage Ratio (as defined in the Term Loan Agreement) of not less than (A) 1.50 to 1.00 as of December 31, 2021 and March 31, 2022, (B) 1.60 to 1.00 as of June 30, 2022, (C) 1.70 to 1.00 as of September 30, 2022, and (D) 1.80 to 1.00 as of December 31, 2022 and each fiscal quarter thereafter, (ii) a Total Net Leverage Ratio (as defined in the Term Loan Agreement) of not greater than (A) 3.25 to 1.00 as of December 31, 2021 through and including June 30, 2022, (B) 3.00 to 1.00 as of September 30, 2022 and December 31, 2022, (C) 2.75 to 1.00 as of March 31, 2023, and (D) 2.50 to 1.00 as of each fiscal quarter thereafter, and (iii) a Current Ratio (as defined in the Term Loan Agreement) of not less than 1.00 to 1.00 , each determined as of the last day of any fiscal quarter period. As of December 31, 2021, the Company was in compliance with the financial covenants under the Term Loan Agreement. ​ The Term Loan Agreement also contains an APOD for the Company’s Monument Draw acreage through the drilling and completion of certain wells. The Term Loan Agreement contains a proved developed producing production test and an APOD economic test which the Company must maintain compliance with otherwise, subject to any available remedies or waivers, the Company is required to immediately cease making expenditures in respect of the APOD other than any expenditures deemed necessary by the Company in respect of no more than six additional APOD wells. 76 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ​ The Term Loan Agreement also contains certain events of default, including non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy. ​ At December 31, 2021, the Company had $ 200.0 million indebtedness outstanding, approximately $ 0.3 million letters of credit outstanding and $ 35.0 million in delayed draw term loans available to be drawn under the Term Loan Agreement, subject to the satisfaction of certain conditions defined in the agreement. ​ In conjunction with the Term Loan Agreement, the Company agreed to pay a premium to the lenders upon a future change of control event in which a majority of the board of directors or the Chief Executive Officer or the Chief Financial Officer positions do not remain held by the same persons as before the change of control event (Change of Control Call Option). The premium is reduced over time through the payment of interest and certain fees. The Company determined that the Change of Control Call Option was an embedded derivative in accordance with FASB ASC 815, Derivatives and Hedging , concluded the embedded derivative was not clearly and closely related to the host debt instrument, and recorded the initial $ 4.2 million fair value separately on the consolidated balance sheet within “Other noncurrent liabilities.” The Change of Control Call Option will be subsequently remeasured at fair value each reporting period with fair value changes recorded in “Interest expense and other” on the consolidated statements of operations. Refer to Note 7, “ Fair Value Measurements ,” for a discussion of the valuation approach used, the significant inputs to the valuation, and for a reconciliation of the change in fair value of the Change of Control Call Option. ​ Senior Revolving Credit Facility ​ On October 8, 2019, the Company entered into a senior secured revolving credit agreement, as amended, (the Senior Credit Agreement) with Bank of Montreal, as administrative agent, and certain other financial institutions party thereto, as lenders, which refinanced the Company’s debtor-in-possession junior secured term credit facility and its Predecessor senior secured revolving credit facility. The Senior Credit Agreement provided for a $ 750.0 million senior secured reserve-based revolving credit facility. A portion of the Senior Credit Agreement, in the amount of $ 25.0 million, was available for the issuance of letters of credit. The maturity date of the Senior Credit Agreement was October 8, 2024. The borrowing base was redetermined semi-annually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base took into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. Amounts outstanding under the Senior Credit Agreement bore interest at specified margins over the base rate of 1.50 % to 2.50 % for ABR-based loans or at specified margins over LIBOR of 2.50 % to 3.50 % for Eurodollar-based loans. These margins fluctuated based on the Company’s utilization of the facility. The Senior Credit Agreement was amended and restated by the Term Loan Agreement. Borrowings outstanding under the Senior Credit Agreement were repaid with proceeds from the Term Loan Agreement and the resulting charge of $ 0.1 million was recorded in “Gain (loss) on extinguishment of debt” in the consolidated statement of operations for the year ended December 31, 2021. On May 10, 2021, the Company entered into the Fourth Amendment to Senior Secured Revolving Credit Agreement (the Fourth Amendment) which reduced the borrowing base to $ 185.0 million effective June 1, 2021 and further reduced the borrowing base to $ 175.0 million effective September 1, 2021. The Fourth Amendment also, among other things, (i) increased interest margins to 2.00 % to 3.00 % for ABR-based loans and 3.00 % to 4.00 % for Eurodollar-based loans, (ii) amended the covenant relating to the minimum mortgaged total value of proved borrowing base properties to increase the value from 90 % to 95 %, (iii) provided for direct reductions in the borrowing base in the event of asset dispositions in excess of $ 1.0 million per fiscal year or swap terminations and (iv) revised certain covenants and covenant-related baskets including, but not limited to, adding covenants prohibiting the designation of unrestricted subsidiaries and requiring prior consent from the lenders regarding asset dispositions or swap terminations in excess of the greater of $ 7.5 million or 3.5 % of the then effective borrowing base. 77 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS On September 24, 2021, the Company entered into the Fifth Amendment to Senior Secured Revolving Credit Agreement (the Fifth Amendment) which, among other things, modified the limits on swap agreements so as not to exceed, (i) from the period of the Fifth Amendment effective date through December 31, 2021, the percentage of the reasonably anticipated hydrocarbon production from proved developed producing reserves during such period hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date; (ii) for the fiscal year ending December 31, 2022, the greater of (a) the proved developed producing reserves during such fiscal year hedged pursuant to secured swap agreements in place as of the Fifth Amendment effective date and (b) 85 % of the proved developed producing reserves during such fiscal year; and (iii) for the fiscal years ending December 31, 2023, December 31, 2024 and December 31, 2025, swap agreements not to exceed 85 %, 70 % and 60 % of the proved developed producing reserves, respectively, during each fiscal year. Paycheck Protection Program Loan On April 16, 2020, the Company entered into a promissory note (the PPP Loan) for a principal amount of approximately $ 2.2 million from Bank of Montreal under the Paycheck Protection Program of the CARES Act, which is administered by the U.S. Small Business Administration (SBA). Pursuant to the terms of the CARES Act, the proceeds of the PPP Loan may be used for payroll costs, mortgage interest, rent or utility costs. The PPP Loan bears interest at a rate of 1.0 % per annum and has a maturity date of April 16, 2022 . As long as the Company made a timely application of forgiveness to the SBA, the Company was not required to make any payments under the PPP Loan until the forgiveness amount was communicated to the Company by the SBA. The Company applied for forgiveness of the amount due on the PPP Loan based on the use of the loan proceeds on eligible expenses in accordance with the terms of the CARES Act. Effective August 13, 2021, the principal amount of the Company’s PPP Loan was reduced to approximately $ 0.2 million by the SBA and the Company recorded a gain on the extinguishment of the forgiven portion of the PPP Loan and related accrued interest of $ 2.1 million. The gain is presented in “Gain (loss) on extinguishment of debt” in the consolidated statements of operations for the year ended December 31, 2021. The PPP Loan contains certain events of default including non-payment, breach of representations and warranties, cross-defaults to other loans with the lender or to material indebtedness, voluntary or involuntary bankruptcy, judgments and change in control. Debt Maturities Aggregate maturities required on debt at December 31, 2021 due in future years are as follows (in thousands): ​ ​ ​ ​ ​ 2022 $ 85 2023 ​ ​ 35,000 2024 ​ ​ 50,000 2025 ​ ​ 115,000 2026 ​ ​ — Thereafter ​ ​ — Total ​ $ 200,085 ​ Debt Issuance Costs The Company capitalizes certain direct costs associated with the issuance of debt and amortizes such costs over the lives of the respective debt. During the year ended December 31, 2021, the Company capitalized approximately $ 14.6 million of debt issuance costs related to the Term Loan Agreement. ​ At December 31, 2021, the Company had $ 14.2 million of unamortized debt issuance costs. ​ 78 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 7. FAIR VALUE MEASUREMENTS Pursuant to ASC 820, Fair Value Measurement (ASC 820), the Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2021 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ Level 1 Level 2 Level 3 Total Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets from derivative contracts ​ $ — ​ $ 3,898 ​ $ — ​ $ 3,898 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities from derivative contracts ​ $ — ​ $ 65,466 ​ $ — ​ $ 65,466 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2020 ​ Level 1 Level 2 Level 3 Total Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Assets from derivative contracts ​ $ — ​ $ 12,568 ​ $ — ​ $ 12,568 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities from derivative contracts ​ $ — ​ $ 26,416 ​ $ — ​ $ 26,416 ​ Derivative contracts listed above as Level 2 include fixed-price swaps, collars, puts, calls, basis swaps and WTI NYMEX rolls that are carried at fair value. The Company records the net change in the fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 8, “Derivative and Hedging Activities,” for additional discussion of derivatives. The Company’s derivative contracts are with major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance. 79 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS As discussed in Note 6, “Debt,” the Company recorded the Change of Control Call Option separately at fair value on the consolidated balance sheets in “Other noncurrent liabilities.” The valuation of the Change of Control Call Option includes significant inputs such as the timing and probability of discrete potential exit scenarios, forward LIBOR curves, and discount rates based on implied and market yields. The following table sets forth a reconciliation of the changes in fair value of the Change of Control Call Option classified as Level 3 in the fair value hierarchy (in thousands): ​ ​ ​ ​ ​ ​ ​ Change of Control ​ ​ Call Option Balance at November 24, 2021 ​ $ 4,216 Change in fair value ​ ​ ( 213 ) Balance at December 31, 2021 ​ $ 4,003 ​ The estimated fair value of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to their short- term nature. The estimated fair value of the Company’s Term Loan Agreement and Senior Credit Agreement approximates carrying value because the interest rates approximate current market rates. ​ The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial recognition of asset retirement obligations for which fair value is used. The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments; and therefore, the Company has designated these liabilities as Level 3. See Note 9, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations. ​ 8. DERIVATIVE AND HEDGING ACTIVITIES The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk and interest rate risk. In accordance with the Company’s policy and the requirements under the Term Loan Agreement, it generally hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes. It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of December 31, 2021, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Term Loan Agreement. The Company’s crude oil and natural gas derivative positions at any point in time may consist of fixed-price swaps, costless put/call collars, basis swaps and WTI NYMEX rolls. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract and a purchased put that establishes a minimum price and are generally utilized less frequently by the Company than fixed-price swaps. Basis swaps effectively lock in a price differential between regional prices (i.e. Midland) where the product is sold and the relevant pricing index under which the oil production is hedged (i.e. Cushing). WTI NYMEX roll agreements account for pricing adjustments to the trade month versus the delivery month for contract pricing. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well 80 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS as all payments and receipts on settled derivative contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations. All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820 and included in the consolidated balance sheets as assets or liabilities. The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2021 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivatives not designated ​ ​ ​ ​ ​ ​ ​ ​ as hedging contracts under ​ ​ ​ Asset derivative contracts ​ ​ ​ Liability derivative contracts ASC 815 Balance sheet location December 31, 2021 December 31, 2020 Balance sheet location December 31, 2021 December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity contracts ​ Current assets - assets from derivative contracts ​ $ 1,383 ​ $ 8,559 ​ Current liabilities - liabilities from derivative contracts ​ $ ( 58,322 ) ​ $ ( 22,125 ) Commodity contracts ​ Other noncurrent assets - assets from derivative contracts ​ ​ 2,515 ​ ​ 4,009 ​ Other noncurrent liabilities - liabilities from derivative contracts ​ ​ ( 7,144 ) ​ ​ ( 4,291 ) Total derivatives not designated as hedging contracts under ASC 815 ​ $ 3,898 ​ $ 12,568 ​ ​ ​ $ ( 65,466 ) ​ $ ( 26,416 ) ​ The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amount of gain or (loss) recognized in ​ ​ ​ ​ income on derivative contracts for the ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivatives not designated ​ Location of gain or (loss) ​ ​ ​ ​ as hedging contracts ​ recognized in income ​ Years Ended December 31, under ASC 815 on derivative contracts 2021 2020 Commodity contracts: ​ ​ ​ ​ ​ ​ ​ ​ Unrealized gain (loss) on commodity contracts ​ Other income (expenses) - net gain (loss) on derivative contracts ​ $ ( 47,721 ) ​ $ ( 6,143 ) Realized gain (loss) on commodity contracts ​ Other income (expenses) - net gain (loss) on derivative contracts ​ ​ ( 77,898 ) ​ ​ 44,902 Total net gain (loss) on derivative contracts ​ $ ( 125,619 ) ​ $ 38,759 ​ During the year ended December 31, 2020, the Company terminated certain derivative contracts in advance of their natural expiration dates and received net proceeds of approximately $ 22.9 million, which were recorded in “Net gain (loss) on derivative contracts” on the consolidated statements of operations. ​ 81 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS At December 31, 2021, the Company had the following open crude oil and natural gas derivative contracts: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Instrument ​ 2022 ​ 2023 ​ 2024 ​ 2025 ​ ​ 2026 Crude oil fixed-price swap: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total volumes (Bbls) ​ ​ 2,504,249 ​ ​ 1,937,165 ​ ​ 1,388,920 ​ ​ 988,260 ​ ​ 29,810 Weighted average price ​ $ 50.19 ​ $ 65.35 ​ $ 60.67 ​ $ 59.59 ​ $ 59.61 Crude oil basis swap: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total volumes (Bbls) ​ ​ 2,278,848 ​ ​ 1,937,165 ​ ​ 1,388,920 ​ ​ 988,260 ​ ​ 29,810 Weighted average price ​ $ 0.47 ​ $ 0.25 ​ $ 0.23 ​ $ 0.16 ​ $ 0.10 Crude oil WTI NYMEX roll: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total volumes (Bbls) ​ ​ 2,286,598 ​ ​ 1,937,165 ​ ​ 1,388,920 ​ ​ 988,260 ​ ​ 29,810 Weighted average price ​ $ 0.01 ​ $ 0.50 ​ $ 0.27 ​ $ 0.10 ​ $ - Natural gas fixed-price swap: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total volumes (MMBtu) ​ ​ 3,277,420 ​ ​ 3,622,200 ​ ​ 2,428,150 ​ ​ 2,250,650 ​ ​ ​ Weighted average price ​ $ 3.60 ​ $ 3.34 ​ $ 3.05 ​ $ 2.95 ​ ​ ​ Natural gas producer two-way collar: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total volumes (MMBtu) ​ ​ 2,963,124 ​ ​ 1,389,500 ​ ​ 1,078,000 ​ ​ 315,000 ​ ​ ​ Weighted average price (call) ​ $ 3.07 ​ $ 5.05 ​ $ 4.58 ​ $ 3.88 ​ ​ ​ Weighted average price (put) ​ $ 2.66 ​ $ 3.41 ​ $ 3.00 ​ $ 3.00 ​ ​ ​ Natural gas basis swap: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total volumes (MMBtu) ​ ​ 6,240,544 ​ ​ 5,011,700 ​ ​ 3,506,150 ​ ​ 2,565,650 ​ ​ ​ Weighted average price ​ $ ( 0.36 ) ​ $ ( 0.58 ) ​ $ ( 0.59 ) ​ $ ( 0.50 ) ​ ​ ​ ​ The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts at December 31, 2021 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Derivative Assets ​ Derivative Liabilities Offsetting of Derivative Assets and Liabilities December 31, 2021 ​ December 31, 2020 December 31, 2021 December 31, 2020 Gross amounts presented in the consolidated balance sheet ​ $ 3,898 ​ $ 12,568 ​ $ ( 65,466 ) ​ $ ( 26,416 ) Amounts not offset in the consolidated balance sheet ​ ​ ( 3,898 ) ​ ​ ( 8,968 ) ​ ​ 3,898 ​ ​ 8,968 Net amount ​ $ — ​ $ 3,600 ​ $ ( 61,568 ) ​ $ ( 17,448 ) ​ The Company enters into an International Swap Dealers Association Master Agreement (ISDA) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency. 9. ASSET RETIREMENT OBLIGATIONS The Company records an asset retirement obligation (ARO) on oil and natural gas properties when it can reasonably estimate the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon costs. The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and natural gas properties” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the consolidated statements of operations. The additional capitalized costs are depreciated on a unit-of-production basis. 82 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS The Company recorded the following activity related to its ARO liability (inclusive of the current portion) (in thousands): ​ ​ ​ ​ ​ Liability for asset retirement obligations as of December 31, 2019 ​ $ 10,590 Liabilities settled and divested (1) ​ ​ ( 1,132 ) Additions ​ ​ 488 Accretion expense ​ ​ 585 Revisions in estimated cash flows ​ ​ 52 Liability for asset retirement obligations as of December 31, 2020 ​ $ 10,583 Additions ​ ​ 111 Accretion expense ​ ​ 477 Revisions in estimated cash flows ​ ​ 725 Liability for asset retirement obligations as of December 31, 2021 ​ $ 11,896 (1) See Note 4, “Divestitures,” for additional information on the Company’s divestiture activities. ​ 10. COMMITMENTS AND CONTINGENCIES Commitments As of December 31, 2021, the Company has a minimum volume commitment with a third party for the treating of sour gas production through June 30, 2022. The future payments associated with the minimum volume commitment are approximately $ 4.8 million. As of December 31, 2021, the Company has an active drilling rig commitment of approximately $ 2.6 million that will be incurred in 2022. Termination of the active drilling rig commitment would require an early termination penalty of $ 0.6 million, which would be in lieu of paying the active drilling rig commitment of $ 2.6 million. The Company has entered into various long-term gathering, transportation and sales contracts with respect to its oil and natural gas production from the Delaware Basin in West Texas. As of December 31, 2021, the Company had in place two long-term crude oil contracts and 12 long-term natural gas contracts in this area and the sales prices under these contracts are based on posted market rates. Under the terms of these contracts, the Company has committed a substantial portion of its production from this area for periods ranging from one to twenty years from the date of first production. Contingencies In addition to the matters described below, from time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. While the outcome and impact of currently pending legal proceedings cannot be determined, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on the Company’s consolidated operating results, financial position or cash flows. Surface owners of properties in Louisiana, where the Company formerly operated, often file lawsuits or assert claims against oil and gas companies claiming that operators and working interest owners are liable for environmental damages arising from operations conducted on the leased properties. These damages are frequently measured by the cost to restore the leased properties to their original condition. Currently and in the past, the Company has been party to such matters in Louisiana. With regard to pending matters, the overall exposure is not currently determinable. The Company intends to vigorously oppose these claims. 83 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS On February 26, 2019, a subsidiary of the Company was ordered to pay $ 9.1 million in a judgment entered by The Court of Common Pleas of Mercer County, Pennsylvania in a litigation matter captioned Vodenichar, et al., v. Halcón Energy Properties, Inc. et al., No. 2013-0512, arising from a dispute over whether the subsidiary complied with the terms of a letter of intent related to the leasing of acreage. The Court of Common Pleas of Mercer County, Pennsylvania marked the judgment as satisfied on February 3, 2020 and the Company considers this contingency resolved. 11. STOCKHOLDERS’ EQUITY Common Stock On October 8, 2019, upon emergence from chapter 11 bankruptcy, the Successor Company filed an amended and restated certificate of incorporation with the Delaware Secretary of State to provide for, among other things, (i) the total number of shares of all classes of capital stock that the Successor Company has the authority to issue is 101,000,000 of which 100,000,000 shares are common stock, par value $ 0.0001 per share and 1,000,000 shares are preferred stock, par value $ 0.0001 per share and (ii) a restriction on the Successor Company from issuing any non-voting equity securities in violation of Section 1123(a)(6) of chapter 11 of title 11 of the United States Code. In addition, pursuant to the Company’s certificate of incorporation, effective at the 2021 annual meeting of stockholders, the board ceased to be divided into two classes, and the provision for the right of removal of any directors designated as a Group II director by an increased voting threshold from a majority to 85 % of the shares then entitled to vote at an election of directors shares expired. Warrants On October 8, 2019, the Company entered into a warrant agreement (the Warrant Agreement) with Broadridge Corporate Issuer Solutions, Inc. as the warrant agent, pursuant to which the Company issued three series of warrants (the Series A Warrants, the Series B Warrants and the Series C Warrants and together, the Warrants, and the holders thereof, the Warrant Holders), on a pro rata basis to pre-emergence holders of the predecessor Company’s common stock pursuant to the Company’s plan of reorganization. ​ Each Warrant represents the right to purchase one share of common stock at the applicable exercise price, subject to adjustment as provided in the Warrant Agreement and as summarized below. On October 8, 2019, the Company issued (i) Series A Warrants to purchase an aggregate of 1,798,322 shares of common stock, with an initial exercise price of $ 40.17 per share, (ii) Series B Warrants to purchase an aggregate of 2,247,985 shares of common stock, with an initial exercise price of $ 48.28 per share and (iii) Series C Warrants to purchase an aggregate of 2,890,271 shares of common stock, with an initial exercise price of $ 60.45 per share. Each series of Warrants issued under the Warrant Agreement has a three-year term, expiring on October 8, 2022. The strike price of each series of Warrants issued under the Warrant Agreement increases monthly at an annualized rate of 6.75 %, compounding monthly, as provided in the Warrant Agreement. As of December 31, 2021, the Company had 1.8 million Series A, 2.2 million Series B and 2.9 million Series C warrants outstanding with corresponding exercise prices of $ 44.95 , $ 54.34 and $ 68.42 , respectively. ​ The Warrants do not grant the Warrant Holder any voting or control rights or dividend rights, or contain any negative covenants restricting the operation of the Company’s business. ​ Incentive Plans On January 29, 2020, the Company’s board of directors adopted the 2020 Long-Term Incentive Plan (the Plan) with an effective date of January 1, 2020 in which an aggregate of approximately 1.5 million shares of the Company’s common stock were available for grant pursuant to awards under the Plan. On June 8, 2021, Amendment No. 1 to the Plan to increase, by 0.3 million shares, the maximum number of shares of common stock that may be issued thereunder, i.e., a maximum of approximately 1.8 million shares, became effective. As of December 31, 2021 and 2020, a maximum of 0.5 million and 0.2 million shares, respectively, of the Company’s common stock remained reserved for issuance under the Plan. 84 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS The Company accounts for stock-based payment accruals under authoritative guidance on stock compensation. The guidance requires all stock-based payments to employees and directors, including grants of stock options and restricted stock, to be recognized in the financial statements based on their fair values. The Company has elected not to apply a forfeiture estimate and will recognize a credit in compensation expense to the extent awards are forfeited. For the years ended December 31, 2021 and 2020, the Company recognized $ 2.0 million and $ 2.6 million, respectively, related to stock-based compensation recorded as a component of “General and administrative” on the consolidated statements of operations. Stock Options From time to time, the Company grants stock options under the Plan covering shares of common stock to employees of the Company. Stock options, when exercised, are settled through the payment of the exercise price in exchange for new shares of stock underlying the option. Awards granted under the Plan typically vest over a four year period at a rate of one -fourth on the annual anniversary date of the grant and expire seven years from the date of grant. No stock options were granted during the year ended December 31, 2021. At December 31, 2021, the Company had $ 0.4 million of unrecognized compensation expense related to non-vested stock-options to be recognized over a weighted-average period of 1.2 years. The aggregate grant date fair value of options granted during the year ended December 31, 2020 was $ 1.9 million. At December 31, 2020, the Company had $ 0.9 million of unrecognized compensation expense related to non-vested stock-options to be recognized over a weighted-average period of 1.7 years. The following table sets forth the stock option transactions for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number Weighted Average Exercise Price Per Share Aggregate Intrinsic Value (1) (In thousands) Weighted Average Remaining Contractual Life (Years) Outstanding at December 31, 2019 ​ — ​ $ — ​ $ — ​ — Granted ​ 557,844 ​ ​ 28.32 ​ ​ ​ ​ ​ Exercised ​ — ​ ​ — ​ ​ ​ ​ ​ Forfeited ​ ( 79,692 ) ​ ​ 28.32 ​ ​ ​ ​ ​ Outstanding at December 31, 2020 ​ 478,152 ​ ​ 28.32 ​ $ — ​ 6.2 Granted ​ — ​ ​ — ​ ​ ​ ​ ​ Exercised ​ — ​ ​ — ​ ​ ​ ​ ​ Forfeited ​ — ​ ​ — ​ ​ ​ ​ ​ Outstanding at December 31, 2021 ​ 478,152 ​ $ 28.32 ​ $ — ​ 5.2 (1) The period end intrinsic value of stock options was calculated as the amount by which the closing market price on December 31, 2021 and 2020 of the underlying stock exceeded the exercise price of the option. 85 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ​ ​ Options outstanding at December 31, 2021 consisted of the following: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Outstanding ​ Exercisable (1) ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ ​ ​ ​ ​ Weighted Average ​ Remaining ​ ​ ​ Weighted Average ​ Aggregate ​ Remaining Range of Grant ​ ​ ​ Exercise Price ​ Contractual Life ​ ​ ​ Exercise Price ​ Intrinsic ​ Contractual Life Prices Per Share Number per Share (Years ) Number per Share Value (Years ) $ 18.91 ​ 159,384 ​ $ 18.91 ​ 5.2 ​ — ​ $ — ​ $ — ​ — ​ 28.23 ​ 159,384 ​ ​ 28.23 ​ 5.2 ​ — ​ ​ — ​ ​ — ​ — ​ 37.83 ​ 159,384 ​ ​ 37.83 ​ 5.2 ​ — ​ ​ — ​ ​ — ​ — (1) At December 31, 2021, none of the Company’s stock options were exercisable due to service performance conditions or options exercise prices above current market value of the underlying stock. ​ The assumptions used in calculating the Black-Scholes-Merton valuation model fair value of the Company’s stock options for year ended December 31, 2020 are set forth in the following table: ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ December 31, 2020 Weighted average value per option granted during the period ​ $ 3.36 ​ Assumptions: ​ ​ ​ ​ Stock price volatility (1) ​ ​ 61.87 % Risk free rate of return ​ ​ 1.21 % Expected term ​ ​ 4.75 years (1) Due to the Company’s limited historical data, expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available. ​ Restricted Stock From time to time, the Company grants shares of restricted stock units (RSUs) under the Plan to employees of the Company. Under the Plan, employee RSUs will vest and convert to shares typically over a four year period at a rate of one -fourth on the annual anniversary date of the grant or when the performance or market conditions described below occur. During the year ended December 31, 2021, the Company granted less than 0.1 million shares of RSUs which will vest over four years at a rate of one -fourth on the annual anniversary date of the grant. The aggregate grant date fair value of these RSUs was $ 0.1 million. At December 31, 2021, the Company had $ 2.2 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted average period of 1.8 years. During the year ended December 31, 2020, the Company granted 1.0 million shares of RSUs with the vesting conditions and fair values described below under the Plan to employees of the Company. At December 31, 2020, the Company had $ 4.1 million of unrecognized compensation expense related to non-vested RSU awards to be recognized over a weighted-average period of 2.5 years. ● 0.4 million RSUs granted will vest over four years at a rate one -fourth on the annual anniversary of date of the grant. The aggregate grant date fair value of these RSUs was $ 5.0 million. ● 0.2 million RSUs granted will vest in full only upon achievement of certain business combination goals, as defined in the awards agreements. The aggregate grant date fair value of these RSUs was $ 2.1 million. As of December 31, 2021, a business combination, as defined in the awards agreements, had not been 86 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS consummated and was not considered probable. As such, no expense has been recognized for the RSUs with business combination vesting conditions. ● 0.4 million RSUs granted will vest in full or in part or may terminate based on the Company’s total shareholder return relative to the total shareholder return of certain of its peer companies as defined in the awards agreements over the performance period ending on February 20, 2024. The aggregate grant date fair value of these RSUs was $ 2.3 million. The following table sets forth the restricted stock transactions for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Number of Shares Weighted Average Grant Date Fair Value Per Share Aggregate Intrinsic Value (1) (In thousands) Unvested outstanding shares at December 31, 2019 ​ — ​ $ — ​ $ — Granted ​ 987,590 ​ ​ 9.46 ​ ​ ​ Vested ​ — ​ ​ — ​ ​ ​ Forfeited ​ ( 113,456 ) ​ ​ 9.36 ​ ​ ​ Unvested outstanding shares at December 31, 2020 ​ 874,134 ​ $ 9.48 ​ $ 3,287 Granted ​ 12,000 ​ ​ 8.00 ​ ​ ​ Vested ​ ( 95,994 ) ​ ​ 11.51 ​ ​ ​ Forfeited ​ ( 14,625 ) ​ ​ 11.89 ​ ​ ​ Unvested outstanding shares at December 31, 2021 ​ 775,515 ​ $ 9.16 ​ $ 2,914 (1) The intrinsic value of restricted stock was calculated as the closing market price on December 31, 2021 and 2020 of the underlying stock multiplied by the number of restricted shares that would be issuable. The total fair value of shares vested was $ 1.1 million for the year ended December 31, 2021. The assumptions used in calculating the Monte Carlo valuation model fair value of the Company’s RSUs with performance based vesting conditions for the year ended December 31, 2020 are set forth in the following table: ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ December 31, 2020 ​ Weighted average value per performance based RSUs granted during the period ​ $ 6.13 ​ Assumptions: ​ ​ ​ ​ Stock price volatility (1) ​ ​ 51.79 % Risk free rate of return ​ ​ 1.22 % Expected term ​ ​ 3.9 years (1) Due to the Company’s limited historical data, expected volatility was estimated using volatilities of peer entities as defined in the award agreements whose share prices and assumptions were publicly available. ​ 87 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 12. INCOME TAXES Income tax benefit (provision) for the indicated periods is comprised of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 Current: ​ ​ ​ ​ ​ ​ Federal ​ $ — ​ $ — State ​ ​ — ​ ​ — ​ ​ ​ — ​ ​ — Deferred: ​ ​ ​ ​ ​ ​ Federal ​ ​ — ​ ​ — State ​ ​ — ​ ​ — ​ ​ ​ — ​ ​ — Total income tax benefit (provision) ​ $ — ​ $ — ​ The actual income tax benefit (provision) differs from the expected income tax benefit (provision) as computed by applying the United States federal corporate income tax rate of 21 % for the periods indicated below, as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 Expected tax benefit (provision) ​ $ 5,947 ​ $ 48,238 Change in valuation allowance and related items ​ ​ 57,845 ​ ​ ( 10,849 ) Attribute reduction ​ ​ ( 64,024 ) ​ ​ ( 37,985 ) Permanent adjustments ​ ​ 404 ​ ​ 577 Employee retention credit ​ ​ ( 153 ) ​ ​ — Other ​ ​ ( 19 ) ​ ​ 19 Total income tax benefit (provision) ​ $ — ​ $ — ​ 88 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 December 31, 2020 Deferred noncurrent income tax assets: ​ ​ ​ ​ ​ ​ Net operating loss carry-forwards ​ $ 135,454 ​ $ 94,742 Built in loss adjustment Section 382 ​ ​ 693 ​ ​ 98,416 Capital loss carryforward ​ ​ 114,725 ​ ​ 74,848 Stock-based compensation expense ​ ​ 1,870 ​ ​ 1,448 Asset retirement obligations ​ ​ 2,447 ​ ​ 2,347 Book-tax differences in property basis ​ ​ 148,008 ​ ​ 199,170 Unrealized hedging transactions ​ ​ 12,929 ​ ​ 2,908 Disallowed interest Section 163(j) ​ ​ 15,230 ​ ​ 13,579 Basis difference in debt ​ ​ — ​ ​ 1,687 Change of Control Call Option Embedded Derivative ​ ​ 841 ​ ​ — Operating lease liability ​ ​ 151 ​ ​ 85 Other ​ ​ 382 ​ ​ 374 Gross deferred noncurrent income tax assets ​ ​ 432,730 ​ ​ 489,604 Valuation allowance ​ ​ ( 431,694 ) ​ ​ ( 489,539 ) Deferred noncurrent income tax assets ​ $ 1,036 ​ $ 65 ​ ​ ​ ​ ​ ​ ​ Deferred noncurrent income tax liabilities: ​ ​ ​ ​ ​ ​ Basis difference in debt ​ $ ( 885 ) ​ $ — Lease right of use ​ ​ ( 151 ) ​ ​ ( 65 ) Deferred noncurrent income tax liabilities ​ $ ( 1,036 ) ​ $ ( 65 ) Net noncurrent deferred income tax assets (liabilities) ​ $ — ​ $ — ​ The amount of U.S. consolidated Net Operating Losses (NOLs) available as of December 31, 2021 after attribute reduction is estimated to be approximately $ 1.1 billion, but the amount after attribute reduction and the Section 382 limitation is $ 644.8 million. Of this amount, $ 105.6 million is subject to the 20 year carryforward period and will expire in 2037. The remaining $ 539.2 million may be carried forward indefinitely but is in part subject to a Section 382 limitation. The Company assesses the recoverability of its deferred tax assets each period by considering whether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The Company considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. The Company evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment. As a result of the Company’s analysis, it was concluded that as of December 31, 2021, a valuation allowance should continue to be applied against the Company’s net deferred tax asset. The Company recorded a valuation allowance as of December 31, 2021 of $ 431.7 million, a decrease of $ 57.8 million from December 31, 2020. The Company will continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized. The Company emerged from Chapter 11 Bankruptcy on October 8, 2019. Under the plan of reorganization, a substantial portion of the Company’s pre-petition debt securities were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (CODI) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC provides that a debtor in bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued 89 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from chapter 11 bankruptcy proceedings, U.S. CODI was approximately $ 524.8 million, which reduced the value of the Company’s net operating losses and capital losses on January 1, 2020. The deferred tax balances disclosed above reflect the estimated impact of the attribute reduction on January 1, 2020. ​ IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future U.S. taxable income in the event of a change in ownership. The Company's emergence from chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. The limitation under the IRC is based on the value of the corporation as of the emergence date. The ownership changes and resulting annual limitation resulted in the expiration of approximately $ 454.2 million of net operating losses generated prior to the emergence date. The expiration of these tax attributes was fully offset by a corresponding decrease in the Company's U.S. valuation allowance, which results in no net tax provision. ASC 740, Income Taxes (ASC 740) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the year ended December 31, 2021 and 2020. Generally, the Company’s income tax years 2018 through 2021 remain open for federal purposes and are subject to examination by Federal tax authorities. The Company's income tax returns are also subject to audit by the tax authorities in Louisiana, Mississippi, North Dakota, Oklahoma, Texas, Pennsylvania, Ohio and certain other state taxing jurisdictions where the Company has, or previously had, operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The open years for state purposes can vary from the normal three year statue expiration period for federal purposes. The Company recognizes interest and penalties accrued to unrecognized benefits in “Interest expense and other” in its consolidated statements of operations. For the year ended December 31, 2021 and 2020, the Company recognized no interest and penalties. ​ During 2020, the CARES Act and the Consolidated Appropriations Act of 2021 (the CAA) were signed into law. The CARES Act provides relief to corporate taxpayers by permitting a five-year carryback of 2018 to 2020 NOLs, removing the 80% limitation on the utilization of those NOLs, increasing the Section 163(j) 30% limitation on interest expense deductibility to 50% of adjusted taxable income for 2019 and 2020, and accelerates refunds for minimum tax credit carryforwards, as well as other provisions. The CAA extends various expiring tax provisions, clarifies that debt forgiven under the Paycheck Protection Program (PPP) is not included in gross income, clarifies that certain business expenses paid with forgiven PPP funds are tax deductible, as well as other tax provisions. Both the CARES Act and CAA did not have a material impact to the Company’s consolidated financial statements and related disclosures. ​ 90 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 13. EARNINGS PER SHARE The following represents the calculation of earnings (loss) per share (in thousands, except per share amounts): ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 Basic: ​ ​ ​ ​ ​ ​ Net income (loss) available to common stockholders ​ $ ( 28,317 ) ​ $ ( 229,707 ) Weighted average basic number of common shares outstanding ​ ​ 16,261 ​ ​ 16,204 Basic net income (loss) per common share ​ $ ( 1.74 ) ​ $ ( 14.18 ) ​ ​ ​ ​ ​ ​ ​ Diluted: ​ ​ ​ ​ ​ ​ Net income (loss) available to common stockholders ​ $ ( 28,317 ) ​ $ ( 229,707 ) Weighted average basic number of common shares outstanding ​ ​ 16,261 ​ ​ 16,204 Common stock equivalent shares representing shares issuable upon: ​ ​ ​ ​ ​ ​ Exercise of Series A Warrants ​ ​ Anti-dilutive ​ ​ Anti-dilutive Exercise of Series B Warrants ​ ​ Anti-dilutive ​ ​ Anti-dilutive Exercise of Series C Warrants ​ ​ Anti-dilutive ​ ​ Anti-dilutive Exercise of stock options ​ ​ Anti-dilutive ​ ​ Anti-dilutive Vesting of restricted stock units ​ ​ Anti-dilutive ​ ​ Anti-dilutive Weighted average diluted number of common shares outstanding ​ ​ 16,261 ​ ​ 16,204 Diluted net income (loss) per common share ​ $ ( 1.74 ) ​ $ ( 14.18 ) ​ Common stock equivalents, including warrants, stock options and restricted stock units, if considered issuable, totaling 7.7 million for the year ended December 31, 2021 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. Common stock equivalents, including warrants, stock options and restricted stock units, if considered issuable, totaling 7.7 million shares for the year ended December 31, 2020 were not included in the computation of diluted earnings per share of common stock because the effect would have been anti-dilutive due to the net loss. 91 Table of Contents BATTALION OIL CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 14. ADDITIONAL FINANCIAL STATEMENT INFORMATION Certain balance sheet amounts are comprised of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 December 31, 2020 Accounts receivable, net: ​ ​ ​ ​ ​ ​ Oil, natural gas and natural gas liquids revenues ​ $ 34,110 ​ $ 22,781 Joint interest accounts ​ ​ 2,503 ​ ​ 8,543 Other ​ ​ 193 ​ ​ 918 ​ ​ $ 36,806 ​ $ 32,242 Prepaids and other: ​ ​ ​ ​ ​ ​ Prepaids ​ $ 975 ​ $ 892 Funds in escrow ​ ​ 390 ​ ​ 1,740 Other ​ ​ 1 ​ ​ 108 ​ ​ $ 1,366 ​ $ 2,740 Funds in escrow and other: ​ ​ ​ ​ ​ ​ Oil, natural gas and natural gas liquids revenues ​ $ 1,010 ​ $ 1,720 Funds in escrow ​ ​ 1,227 ​ ​ 581 Other ​ ​ 33 ​ ​ 50 ​ ​ $ 2,270 ​ $ 2,351 Accounts payable and accrued liabilities: ​ ​ ​ ​ ​ ​ Trade payables ​ $ 25,315 ​ $ 22,740 Accrued oil and natural gas capital costs ​ ​ 4,881 ​ ​ 8,344 Revenues and royalties payable ​ ​ 22,763 ​ ​ 16,412 Accrued interest expense ​ ​ 42 ​ ​ 482 Accrued employee compensation ​ ​ 3,735 ​ ​ 3,223 Accrued lease operating expenses ​ ​ 6,090 ​ ​ 7,622 Other ​ ​ — ​ ​ 105 ​ ​ $ 62,826 ​ $ 58,928 ​ ​ ​ ​ ​ 92 Table of Contents SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves represent estimated quantities of natural gas, crude oil and condensate and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made. The proved reserves estimates reported herein for the years ended December 31, 2021, 2020 and 2019 have been independently evaluated by Netherland, Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland, Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland, Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell reserves reports incorporated herein are Mr. Neil H. Little and Mr. Edward Roy III. Mr. Little, a Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing consulting petroleum engineering at Netherland, Sewell since 2011 and has over nine years of prior industry experience. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from University of Houston in 2007 with a Master of Business Administration Degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at Netherland, Sewell since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master of Science Degree in Geology. Netherland, Sewell has reported to the Company that both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; they are both proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The Company’s board of directors has established an independent reserves committee composed of independent directors with experience in energy company reserve evaluations. The Company’s independent engineering firm reports jointly to the reserves committee and to the Executive Vice President and Chief Operating Officer. The reserves committee is charged with ensuring the integrity of the process of selection and engagement of the independent engineering firm and in making a recommendation to the board of directors as to whether to approve the report prepared by the independent engineering firm. Mr. Daniel P. Rohling, the Company’s Executive Vice President and Chief Operating Officer is primarily responsible for overseeing the preparation of the annual reserve report by Netherland, Sewell. He has approximately 15 years of oil and gas operations experience and earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is an active member of the Society of Petroleum Engineers. The reserves information in this Annual Report on Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they 93 Table of Contents were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced. The following tables illustrate changes in the Company’s estimated net proved developed and proved undeveloped reserves for the periods indicated. The oil and natural gas liquids prices as of December 31, 2021, 2020 and 2019 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate spot price which equates to $66.55 per barrel, $39.54 per barrel and $55.85 per barrel, respectively. The natural gas prices as of December 31, 2021, 2020 and 2019 are based on the respective 12-month unweighted average of the first of the month prices of the Henry Hub spot price which equates to $3.60 per MMBtu, $1.99 per MMBtu and $2.58 per MMBtu, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines. All proved reserves are located in the United States. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Proved Reserves ​ ​ ​ ​ ​ ​ Natural Gas ​ ​ ​ ​ ​ ​ Natural Gas ​ Liquids ​ Equivalent ​ Oil (MBbls) (MMcf) (MBbls) (MBoe) Proved reserves, December 31, 2018 (Predecessor) ​ 50,654 ​ 104,749 ​ 17,100 ​ 85,212 Extensions and discoveries ​ 9,161 ​ 12,372 ​ 1,952 ​ 13,175 Production ​ (3,780) ​ (9,136) ​ (1,262) ​ (6,565) Revision of previous estimates ​ (16,801) ​ (35,724) ​ (7,015) ​ (29,769) Proved reserves, December 31, 2019 (Successor) ​ 39,234 ​ 72,261 ​ 10,775 ​ 62,053 Extensions and discoveries ​ 8,268 ​ 12,157 ​ 2,090 ​ 12,384 Production ​ (3,446) ​ (8,769) ​ (1,262) ​ (6,170) Sale of minerals in place ​ (1,433) ​ (2,177) ​ (246) ​ (2,042) Revision of previous estimates ​ (4,407) ​ 5,034 ​ 718 ​ (2,850) Proved reserves, December 31, 2020 (Successor) ​ 38,216 ​ 78,506 ​ 12,075 ​ 63,375 Extensions and discoveries ​ 18,447 ​ 26,508 ​ 3,655 ​ 26,520 Production ​ (3,196) ​ (9,447) ​ (1,157) ​ (5,928) Revision of previous estimates ​ 5,265 ​ 29,398 ​ 1,747 ​ 11,913 Proved reserves, December 31, 2021 (Successor) ​ 58,732 ​ 124,965 ​ 16,320 ​ 95,880 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equivalent (Mboe) ​ ​ Proved ​ Proved ​ ​ ​ ​ Developed ​ Undeveloped ​ Total Proved ​ Reserves Reserves Reserves Proved reserves, December 31, 2018 (Predecessor) ​ 39,869 ​ 45,343 ​ 85,212 Extensions and discoveries ​ 2,813 ​ 10,362 ​ 13,175 Production ​ (6,565) ​ — ​ (6,565) Transfers ​ 10,213 ​ (10,213) ​ — Revision of previous estimates ​ (8,395) ​ (21,374) ​ (29,769) Proved reserves, December 31, 2019 (Successor) ​ 37,935 ​ 24,118 ​ 62,053 Extensions and discoveries ​ 13 ​ 12,371 ​ 12,384 Production ​ (6,170) ​ — ​ (6,170) Sale of minerals in place ​ (2,042) ​ — ​ (2,042) Transfers ​ 6,513 ​ (6,513) ​ — Revision of previous estimates ​ (17) ​ (2,833) ​ (2,850) Proved reserves, December 31, 2020 (Successor) ​ 36,232 ​ 27,143 ​ 63,375 Extensions and discoveries ​ 7 ​ 26,513 ​ 26,520 Production ​ (5,928) ​ — ​ (5,928) Transfers ​ 2,104 ​ (2,104) ​ — Revision of previous estimates ​ 9,995 ​ 1,918 ​ 11,913 Proved reserves, December 31, 2021 (Successor) ​ 42,410 ​ 53,470 ​ 95,880 ​ 94 Table of Contents ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved Developed Reserves ​ ​ ​ ​ ​ ​ Natural Gas ​ ​ ​ ​ ​ ​ Natural Gas ​ Liquids ​ Equivalent ​ Oil (MBbls) (MMcf) (MBbls) (MBoe) December 31, 2021 ​ 21,694 ​ 71,009 ​ 8,881 ​ 42,410 December 31, 2020 ​ 20,371 ​ 51,097 ​ 7,345 ​ 36,232 December 31, 2019 ​ 22,821 ​ 48,558 ​ 7,021 ​ 37,935 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved Undeveloped Reserves ​ ​ ​ ​ ​ ​ Natural Gas ​ ​ ​ ​ ​ ​ Natural Gas ​ Liquids ​ Equivalent ​ Oil (MBbls) (MMcf) (MBbls) (MBoe) December 31, 2021 ​ 37,038 ​ 53,956 ​ 7,439 ​ 53,470 December 31, 2020 ​ 17,845 ​ 27,409 ​ 4,730 ​ 27,143 December 31, 2019 ​ 16,413 ​ 23,703 ​ 3,754 ​ 24,118 ​ The Company’s proved reserves have been estimated using deterministic methods. At December 31, 2021, total proved reserves were approximately 95.9 MMBoe, a 32.5 MMBoe net increase over the previous year’s estimate of 63.4 MMBoe. The net increase in total proved reserves was the result of additions and extensions of 26.5 MMBoe and positive revisions of 11.9 MMBoe due primarily to increases in SEC pricing, partially offset by production of 5.9 MMBoe. At December 31, 2021, the Company’s proved developed reserves were approximately 42.4 MMBoe, a 6.2 MMBoe net increase from the previous year’s estimate of 36.2 MMBoe. The net increase in total proved reserves was the result of positive revisions of 10.0 MMBoe due to increases in SEC pricing and the development of 2.1 MMBoe (transferred from proved undeveloped), partially offset by production of 5.9 MMBoe. At December 31, 2021, the Company’s estimated proved undeveloped (PUD) reserves were approximately 53.5 MMBoe, a 26.4 MMBoe net increase from the previous year’s estimate of 27.1 MMBoe. The net increase in total PUD reserves was the result of additions and extensions of 26.5 MMBoe and positive revisions of 1.9 MMBoe due to increases in SEC pricing, partially offset by development of 2.1 MMBoe. Of the 26.5 MMBoe of extensions and discoveries in PUD reserves, all are associated with drilling extensions in the Delaware Basin. None of the extensions and discoveries in PUD reserves in 2021 were associated with infill drilling activity. At December 31, 2020, the Company’s proved developed reserves were approximately 36.2 MMBoe, a 1.7 MMBoe net decrease from the previous year’s estimate of 37.9 MMBoe. The net decrease in total proved reserves was the result of production of 6.2 MMBoe and sales of 2.0 MMBoe, partially offset by development of 6.5 MMBoe (transferred from proved undeveloped). At December 31, 2020, the Company’s estimated PUD reserves were approximately 27.1 MMBoe, a 3.0 MMBoe net increase from the previous year’s estimate of 24.1 MMBoe. The net increase in total PUD reserves was the result of additions and extensions of 12.4 MMBoe, partially offset by development of 6.5 MMBoe and negative revisions of 2.8 MMBoe due primarily to decreases in SEC pricing. Of the 12.4 MMBoe of extensions and discoveries in PUD reserves, all are associated with drilling extensions in the Delaware Basin. None of the extensions and discoveries in PUD reserves in 2020 were associated with infill drilling activity. At December 31, 2019, the Company’s proved developed reserves were approximately 37.9 MMBoe, a 2.0 MMBoe net decrease from the previous year’s estimate of 39.9 MMBoe. The net decrease in total proved reserves was the result of negative revisions of 8.4 MMBoe and production of 6.5 MMBoe, partially offset by additions and extensions of 2.8 MMBoe and development of 10.1 MMBoe (transferred from proved undeveloped). Negative revisions of 8.4 MMBoe primarily relate to changes in the Company’s development plans to focus on Monument Draw and due to the effect of lower prices. Of the 2.8 MMBoe of extensions and discoveries in proved developed reserves, approximately 1.2 MMBoe are associated with infill drilling activity and 1.6 MMBoe are associated with drilling extensions in the Delaware Basin. 95 Table of Contents At December 31, 2019, the Company’s estimated PUD reserves were approximately 24.1 MMBoe, a 21.2 MMBoe net decrease from the previous year’s estimate of 45.3 MMBoe. The net decrease in total PUD reserves was the result of negative revisions of 21.4 MMBoe and development of 10.2 MMBoe, partially offset by additions and extensions of 10.4 MMBoe. The negative revisions to PUD reserves in 2019 were primarily attributable to the changes in the Company’s development plans to focus on Monument Draw and due to the effect of lower prices. Of the 10.4 MMBoe of extensions and discoveries in PUD reserves, approximately 6.6 MMBoe are associated with infill drilling activity and 3.8 MMBoe are associated with drilling extensions in the Delaware Basin. As of December 31, 2021 all of the Company’s PUD reserves are planned to be developed within five years from the date they were initially recorded. During 2021, approximately $37.6 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lacked sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics, combined with volumetric methods. The volumetric estimates were based on geologic maps and rock and fluid properties derived from well logs, core data, pressure measurements, and fluid samples. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and volumetric estimates for each area or field. PUD locations were limited to areas of uniformly high quality reservoir properties, between existing commercial producers. Reliable technologies were used to determine areas where PUD locations are more than one offset location away from a producing well. These technologies include seismic data, wire line openhole log data, core data, log cross-sections, performance data, and statistical analysis. In such areas, these data demonstrated consistent, continuous reservoir characteristics in addition to significant quantities of economic EURs from individual producing wells. The Company relied only on production flow tests and historical production data, along with the reliable geologic data mentioned above to estimate proved reserves. No other alternative methods or technologies were used to estimate proved reserves. Out of total proved undeveloped reserves of 53.5 MMBoe at December 31, 2021, 37.7 MMBoe were associated with 39 gross PUD locations that were more than one offset location from a producing well. Capitalized Costs Relating to Oil and Natural Gas Producing Activities The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depletion, depreciation and accretion (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ December 31, 2020 ​ December 31, 2019 Evaluated oil and natural gas properties ​ $ 569,886 ​ $ 509,274 ​ $ 420,609 Unevaluated oil and natural gas properties ​ ​ 64,305 ​ ​ 75,494 ​ ​ 105,009 ​ ​ ​ 634,191 ​ ​ 584,768 ​ ​ 525,618 Accumulated depletion ​ ​ (339,776) ​ ​ (295,163) ​ ​ (19,474) ​ ​ $ 294,415 ​ $ 289,605 ​ $ 506,144 ​ 96 Table of Contents Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Successor ​ ​ Predecessor ​ ​ ​ ​ ​ ​ ​ ​ Period from ​ ​ Period from ​ ​ ​ ​ ​ ​ October 2, 2019 ​ ​ January 1, 2019 ​ ​ Years Ended December 31, ​ through ​ ​ through ​ 2021 2020 December 31, 2019 October 1, 2019 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Property acquisition costs, proved ​ $ — ​ $ 23 ​ $ — ​ ​ $ — Property acquisition costs, unproved ​ ​ — ​ ​ — ​ ​ — ​ ​ ​ 2,809 Exploration and extension well costs ​ ​ 6,125 ​ ​ 14,082 ​ ​ 9,209 ​ ​ ​ 89,389 Development costs (1) ​ ​ 37,611 ​ ​ 43,256 ​ ​ 15,839 ​ ​ ​ 60,275 Total costs ​ $ 43,736 ​ $ 57,361 ​ $ 25,048 ​ ​ $ 152,473 (1) Excludes $5.7 million, $31.5 million, $11.3 million and $72.9 million for the years ended December 31, 2021 and 2020, the period from October 2, 2019 to December 31, 2019 and the period from January 1, 2019 to October 1, 2019, respectively, of development costs related to the Company’s treating equipment and gathering support facilities. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing ASC 932, Extractive Activities—Oil and Gas (ASC 932) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account when reviewing the following information: ● future costs and selling prices will probably differ from those required to be used in these calculations; ● due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; ● a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and ● future net revenues may be subject to different rates of income taxation. At December 31, 2021, 2020 and 2019, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. 97 Table of Contents The Standardized Measure is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ ​ 2021 ​ 2020 ​ 2019 ​ ​ (In thousands) Future cash inflows ​ $ 4,688,646 ​ $ 1,660,950 ​ $ 2,257,083 Future production costs ​ ​ (1,947,781) ​ ​ (911,099) ​ ​ (1,207,370) Future development costs ​ ​ (540,596) ​ ​ (315,078) ​ ​ (261,747) Future income tax expense ​ ​ (725) ​ ​ (1,459) ​ ​ (1,577) Future net cash flows before 10% discount ​ ​ 2,199,544 ​ ​ 433,314 ​ ​ 786,389 10% annual discount for estimated timing of cash flows ​ ​ (1,123,889) ​ ​ (223,918) ​ ​ (377,514) Standardized measure of discounted future net cash flows ​ $ 1,075,655 ​ $ 209,396 ​ $ 408,875 ​ Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Years Ended December 31, ​ 2021 2020 2019 ​ ​ (In thousands) Beginning of year ​ $ 209,396 ​ $ 408,875 ​ $ 853,567 Sale of oil and natural gas produced, net of production costs ​ ​ (164,221) ​ ​ (34,888) ​ ​ (104,007) Sales of minerals in place ​ ​ — ​ ​ (22,387) ​ ​ — Extensions and discoveries ​ ​ 268,319 ​ ​ 17,127 ​ ​ 71,585 Changes in income taxes, net ​ ​ 119 ​ ​ 25 ​ ​ 5,845 Changes in prices and costs ​ ​ 472,162 ​ ​ (231,791) ​ ​ (306,466) Previously estimated development costs incurred ​ ​ 28,208 ​ ​ 68,135 ​ ​ 85,538 Net changes in future development costs ​ ​ 1,760 ​ ​ 3,867 ​ ​ 26,742 Revisions of previous quantities ​ ​ 184,284 ​ ​ (30,757) ​ ​ (266,538) Accretion of discount ​ ​ 20,963 ​ ​ 40,914 ​ ​ 85,968 Changes in production rates and other ​ ​ 54,665 ​ ​ (9,724) ​ ​ (43,359) End of year ​ $ 1,075,655 ​ $ 209,396 ​ $ 408,875 ​ ​ ​ ​ ​ 98 Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.