HighPeak Energy, Inc. 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm 80 Consolidated Balance Sheets as of December 31, 2023 and 2022 81 Consolidated Statements of Operations for the Years Ended December 31, 2023, 2022 and 2021 82 Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2023, 2022 and 2021 83 Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, 2022 and 2021 84 Notes to Consolidated Financial Statements 85 Unaudited Supplementary Data 104 80 Report of Independent Registered Public Accounting Firm To the Stockholders and the Board of Directors of HighPeak Energy, Inc. Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of HighPeak Energy, Inc. and its subsidiaries (the Company) as of December 31, 2023 and 2022, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 consolidated 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 consolidated 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 consolidated 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 consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ WEAVER AND TIDWELL, L.L.P. We have served as the Company’s auditor since 2020. Fort Worth, Texas March 6, 2024 81 HighPeak Energy, Inc. Consolidated Balance Sheets (in thousands, except share data) December 31, 2023 2022 ASSETS Current assets: Cash and cash equivalents $ 194,515 $ 30,504 Accounts receivable 94,589 96,596 Derivative instruments 31,480 17 Inventory 7,254 13,275 Prepaid expenses 995 4,133 Total current assets 328,833 144,525 Crude oil and natural gas properties, using the successful efforts method of accounting: Proved properties 3,338,107 2,270,236 Unproved properties 72,715 114,665 Accumulated depletion, depreciation and amortization ( 684,179 ) ( 259,962 ) Total crude oil and natural gas properties, net 2,726,643 2,124,939 Other property and equipment, net 3,572 3,587 Derivative instruments 16,059 — Other noncurrent assets 5,684 6,431 Total assets $ 3,080,791 $ 2,279,482 LIABILITIES AND STOCKHOLDERS ’ EQUITY Current liabilities: Current maturities of long-term debt $ 120,000 $ — Accounts payable – trade 63,583 105,565 Accrued capital expenditures 39,231 91,842 Revenues and royalties payable 29,724 15,623 Other accrued liabilities 19,613 15,600 Derivative instruments 13,054 16,702 Accrued interest 1,398 13,152 Operating leases 528 343 Advances from joint interest owners 262 7,302 Total current liabilities 287,393 266,129 Noncurrent liabilities: Long-term debt, net 1,030,299 704,349 Deferred income taxes 197,068 131,164 Asset retirement obligations 13,245 7,502 Derivative instruments 65 691 Commitments and contingencies (Note 10) Stockholders’ equity: Preferred stock, $ 0.0001 par value, 10,000,000 shares authorized, none issued and outstanding at December 31, 2023 and 2022 — — Common stock, $ 0.0001 par value, 600,000,000 shares authorized, 128,420,923 and 113,165,027 shares issued and outstanding at December 31, 2023 and 2022, respectively 13 11 Additional paid-in capital 1,189,424 1,008,896 Retained earnings 363,284 160,740 Total stockholders’ equity 1,552,721 1,169,647 Total liabilities and stockholders ’ equity $ 3,080,791 $ 2,279,482 The accompanying notes are an integral part of these consolidated financial statements. 82 HighPeak Energy, Inc. Consolidated Statements of Operations (in thousands, except per share data) Years Ended December 31, 2023 2022 2021 Operating Revenues: Crude oil sales $ 1,086,598 $ 715,469 $ 210,453 NGL and natural gas sales 24,695 40,217 9,671 Total operating revenues 1,111,293 755,686 220,124 Operating Costs and Expenses: Crude oil and natural gas production 145,362 69,599 25,053 Production and ad valorem taxes 58,472 38,440 10,746 Exploration and abandonments 5,234 1,149 1,549 Depletion, depreciation and amortization 424,424 177,742 65,201 Accretion of discount 522 370 167 General and administrative 16,598 12,470 8,885 Stock-based compensation 25,957 33,352 6,676 Total operating costs and expenses 676,569 333,122 118,277 Other expense 8,262 — 167 Income from operations 426,462 422,564 101,680 Interest and other income 2,908 266 1 Interest expense ( 147,901 ) ( 50,610 ) ( 2,484 ) Gain (loss) on derivative instruments, net 27,602 ( 60,005 ) ( 26,734 ) Loss on extinguishment of debt ( 27,300 ) — — Income before income taxes 281,771 312,215 72,463 Provision for income taxes 65,905 75,361 16,904 Net income $ 215,866 $ 236,854 $ 55,559 Earnings per share: Basic net income $ 1.64 $ 2.04 $ 0.55 Diluted net income $ 1.58 $ 1.93 $ 0.54 Weighted average shares outstanding: Basic 117,956 104,738 93,127 Diluted 123,020 111,164 94,772 Dividends declared per share $ 0.100 $ 0.100 $ 0.125 The accompanying notes are an integral part of these consolidated financial statements. 83 HighPeak Energy, Inc. Consolidated Statements of Changes in Stockholders ’ Equity (in thousands) Years ended December 31, 2023, 2022 and 2021 Shares Outstanding Common Stock Additional Paid-in- Capital Retained Earnings (Accumulated Deficit) Total Stockholders’ Equity Balance, December 31, 2020 91,968 $ 9 $ 581,426 $ ( 107,209 ) $ 474,226 Dividends declared ($ 0.125 per share) — — — ( 11,593 ) ( 11,593 ) Dividend equivalents declared on outstanding stock options ($ 0.125 per share) — — — ( 1,193 ) ( 1,193 ) Issuance of common stock 2,530 1 22,836 — 22,837 Exercise of warrants 554 — 5,466 — 5,466 Stock-based compensation costs: Shares issued upon options being exercised 154 — 1,573 — 1,573 Restricted shares issued to outside directors 68 — — — — Restricted shares issued to employee directors 1,500 — — — — Compensation costs included in net income — — 6,188 — 6,188 Net income — — — 55,559 55,559 Balance, December 31, 2021 96,774 10 617,489 ( 64,436 ) 553,063 Dividends declared ($ 0.100 per share) — — — ( 10,623 ) ( 10,623 ) Dividend equivalents declared on outstanding stock options ($ 0.100 per share) — — — ( 1,055 ) ( 1,055 ) Stock issued for acquisitions 10,854 1 264,981 — 264,982 Stock issued in private placement 3,933 — 85,000 — 85,000 Stock issuance costs — — ( 339 ) — ( 339 ) Exercise of warrants 971 — 7,805 — 7,805 Stock-based compensation costs: Shares issued upon options being exercised 12 — 120 — 120 Restricted shares issued to outside directors 21 — — — — Restricted shares issued to employees 600 — — — — Compensation costs included in net income — — 33,840 — 33,840 Net income — — — 236,854 236,854 Balance, December 31, 2022 113,165 11 1,008,896 160,740 1,169,647 Dividends declared ($ 0.100 per share) — — — ( 12,076 ) ( 12,076 ) Dividend equivalents declared on outstanding stock options ($ 0.100 per share) — — — ( 1,246 ) ( 1,246 ) Stock issued in public offering 14,835 2 155,766 — 155,768 Stock issuance costs — — ( 5,371 ) — ( 5,371 ) Exercise of warrants 350 — 4,028 — 4,028 Stock-based compensation costs: Shares issued upon options being exercised 12 — 148 — 148 Restricted shares issued to outside directors 59 — — — — Compensation costs included in net income — — 25,957 — 25,957 Net income — — — 215,866 215,866 Balance, December 31, 2023 128,421 $ 13 $ 1,189,424 $ 363,284 $ 1,552,721 The accompanying notes are an integral part of these consolidated financial statements. 84 HighPeak Energy, Inc. Consolidated Statements of Cash Flows (in thousands) Years Ended December 31, 2023 2022 2021 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 215,866 $ 236,854 $ 55,559 Adjustments to reconcile net income to net cash provided by operations: Provision for deferred income taxes 65,905 75,361 16,904 Loss on extinguishment of debt 27,300 — — (Gain) loss on derivative instruments, net ( 27,602 ) 60,005 26,734 Cash paid on settlement of derivative instruments ( 24,194 ) ( 58,096 ) ( 11,267 ) Amortization of debt issuance costs 11,411 5,635 498 Amortization of discounts on long-term debt 15,140 7,735 — Stock-based compensation expense 25,957 33,352 6,676 Accretion expense 522 370 167 Depletion, depreciation and amortization expense 424,424 177,742 65,201 Exploration and abandonment expense 4,242 146 742 Changes in operating assets and liabilities: Accounts receivable 2,007 ( 57,218 ) ( 31,655 ) Prepaid expenses, inventory and other assets 6,923 ( 11,959 ) ( 7,053 ) Accounts payable, accrued liabilities and other current liabilities 8,488 34,087 24,509 Net cash provided by operating activities 756,389 504,014 147,015 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to crude oil and natural gas properties ( 1,009,855 ) ( 1,046,739 ) ( 236,242 ) Changes in working capital associated with oil and gas property additions ( 100,802 ) 128,938 37,259 Acquisitions of crude oil and natural gas properties ( 15,085 ) ( 262,363 ) ( 54,045 ) Proceeds from sales of properties — — 3,366 Other property additions ( 193 ) ( 2,244 ) ( 709 ) Net cash used in investing activities ( 1,125,935 ) ( 1,182,408 ) ( 250,371 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under Term Loan Credit Agreement, net of discount 1,170,000 — — Borrowings under Prior Credit Agreement 255,000 925,000 120,000 Proceeds from issuance of senior notes, net of discount — 440,179 — Repayments under Prior Credit Agreement ( 525,000 ) ( 755,000 ) ( 20,000 ) Repayments of 10.000% Senior Notes and 10.625% Senior Notes ( 475,000 ) — — Premium on extinguishment of debt ( 4,457 ) — — Proceeds from issuance of common stock 155,768 85,000 25,300 Proceeds from exercises of warrants 4,028 7,805 5,466 Proceeds from subscription receivable from exercises of warrants — — 3,596 Proceeds from exercises of stock options 148 120 1,573 Debt issuance costs ( 28,444 ) ( 17,128 ) ( 2,169 ) Stock offering costs ( 5,371 ) ( 339 ) ( 2,463 ) Dividends paid ( 11,864 ) ( 10,412 ) ( 11,593 ) Dividend equivalents paid ( 1,251 ) ( 1,196 ) ( 1,037 ) Net cash provided by financing activities 533,557 674,029 118,673 Net increase (decrease) in cash and cash equivalents 164,011 ( 4,365 ) 15,317 Cash and cash equivalents, beginning of period 30,504 34,869 19,552 Cash and cash equivalents, end of period $ 194,515 $ 30,504 $ 34,869 Supplemental cash flow information: Cash paid for interest $ 133,104 $ 24,268 $ 1,811 Cash paid for income taxes $ — $ — $ — Supplemental disclosure of non-cash transactions: Stock issued for acquisitions $ — $ 264,982 $ — Additions to asset retirement obligations $ 6,048 $ 2,879 $ 1,844 The accompanying notes are an integral part of these consolidated financial statements. 85 HIGHPEAK ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. Organization and Nature of Operations HighPeak Energy, Inc. ("HighPeak Energy" or the "Company,") is a Delaware corporation, formed in October 2019. HighPeak Energy’s common stock and warrants are listed and traded on the Nasdaq Global Market (the "Nasdaq") under the ticker symbols “HPK” and “HPKEW,” respectively. The Company is an independent crude oil and natural gas exploration and production company that explores for, develops and produces crude oil, NGL and natural gas in the Permian Basin in West Texas, more specifically, the Midland Basin primarily in Howard and Borden Counties. Our acreage is composed of two core areas, Flat Top primarily in the northern portion of Howard County extending into southern Borden County, southwest Scurry County and northwest Mitchell County and Signal Peak in the southern portion of Howard County. NOTE 2. Basis of Presentation and Summary of Significant Accounting Policies Presentation. The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments, consisting of normal and recurring accruals considered necessary for a fair presentation, have been included. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2023, through the date of this Annual Report. Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation, which had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows. Use of estimates in the preparation of consolidated financial statements. Preparation of the Company's consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of crude oil and natural gas properties is determined using estimates of proved crude oil, NGL and natural gas reserves and evaluations for impairment of proved and unproved crude oil and natural gas properties, in part, is determined using estimates of proved and risk adjusted probable and possible crude oil, NGL and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, if needed, evaluations for impairment of proved crude oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves, commodity price outlooks and future undiscounted and discounted net cash flows. In addition, evaluations for impairment of unproved crude oil and natural gas properties on a project-by-project basis are also subject to numerous uncertainties including, among others, estimates of future recoverable reserves, results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. Other items subject to such estimates and assumptions include, but are not limited to, the carrying value of crude oil and natural gas properties, asset retirement obligations, equity-based compensation, fair value of derivatives, expected credit losses and estimates of income taxes. Actual results could differ from the estimates and assumptions utilized. Cash and cash equivalents. The Company’s cash and cash equivalents include depository accounts held by banks with original issuance maturities of 90 days or less. The Company’s cash and cash equivalents are generally held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation. However, management believes that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. Accounts receivable. As of December 31, 2023 and 2022, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $ 82.5 million and $ 81.6 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, receivables related to settlements of derivative contracts of $ 4.5 million and $ 4.7 million, respectively, joint interest receivables of $ 4.4 million and $ 2.2 million, respectively, current U.S. federal income tax receivables of $ 3.2 million and $ 3.2 million, respectively, and zero and $ 4.9 million, respectively, related to receivables from electric power infrastructure installed throughout Flat Top by the Company for which it was reimbursed. The Company’s share of crude oil, NGL and natural gas production is sold to various purchasers who must be prequalified under the Company’s credit risk policies and procedures. The Company’s credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty or other credit support. 86 The Company adopted ASU 2016-13 and the subsequent applicable modifications to the rule on January 1, 2023. Accounts receivable are stated at amounts due from purchasers or joint interest owners, net of an allowance for expected losses as estimated by the Company when collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from purchasers or joint interest owners outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. As of December 31, 2023 and 2022, the Company had no allowance for credit losses related to accounts receivable and no allowance for doubtful accounts, respectively. Concentration of credit risk. The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the years ended December 31, 2023, 2022 and 2021, sales to the Company’s largest purchaser accounted for approximately 82 %, 88 % and 94 %, respectively, of the Company’s total crude oil, NGL and natural gas sales revenues and for the year ended December 31, 2023, sales to the Company’s second largest purchaser accounted for approximately 14 % of the Company’s total crude oil, NGL and natural gas revenues. The Company generally does not require collateral and does not believe the loss of these particular purchasers would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in various regions. Inventory. Inventory is comprised primarily of crude oil and natural gas drilling and completion or repair items such as pumps, tubing, casing, vessels, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling and completion or repair operations and is carried at the lower of cost or net realizable value, on a weighted average cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company’s consolidated balance sheet and as charges to other expense in the consolidated statements of operations. The Company’s materials and supplies inventory as of December 31, 2023 and 2022 is $ 7.3 million and $ 13.3 million, respectively, and the Company has not recognized any valuation allowance to date. Prepaid expenses. Prepaid expenses are comprised primarily of prepaid insurance costs that will be amortized over the life of the policies, caliche that will be used on future locations and roads in our development areas, tubulars and proppant that the Company has prepaid the suppliers to guarantee their availability when needed for our current drilling program and prepaid agency fees and software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of December 31, 2023 and 2022 are $ 1.0 million and $ 4.1 million, respectively. Crude oil and natural gas properties. The Company utilizes the successful efforts method of accounting for its crude oil and natural gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheet following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predict the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company’s assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonment expense. See Note 6 for additional information. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves for leasehold costs and proved developed reserves for drilling, completion and other crude oil and natural gas property costs. Costs of unproved leasehold costs are excluded from depletion until proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties are credited to proved or unproved crude oil and natural gas properties, as the case may be, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. 87 The Company performs assessments of its long-lived assets to be held and used, including proved crude oil and natural gas properties accounted for under the successful efforts method of accounting, whenever changes in events or circumstances indicate that the carrying value of those assets may not be recoverable. If there is an indication the carrying value of the assets may not be recovered, an impairment loss is recognized if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment charge for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Unproved crude oil and natural gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the estimates of future recoverable reserves, results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment charge at that time. Other property and equipment, net. Other property and equipment is recorded at cost. The carrying values of other property and equipment, net of accumulated depreciation of $ 904,000 and $ 696,000 as of December 31, 2023 and 2022, respectively, are as follows (in thousands): December 31, 2023 2022 Land $ 2,139 $ 2,139 Transportation equipment 689 691 Buildings 530 544 Leasehold improvements 209 206 Field equipment 4 6 Furniture and fixtures 1 1 Total other property and equipment, net $ 3,572 $ 3,587 Other property and equipment are depreciated over their estimated useful life on a straight-line basis. Land is not depreciated. Transportation equipment is generally depreciated over five years, buildings are generally depreciated over forty years, field equipment is generally depreciated over seven years and furniture and fixtures is generally depreciated over five years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recorded is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. Aid-in-construction assets. As of December 31, 2023 and 2022, the Company had aid-in-construction assets totaling $ 5.2 million and $ 6.1 million, respectively, included in other noncurrent assets. The Company has received and will continue to receive payments based on gross system throughput, including any third-party natural gas that is potentially tied into the Flat Top gathering system in the future. The contract calls for future aid-in-construction funding if expansions of the system are necessary as determined in the sole discretion of the Company. Leases. The Company enters into leases for drilling rigs, storage tanks, equipment and buildings and recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of a lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are generally not recorded as lease right-of-use assets and liabilities. See Note 10 for additional information. Current liabilities. Current liabilities as of December 31, 2023 and 2022 totaled approximately $ 287.4 million and $ 266.1 million, respectively, including current maturities of long-term debt, trade accounts payable, accrued capital expenditures, revenues and royalties payable, derivative liabilities and accruals for operating and general and administrative expenses, interest expense, operating leases, dividends and dividend equivalents and other miscellaneous items. 88 Debt issuance costs and original issue discount. The Company has paid a total of $ 48.1 million in debt issuance costs, $ 28.4 million of which was incurred during the year ended December 31, 2023 primarily related to the completion of the Term Loan Credit Agreement and Senior Credit Facility Agreement and amendments to the Prior Credit Agreement. Amortization based on the straight-line method over the terms of the Term Loan Credit Agreement, Senior Credit Facility Agreement, Prior Credit Agreement, 10.000 % Senior Notes and 10.625 % Senior Notes which approximates the effective interest method was $ 11.4 million, $ 5.6 million and $ 498,000 during the years ended December 31, 2023, 2022 and 2021, respectively. In addition, the Company realized a total of $ 64.8 million in original issue discounts on the issuance of its Term Loan Credit Agreement, 10.000 % Senior Notes and 10.625 % Senior Notes that is being amortized over the life of the agreements which approximates the effective interest method and was $ 15.1 million, $ 7.7 million and zero during the years ended December 31, 2023, 2022 and 2021, respectively. All unamortized debt issuance costs and discounts as of the termination of the Prior Credit Agreement and redemption of the 10.000% Senior Notes and 10.625% Senior Notes during September 2023 were charged to expense and included in loss on extinguishment of debt in the accompanying consolidated statements of operations. See Note 7 for more information. As of December 31, 2023 and 2022, the remaining net debt issuance costs and discounts related to the Term Loan Credit Agreement and Senior Credit Facility Agreement are netted against the outstanding long-term debt on the accompanying consolidated balance sheets. Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which the associated asset is acquired or placed into service if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recorded when incurred and when fair value can be reasonably estimated. See Note 8 for additional information. Revenue recognition . The Company follows FASB ASC 606, “Revenue from Contracts with Customers,” (“ASC 606”) whereby the Company recognizes revenues from the sales of crude oil, NGL and natural gas to its purchasers and presents them disaggregated on the Company’s consolidated statements of operations. The Company enters into contracts with purchasers to sell its crude oil, NGL and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model prescribed in ASC 606. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the crude oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the crude oil and natural gas marketing contracts is typically received from the purchaser one to two months after the date of sale. As of December 31, 2023 and 2022, the Company had receivables related to contracts with purchasers of approximately $ 82.5 million and $ 81.6 million, respectively. Crude Oil Contracts. The Company’s crude oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the crude oil has been transferred to the purchaser. The crude oil produced is sold under contracts using market-based pricing which is then adjusted for the differentials based upon delivery location and crude oil quality. Since the differentials are incurred after the transfer of control of the crude oil, the differentials are included in crude oil sales on the consolidated statements of operations as they represent part of the transaction price of the contract. Natural Gas Contracts. The majority of the Company’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts or (ii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of the Company’s contracts, the purchaser gathers the natural gas in the field where it is produced and transports it to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue natural gas are then sold by the purchaser. Under percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Company receives a percentage of the value for the extracted liquids and the residue natural gas. Since control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized as the net amount received from the purchaser. The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Derivatives. All the Company’s derivatives are accounted for as non-hedge derivatives and are recorded at estimated fair value in the consolidated balance sheets. All changes in the fair values of its derivative contracts are recorded as gains or losses in the earnings of the periods in which they occur. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company’s credit risk related to derivatives is a counterparties’ failure to perform under derivative contracts owed to the Company. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures. 89 The Company has entered into International Swap Dealers Association Master Agreements (“ISDA Agreements”) with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note 5 for additional information. Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the carrying amounts for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date. The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50 percent) that some portion or all the deferred tax assets will not be realized. The Company has not established a valuation allowance as of December 31, 2023 and 2022. Tax benefits from an uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company’s deferred tax liability and will affect the Company’s effective tax rate in the period it is recognized. See Note 13 for additional information. Tax-related interest charges are recorded as interest expense and any tax-related penalties as other expense in the consolidated statements of operations of which there have been none to date. The Company is also subject to Texas Margin Tax. The Company realized no current Texas Margin Tax in the accompanying consolidated financial statements as we do not anticipate owing any Texas Margin Tax for the periods presented. Stock-based compensation. Stock-based compensation expense for stock option awards is measured at the grant date or modification date, as applicable, using the fair value of the award, and is recorded, net of forfeitures, on a straight-line basis over the requisite service period of the respective award. The fair value of stock option awards is determined on the grant date or modification date, as applicable, using a Black-Scholes option valuation model with the following inputs; (i) the grant date’s closing stock price, (ii) the exercise price of the stock options, (iii) the expected term of the stock option, (iv) the estimated risk-free adjusted interest rate for the duration of the option’s expected term, (v) the expected annual dividend yield on the underlying stock and (vi) the expected volatility over the option’s expected term. Stock-based compensation for restricted stock awarded to outside directors, employee members of the Board and certain other employees is measured at the grant date using the fair value of the award and is recognized on a straight-line basis over the requisite service period of the respective award. Segments. Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. Recently adopted accounting pronouncements. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments – Credit Losses.” This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investment in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. The Company adopted this update effective January 1, 2023. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity since it does not have a history of credit losses. New accounting pronouncements not yet adopted. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures,” which enhances the transparency and decision usefulness of income tax disclosures. The amendments address more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. The ASU also includes certain other amendments to improve the effectiveness of income tax disclosures. The amendments in this ASU are effective for public business entities for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of this guidance. In November 2023, the FASB issued ASU 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” This ASU updates reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses and information used to assess segment performance. The amendments in this ASU are effective for public entities for fiscal years beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The Company is still evaluating the effect of the adoption of this guidance. The Company considers the applicability and the impact of all ASUs. ASUs were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed. 90 NOTE 3. Acquisitions and Divestitures Hannathon Acquisition . In June 2022, the Company closed the Hannathon Acquisition for total net consideration of $ 337.2 million after normal and customary closing adjustments, including 3,522,117 shares of HighPeak Energy common stock valued at $ 97.2 million at closing to acquire various crude oil and natural gas properties largely contiguous to its Signal Peak operating area in Howard County, including associated producing properties, water system infrastructure and in-field fluid gathering pipelines. The Hannathon Acquisition was accounted for as an asset acquisition as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. The consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. All transaction costs associated with the Hannathon Acquisition were capitalized. Alamo Acquisitions . In March and June 2022, the Company closed the Alamo Acquisitions in two separate deals for total net consideration of $ 156.1 million and $ 11.0 million, respectively, after normal and customary closing adjustments, including 6,960,000 and 371,517 shares of HighPeak Energy common stock valued at $ 156.6 million and $ 11.2 million, respectively, at closing to acquire various crude oil and natural gas properties contiguous to its Flat Top operating area in Borden county, including associated producing properties, water system infrastructure and in-field fluid gathering pipelines. The Alamo Acquisitions were accounted for as asset acquisitions as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. The consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values. All transaction costs associated with the Alamo Acquisitions were capitalized. Other Acquisitions . During the years ended December 31, 2023 and 2022, the Company also incurred an additional $ 15.1 million and $ 23.0 million, respectively, in acquisition costs primarily to acquire various undeveloped crude oil and natural gas properties largely contiguous to its Signal Peak and Flat Top operating areas primarily in Howard, Borden, Mitchell and Scurry counties. During the year ended December 31, 2021, the Company incurred a total of $ 54.0 million in acquisition costs related to multiple bolt-on producing property acquisitions and lease acquisitions to acquire interests in non-operated producing wells and undeveloped acreage in and around the Company’s existing properties. Divestitures. During the year ended December 31, 2021, the Company realized net proceeds of $ 3.3 million, which reduced the Company’s proved properties with no gain or loss recognized when it divested of 1 gross ( 0.2 net) non-operated horizontal well and acquired 4 gross ( 3.7 gross) operated vertical wells in a trade with another operator whereby the Company traded an approximate equal number of net mineral acres to increase its working interest in certain areas of Flat Top where it serves as operator and decrease its working interest in other areas of Flat Top where the other party serves as operator. NOTE 4. Fair Value Measurements The Company determines fair value based on the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The three input levels of the fair value hierarchy are as follows: ● Level 1 – quoted prices for identical assets or liabilities in active markets. ● Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. ● Level 3 – unobservable inputs for the asset or liability, typically reflecting management’s estimate of assumptions that market participants would use in pricing the asset or liability. The fair values are therefore, determined using model-based techniques, including discounted cash flow models. 91 Assets and liabilities measured at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and 2022 are as follows (in thousands): As of December 31, 2023 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Assets: Commodity price derivatives – current $ — $ 31,480 $ — $ 31,480 Commodity price derivatives – noncurrent — 16,059 — 16,059 Total assets — 47,539 — 47,539 Liabilities: Commodity price derivatives – current — 13,054 — 13,054 Commodity price derivatives – noncurrent — 65 — 65 Total liabilities — 13,119 — 13,119 Total recurring fair value measurements $ — $ 34,420 $ — $ 34,420 As of December 31, 2022 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Assets: Commodity price derivatives– current $ — $ 17 $ — $ 17 Liabilities: Commodity price derivatives – current — 16,702 — 16,702 Commodity price derivatives – noncurrent — 691 — 691 Total liabilities — 17,393 — 17,393 Total recurring fair value measurements $ — $ ( 17,376 ) $ — $ ( 17,376 ) Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil swap contracts, enhanced collars and deferred premium put options. The Company measures derivatives using an industry-standard pricing model that is provided by the counterparties. The inputs utilized in the third-party discounted cash flow and option-pricing models for valuing commodity price derivatives include forward prices for crude oil, contracted volumes, volatility factors and time to maturity, which are considered Level 2 inputs. Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Specifically, (i) stock-based compensation is measured at fair value on the date of grant based on Level 1 inputs for restricted stock awards or Level 2 inputs for stock option awards based upon market data, and (ii) the estimates and fair value measurements used for the evaluation of proved property for potential impairment using Level 3 inputs based upon market conditions in the area. The Company assesses the recoverability of the carrying amount of certain assets and liabilities whenever events or changes in circumstances indicate the carrying amount of an asset or liability may not be recoverable. These assets and liabilities can include inventories, proved and unproved crude oil and natural gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. The Company did not record any impairments to proved or unproved crude oil and natural gas properties for the periods presented in the accompanying consolidated financial statements. Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidating balance sheets are as follows (in thousands): As of December 31, 2023 As of December 31, 2022 Carrying Carrying Value Fair Value Value Fair Value Liabilities: Long-term debt: 10.625% Senior Notes (a) $ — $ — $ 250,000 $ 250,000 10.000% Senior Notes (a) $ — $ — $ 225,000 $ 225,000 (a) Fair value is determined using Level 2 inputs. The Company’s senior unsecured notes are quoted, but not actively traded, on major exchanges; therefore, fair value is based on periodic values as quoted on major exchanges. See Note 7 for additional information. The Company has other financial instruments consisting primarily of cash and cash equivalents, accounts receivable, accounts payable, long-term debt (specifically the Term Loan Credit Agreement, Senior Credit Facility Agreement and the Prior Credit Agreement), and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. 92 NOTE 5. Derivative Financial Instruments The Company primarily utilizes commodity swap contracts, deferred premium put options and enhanced collars to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company’s capital budgeting and expenditure plans, (iii) protect the Company’s commitments under the Term Loan Credit Agreement and Senior Credit Facility Agreement and (iv) support the payment of contractual obligations. The following table summarizes the effect of derivative instruments on the Company’s consolidated statements of operations (in thousands): Year Ended December 31, 2023 2022 2021 Noncash gain (loss) on derivative instruments, net $ 51,796 $ ( 1,909 ) $ ( 15,467 ) Cash paid on settlement of derivative instruments, net ( 24,194 ) ( 58,096 ) ( 11,267 ) Gain (loss) on derivative instruments, net $ 27,602 $ ( 60,005 ) $ ( 26,734 ) Crude oil production derivatives. The Company sells its crude oil production at the lease and the sales contracts governing such crude oil production are tied directly to, or are correlated with, NYMEX WTI crude oil prices. As such, the Company uses NYMEX WTI derivative contracts to manage future crude oil price volatility. The Company’s outstanding crude oil derivative instruments as of December 31, 2023 and the weighted average crude oil prices and premiums payable per barrel for those contracts are as follows: Swaps Enhanced Collars & Deferred Premium Puts Settlement Month Settlement Year Type of Contract Bbls Per Day Index Price per Bbl Floor or Strike Price per Bbl Ceiling Price per Bbl Deferred Premium Payable per Bbl Crude Oil: Jan - Mar 2024 Swap 4,000 WTI $ 84.00 $ — $ — $ — Jan - Mar 2024 Collar 6,000 WTI $ — $ 80.00 $ 100.00 $ 3.50 Jan - Mar 2024 Put 20,000 WTI $ — $ 66.44 $ — $ 5.00 Apr - Jun 2024 Swap 4,000 WTI $ 84.00 $ — $ — $ — Apr - Jun 2024 Collar 5,500 WTI $ — $ 69.73 $ 95.00 $ 0.61 Apr - Jun 2024 Put 14,000 WTI $ — $ 60.41 $ — $ 5.00 Jul - Sep 2024 Swap 4,000 WTI $ 84.00 $ — $ — $ — Jul - Sep 2024 Collar 1,500 WTI $ — $ 69.00 $ 95.00 $ 0.85 Jul - Sep 2024 Put 14,000 WTI $ — $ 60.41 $ — $ 5.00 Oct - Dec 2024 Swap 5,500 WTI $ 76.37 $ — $ — $ — Oct - Dec 2024 Collar 10,600 WTI $ — $ 65.68 $ 90.32 $ 1.85 Oct - Dec 2024 Put 2,000 WTI $ — $ 58.00 $ — $ 5.00 Jan - Mar 2025 Swap 5,500 WTI $ 76.37 $ — $ — $ — Jan - Mar 2025 Collar 8,000 WTI $ — $ 65.00 $ 90.00 $ 2.12 Jan - Mar 2025 Put 2,000 WTI $ — $ 58.00 $ — $ 5.00 Apr - Jun 2025 Swap 5,500 WTI $ 76.37 $ — $ — $ — Apr - Jun 2025 Collar 7,000 WTI $ — $ 65.00 $ 90.08 $ 2.28 Apr - Jun 2025 Put 2,000 WTI $ — $ 58.00 $ — $ 5.00 Jul - Sep 2025 Swap 3,000 WTI $ 75.85 $ — $ — $ — Jul - Sep 2025 Collar 7,000 WTI $ — $ 65.00 $ 90.08 $ 2.28 Jul - Sep 2025 Put 2,000 WTI $ — $ 58.00 $ — $ 5.00 93 The Company uses credit and other financial criteria to evaluate the credit standings of, and to select, counterparties to its derivative financial instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative financial instruments, associated credit risk is mitigated by the Company’s credit risk policies and procedures. Net derivative assets associated with the Company’s open commodity derivative instruments by counterparty are as follows (in thousands): As of December 31, 2023 Mercuria Energy Trading SA $ 19,520 Wells Fargo Bank, National Association 7,570 Fifth Third Bank, National Association 5,004 Macquarie Bank Limited 2,326 $ 34,420 NOTE 6. Exploratory/Extension Well Costs The Company capitalizes exploratory/extension wells and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company’s capitalized exploratory/extension well and project costs are included in proved properties in the consolidated balance sheets. If the exploratory/extension well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense. The changes in capitalized exploratory/extension well costs are as follows (in thousands): Year Ended December 31, 2023 2022 2021 Beginning capitalized exploratory/extension well costs $ 186,427 $ 28,076 $ 32,592 Additions to exploratory/extension well costs 527,502 655,294 189,859 Reclassification to proved properties ( 673,041 ) ( 496,943 ) ( 194,375 ) Exploratory/extension well costs charged to exploration and abandonment expense — — — Ending capitalized exploratory/extension well costs $ 40,888 $ 186,427 $ 28,076 All capitalized exploratory/extension well costs have been capitalized for less than one year based on the date of drilling. NOTE 7. Long-Term Debt The components of long-term debt, including the effects of discounts and debt issuance costs, are as follows (in thousands): December 31, 2023 2022 Term Loan Credit Agreement due 2026 $ 1,200,000 $ — Senior Credit Facility Agreement due 2026 — — Prior Credit Agreement — 270,000 10.625% Senior Notes — 250,000 10.000% Senior Notes — 225,000 Discounts, net (a) ( 27,062 ) ( 27,086 ) Debt issuance costs, net (b) ( 22,639 ) ( 13,565 ) Total debt 1,150,299 704,349 Less current maturities of long-term debt ( 120,000 ) — Long-term debt, net $ 1,030,299 $ 704,349 (a) Discounts as of December 31, 2023 and 2022 consisted of $ 30.0 million and $ 34.8 million, respectively, in discounts less accumulated amortization of $ 2.9 million and $ 7.7 million, respectively. (b) Debt issuance costs as of December 31, 2023 and 2022 consisted of $ 25.0 million and $ 19.7 million, respectively, in costs less accumulated amortization of $ 2.4 million and $ 6.1 million, respectively. 94 Term Loan Credit Agreement. On September 12, 2023, the Company entered into a Term Loan Credit Agreement with Texas Capital Bank (“Texas Capital”) as the administrative agent and Chambers Energy Management, LP (“Chambers”) as collateral agent and lenders from time-to-time party thereto to establish a term loan (“Term Loan Credit Agreement”) totaling $ 1.2 billion in borrowings, less a 2.5 % original issue discount of $ 30.0 million at closing and customary debt issuance costs which totaled approximately $ 24.0 million. The Term Loan Credit Agreement matures on September 30, 2026. Loans under the Term Loan Credit Agreement bear interest at a rate per annum equal to the Adjusted Term SOFR (as defined in the Term Loan Credit Agreement) plus an applicable margin of 7.50 %. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Term Loan Credit Agreement) under the Term Loan Credit Agreement, all amounts outstanding under the Term Loan Credit Agreement will bear interest at 2.00 % per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date, subject to a concurrent payment of (i) the Make-Whole Amount (as defined in the Term Loan Credit Agreement) for any optional prepayment prior to the date 18 months after the closing date, (ii) 1.00 % of the principal amount being repaid for any optional prepayment on or after the date 18 months after the closing date but prior to the date 24 months after the closing date and (iii) without any premium for any optional prepayment on or after the date that is 24 months after the closing date. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries. The Term Loan Credit Agreement also contains certain financial covenants, including (i) an asset coverage ratio that may not be less than 1.50 to 1.00 as of the last day of any fiscal quarter and (ii) a total net leverage ratio that may not exceed 2.00 to 1.00 as of the last day of any fiscal quarter. Additionally, the Term Loan Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with such exceptions including, among other things, a super priority revolving credit facility limited to $ 100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, materially increase dividends and other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures based on the Company’s total net leverage ratio. The Term Loan Credit Agreement contains customary mandatory prepayments, including quarterly installments of $ 30.0 million in aggregate principal amount beginning March 31, 2024, the prepayment of gross proceeds from an incurred indebtedness other than Permitted Indebtedness (as defined in the Term Loan Credit Agreement), the prepayment of net cash proceeds for asset sales and hedge terminations in excess of $ 20.0 million within one calendar year, and prepayments of Excess Cash Flow (as defined in the Term Loan Credit Agreement) beginning with the fiscal quarter ending March 31, 2024. In addition, the Term Loan Credit Agreement is subject to customary events of default, including a change in control. If an event of default occurs and is continuing, the collateral agent or the majority lenders may accelerate any amounts outstanding and terminate lender commitments. Collateral Agency Agreement. On September 12, 2023, the Company entered into a collateral agency agreement (the “Collateral Agency Agreement”) among the Company, Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA, as first-out representative prior to giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023 and Fifth Third Bank, National Association as first-out representative after giving effect to that certain Collateral Agency Joinder – Additional First-Out Debt, dated as of November 1, 2023. The Collateral Agency Agreement provides for the appointment of Texas Capital, as collateral agent, for the present and future holders of the first lien obligations (including the obligations of the Company and certain of its subsidiaries under the Term Loan Credit Agreement) to receive, hold, administer and distribute the collateral that is at any time delivered to Texas Capital or the subject of the Security Documents (as defined in the Collateral Agency Agreement) and to enforce the Security Documents and all interests, rights, powers and remedies of Texas Capital with respect thereto or thereunder and the proceeds thereof. Senior Credit Facility Agreement. On November 1, 2023, the Company entered into a credit agreement with Fifth Third Bank, National Association (“Fifth Third”) as the administrative agent and as the collateral agent and a number of banks included in the syndicate to establish a senior revolving credit facility (“Senior Credit Facility Agreement”) that matures on September 30, 2026. The Senior Credit Facility Agreement has aggregate maximum commitments of $ 100.0 million with current commitments of $ 75.0 million. Loans under the Senior Credit Facility Agreement bear interest at either the Adjusted Term SOFR (as defined in the Senior Credit Facility Agreement) or the Base Rate (as defined in the Senior Credit Facility Agreement) at the Company’s option, plus an applicable margin ranging (i) for Adjusted Term SOFR loans, from 4.00% to 5.00%, and (ii) for Base Rate loans, from 3.00% to 4.00%, in each case calculated based on the ratio at such time of the outstanding principal loan amounts to the aggregate amount of lenders’ commitments. To the extent that a payment default exists and is continuing, at the election of the Required Lenders (as defined in the Senior Credit Facility Agreement) under the Senior Credit Facility Agreement, all amounts outstanding under the Senior Credit Facility Agreement will bear interest at 2.00% per annum above the rate and margin otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Senior Credit Facility Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first lien security interest in substantially all assets of the Company and certain of its subsidiaries. 95 Prior Credit Agreement . In December 2020, the Company entered into a credit agreement with Fifth Third as the administrative agent and sole lender to establish a revolving credit facility (the “Prior Credit Agreement”) that was set to mature on June 17, 2024. In June 2021, the Company entered into the First Amendment to, among other things, (i) complete the semi-annual borrowing base redetermination process which increased the borrowing base from $ 40.0 million to $ 125.0 million and (ii) modify the terms of the Prior Credit Agreement to increase the aggregate elected commitments from $ 20.0 million to $ 125.0 million. A syndicate of banks joined the credit facility at differing levels of commitments with Fifth Third remaining the administrative agent. In October 2021, the Company entered into the Second Amendment to, among other things, (i) complete a semi-annual borrowing base redetermination process, which increased the borrowing base from $ 125.0 million to $ 195.0 million and (ii) modify the terms of the Prior Credit Agreement to increase the aggregate elected commitments from $ 125.0 million to $ 195.0 million. In February 2022, the Company entered into the Third Amendment to, among other things, (i) reduce the borrowing base from $ 195.0 million to $ 138.8 million, (ii) modify the terms of the Prior Credit Agreement to reduce the aggregate elected commitments from $ 195.0 million to $ 138.8 million, (iii) update the maturity date to a springing maturity date, which will cause the Prior Credit Agreement to mature on October 1, 2023 if the 10.000% Senior Notes are not redeemed or refinanced by that date or the terms of the 10.000% Senior Notes have not been amended to extend the scheduled repayment thereof to no earlier than October 1, 2024, (iv) allow the Company to redeem the 10.000% Senior Notes with proceeds of a refinancing, with proceeds of an equity offering or with cash, in each case, subject to certain customary conditions and (v) replace the USD LIBOR rates with Term SOFR rates. In June 2022, the Company entered into the Fourth Amendment to, among other things, (i) increase (a) the aggregate elected commitments to $ 400.0 million, (b) the borrowing base to $ 400.0 million and (c) the maximum credit amount to $ 1.5 billion, (ii) increase the excess cash threshold to $ 75.0 million, (iii) modify the affirmative hedging requirement so that if total debt to EBITDAX is greater than 1.25 to 1.00 but less than or equal to 1.75 to 1.00, notional volumes covering the first 24 months following the measurement date shall be hedged in an amount equal to not less than 25 % of the projected production and if total debt to EBITDAX is greater than 1.75 to 1.00, notional volumes covering the first 24 months following the measurement date shall be hedged in an amount equal to not less than 50 % of the projection production and (iv) increase the number of banks included in the syndicate at differing levels of commitments, with Fifth Third remaining the administrative agent. In October 2022, the Company entered into the Fifth Amendment to, among other things, (i) increase the elected commitments to $ 525 million and the borrowing base to $ 550 million, (ii) require an additional borrowing base redetermination on or about December 1, 2022, (iii) modify the permitted dividends and distributions conditions such that minimum availability under the credit facility must be 25 % percent (as opposed to 30 % before giving effect to the Fifth Amendment) and (iv) appoint Wells Fargo Bank, National Association (“Wells Fargo”) as the new administrative agent to replace Fifth Third. In addition, in connection with the Fifth Amendment, to the extent the Company incurs any additional specified unsecured senior, senior subordinated or subordinated future indebtedness in an aggregate amount of up to $ 250.0 million before June 30, 2023, the Company’s obligation to reduce the borrowing base by an amount equal to 25 % of the principal amount of such additional future indebtedness shall be waived. In connection with the Fifth Amendment, the lenders waived two events of default existing with the Prior Credit Agreement, as it existed prior to giving effect to the Fifth Amendment, related to entering into and maintaining certain minimum hedges as of the fiscal quarters ending June 30, 2022 and September 30, 2022 and complying with the required current ratio as of the fiscal quarter ending September 30, 2022. In October 2022, the Company entered into the Sixth Amendment to, among other things, (i) change the period to 120 days following the maturity date for which there can be no scheduled principal payments, mandatory redemption or maturity date for the 10.000% Senior Notes and the Specified Senior Notes, (ii) clarify that the Specified Senior Notes are subject to the restriction on the voluntary redemption by the Company of certain specified additional debt, including the 10.000% Senior Notes, (iii) add a permitted lien basket in connection with the escrow account to be opened in connection with the Specified Senior Notes and (iv) provide for an exception for the restriction on mandatory redemptions of the Specified Senior Notes in connection with the special mandatory redemption provided for with respect to the Specified Senior Notes. In December 2022, the Company entered into the Seventh Amendment to, among other things, increase the amount of Specified Senior Notes from $ 225.0 million to $ 250.0 million. In March 2023, the Company entered into the Eighth Amendment to, among other things, (a) increase the borrowing base to $ 700.0 million, (b) add an aggregate elected commitments concept at an initial amount of $ 575.0 million, (c) provide that the applicable margin shall be determined in reference to such aggregate elected commitments (as opposed to being determined in reference to the borrowing base before giving effect to the Eighth Amendment), (d) modify the permitted dividends and distributions conditions such that minimum availability under the credit facility must be 25 % of such aggregate elected commitments (as opposed to the borrowing base before giving effect to the Eighth Amendment), (e) permit quarterly dividends and distributions in an amount not to exceed $ 4.0 million provided that there is no default and that after giving effect thereto and any concurrent borrowing, the Company is in pro forma compliance with its financial covenants, (f) require the Company, on or before June 30, 2023, to redeem or refinance the 10.000% Senior Notes, allocate a portion of its cash flow that will retire the 10.000% Senior Notes on or before November 30, 2023 or amend the terms of the 10.000% Senior Notes to extend the scheduled repayment thereof to no earlier than February 15, 2025, (g) permit the redemption of Specified Additional Debt (defined in the Prior Credit Agreement to mean any unsecured senior, senior subordinated or subordinated Debt of the Borrower incurred after the Effective Date and any refinancing of such Debt, including without limitation, the 10.000% Senior Notes; provided that any such Debt may be refinanced only to the extent that the aggregate principal amount of such refinanced Debt does not result in an increase in the principal amount thereof plus amounts to fund any original issue discount or upfront fees relating thereto plus amounts to fund accrued interest, fees, expenses and premiums, with all Capitalized terms defined in such Prior Credit Agreement) with the proceeds of Loans if pre-approved by all Lenders provided that there is no default and that after giving effect thereto, the Company is in pro forma compliance with its financial covenants and (h) add Texas Capital Bank as a Lender. 96 In July 2023, the Company entered into the Ninth Amendment to, among other things, provide for (i) a waiver of the minimum current ratio covenant for the fiscal quarter ended June 30, 2023 under the Prior Credit Agreement, (ii) a waiver of the failure to subject one or more certain accounts to an Account Control Agreement within the period provided in the Prior Credit Agreement, (iii) a postponement of the April 2023 borrowing base redetermination until September 2023, (iv) a postponement of the date on which the Company was previously obligated thereunder to either extend the maturity of the 10.000% Senior Notes due February 2024, redeem or refinance the 10.000% Senior Notes or allocate a portion of the Company’s cash flow satisfactory to the Administrative Agent and the Majority Lenders that will retire the 10.000% Senior Notes on or before November 30, 2023 to September 1, 2023 or such later date as agreed to in writing by the Majority Lenders in their reasonable discretion, (v) certain pricing increases and additional minimum hedging requirements, (vi) an additional requirement to deliver a 13-week cash flow forecast on a weekly basis through completion of the September 2023 borrowing base redetermination and (vii) a temporary restriction on borrowing further amounts under the Prior Credit Agreement until the Company has received at least $ 95 million of net proceeds from the sales of the Company’s equity securities, which has been subsequently satisfied and the restriction no longer applies. In connection with the entry into the aforementioned Term Loan Credit Agreement, the Prior Credit Agreement was terminated, all outstanding obligations for principal, interest and fees were paid off in full, and all liens securing such obligations and guarantees of such obligations and securing any letter of credit or hedging obligations (other than those novated pursuant to the terms of the Term Loan Credit Agreement) permitted by the Prior Credit Agreement to be secured by such liens were released. In addition, unamortized debt issuance costs as of the termination date of $ 2.7 million were charged to expense and included in the accompanying consolidated statements of operations in loss on extinguishment of debt. 10.000% Senior Notes. In February 2022, the Company issued $ 225.0 million aggregate principal amount of its 10.000 % Senior Notes due 2024 (“10.000% Senior Notes”), which were set to mature on February 15, 2024. The Company received proceeds of $ 202.9 million, net of $ 22.1 million of issuance costs and discounts. The net proceeds were used to pay down the balance of the Prior Credit Agreement to zero at closing and to fund our ongoing capital development program with subsequent draws on the Prior Credit Agreement. Interest on the 10.000% Senior Notes was payable on February 15 and August 15 of each year. In connection with the aforementioned Term Loan Credit Agreement, the 10.000% Senior Notes were redeemed at a redemption price of 100% of the principal amount thereof plus accrued and unpaid interest and fees. In addition, unamortized discounts and debt issuance costs as of the redemption date of $ 3.2 million and $ 1.5 million, respectively, were charged to expense and included in the accompanying consolidated statements of operations in loss on extinguishment of debt. 10.625% Senior Notes. In November 2022 and December 2022, the Company issued $ 225.0 million and $ 25.0 million, respectively, under separate indentures, of its 10.625% Senior Notes due 2024 (“ 10.625 % Senior Notes”), which were set to mature on November 15, 2024. The Company received proceeds of $ 223.7 million, net of $ 26.3 million of issuance costs and discounts. The net proceeds were used to reduce the outstanding balance of the Prior Credit Agreement at closing and for general corporate purposes. Interest on the 10.625% Senior Notes was payable on May 15 and November 15 of each year. In addition, the Company paid additional interest of $ 8.3 million in June 2023 in accordance with the indentures whereby if the Company did not receive a rating increase by June 30, 2023, it was required to pay said additional interest that is included in interest expense during the nine months ended September 30, 2023. In connection with the aforementioned Term Loan Credit Agreement, the 10.625% Senior Notes were redeemed at a redemption price of 100% of the principal amount thereof plus accrued and unpaid interest and fees, plus the applicable premium calculated as $ 4.5 million, which was the present value at September 14, 2023 of all required interest payments due on the 10.625% Senior Notes through November 15, 2023. In addition, unamortized discounts and debt issuance costs as of the redemption date of $ 11.7 million and $ 3.7 million, respectively, were charged to expense and included in the accompanying consolidated statements of operations in loss on extinguishment of debt. The Term Loan Credit Agreement and the Senior Credit Facility Agreement have hedging requirements to which the Company adheres. NOTE 8. Asset Retirement Obligations The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company’s credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. 97 Asset retirement obligations activity is as follows (in thousands): Year Ended December 31, 2023 2022 2021 Beginning asset retirement obligations $ 7,502 $ 4,260 $ 2,293 Liabilities incurred from new wells 445 573 980 Liabilities assumed in acquisitions 2,638 3,219 981 Liabilities divested ( 81 ) — ( 6 ) Dispositions — — ( 25 ) Revision of estimates (a) 2,219 ( 920 ) ( 130 ) Accretion of discount 522 370 167 Ending asset retirement obligations $ 13,245 $ 7,502 $ 4,260 (a) The revisions to the Company’s asset retirement obligation estimates are primarily due to changes in the ultimate expected useful lives of the properties. As of December 31, 2023 and 2022, all asset retirement obligations are considered noncurrent and classified as such in the accompanying consolidated balance sheets. NOTE 9. Incentive Plans 401(k) Plan. The HighPeak Energy Employees, Inc 401(k) Plan (the “401(k) Plan”) is a defined contribution plan established under Section 401 of the Internal Revenue Code of 1986, as amended (the “Code”). All regular full-time and part-time employees of the Company are eligible to participate in the 401(k) Plan after three continuous months of employment with the Company. Participants may contribute up to 80 percent of their annual base salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by the Company in amounts equal to 100 percent of a participant’s contributions to the 401(k) Plan up to four percent of the participant’s annual base salary (the “Matching Contribution”). Each participant’s account is credited with the participant’s contributions, Matching Contributions and allocations of the 401(k) Plan’s earnings. Participants are fully vested in their account balances at their eligibility date. During the years ended December 31, 2023, 2022 and 2021, the Company contributed $ 218,000 , $ 358,000 and $ 227,000 to the 401(k) Plan, respectively. Long-Term Incentive Plan. The Company’s Second Amended & Restated Long Term Incentive Plan (“LTIP”) provides for the grant of stock options, restricted stock, stock awards, dividend equivalents, cash awards and substitute awards to officers, employees, directors and consultants of the Company. The number of shares available for grant pursuant to awards under the LTIP as of December 31, 2023 and 2022 are as follows: December 31, 2023 2022 Approved and authorized shares 16,414,015 14,340,324 Shares subject to awards issued under plan ( 15,759,791 ) ( 13,769,191 ) Shares available for future grant 654,224 571,133 Stock options. Stock option awards were granted to employees on August 24, 2020, November 4, 2021, May 4, 2022, August 15, 2022 and July 21, 2023. Stock-based compensation expense related to the Company’s stock option awards for the years ended December 31, 2023 and 2022 was $ 11.0 million and $ 18.1 million, respectively, and as of December 31, 2023 and 2022 there was $ 145,000 and $ 1.1 million, respectively, of unrecognized stock-based compensation expense related to unvested stock option awards. The unrecognized compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than one year. The 1,949,000 stock options granted in July 2023 were 100 % vested upon grant on July 21, 2023. However, to encourage long-term alignment with the Company stockholders, the stock options are not exercisable until the earlier of (i) August 31, 2026, (ii) upon a change in control or (iii) upon the death or disability of the grantee. 98 The Company estimates the fair values of stock options granted on the grant date using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The expected term of options granted was determined based on the simplified method of the midpoint between the vesting dates and the contractual term of the options. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant and the volatility was based on the volatility of either an index of exploration and production crude oil and natural gas companies or on a peer group of companies with similar characteristics of the Company on the date of grant since the Company had minimal or did not have any trading history. More detailed stock options activity and details are as follows: Stock Options Average Exercise Price Remaining Term in Years Intrinsic Value (in thousands) Outstanding at December 31, 2021 9,983,727 $ 10.19 8.7 $ 44,395 Awards granted 1,564,500 $ 25.09 Exercised ( 12,000 ) $ 10.00 Forfeitures ( 18,999 ) $ 18.66 Outstanding at December 31, 2022 11,517,228 $ 12.20 7.9 $ 128,429 Awards granted 1,949,000 10.50 Exercised ( 11,834 ) $ 12.52 Forfeitures ( 5,333 ) $ 24.83 Outstanding at December 31, 2023 13,449,061 $ 11.95 6.3 $ 47,672 Vested at December 31, 2022 11,304,747 $ 12.02 7.9 $ 127,591 Exercisable at December 31, 2022 11,304,747 $ 12.02 7.9 $ 127,591 Vested at December 31, 2023 13,387,074 $ 11.88 6.3 $ 47,672 Exercisable at December 31, 2023 11,438,074 $ 12.12 6.9 $ 40,383 Restricted stock issued to employee members of the Board and certain employees. A total of 1,500,500 shares of restricted stock was approved by the Board to be granted to certain employee members of the Board of the Company on November 4, 2021, which vest on the three -year anniversary of such grant assuming the employees remain in his or her position as of the anniversary date. Therefore, stock-based compensation expense of $ 7.2 million, $ 7.2 million and $ 1.2 million was recognized during the years ended December 31, 2023, 2022 and 2021, respectively, and the remaining $ 6.0 million as of December 31, 2023 will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuance. The Board also cancelled the previously issued equity-based liability bonuses and approved a total of 600,000 shares of restricted stock to be granted to certain employees of the Company on June 1, 2022, which vest on November 4, 2024, assuming the employees remain in his or her position as of that date and cancelled certain contractual equity-based bonuses to such employees. Therefore, stock-based compensation expense of $ 7.0 million, $ 7.3 million and $ 488,000 was recognized during the years ended December 31, 2023, 2022 and 2021, respectively, and the remaining $ 5.9 million as of December 31, 2023 will be recognized over the remaining restricted period, which was based upon the closing price of the stock on the date of the restricted stock issuance. Stock issued to outside directors. A total of 58,767 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2023, which will vest at the next annual meeting, assuming the Board members maintain their positions on the Board. Therefore, stock-based compensation expense of $ 442,000 was recognized during the year ended December 31, 2023 and the remaining $ 316,000 will be recognized between January and May 2024, which was based upon the closing price of the stock on the date of the restricted stock issuance. In addition, a total of 21,184 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2022, which vested during the second quarter of 2022. Therefore, stock-based compensation expense of $ 305,000 , $ 427,000 was recognized during the years ended December 31, 2023 and 2022, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. Finally, a total of 67,779 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 1, 2021, which vested in January 2022. Therefore, stock-based compensation expense of $ 284,000 and $ 398,000 was recognized during the years ended December 31, 2022 and 2021, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. NOTE 10. Commitments and Contingencies Leases. The Company follows ASC Topic 842, “Leases” to account for its operating and finance leases. Therefore, as of December 31, 2023, the Company had right-of-use assets totaling $ 510,000 included in other noncurrent assets and operating lease liabilities totaling $ 528,000 , all of which are included in current liabilities, and as of December 31, 2022 the Company had right-of-use assets totaling $ 333,000 included in other noncurrent assets and operating lease liabilities totaling $ 343,000 , included in other current liabilities on the accompanying consolidated balance sheets. The Company does not currently have any finance right-of-use leases. Maturities of the operating lease obligations are as follows (in thousands): December 31, 2023 2024 $ 552 Less present value discount ( 24 ) Present value of lease liabilities $ 528 Legal actions. From time to time, the Company may be a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company’s consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable, and the amount of the loss can be reasonably estimated. 99 Indemnifications. The Company has agreed to indemnify its directors, officers and certain employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation. Environmental. Environmental expenditures that relate to an existing condition caused by past operations and have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement or remediation occurs. Crude oil delivery commitments. In May 2021, the Company entered into a crude oil marketing contract with DK Trading & Supply, LLC (“Delek”) as the purchaser and DKL Permian Gathering, LLC (“DKL”) as the gatherer and transporter. The contract includes the Company’s current and future crude oil production from the majority of its horizontal wells in Flat Top where DKL is continually constructing a crude oil gathering system and custody transfer meters to most of the Company’s central tank batteries. The contract contains a minimum volume commitment commencing October 2021 based on the gross barrels delivered at the Company’s central tank battery facilities and is 5,000 Bopd for the first year, 7,500 Bopd for the second year and 10,000 Bopd for the remaining eight years of the contract. However, the Company has the ability under the contract to cumulatively bank excess volumes delivered to offset future minimum volume commitments. For the period from October 1, 2021 to December 31, 2023, the Company has delivered approximately 29,600 Bopd under the contract which is approximately 72 percent of the contracted volume for the life of the contract. The monetary commitment for the remaining 9.5 MMBbl as of December 31, 2023, if the Company never delivers any additional volumes under the agreement, is approximately $ 7.8 million. Natural gas purchasing replacement contract. In May 2021, the Company entered into a replacement natural gas purchase contract with WTG Gas Processing, L.P. (“WTG”) as the gatherer, processor and purchaser of the Company’s current and future gross natural gas production in Flat Top. The replacement contract provides the Company with improved natural gas and NGL pricing and required WTG to expand its current low-pressure gathering system, which eliminates the need for in-field compression in Flat Top to accommodate the Company’s increased natural gas production volumes based on the current plan of development. The Company provides WTG with certain aid-in-construction payments to be reimbursed over time based on throughput through the system. The replacement contract does not contain any minimum volume commitments. Power contracts. In June 2022, the Company entered into a contract with TXU Energy Retail Company LLC (“TXU”) to provide a block of electric power at an attractive variable rate, which fluctuates based on the usage by the Company through May 31, 2032. In conjunction with this contract, the Company currently has a $ 3.9 million letter of credit issued in lieu of a deposit to TXU that is cancellable at the end of the contract term. Sand commitments. The Company is party to an amended agreement whereby it has agreed to purchase at least 1.6 million tons of sand over a two-year period beginning July 1, 2022. There are stipulations in the agreement that reduce this commitment should there be a downturn in crude oil prices. As of December 31, 2023, the Company has purchased approximately 1.2 million tons of sand under the contract. However, generally if the Company never takes delivery of any additional sand under the agreement, the monetary commitment that remains as of December 31, 2023 is approximately $ 9.5 million. NOTE 11. Related Party Transactions Underwritten Equity Offering. In connection with the Company’s underwritten equity offering in July 2023, certain of the Company’s existing stockholders, John Paul DeJoria Family Trust and Jack Hightower, the Company’s Chairman and Chief Executive Officer, and entities and individuals associated with them, purchased an aggregate of approximately 10 million shares of common stock in the offering at the public offering price per share. In connection therewith, the Underwriter received a reduced underwriting discount on such shares purchased by these persons or entities compared with other shares sold to the public in the offering. Water Treatment. In September 2021, the Company entered into a contract with Pilot Exploration, Inc., (“Pilot”), whose President and CEO was an outside director of the Company, to deploy Pilot’s proprietary water treatment technology in the Company’s Flat Top area to treat up to 25,000 barrels of produced water per day that can be reused in the Company’s completion operations or sold to third parties for their completion operations. This contract was set to expire on March 1, 2022; however, it was extended to October 1, 2022 based on the early results of the project. During the year ended December 31, 2022, the Company paid $ 2.0 million to Pilot for such services. In May 2022, the Company entered into an agreement with Pilot to utilize Pilot’s proprietary water treatment technology in the Company’s Flat Top area to treat produced water such that it can be reused in the Company’s completion operations or sold to third parties for their completion operations. During the one-year term of the agreement, beginning on October 1, 2022, the Company agreed to a minimum volume commitment of 29.2 million barrels of produced water while maintaining the ability to bank excess produced water processed each month toward the minimum volume commitment. During the years ended December 31, 2023 and 2022, the Company paid $ 1.5 million and $ 1.6 million, respectively, to Pilot for such services. In April 2023, the Company terminated the contract with Pilot in exchange for $ 6.5 million that was charged to other expense in the accompanying consolidated statements of operations during the year ended December 31, 2023. 100 Private Investment in Public Equity. On August 22 and 23, 2022, HighPeak Energy entered into multiple Subscription Agreements (the “Subscription Agreements”) with certain accredited investors (collectively, the “Investors”) pursuant to which, among other things, the Investors agreed to subscribe for and purchase, and the Company agreed to issue and sell to the Investors, an aggregate 2,855,162 newly issued shares of the Company’s common stock at a price per share of $ 21.61 (as determined by the 5-day volume weighted average trading price per share for the five trading days immediately prior to (and excluding) August 22, 2022), for aggregate gross proceeds of approximately $ 61.7 million. The Company used the proceeds of the Private Placement for general corporate purposes. The transactions contemplated by the Subscription Agreements closed in multiple closings on or about September 2, 2022, subject to customary closing conditions. As part of the private placement, certain related persons of the Company participated as investors, and such participation was approved by the Board pursuant to and in accordance with the terms of the Related Party Transactions Policy adopted by the Board on August 21, 2020. Specifically, Messrs. Jack Hightower (the Company’s Chief Executive Officer), Michael Hollis (the Company’s President), Steven Tholen (the Company’s Chief Financial Officer), Rodney Woodard (the Company’s Chief Operating Officer) and John Paul DeJoria as trustee for the John Paul DeJoria Family Trust (a greater than ten percent (10%) holder of the Company’s outstanding common stock) entered into Subscription Agreements to purchase 462,749 , 46,276 , 9,255 , 23,138 and 2,313,744 shares of common stock, respectively, in each case on substantially the same terms as other investors in the private placement. In addition, each Subscription Agreement with an investor other than Messrs. Hightower and DeJoria (each of which has existing registration rights with respect to the Company’s securities) provides for customary registration rights with respect to the shares issued thereunder, including the right to have such shares registered for resale on a “shelf” registration statement. NOTE 12. Major Customers Delek accounted for approximately 82 %, 88 % and 94 % of the Company’s revenues during the years ended December 31, 2023, 2022 and 2021, respectively. In addition, Energy Transfer Crude Marketing, LLC (“ETC”) accounted for approximately 14 % of the Company’s revenues during the year ended December 31, 2023. Based on the current demand for crude oil and natural gas and the availability of other purchasers, management believes the loss of these major purchasers would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers. NOTE 13. Income Taxes Enactment of the Inflation Reduction Act of 2022. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, imposes a 15 percent corporate alternative minimum tax on corporations with book financial statement income in excess of $1.0 billion, effective for tax years beginning after December 31, 2022. The IRA 2022 also establishes a one percent excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases in excess of an annual limit of $1.0 million after December 31, 2022. The IRA 2022 did not impact the Company’s current year tax provision or the Company’s consolidated financial statements. The Company is evaluating the accounting and disclosure implications of the IRA 2022 on its future filings. The Company’s income tax expense attributable to income from operations consisted of the following (in thousands): Year Ended December 31, 2023 2022 2021 Current income tax expense: Federal $ — $ — $ — State — — — Total current income tax expense — — — Deferred income tax expense: Federal 63,002 73,026 15,084 State 2,903 2,335 1,820 Deferred income tax expense 65,905 75,361 16,904 Total income tax expense $ 65,905 $ 75,361 $ 16,904 101 The reconciliation between the income tax expense computed by multiplying pre-tax income by the U.S. federal statutory rate and the reported amounts of income tax expense is as follows (in thousands, except rate): Year Ended December 31, 2023 2022 2021 Income tax expense at U.S. federal statutory rate $ 59,172 $ 65,565 $ 15,217 Limited tax benefit due to wage and stock-based compensation 3,811 7,362 ( 51 ) State deferred income taxes 2,903 2,335 1,730 Other 19 99 8 Income tax expense $ 65,905 $ 75,361 $ 16,904 Effective income tax rate 23.4 % 24.1 % 23.3 % The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities were as follows as of December 31, 2023 and 2022 (in thousands): December 31, 2023 2022 Deferred tax assets: Interest expense limitations $ 41,352 $ 10,623 Net operating loss carryforwards 13,503 5,496 Stock-based compensation 6,332 4,102 Other 36 32 Unrecognized derivative losses, net — 3,752 Less: Valuation allowance — — Deferred tax assets 61,223 24,005 Deferred tax liabilities: Crude oil and natural gas properties, principally due to differences in basis and depreciation and the deduction of intangible drilling costs for tax purposes ( 250,859 ) ( 155,169 ) Unrecognized derivative gains, net ( 7,432 ) — Deferred tax liabilities ( 258,291 ) ( 155,169 ) Net deferred tax liabilities $ ( 197,068 ) $ ( 131,164 ) The effective income tax rate differs from the U.S. statutory rate of 21 percent primarily due to reversing a portion of its deferred tax asset related to stock-based compensation, deferred state income taxes and other permanent differences between GAAP income and taxable income. As required by ASC Topic 740, “Income Taxes,” (“ASC 740”) the Company uses reasonable judgments and makes estimates and assumptions related to evaluating the probability of uncertain tax positions. The Company bases its estimates and assumptions on the potential liability related to an assessment of whether the income tax position will “more likely than not” be sustained in an income tax audit. Based on that analysis, the Company believes the Company has not taken any material uncertain tax positions, and therefore has not recorded an income tax liability related to uncertain tax positions. However, if actual results materially differ, the Company’s effective income tax rate and cash flows could be affected in the period of discovery or resolution. The Company also reviews the estimates and assumptions used in evaluating the probability of realizing the future benefits of the Company’s deferred tax assets and records a valuation allowance when the Company believes that a portion or all the deferred tax assets may not be realized. If the Company is unable to realize the expected future benefits of its deferred tax assets, the Company is required to provide a valuation allowance. The Company uses its history and experience, overall profitability, future management plans, tax planning strategies, and current economic information to evaluate the amount of valuation allowance to record. As of December 31, 2023 and 2022, the Company had not recorded a valuation allowance for deferred tax assets arising from its operations because the Company believed they met the “more likely than not” criteria as defined by the recognition and measurement provisions of ASC 740. The Company reversed a portion of its deferred tax asset related to stock-based compensation based on the assumption that the tax deduction will be subject to IRC Section 162(m) limits when the stock options are exercised and the restricted stock vests. IRC Section 162(m) limits compensation deductions to $1.0 million per year for certain Company executives. This resulted in a $ 3.4 million reduction in the deferred tax asset and reduced the amount of income tax expense realized during the year ended December 31, 2022. The Company is also subject to Texas Margin Tax. The Company realized no current Texas Margin Tax in the accompanying consolidated financial statements as we do not anticipate owing any Texas Margin Tax for 2023, 2022 or 2021. However, the Company has recognized a net deferred Texas Margin Tax liability of $ 7.1 million and $ 4.1 million as of December 31, 2023 and 2022, respectively, in the accompanying consolidated financial statements. 102 NOTE 14. Earnings Per Share The Company uses the two-class method of calculating earnings per share because certain of the Company’s stock-based awards qualify as participating securities. The Company’s basic earnings per share attributable to common stockholders is computed as (i) net income as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted earnings per share attributable to common stockholders is computed as (i) basic earnings attributable to common stockholders, (ii) plus reallocation of participating earnings (iii) divided by weighted average diluted common shares outstanding. The following table reconciles the Company’s earnings from operations and earnings attributable to common stockholders to the basic and diluted earnings used to determine the Company’s earnings per share amounts for the years ended December 31, 2023, 2022 and 2021 under the two-class method (in thousands): Year Ended December 31, 2023 2022 2021 Net income as reported $ 215,866 $ 236,854 $ 55,559 Participating basic earnings (a) ( 21,890 ) ( 22,991 ) ( 4,674 ) Basic earnings attributable to common stockholders 193,976 213,863 50,885 Reallocation of participating earnings 334 401 58 Diluted net income attributable to common stockholders $ 194,310 $ 214,264 $ 50,943 Basic weighted average shares outstanding 117,956 104,738 93,127 Dilutive warrants and unvested stock options 2,905 4,304 145 Dilutive unvested restricted stock 2,159 2,122 1,500 Diluted weighted average shares outstanding 123,020 111,164 94,772 (a) Vested stock options represent participating securities because they participate in dividend equivalents with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Certain unvested restricted stock awarded to outside directors, employee members of the Board and certain employees do not represent participating securities because, while they participate in dividends with the common equity holders of the Company, the dividends associated with such unvested restricted stock are forfeitable in connection with the forfeitability of the underlying restricted stock. Unvested stock options do not represent participating securities because, while they participate in dividend equivalents with the common equity holders of the Company, the dividend equivalents associated with unvested stock options are forfeitable in connection with the forfeitability of the underlying stock options. The calculation for weighted average shares reflects shares outstanding over the reporting period based on the actual number of days the shares were outstanding. NOTE 15. Stockholders ’ Equity Issuance of Common Stock. In July 2023, the Company issued 14,835,000 shares of its common stock in a public offering discussed below. The remaining 420,896 shares of HighPeak Energy common stock issued during the year ended December 31, 2023 were the result of warrants ( 350,295 shares) being exercised, the issuance of restricted stock ( 58,767 shares) to outside directors and stock options ( 11,834 shares) being exercised. On March 25, 2022, June 21, 2022 and June 27, 2022, respectively, the Company issued 6,960,000 , 371,517 and 3,522,117 shares of HighPeak Energy common stock related to the aforementioned crude oil and natural gas property acquisitions. On June 1, 2022, the Company issued 21,184 and 600,000 shares of restricted stock to outside directors and certain employees, respectively. On September 2, 2022, the Company closed an aggregate $ 85.0 million private placement of 3,933,376 newly issued shares of HighPeak Energy common stock at a price per share of $ 21.61 as determined by the 5-day volume weighted average closing price per share for the five days immediately prior to (and excluding) August 22, 2022. The initial closings occurred on August 22, 2022, with the final closings on September 2, 2022. The remaining 982,648 shares of HighPeak Energy common stock issued during the year ended December 31, 2022 were the result of warrants ( 970,648 shares) and stock options ( 12,000 shares) being exercised. On June 1, 2021 and November 4, 2021, the Company issued 67,779 and 1,500,500 shares of restricted stock to outside directors and employee members of the Board, respectively. In October 2022, the Company issued 2,530,000 shares of its common stock in a public offering discussed below. The remaining 708,341 shares of HighPeak Energy common stock issued during the year ended December 31, 2021 were the result of warrants ( 554,073 shares) and stock options ( 154,268 shares) being exercised. 103 Public Offerings of Common Stock. On July 19, 2023, the Company completed the offering of 1 4,835,000 shares of its common stock, at a price to the public of $ 10.50 per share, pursuant to a Registration Statement on Form S-3 (File No. 333-261706) filed on December 17, 2021. The net proceeds to the Company from the offering, after deducting the underwriting discounts and commissions and other offering expenses, were approximately $ 150.4 million. On October 25, 2021, the Company completed the offering of 2,530,000 shares of its common stock, at a price to the public of $ 10.00 per share, pursuant to a Registration Statement on Form S-1 (File No. 333-258853) filed on October 19, 2021 and a Registration Statement on Form S-1MEF (File No. 333-260394) filed with the SEC on October 20, 2021. The net proceeds to the Company from the offering, after deducting the underwriting discounts and commissions and other offering expenses, were approximately $ 22.8 million. Dividends and dividend equivalents . In October 2023, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 3.2 million in dividends being paid on November 22, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 348,000 in November 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $ 54,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In July 2023, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 3.2 million in dividends being paid on August 25, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 334,000 in August 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $ 54,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In April 2023, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.8 million in dividends being paid on May 25, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 286,000 in May 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $ 53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In January 2023, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.8 million in dividends being paid on February 24, 2023. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 282,000 in February 2023 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $ 53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In October 2022, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.8 million in dividends being paid on November 23, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 288,000 in November 2022 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company will accrue an additional combined $ 53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In July 2022, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.7 million in dividends being paid on August 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 481,000 in August 2022 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company will accrue an additional combined $ 53,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In April 2022, the Board declared a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.6 million in dividends being paid on May 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 214,000 in May 2022 and accrued a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company will accrue an additional combined $ 53,000 in dividends on the restricted stock issued to management directors and certain employees that will be payable upon vesting. In January 2022, the Board approved a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.4 million in dividends being paid on February 25, 2022. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 214,000 in February 2022 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. In addition, the Company accrued an additional combined $ 53,000 in dividends on the restricted stock issued to management directors and certain employees that will be payable upon vesting. 104 In September 2021, the Board approved a quarterly dividend of $ 0.025 per share of common stock outstanding which resulted in a total of $ 2.3 million in dividends being paid on October 25, 2021. In addition, under terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 207,000 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. In July 2021, the Board approved a quarterly dividend of $ 0.025 and a special dividend of $ 0.075 per share of common stock outstanding which resulted in a total of $ 9.3 million in dividends being paid on July 26, 2021. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 830,000 and accrued a dividend equivalent per share to all unvested stock option holders which was payable upon vesting, assuming no forfeitures. Outstanding Securities. At December 31, 2023 and 2022, the Company had 128,420,923 and 113,165,027 shares of common stock outstanding, respectively, and 7,934,977 and 8,285,272 warrants outstanding, respectively, with an exercise price of $ 11.50 per share that expire on August 21, 2025. NOTE 16. Subsequent Events Derivative Financial Instruments. In January 2024, the Company entered into fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price. The weighted average differential represents the amount of premium to the Cushing, Oklahoma crude oil price for the notional volumes covered by the basis swap contracts as shown below. Swaps Settlement Month Settlement Year Type of Contract Bbls Per Day Index Weighted Average Differential per Bbl Crude Oil: Jan - Mar 2024 Basis Swap 16,484 Argus WTI Midland $ 1.12 Apr - Jun 2024 Basis Swap 25,000 Argus WTI Midland $ 1.12 Jul - Sep 2024 Basis Swap 25,000 Argus WTI Midland $ 1.12 Oct - Dec 2024 Basis Swap 25,000 Argus WTI Midland $ 1.12 Share Repurchase Program. In February 2024, the Board approved a repurchase program of up to $ 75 million of the Company’s common stock. The approval grants HighPeak’s management the authority to repurchase shares opportunistically in the open market from time to time, through block trades, in privately negotiated transactions or by such other means which comply with applicable state and federal laws. This is the Company’s first authorization for a stock repurchase program since its founding. The Company intends to fund the repurchases from available working capital, cash provided from operations and borrowings under its Senior Credit Facility Agreement. The timing, number and value of shares repurchased under the program will be at the discretion of management and the Board of Directors and will depend on a number of factors, including general market and economic conditions, business conditions, the trading price of the Company’s common stock, the nature of other investment opportunities available to the Company and compliance with the Company’s debt and other agreements. The stock repurchase program does not obligate HighPeak to acquire any particular dollar amount or number of shares of its common stock and the stock repurchase program may be suspended from time to time, modified, extended or discontinued by the Company’s Board of Directors. The stock repurchase program authority will expire December 31, 2024. Dividends and dividend equivalents. In February 2024, the Board approved a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.1 million in dividends being paid on March 25, 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 536,000 in March 2024 and will accrue a dividend equivalent per share to all unvested stock option holders which is payable upon vesting, assuming no forfeitures. In addition, the Company will accrue an additional combined $ 86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. NOTE 17 – Supplemental Crude Oil and Natural Gas Disclosures (Unaudited) The Company only has one reportable operating segment, which is crude oil and natural gas development, exploration and production in the U.S. Net Capitalized Costs The following table reflects the capitalized costs of crude oil and natural gas properties and the related accumulated depletion (in thousands): December 31, 2023 2022 Proved properties $ 3,338,107 $ 2,270,236 Unproved properties 72,715 114,665 Total capitalized costs 3,410,822 2,384,901 Less: accumulated depletion ( 684,179 ) ( 259,962 ) Net capitalized costs $ 2,726,643 $ 2,124,939 105 Cost Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development The following table reflects costs incurred in crude oil and natural gas property acquisition, development and exploratory activities (in thousands): Year Ended December 31, 2023 2022 2021 Acquisition costs: Proved properties $ 3,308 $ 352,791 $ 33,253 Unproved properties 11,777 174,554 20,792 Total acquisition costs 15,085 527,345 54,045 Exploration costs 527,502 655,433 190,346 Development costs 481,528 391,298 45,852 Crude oil and natural gas expenditures 1,024,115 1,574,076 290,243 Asset retirement obligations, net 6,048 2,879 1,844 Total costs incurred $ 1,030,163 $ 1,576,955 $ 292,087 Results of Operations for Crude Oil, NGL and Natural Gas Producing Activities The following table reflects the Company’s results of operations for crude oil, NGL and natural gas producing activities (in thousands): Year Ended December 31, 2023 2022 2021 Crude oil, NGL and natural gas sales $ 1,111,293 $ 755,686 $ 220,124 Lease operating expenses 145,362 69,599 25,053 Production and ad valorem taxes 58,472 38,440 10,746 Exploration and abandonment expense 5,234 1,149 1,549 Depletion, depreciation and amortization expense 424,424 177,742 65,201 Accretion of discount on asset retirement obligations 522 370 167 Income tax expense 100,229 98,361 24,656 Results of operations from crude oil and natural gas production activities $ 377,050 $ 370,025 $ 92,752 Crude Oil, NGL and Natural Gas Reserves Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month spot prices prior to the end of the reporting period. These prices as of December 31, 2023, 2022 and 2021 were $ 78.22 , $ 93.67 and $ 66.56 per barrel for crude oil and NGL and $ 2.637 , $ 6.358 and $ 3.598 per MMBtu for natural gas, respectively. The estimated realized prices used in computing the Company’s reserves as of December 31, 2023 were as follows: (i) $ 78.13 per barrel of crude oil, (ii) $ 17.33 per barrel of NGL, and (iii) $ 0.198 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2022 were as follows: (i) $ 94.59 per barrel of crude oil, (ii) $ 36.69 per barrel of NGL, and (iii) $ 4.871 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2021 were as follows: (i) $ 66.10 per barrel of crude oil, (ii) $ 29.76 per barrel of NGL, and (iii) $ 0.786 per Mcf of natural gas. All prices are net of adjustments for regional basis differentials, treating costs, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity adjustments. The proved reserve estimates as of December 31, 2023, 2022 and 2021 were prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), independent reserve engineers, and reflect the Company’s current development plans. All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond the Company’s control, such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate. 106 Reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. Estimating quantities of proved crude oil and natural gas reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as crude oil and natural gas prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from crude oil and natural gas properties the Company owns declines as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company’s proved reserves will decline as reserves are produced. The following table reflects changes in proved reserves during the periods indicated: Crude Oil (MBbl) NGL (MBbl) Natural Gas (MMcf) Total (MBoe) Proved Reserves on December 31, 2020 19,032 2,160 7,939 22,515 Extensions and discoveries 36,867 4,845 19,529 44,967 Purchase of reserves-in-place 973 631 2,910 2,089 Sales of minerals-in-place ( 238 ) ( 44 ) ( 139 ) ( 305 ) Revisions of previous estimates ( 1,807 ) 10 842 ( 1,657 ) Production ( 3,002 ) ( 224 ) ( 1,020 ) ( 3,396 ) Proved Reserves on December 31, 2021 51,825 7,378 30,061 64,213 Extensions and discoveries 47,677 6,162 24,887 57,987 Purchase of reserves-in-place 13,031 3,467 14,448 18,906 Revisions of previous estimates ( 6,155 ) ( 1,817 ) ( 7,435 ) ( 9,211 ) Production ( 7,562 ) ( 821 ) ( 3,323 ) ( 8,937 ) Proved Reserves on December 31, 2022 98,816 14,369 58,638 122,958 Extensions and discoveries 54,137 6,456 27,330 65,148 Purchase of reserves-in-place 89 47 208 171 Sales of reserves-in-place ( 1,171 ) ( 127 ) ( 531 ) ( 1,387 ) Revisions of previous estimates ( 18,432 ) 898 8,644 ( 16,093 ) Production ( 13,885 ) ( 1,547 ) ( 7,218 ) ( 16,635 ) Proved Reserves on December 31, 2023 119,554 20,096 87,071 154,162 On December 31, 2023, the Company had approximately 154,162 MBoe of proved reserves. For the year ended December 31, 2023, extensions and discoveries increased proved reserves by 65,148 MBoe as a result of; (i) drilling 63 gross ( 56.4 net) exploratory/extension wells that were on production as of December 31, 2023, (ii) 7 gross ( 6.6 net) exploratory/extension wells that were in the final stages of completion as of December 31, 2023, and (iii) the addition of 117 gross ( 102.4 net) PUDs. The Company also acquired 171 MBoe of reserves as part of its acquisition activities and divested of 1,387 MBoe of reserves in a farm out to another operator in return for a carried interest during the year ended December 31, 2023. Downward revisions of previous estimates of 16,093 MBoe for the year ended December 31, 2023 were the result of negative revisions of approximately 13,729 MBoe primarily due to technical revisions attributable to decreased well performance and adjustments to our estimates, approximately 1,775 MBoe primarily related to decreases in crude oil, NGL and natural gas realized prices and approximately 589 MBoe primarily due to increased forecasted operating expenses. The aforementioned net increase in proved reserves was partially offset by 16,635 MBoe in production during the year ended December 31, 2023. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. On December 31, 2022, the Company had approximately 122,958 MBoe of proved reserves. For the year ended December 31, 2022, extensions and discoveries increased proved reserves by 57,987 MBoe as a result of: (i) drilling 37 gross ( 32.1 net) exploratory/extension wells that were on production as of December 31, 2022, (ii) 16 gross ( 14.8 net) exploratory/extension wells that were in the final stages of completion as of December 31, 2022, and (iii) the addition of 80 gross ( 75.2 net) PUDs. The Company also acquired 18,906 MBoe of reserves as part of its acquisition activities during the year ended December 31, 2022. Downward revisions of previous estimates of 9,21 1 MBoe for the year ended December 31, 2022 were primarily the result of negative revisions of 10,418 MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, partially offset by positive revisions of approximately 1,116 MBoe related to increases in crude oil, NGL and natural gas realized prices and positive revisions of approximately 91 MBoe primarily due to increased forecasted operating expenses. The aforementioned net increase in proved reserves was partially offset by 8,937 MBoe in production during the year ended December 31, 2022. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. On December 31, 2021, the Company had approximately 64,213 MBoe of proved reserves. For the year ended December 31, 2021, extensions and discoveries increased proved reserves by 44,967 MBoe as a result of: (i) drilling 22 gross ( 17.8 net) exploratory wells that were on production as of December 31, 2021, (ii) 15 gross ( 11.0 net) exploratory wells that were in the final stages of completion as of December 31, 2021, and (iii) the addition of 53 gross ( 41.5 net) PUDs. The Company also acquired 2,089 MBoe of reserves as part of its acquisition activities and sold assets with proved reserves totaling 305 MBoe during the year ended December 31, 2021 in an acreage trade with an industry partner. Downward revisions of previous estimates of 1,657 MBoe for the year ended December 31, 2021 were primarily the result of: (i) negative revisions of 2,529 MBoe due to technical revisions attributable to decreased well performance and adjustments to our PUD estimates, (ii) negative revisions of approximately 85 MBoe primarily due to increased forecasted operating expenses and (iii) partially offset by positive revisions of approximately 957 MBoe related to increases in crude oil, NGL and natural gas realized prices. The aforementioned net increase in proved reserves was partially offset by 3,396 MBoe in production during the year ended December 31, 2021. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. 107 The following table sets forth the Company’s estimated quantities of proved developed and proved undeveloped crude oil, NGL and natural gas reserves: December 31, 2023 2022 2021 Proved Developed Reserves (1) Crude oil (MBbl) 58,631 47,845 22,610 NGL (MBbl) 12,183 7,968 3,540 Natural gas (MMcf) 52,671 32,669 14,611 Total (MBoe) 79,593 61,258 28,585 Proved Undeveloped Reserves Crude oil (MBbl) 60,923 50,971 29,215 NGL (MBbl) 7,913 6,401 3,838 Natural gas (MMcf) 34,400 25,969 15,450 Total (MBoe) 74,569 61,700 35,628 Total Proved Reserves Crude oil (MBbl) 119,554 98,816 51,825 NGL (MBbl) 20,096 14,369 7,378 Natural gas (MMcf) 87,071 58,638 30,061 Total (MBoe) 154,162 122,958 64,213 (1) As of December 31, 2023, 2022 and 2021 and 2020, proved developed reserves includes proved developed non-producing reserves of 4,598 , 7,417 , 6,884 and 4,517 MBbl of crude oil, 534 , 927 , 793 and 517 MBbl of NGL and 1,889 , 3,641 , 3,222 and 1,912 MMcf of natural gas, respectively. On December 31, 2023, the Company’s estimated PUD reserves were approximately 74,569 MBoe, a 12,869 MBoe increase over the reserve estimate at December 31, 2022 of 61,700 MBoe. The following table includes the changes in PUD reserves for 2023 (in MBoe): Beginning proved undeveloped reserves on December 31, 2022 61,700 Undeveloped reserves transferred to proved developed reserves ( 25,955 ) Extensions and discoveries 42,440 Sales of reserves-in-place ( 1,387 ) Revisions ( 2,229 ) Ending proved undeveloped reserves on December 31, 2023 74,569 Standardized Measure of Discounted Future Net Cash Flows The following table reflects the Company’s standardized measure of discounted future net cash flows relating from its proved crude oil, natural gas and NGL reserves (in thousands): December 31, 2023 2022 2021 Future cash inflows $ 9,706,290 $ 10,159,310 $ 3,668,535 Future production costs ( 2,869,377 ) ( 2,289,852 ) ( 824,865 ) Future development costs (1) ( 1,568,033 ) ( 983,732 ) ( 432,370 ) Future income tax expense ( 680,894 ) ( 1,102,156 ) ( 431,737 ) Future net cash flows 4,587,986 5,783,570 1,979,563 Discount to present value at 10% annual rate ( 1,980,282 ) ( 2,367,062 ) ( 860,754 ) Standardized measure of discounted future net cash flows (1) $ 2,607,704 $ 3,416,508 $ 1,118,809 The following table reflects the principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves (in thousands): Year Ended December 31, 2023 2022 2021 Standardized measure of discounted future net cash flows, beginning of year $ 3,416,508 $ 1,118,809 $ 222,192 Sales of crude oil and natural gas, net of production costs ( 907,459 ) ( 647,647 ) ( 184,325 ) Extensions and discoveries, net of future development costs (1) 1,202,674 1,785,822 987,689 Net changes in prices and production costs ( 1,404,147 ) 909,053 272,889 Changes in estimated future development costs (1) ( 37,820 ) ( 23,647 ) ( 13,551 ) Purchases of minerals-in-place 4,344 499,478 31,353 Sales of reserves-in-place ( 25,069 ) — ( 3,067 ) Revisions of previous quantity estimates ( 390,282 ) ( 354,868 ) ( 40,466 ) Accretion of discount 395,656 134,338 23,419 Net changes in income taxes 266,579 ( 315,478 ) ( 212,574 ) Net changes in timing of production and other 86,720 310,648 35,250 Standardized measure of discounted future net cash flows, end of year (1) $ 2,607,704 $ 3,416,508 $ 1,118,809 (1) The standardized measure of discounted future net cash flows reflects, within the category for future development costs, all estimated future costs that will be incurred to settle our asset retirement obligations, including costs for dismantlement, restoration, and abandonment of the existing wells (including both active and inactive wells on leases and future proved undeveloped locations), in each case in compliance with FASB ASC 932-235-50-36. 108 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.