HighPeak Energy, Inc. 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410 ) 87 Consolidated Balance Sheets as of December 31, 2025 and 2024 89 Consolidated Statements of Operations for the Years Ended December 31, 2025, 2024 and 2023 90 Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2025, 2024 and 2023 91 Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023 92 Notes to Consolidated Financial Statements 93 Unaudited Supplementary Data 115 86 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 and Internal Control Over Financial Reporting We have audited the accompanying consolidated balance sheets of HighPeak Energy, Inc. and its subsidiaries (the Company) as of December 31, 2025 and 2024, 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, 2025, and the related notes (collectively, consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in 2013 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in COSO. Basis for opinion The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the entity’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects Our audits of the consolidated financial statements 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 responds 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control Over Financial Reporting An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Critical audit matter The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter did not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which they relate. Estimation of proved oil and gas reserves impacting depletion expense As described in Note 2 to the consolidated financial statements, the Company utilizes the successful efforts method of accounting for its crude oil and natural gas properties. Depletion of crude oil and natural gas properties is determined using estimates of proved crude oil, NGL and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense, as a critical audit matter. 87 The principal consideration for our determination that the estimation of proved oil and gas reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate volumes and future revenues of the Company’s proved oil and gas reserves could have a significant impact on the measurement of depletion expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved oil and gas reserves included, among others, the following: ● We evaluated the level of knowledge, skill, and ability of the Company’s external reservoir engineer specialists, made inquiries of these specialists regarding the process followed and judgments made to estimate the Company’s proved oil and gas reserve volumes, and read the report prepared by the Company’s specialists. ● We tested the design and operating effectiveness of key controls relating to management’s estimation of proved oil and gas reserves for the purpose of calculating depletion expense. ● We evaluated the methods, data (both company-produced and date from external sources) and significant assumptions used by the Company’s reservoir engineering specialists to estimate the Company’s proved oil and gas reserve volumes. Specifically, our audit procedures included, among others, the following: o Compared estimated future production volumes to relevant historical and current period information, as applicable; and o Assessed the reasonableness of the production volume decline curves by comparing to historical decline curve estimates. /s/ WEAVER AND TIDWELL, L.L.P. We have served as the Company’s auditor since 2020. Austin, Texas March 11, 2026 88 HighPeak Energy, Inc. Consolidated Balance Sheets (in thousands, except share data) December 31, 2025 2024 ASSETS Current assets: Cash and cash equivalents $ 162,075 $ 86,649 Accounts receivable 55,546 85,242 Derivative instruments 29,574 7,582 Inventory 7,648 10,952 Prepaid expenses 5,054 4,587 Total current assets 259,897 195,012 Crude oil and natural gas properties, using the successful efforts method of accounting: Proved properties 4,477,368 3,959,545 Unproved properties 59,285 70,868 Accumulated depletion, depreciation and amortization ( 1,606,217 ) ( 1,184,684 ) Total crude oil and natural gas properties, net 2,930,436 2,845,729 Other property and equipment, net 3,012 3,201 Derivative instruments 4,197 — Other noncurrent assets 16,172 19,346 Total assets $ 3,213,714 $ 3,063,288 LIABILITIES AND STOCKHOLDERS ’ EQUITY Current liabilities: Current maturities of long-term debt $ 60,000 $ 120,000 Accounts payable – trade 84,313 74,011 Accrued capital expenditures 30,921 35,170 Revenues and royalties payable 30,665 26,838 Other accrued liabilities 20,927 22,196 Advances from joint interest owners 2,205 316 Operating leases 845 719 Derivative instruments 380 5,380 Total current liabilities 230,256 284,630 Noncurrent liabilities: Long-term debt, net 1,132,807 928,384 Deferred income taxes 239,636 232,398 Asset retirement obligations 15,944 14,750 Derivative instruments 360 — Operating leases 142 670 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, 2025 and 2024 — — Common stock, $ 0.0001 par value, 600,000,000 shares authorized, 125,330,104 and 126,067,436 shares issued and outstanding at December 31, 2025 and 2024, respectively 13 13 Additional paid-in capital 1,162,007 1,166,609 Retained earnings 432,549 435,834 Total stockholders’ equity 1,594,569 1,602,456 Total liabilities and stockholders ’ equity $ 3,213,714 $ 3,063,288 The accompanying notes are an integral part of these consolidated financial statements. 89 HighPeak Energy, Inc. Consolidated Statements of Operations (in thousands, except per share data) Years Ended December 31, 2025 2024 2023 Operating Revenues: Crude oil sales $ 785,977 $ 1,060,476 $ 1,086,598 NGL and natural gas sales 77,382 56,699 44,533 Total operating revenues 863,359 1,117,175 1,131,131 Operating Costs and Expenses: Crude oil and natural gas production 139,492 132,244 145,362 Gathering, processing and transportation 68,401 47,761 19,838 Production and ad valorem taxes 37,224 59,677 58,472 Exploration and abandonments 16,685 1,476 5,234 Depletion, depreciation and amortization 421,776 500,752 424,424 Accretion of discount 1,075 966 522 General and administrative 25,270 20,392 16,598 Stock-based compensation 619 12,701 25,957 Total operating costs and expenses 710,542 775,969 696,407 Other expense 2,836 3,795 8,262 Income from operations 149,981 337,411 426,462 Interest income 3,847 8,685 2,908 Interest expense ( 147,136 ) ( 168,712 ) ( 147,901 ) Gain (loss) on derivative instruments, net 44,913 ( 46,464 ) 27,602 Loss on extinguishment of debt ( 25,437 ) — ( 27,300 ) Income before income taxes 26,168 130,920 281,771 Provision for income taxes 7,205 35,851 65,905 Net income $ 18,963 $ 95,069 $ 215,866 Earnings per share: Basic net income $ 0.13 $ 0.69 $ 1.64 Diluted net income $ 0.14 $ 0.67 $ 1.58 Weighted average shares outstanding: Basic 125,265 125,281 117,956 Diluted 125,330 129,205 123,020 Dividends declared per share $ 0.16 $ 0.16 $ 0.10 The accompanying notes are an integral part of these consolidated financial statements. 90 HighPeak Energy, Inc. Consolidated Statements of Changes in Stockholders ’ Equity (in thousands) Years ended December 31, 2023, 2024 and 2025 Shares Outstanding Common Stock Additional Paid-in- Capital Retained Earnings (Accumulated Deficit) Total Stockholders’ Equity Balance, December 31, 2022 113,165 $ 11 $ 1,008,896 $ 160,740 $ 1,169,647 Dividends declared ($ 0.10 per share) — — — ( 12,076 ) ( 12,076 ) Dividend equivalents declared on outstanding stock options ($ 0.10 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 Dividends declared ($ 0.16 per share) — — — ( 20,395 ) ( 20,395 ) Dividend equivalents declared on outstanding stock options ($ 0.16 per share) — — — ( 2,124 ) ( 2,124 ) Exercise of warrants — — 1 — 1 Repurchased shares under buyback program ( 2,408 ) — ( 35,517 ) — ( 35,517 ) Stock-based compensation costs: Restricted shares issued to outside directors 54 — — — — Compensation costs included in net income — — 12,701 — 12,701 Net income — — — 95,069 95,069 Balance, December 31, 2024 126,067 13 1,166,609 435,834 1,602,456 Dividends declared ($ 0.16 per share) — — — ( 20,154 ) ( 20,154 ) Dividend equivalents declared on outstanding stock options ($ 0.16 per share) — — — ( 2,094 ) ( 2,094 ) Exercise of warrants — — 1 — 1 Stock issuance costs — — ( 155 ) — ( 155 ) Stock-based compensation costs: Restricted shares issued to outside directors 65 — — — — Compensation costs included in net income — — 619 — 619 Cash paid for tax withholding on vested equity awards ( 802 ) — ( 5,067 ) — ( 5,067 ) Net income — — — 18,963 18,963 Balance, December 31, 2025 125,330 $ 13 $ 1,162,007 $ 432,549 $ 1,594,569 The accompanying notes are an integral part of these consolidated financial statements. 91 HighPeak Energy, Inc. Consolidated Statements of Cash Flows (in thousands) Years Ended December 31, 2025 2024 2023 CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 18,963 $ 95,069 $ 215,866 Adjustments to reconcile net income to net cash provided by operations: Provision for deferred income taxes 7,239 35,330 65,905 Loss on extinguishment of debt 25,437 — 27,300 (Gain) loss on derivative instruments, net ( 44,913 ) 46,464 ( 27,602 ) Cash received (paid) on settlement of derivative instruments 14,084 ( 14,246 ) ( 24,194 ) Amortization of debt issuance costs 5,881 8,278 11,411 Amortization of discounts on long-term debt 5,714 9,865 15,140 Stock-based compensation expense 619 12,701 25,957 Accretion expense 1,075 966 522 Depletion, depreciation and amortization expense 421,776 500,752 424,424 Exploration and abandonment expense 15,413 620 4,242 Changes in operating assets and liabilities: Accounts receivable 29,697 9,347 2,007 Prepaid expenses, inventory and other assets 5,635 ( 19,474 ) 6,923 Accounts payable, accrued liabilities and other current liabilities 4,977 4,719 8,488 Net cash provided by operating activities 511,597 690,391 756,389 CASH FLOWS FROM INVESTING ACTIVITIES: Additions to crude oil and natural gas properties ( 515,379 ) ( 604,828 ) ( 1,009,855 ) Changes in working capital associated with oil and gas property additions 6,250 ( 1,294 ) ( 100,802 ) Acquisitions of crude oil and natural gas properties ( 6,724 ) ( 14,844 ) ( 15,085 ) Proceeds from sales of properties 570 339 — Other property additions ( 54 ) ( 216 ) ( 193 ) Net cash used in investing activities ( 515,337 ) ( 620,843 ) ( 1,125,935 ) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings under Term Loan Credit Agreement, net of discount 180,000 — 1,170,000 Repayments under Term Loan Credit Agreement ( 60,000 ) ( 120,000 ) — Borrowings under Senior Credit Facility Agreement 30,000 — — Repayments under Senior Credit Facility Agreement ( 30,000 ) — — Dividends paid ( 20,910 ) ( 20,058 ) ( 11,864 ) Debt issuance costs ( 7,859 ) ( 58 ) ( 28,444 ) Cash paid for tax withholding on vested equity awards ( 5,067 ) — — Premium on extinguishment of debt ( 4,750 ) — ( 4,457 ) Dividend equivalents paid ( 2,094 ) ( 2,133 ) ( 1,251 ) Stock offering costs ( 155 ) — ( 5,371 ) Proceeds from exercises of warrants 1 1 4,028 Repurchased shares under buyback program — ( 35,166 ) — Borrowings under Prior Credit Agreement — — 255,000 Repayments under Prior Credit Agreement — — ( 525,000 ) Repayments of 10.000% Senior Notes and 10.625% Senior Notes — — ( 475,000 ) Proceeds from issuance of common stock — — 155,768 Proceeds from exercises of stock options — — 148 Net cash provided (used in) by financing activities 79,166 ( 177,414 ) 533,557 Net increase (decrease) in cash and cash equivalents 75,426 ( 107,866 ) 164,011 Cash and cash equivalents, beginning of period 86,649 194,515 30,504 Cash and cash equivalents, end of period $ 162,075 $ 86,649 $ 194,515 Supplemental cash flow information: Cash paid for interest $ 135,541 $ 151,967 $ 133,104 Cash paid for income taxes $ 498 $ — $ — Supplemental disclosure of non-cash transactions: Additions to asset retirement obligations $ 3,823 $ 1,068 $ 6,048 The accompanying notes are an integral part of these consolidated financial statements. 92 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 is listed and traded on the Nasdaq Global Market (the "Nasdaq") under the ticker symbol “HPK.” 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, the consolidated financial statements include all adjustments and accruals, consisting only of normal, recurring adjustments and accruals necessary for a fair presentation of the consolidated financial statements in conformity with GAAP. The Company evaluated subsequent events after the balance sheet date of December 31, 2025, 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, specifically gathering, processing and transportation expenses, which were previously netted against NGL and natural gas sales and are now reflected as a component of total operating costs and expenses, which had no 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, 2025 and 2024, the Company’s accounts receivables primarily consist of amounts due from the sale of crude oil, NGL and natural gas of $ 35.4 million and $ 76.0 million, respectively, and are based on estimates of sales volumes and realized prices the Company anticipates it will receive, receivables from the State of Texas of $ 10.0 million and zero , respectively, for a multi-year natural gas severance tax refund, joint interest receivables of $ 5.0 million and $ 4.7 million, respectively, current U.S. federal income tax receivables of $ 3.2 million and $ 3.1 million, respectively, and receivables related to settlements of derivative contracts of $ 1.9 million and $ 1.4 million, respectively. 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. 93 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, 2025 and 2024, the Company had no allowance for credit losses related to accounts receivable and no allowance for credit losses, 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, 2025, 2024 and 2023, sales to the Company’s largest purchaser accounted for approximately 82 %, 76 % and 82 %, respectively, of the Company’s total crude oil, NGL and natural gas sales revenues and sales to the Company’s second largest purchaser accounted for approximately 8 %, 18 % and 14 %, respectively, 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, 2025 and 2024 is $ 7.6 million and $ 11.0 million, respectively, and the Company has not recognized any valuation allowance to date. Prepaid expenses. Prepaid expenses are comprised primarily of fees related to advisory services that will be deducted from eventual commissions on a future transaction, if any, caliche that will be used on future locations and roads in our development areas and prepaid agency fees and software maintenance fees that will be amortized over the life of the contracts. Prepaid expenses as of December 31, 2025 and 2024 are $ 5.1 million and $ 4.6 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. 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. 94 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 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 $ 1.3 million and $ 1.1 million as of December 31, 2025 and 2024, respectively, are as follows (in thousands): December 31, 2025 2024 Land $ 1,869 $ 1,869 Buildings 502 516 Transportation equipment 411 620 Leasehold improvements 177 193 Field equipment 52 2 Furniture and fixtures 1 1 Total other property and equipment, net $ 3,012 $ 3,201 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, 2025 and 2024, the Company had aid-in-construction assets totaling $ 15.2 million and $ 18.0 million, respectively, included in other noncurrent assets. The Company funded aid-in-construction projects during the years ended December 31, 2025, 2024 and 2023 of $ 71,000 , $ 13.8 million and $ 1.0 million, respectively, under the contract. 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. Payments received during the years ended December 31, 2025, 2024 and 2023 were approximately $ 2.8 million, $ 2.0 million and $ 924,000 , respectively. The contract calls for future additional aid-in-construction fundings 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, 2025 and 2024 totaled approximately $ 230.3 million and $ 284.6 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. 95 Debt issuance costs and original issue discount. The Company has paid and has capitalized a total of $ 8.9 million in debt issuance costs, $ 7.9 million of which was incurred during the year ended December 31, 2025, primarily related to amendments to the Term Loan Credit Agreement and Senior Credit Facility Agreement in August 2025. In addition, the Company incurred $ 58,000 and $ 3.3 million during the years ended December 31, 2024 and 2023, respectively, primarily related to the Term Loan Credit 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 $ 5.9 million, $ 8.3 million and $ 11.4 million during the years ended December 31, 2025, 2024 and 2023, respectively. In addition, the Company realized a total of $ 64.8 million in original issue discounts on the issuances of its Term Loan Credit Agreement, 10.000 % Senior Notes and 10.625 % Senior Notes that were being amortized over the life of the agreements which approximates the effective interest method and was $ 5.7 million, $ 9.9 million and $ 15.1 million during the years ended December 31, 2025, 2024 and 2023, respectively. All unamortized debt issuance costs and discounts as of the refinancing of the Term Loan Credit Agreement in August 2025 and 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, 2025 and 2024, the remaining net debt issuance costs 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, 2025 and 2024, the Company had receivables related to contracts with purchasers of approximately $ 35.4 million and $ 76.0 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. 96 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, 2025 and 2024. Tax benefits from 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 a $ 16,000 benefit and a $ 469,000 expense related to current Texas margin tax for the years ended December 31, 2025 and 2024, respectively, in the accompanying consolidated financial statements. However, during all other years, the Company realized no current Texas margin tax as we did not owe any Texas margin tax. 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 or modification 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. Reportable Segments. The Company is an independent energy company engaged in the exploration, development and production of crude oil and natural gas. The Company’s crude oil and natural gas exploration and production activities are solely focused in the U.S., specifically the Midland Basin portion of the Permian Basin in West Texas. For financial reporting purposes, the Company aggregates its operations into one reporting segment due to the similar geographic location and nature of the operations. The Company’s President and Chief Executive Officer is the chief operating decision maker (“CODM”). To assess the performance of our assets, the CODM uses net income. We believe net income provides information useful in assessing our operating and financial performance across periods. 97 The following table reflects the Company’s net income, assets and capital expenditures for the Company’s one reporting segment for the time periods presented: For the Year Ended December 31, 2025 2024 2023 Total operating revenues $ 863,359 $ 1,117,175 $ 1,131,131 Lease operating expenses 119,487 123,590 133,737 Gathering, processing and transportation expenses 68,401 47,761 19,838 Production and ad valorem taxes 37,224 59,677 58,472 Expense workover costs 20,005 8,654 11,625 Total significant expenses 245,117 239,682 223,672 Depletion, depreciation and amortization 421,776 500,752 424,424 General and administrative expenses, including stock-based comp 25,889 33,093 42,555 Interest expense, net (1) 168,726 160,027 172,293 Provision for income taxes 7,205 35,851 65,905 Other segment items (2) ( 24,317 ) 52,701 ( 13,584 ) Total expenses 844,396 1,022,106 915,265 Net income $ 18,963 $ 95,069 $ 215,866 Total assets $ 3,213,714 $ 3,063,288 $ 3,080,791 Capital costs incurred, including acquisitions $ 522,310 $ 620,211 $ 1,030,163 (1) Interest expense, net included in segment net income includes interest expense and loss on extinguishment of debt, partially offset by interest income. (2) Other segment items included in segment net income are exploration and abandonment expense, accretion of discount, other expense and gains and losses on derivative instruments. Recently adopted accounting pronouncements. In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures,” which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changes to the rate reconciliation and income taxes paid. This ASU is effective for the Company prospectively to all annual periods beginning after December 15, 2024, and interim reporting periods beginning after December 15, 2025. The Company adopted this update effective December 31, 2025. While the adoption of this ASU modified the Company’s disclosures, it had no impact on the Company’s consolidated balance sheets, consolidated statements of operations or consolidated statements of cash flows in its consolidated financial statements. New accounting pronouncements not yet adopted. In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Topic 220): Disaggregation of Income Statement Expenses. The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation and amortization recognized as part of crude oil and natural gas producing activities and employee compensation. This ASU is effective for the Company to all annual periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. While the adoption of this ASU will modify the Company’s disclosures, it will not have an impact on the Company's consolidated balance sheets, consolidated statements of operations or consolidated statements of cash flows in its consolidated financial statements. 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. 98 NOTE 3. Acquisitions During the years ended December 31, 2025, 2024 and 2023, the Company incurred $ 6.7 million, $ 14.8 million and $ 15.1 million, respectively, in acquisition costs primarily to acquire various undeveloped crude oil and natural gas properties largely contiguous to its Flat Top and Signal Peak operating areas primarily in Howard, Borden, Mitchell and Scurry counties. NOTE 4. Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available techniques based on available inputs to measure the fair value of its assets and liabilities. ● Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. ● Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. ● Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. 99 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, 2025 and 2024 are as follows (in thousands): As of December 31, 2025 (Level 1) (Level 2) (Level 3) Total Gross Fair Value Assets: Commodity price derivatives – current $ — $ 29,574 $ — $ 29,574 Commodity price derivatives – noncurrent — 4,197 — 4,197 Total assets — 33,771 — 33,771 Liabilities: Commodity price derivatives – current — 380 — 380 Commodity price derivatives – noncurrent — 360 — 360 Total liabilities — 740 — 740 Total recurring fair value measurements $ — $ 33,031 $ — $ 33,031 As of December 31, 2024 (Level 1) (Level 2) (Level 3) Total Gross Fair Value Assets: Commodity price derivatives – current $ — $ 7,582 $ — $ 7,582 Liabilities: Commodity price derivatives – current — 5,380 — 5,380 Total recurring fair value measurements $ — $ 2,202 $ — $ 2,202 Commodity price derivatives. The Company’s commodity price derivatives are currently made up of crude oil costless collars, swap contracts and basis swaps and natural gas swap contracts. 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, (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, and (iii) asset retirement obligations are measured at estimated fair value on the date the liabilities are incurred using Level 3 inputs based on expected future costs to retire the assets, market conditions and estimated lives of the assets. 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. As of December 31, 2025 and 2024, the Company has financial instruments consisting primarily of cash and cash equivalents, accounts receivable, accounts payable, long-term debt (specifically the Term Loan Credit Agreement and Senior Credit Facility Agreement), and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. 100 NOTE 5. Derivative Financial Instruments The Company utilizes derivative financial instruments, primarily swaps, costless collars, basis swaps and roll swaps 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 Company has not designated its derivative financial instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” The following table summarizes the effect of derivative instruments on the Company’s consolidated statements of operations (in thousands): Year Ended December 31, 2025 2024 2023 Noncash gain (loss) on derivative instruments, net $ 30,829 $ ( 32,218 ) $ 51,796 Cash received (paid) on settlement of derivative instruments, net 14,084 ( 14,246 ) ( 24,194 ) Gain (loss) on derivative instruments, net $ 44,913 $ ( 46,464 ) $ 27,602 By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company has entered into commodity derivative instruments only with counterparties that are also lenders under its Term Loan Credit Agreement and Senior Credit Facility Agreement and have been deemed acceptable credit risk. As such, collateral is not required from either the counterparties or the Company on its outstanding derivative contracts. 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 Cushing and Argus WTI Midland crude oil prices. As such, the Company primarily uses NYMEX WTI Cushing derivative contracts as well as Argus WTI Midland basis swaps and NYMEX WTI roll swaps from time to time to manage future crude oil price volatility. The Argus WTI Midland basis differential represents the amount of premium to NYMEX WTI Cushing. The Company’s outstanding NYMEX WTI Cushing and Argus WTI Midland crude oil derivative instruments as of December 31, 2025 and the weighted average crude oil prices per barrel for those contracts are as follows: Settlement Month Settlement Year Type of Contract Bbls Per Day Index Swap Price per Bbl Costless Collar Floor Price per Bbl Costless Collar Ceiling Price per Bbl Crude Oil: Jan - Mar 2026 Costless Collar 14,350 WTI Cushing $ — $ 60.58 $ 69.62 Jan - Mar 2026 Swap 2,000 WTI Cushing $ 63.14 $ — $ — Apr - Jun 2026 Costless Collar 12,350 WTI Cushing $ — $ 59.87 $ 66.82 Apr - Jun 2026 Swap 1,000 WTI Cushing $ 63.25 $ — $ — Jul - Sep 2026 Costless Collar 12,000 WTI Cushing $ — $ 59.83 $ 66.84 Jul - Sep 2026 Swap 1,000 WTI Cushing $ 63.25 $ — $ — Oct – Dec 2026 Costless Collar 9,800 WTI Cushing $ — $ 59.80 $ 65.31 Oct - Dec 2026 Swap 1,000 WTI Cushing $ 63.25 $ — $ — Jan – Mar 2027 Costless Collar 8,900 WTI Cushing $ — $ 59.78 $ 65.24 Jan - Mar 2027 Swap 1,000 WTI Cushing $ 63.25 $ — $ — Apr – Jun 2027 Costless Collar 4,000 WTI Cushing $ — $ 52.00 $ 62.85 Apr – Jun 2027 Swap 3,520 WTI Cushing $ 58.00 $ — $ — 101 Natural gas production derivatives. The Company sells its natural gas production at the tailgate of the gas processing plants and the sales contracts governing such natural gas production are correlated with HH natural gas prices. As such, the Company primarily uses HH derivative contracts to manage future natural gas price volatility. The Company’s outstanding HH natural gas derivative instruments as of December 31, 2025 and the weighted average natural gas prices per MMBtu for those contracts are as follows: Settlement Month Settlement Year Type of Contract MMBtu Per Day Index Price per MMBtu Natural Gas: Jan – Mar 2026 Swap 30,000 HH $ 4.39 Apr – Jun 2026 Swap 30,000 HH $ 4.30 Jul – Sep 2026 Swap 30,000 HH $ 4.30 Oct – Dec 2026 Swap 30,000 HH $ 4.30 Jan – Mar 2027 Swap 19,667 HH $ 4.30 Balance Sheet Offsetting of Derivative Assets and Liabilities. The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. While it is acceptable to record these fair values by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement, the Company elects to record them at the gross level showing assets and liabilities as if they were settled separately. See Note 4 – Fair Value Measurements for further details. Net derivative assets associated with the Company’s open commodity derivative instruments by counterparty are as follows (in thousands): As of December 31, 2025 Fifth Third Bank, National Association $ 25,075 Macquarie Bank Limited 6,495 Mercuria Energy Trading SA 1,461 $ 33,031 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, 2025 2024 2023 Beginning capitalized exploratory/extension well costs $ 33,619 $ 40,888 $ 186,427 Additions to exploratory/extension well costs 145,679 162,190 527,502 Reclassification to proved properties ( 152,089 ) ( 169,230 ) ( 673,041 ) Exploratory/extension well costs charged to exploration and abandonment expense ( 11,092 ) ( 229 ) — Ending capitalized exploratory/extension well costs $ 16,117 $ 33,619 $ 40,888 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, 2025 2024 Term Loan Credit Agreement due 2028 $ 1,200,000 $ 1,080,000 Senior Credit Facility Agreement due 2028 — — Debt issuance costs, net (a) ( 7,193 ) ( 14,419 ) Discounts, net (b) — ( 17,197 ) Total debt 1,192,807 1,048,384 Less current maturities of long-term debt ( 60,000 ) ( 120,000 ) Long-term debt, net $ 1,132,807 $ 928,384 (a) Debt issuance costs as of December 31, 2025 and 2024 consisted of $ 8.9 million and $ 25.1 million, respectively, in costs less accumulated amortization of $ 1.7 million and $ 10.7 million, respectively. (b) Discounts as of December 31, 2025 and 2024 consisted of zero and $ 30.0 million, respectively, in discounts less accumulated amortization of zero and $ 12.8 million, respectively. 102 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”) in an aggregate principal amount of $ 1.2 billion, 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 was set to mature on September 30, 2026. On August 1, 2025, the Company entered into the First Term Loan Amendment whereby, among other things, (i) the maturity was extended to September 30, 2028, (ii) borrowings were upsized to $ 1.2 billion, providing additional liquidity, and (iii) the quarterly amortization payments of $ 30.0 million were deferred for one year such that they begin again in September 2026. As of December 31, 2025, $ 1.2 billion was outstanding under the Term Loan Credit Agreement. As a result of this amendment which was considered an extinguishment of debt, the Company recognized a loss on extinguishment of debt of $ 25.4 million consisting of (i) $ 11.5 million in unamortized discounts, (ii) $ 9.2 million in unamortized debt issuance costs and (iii) $ 4.7 million in premiums paid to those lenders that chose to exit the Term Loan Credit Agreement upon closing of the First Term Loan Amendment. Effective as of December 30, 2025, the Company entered into the Second Term Loan Amendment whereby, among other things, (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the Fourth Quarter of 2025 and the first quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the second quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to these amendments. 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 a payment or other event of default exists and is continuing, at the election of the Required Lenders (as defined in 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 otherwise applicable thereto. The Company is able to repay any amounts borrowed prior to the maturity date without premium or penalty. The Term Loan Credit Agreement is guaranteed by the Company and certain of its subsidiaries and is secured by a first-lien second-out security interest in substantially all assets of the Company and certain of its subsidiaries, which will require the Company to comply with an asset coverage ratio of not less than 1.25 :1.00 for the fiscal quarter ending June 30, 2026 and 1.50 :1.00 for fiscal quarters ending thereafter and a total net leverage ratio of not greater than 2.00 :1.00 for the fiscal quarter ending June 30, 2026 and fiscal quarters ending thereafter. The Term Loan Credit Agreement contains customary restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things, incur additional indebtedness (with exceptions permitting, among other things, the incurrence of a super priority revolving credit facility, subject to a cap of $ 100 million), incur additional liens, make investments and loans, enter into mergers and acquisitions, make dividends and certain other payments, enter into certain hedging transactions, sell assets, engage in transactions with affiliates and make certain capital expenditures. In addition, the Term Loan Credit Agreement contains customary mandatory prepayments, in addition to quarterly scheduled amortization payments of $ 30.0 million referenced above, consisting of prepayments with proceeds of prohibited indebtedness and asset sales (including hedge terminations) in excess of $ 20.0 million in any calendar year, and prepayments with a percentage of Excess Cash Flow (as defined in the Term Loan Credit Agreement) equal to 0%, 25% or 50% based on a total net leverage ratio to the extent pro forma for any such payment, the aggregate cash and cash equivalents of the Company and its restricted subsidiaries would not be less than $ 100.0 million as of the date of such payment (with no such excess cash flow prepayments made as of December 31, 2025). The Term Loan Credit Agreement is subject to customary events of default, including upon the occurrence of 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”) with Texas Capital, as collateral agent, Chambers, as term representative, and Mercuria Energy Trading SA, as initial first-out representative, which was later joined by Fifth Third Bank, National Association, as successor first-out representative. 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 holders of “first-out” obligations and obligations under the Term Loan Credit Agreement) to receive, hold, administer and distribute proceeds of the collateral and to enforce the Security Documents. Under the terms of the Collateral Agency Agreement, proceeds of collateral are first distributed to holders of “first-out” obligations, including certain hedging and cash management obligations and obligations under the Senior Credit Facility Agreement but excluding certain “excess” first-out obligations, and second to holders of obligations under the Term Loan Credit Agreement. 103 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, together with a number of other banks and financial institutions party thereto, to establish a senior revolving credit facility (“Senior Credit Facility Agreement”). The Senior Credit Facility Agreement has aggregate maximum commitments of $ 100.0 million. On August 1, 2025, the Company entered into the Second Facility Amendment which, among other things, extended the maturity date to September 30, 2028, which was not considered an extinguishment of debt. As of December 31, 2025, the balance due under the Senior Credit Facility Agreement was zero. 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 or other event of default exists and is continuing, at the election of the Required Lenders (as defined in 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 otherwise applicable thereto. Effective as of December 30, 2025, the Company entered into the Third Facility Amendment whereby, among other things, (i) the Company will be required to maintain an asset coverage ratio of not less than 1.00 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.25x decrease in the required ratio levels for such quarters, (ii) the Company will be required to maintain a total net leverage ratio of not greater than 2.50 to 1.00 for the fourth quarter of 2025 and the first quarter of 2026, representing a 0.50x increase in the required ratio levels for such quarters, (iii) the Company’s hedging obligations will be increased requiring it to maintain hedging agreements with respect to 75% of its proved developed producing oil production for the period from April 1, 2026 to March 31, 2027 and 60% of its proved developed producing oil production for the period from April 1, 2027 to September 30, 2027, in each case as provided in the January 1, 2026 reserve report and (iv) the Company will be prohibited from making quarterly dividends on its common stock until September 30, 2026. For the second quarter of 2026 and quarterly periods ending thereafter, the required asset coverage ratio and total net leverage ratio levels will reset to the levels in effect for such quarters prior to these amendments. 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 first-out security interest in substantially all assets of the Company and certain of its subsidiaries. The Term Loan Credit Agreement and the Senior Credit Facility Agreement have hedging requirements to which the Company adheres. 104 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 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. 105 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 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 loss on extinguishment of debt during the year ended December 31, 2023. 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 loss on extinguishment of debt during the year ended December 31, 2023. 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 loss on extinguishment of debt during the year ended December 31, 2023. NOTE 8. Asset Retirement Obligations The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and remediation of 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. 106 Asset retirement obligations activity is as follows (in thousands): Year Ended December 31, 2025 2024 2023 Beginning asset retirement obligations $ 14,750 $ 13,245 $ 7,502 Liabilities incurred from new wells 873 747 445 Liabilities assumed in acquisitions — — 2,638 Liabilities divested ( 754 ) ( 208 ) ( 81 ) Revision of estimates (a) — — 2,219 Accretion of discount 1,075 966 522 Ending asset retirement obligations $ 15,944 $ 14,750 $ 13,245 (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, 2025 and 2024, 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 of up to four percent of the participant’s annual base salary (the “Matching Contributions”). Each participant’s account is credited with the participant’s contributions, the 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, 2025, 2024 and 2023, the Company contributed $ 341,000 , $ 353,000 and $ 218,000 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, 2025 and 2024 are as follows: December 31, 2025 2024 Approved and authorized shares 16,284,491 16,414,015 Shares subject to awards issued under plan ( 15,134,295 ) ( 15,808,671 ) Shares available for future grant 1,150,196 605,344 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, 2025, 2024 and 2023 was negative $ 109,000 due to certain forfeitures, $ 86,000 and $ 11.0 million, respectively, and as of December 31, 2025 there was no unrecognized stock-based compensation expense related to unvested stock option awards. 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. 107 The Company estimates the fair value of stock options granted on the grant date using a Black-Scholes option valuation model, which requires the Company to make several assumptions. In 2025, the Company approved an extension of the expiration term for certain outstanding stock options, lengthening the window to exercise those awards, and the table below reflects such extension. The expected term of the stock options granted was determined based on the simplified method of the midpoint between the vesting dates and the contractual term of the stock options. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the stock 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, 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 Forfeitures ( 4,999 ) $ 24.83 Outstanding at December 31, 2024 13,444,062 $ 11.95 5.3 $ 53,093 Forfeitures ( 739,168 ) $ 24.99 Outstanding at December 31, 2025 12,704,894 $ 11.19 4.2 $ — Vested at December 31, 2024 13,444,062 $ 11.95 5.3 $ 53,093 Exercisable at December 31, 2024 11,495,062 $ 12.19 5.9 $ 44,907 Vested at December 31, 2025 12,704,894 $ 11.19 4.2 $ — Exercisable at December 31, 2025 10,755,894 $ 11.31 4.8 $ — 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 were scheduled to 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 $ 6.0 million, $ 7.2 million and $ 7.2 million was recognized during the years ended December 31, 2024, 2023 and 2022, respectively, 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 were scheduled to 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 $ 5.9 million, $ 7.0 million and $ 7.3 million was recognized during the years ended December 31, 2024, 2023 and 2022, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. On October 31, 2024, the vesting date for the aforementioned 2,100,500 shares of restricted stock was extended from November 4, 2024 to December 31, 2025 to ensure said restricted stock would continue to provide retention value to the Company. There is no excess stock-based compensation expense as the closing price on the modification date was lower than the original grant dates. On September 15, 2025, the Company’s Chief Executive Officer retired and in conjunction with said retirement, the 1,385,500 shares of restricted stock issued to him vested immediately. As a result, 545,195 shares were withheld and cancelled in lieu of $ 3.8 million in cash taxes withheld and paid by the Company on his behalf. On December 31, 2025, the remaining 715,000 shares of restricted stock issued to certain other employees became vested. As a result, 256,989 shares were withheld and cancelled in lieu of $ 1.2 million in cash taxes withheld and paid by the Company on their behalf. Stock issued to outside directors. A total of 64,792 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 3, 2025, which will vest at the next annual meeting, assuming the Board members maintain their positions on the Board. Therefore, stock-based compensation expense of $ 413,000 was recognized during the year ended December 31, 2025 and the remaining $ 295,000 will be recognized through May 2026, which was based upon the closing price of the stock on the date of the restricted stock issuance. In addition, a total of 53,879 shares of restricted stock was approved by the Board to be granted to the outside directors of the Company on June 4, 2024, which vested in June 2025. Therefore, stock-based compensation expense of $ 316,000 and $ 442,000 was recognized during the years ended December 31, 2025 and 2024, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. Also, 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 vested in June 2024. Therefore, stock-based compensation expense of $ 316,000 and $ 442,000 was recognized during the years ended December 31, 2024 and 2023, respectively, which was based upon the closing price of the stock on the date of the restricted stock issuance. Finally, 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 2023. Therefore, stock-based compensation expense of $ 305,000 was recognized during the year ended December 31, 2023, which was based upon the closing price of the stock on the date of the restricted stock issuance. 108 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, 2025, the Company had right-of-use assets totaling $ 957,000 included in other noncurrent assets and operating lease liabilities totaling $ 987,000 , $ 845,000 of which are included in current liabilities and $ 142,000 of which are included in noncurrent liabilities , and as of December 31, 2024 the Company had right-of-use assets totaling $ 1.4 million included in other noncurrent assets and operating lease liabilities totaling $ 1.4 million, $ 719,000 of which are included in current liabilities and $ 670,000 of which are included in noncurrent 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, 2025 2026 $ 888 2027 118 2028 31 Total 1,037 Less present value discount ( 50 ) Present value of lease liabilities $ 987 109 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. 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 September 2024, the Company entered into an amended and restated 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 and Signal Peak 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 May 2024 that totals $ 138.7 million based on the gross piped barrels delivered of 23,500 Bopd for the first ten years of the contract at a certain amount per barrel escalating throughout the term of the contract. However, the Company generally has the ability under the contract to cumulatively bank dollars based on excess volumes delivered to offset the minimum volume commitment. For the period from May 1, 2024 to December 31, 2025, the Company has delivered approximately 31,594 Bopd under the contract. The remaining monetary commitment as of December 31, 2025, if the Company never delivers any additional volumes under the agreement, is approximately $ 115.9 million. Natural gas gathering and treating agreement. In June 2024, the Company entered into a natural gas gathering and treating agreement to gather certain natural gas in its Signal Peak area. Pursuant to said agreement, the Company has agreed to fund certain aid-in-construction costs totaling $ 21.9 million and $ 5.4 million during the years ended December 31, 2025 and 2024, respectively. In addition, throughout the first quarter of 2026, the Company has a remaining commitment under the contract of $ 5.3 million as certain milestones are attained. The agreement does not contain any minimum volume commitments. Power contracts. In June 2022, the Company entered into a contract 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 March 2024, the Company entered into a contract to provide an additional block of electric power under similar terms. In conjunction with these contracts, the Company has a $ 4.6 million letter of credit in place in lieu of a deposit that is cancellable at the end of the contract term. NOTE 11. Related Party Transactions Retirement of Jack Hightower. On September 16, 2025, the Company announced Mr. Jack Hightower’s retirement and resignation from his role as Chief Executive Officer and Chairman of the Board of the Company, effective as of September 15, 2025 (the “Separation Date”). In connection with Mr. Hightower’s notice of retirement and resignation from employment with the Company and his resignation from the Board, the Company entered into a Separation Agreement and General Release of Claims with Mr. Hightower on September 15, 2025 (the “Separation Agreement”), pursuant to which Mr. Hightower released the Company and its affiliates from certain liabilities and agrees to certain restrictive covenants. The Company, in turn, released Mr. Hightower from certain liabilities and provided Mr. Hightower with certain payments and benefits pursuant to the terms and conditions of the Separation Agreement, which, among other things, modified the benefits provided under Mr. Hightower’s outstanding equity awards, namely, his outstanding stock option grant notices and agreements, dated August 24, 2020, November 4, 2021, May 4, 2022, and August 15, 2022, respectively (the “Stock Option Agreements”), and his certain restricted stock agreement and the amendment thereto, dated November 4, 2021 and October 31, 2024, respectively (the “Restricted Stock Agreement”). The Separation Agreement provided for (i) Mr. Hightower’s 1,385,500 unvested shares outstanding under the Restricted Stock Agreement to fully vest as of the Separation Date; (ii) extending the period in which Mr. Hightower may exercise the stock options pursuant to the 2020 and 2021 Stock Option Agreements such that the stock options pursuant to such agreements remains exercisable by Mr. Hightower until the date that is twelve (12) months following the Separation Date; (iii) forfeiture by Mr. Hightower of the right to exercise the outstanding stock options granted pursuant to the 2022 Stock Option Agreements as of the Separation Date; (iv) a cash separation payment to Mr. Hightower in the amount of $ 2,400,000 , payable on the Company’s next regularly scheduled payroll date after the Separation Date and (v) the registration of Mr. Hightower’s 1,532,478 founder’s shares as soon as reasonably possible following the Separation Date. Underwritten Equity Offering. In connection with the Company’s underwritten equity offering in July 2023, certain of the Company’s stockholders, John Paul DeJoria Family Trust and Jack Hightower, the Company’s former 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, 2025, 2024 and 2023, the Company paid zero , zero and $ 1.5 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. 110 NOTE 12. Major Customers Delek accounted for approximately 82 %, 76 % and 82 % of the Company’s revenues during the years ended December 31, 2025, 2024 and 2023, respectively. In addition, Energy Transfer Crude Marketing, LLC (“ETC”) accounted for approximately 8 %, 18 % and 14 % of the Company’s revenues during the years ended December 31, 2025, 2024 and 2023, respectively. 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 Income Tax Expense The following table presents the Company’s income tax expense (in thousands): Year Ended December 31, 2025 2024 2023 Current income tax (benefit) expense: Federal $ ( 17 ) $ 52 $ — State ( 16 ) 469 — Total current income tax (benefit) expense ( 33 ) 521 — Deferred income tax expense: Federal 6,167 33,945 63,002 State 1,071 1,585 2,903 Deferred income tax expense 7,238 35,330 65,905 Income tax expense $ 7,205 $ 35,851 $ 65,905 111 The income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following (in thousands, except rate): Year Ended December 31, 2025 2024 2023 Income tax expense at U.S. federal statutory rate $ 5,495 21 % $ 27,493 21 % $ 59,172 21 % State income tax, net of federal income tax effect (1) 1,059 4 1,955 1 2,903 1 Tax Credits — — — — — — Changes in valuation allowances — — — — — — Nontaxable or nondeductible items: Limited tax benefit due to compensation 369 2 3,388 3 3,811 1 Other 26 — 16 — 19 — Changes in unrecognized tax benefits 162m stock compensation limitation — — 2,999 2 — — Other, net 256 1 — — — — Income tax expense $ 7,205 28 % $ 35,851 27 % $ 65,905 23 % (1) State taxes in Texas make up 100% of the tax effect of this category. Income taxes were paid in the following jurisdictions (in thousands): Year Ended December 31, 2025 Federal $ 33 State 465 Total income taxes paid $ 498 On July 4, 2025, the “One Big Beautiful Bill” (“OBBB”) was signed into law. The OBBB is a significant piece of tax legislation that includes provisions that restore 100% bonus depreciation under section 168(k) for certain property place in service after January 19, 2025, allow for the expensing of domestic R&D expenditures beginning in 2025, and allow for the deduction of intangible drilling costs as part of the computation of the corporate alternative minimum tax beginning in 2026. The OBBB did not have a significant impact on the Company’s 2025 income tax expense. Deferred Tax Assets and Liabilities The following table presents the tax effects of temporary differences that give rise to the Company’s deferred tax assets and liabilities (in thousands): December 31, 2025 2024 Deferred tax assets: Interest expense limitations $ 94,623 $ 73,013 Net operating loss carryforwards 28,360 13,089 Stock-based compensation 3,322 3,351 Other 44 35 Less: Valuation allowance — — Deferred tax assets 126,349 89,488 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 ( 358,853 ) ( 321,411 ) Unrecognized derivative gains, net ( 7,132 ) ( 475 ) Deferred tax liabilities ( 365,985 ) ( 321,886 ) Net deferred tax liabilities $ ( 239,636 ) $ ( 232,398 ) 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, 2025 and 2024, 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 $ 3.0 million reduction in the deferred tax asset and increased the amount of income tax expense realized during the year ended December 31, 2024. The Company is also subject to Texas margin tax. The Company realized a benefit of $ 16,000 and an expense of $ 469,000 in current Texas margin tax in the accompanying consolidated financial statements for the years ended December 31, 2025 and 2024, respectively, and zero for the year ended December 31, 2023 as the Company did not owe any Texas margin tax for 2023. The Company has recognized a net deferred Texas margin tax liability of $ 9.7 million and $ 8.6 million as of December 31, 2025 and 2024, respectively, in the accompanying consolidated balance sheets. In addition to the provision for income taxes, the Company recognized and paid an excise tax of 1% on its stock repurchases during the year ended December 31, 2024 of $ 351,000 recognized as part of the cost basis of the stock repurchased in the condensed consolidated statements of changes in stockholders’ equity. 112 NOTE 14. (Losses) Earnings Per Share The Company uses the two-class method of calculating (losses) earnings per share because certain of the Company’s stock-based awards qualify as participating securities. The Company’s basic (losses) earnings per share attributable to common stockholders is computed as (i) net (loss) income as reported, (ii) less participating basic earnings (iii) divided by weighted average basic common shares outstanding. The Company’s diluted (losses) earnings per share attributable to common stockholders is computed as (i) basic (losses) 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 (losses) earnings from operations and (losses) earnings attributable to common stockholders to the basic and diluted (losses) earnings used to determine the Company’s (losses) earnings per share amounts for the years ended December 31, 2025, 2024 and 2023 under the two-class method (in thousands): Year Ended December 31, 2025 2024 2023 Net income as reported $ 18,963 $ 95,069 $ 215,866 Participating basic earnings (a) ( 2,094 ) ( 9,155 ) ( 21,890 ) Basic (losses) earnings attributable to common stockholders 16,869 85,914 193,976 Reallocation of participating earnings 302 108 334 Diluted net (loss) income attributable to common stockholders $ 17,171 $ 86,022 $ 194,310 Basic weighted average shares outstanding 125,265 125,281 117,956 Dilutive warrants and unvested stock options — 1,770 2,905 Dilutive unvested restricted stock 65 2,154 2,159 Diluted weighted average shares outstanding 125,330 129,205 123,020 (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 Stock Repurchase Program. In February 2024, the Company’s board of directors approved a common stock repurchase program to acquire up to $ 75.0 million of the Company’s outstanding common stock, excluding excise taxes and other expenses, which expired on December 31, 2025. Purchases under the repurchase program could have been made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program did not require the Company to acquire any specific number of shares. This repurchase program has expired, but may be reimplemented by the board of directors at any time. During the years ended December 31, 2025 and 2024, the Company repurchased zero and 2,407,421 , respectively, shares of common stock that were cancelled and terminated for a total of approximately zero and $ 35.1 million, respectively. Issuance of Common Stock. During the years ended December 31, 2025 and 2024, the Company issued 64,792 and 53,879 shares, respectively, of restricted stock to outside directors and 60 and 55 shares of HighPeak Energy common stock, respectively, as a result of warrants being exercised. 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. 113 Public Offerings of Common Stock. On July 19, 2023, the Company completed the offering of 14,835,000 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. Dividends and dividend equivalents . In November 2025, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid in December 2025. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 502,000 in December 2025. In addition, the Company accrued an additional combined $ 3,000 in dividends on the restricted stock issued to outside directors that will be payable upon vesting. Also, simultaneously with the vesting of restricted stock previously issued to management directors and certain employees, previously accrued $ 372,000 in dividends were paid on that date. In August 2025, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid in September 2025. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 531,000 in September 2025. In addition, the Company accrued an additional combined $ 31,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. Also, simultaneously with the aforementioned retirement of our former Chief Executive Officer in September 2025, previously accrued $ 665,000 in dividends were paid in respect of his restricted stock vesting on that date. In May 2025, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid in June 2025. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 531,000 in June 2025. In addition, the Company accrued an additional combined $ 84,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In February 2025, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid in March 2025. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 531,000 in March 2025. In addition, the Company accrued 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. In November 2024, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid on December 23, 2024. In addition, under the terms of the LTIP, the Company paid a dividend equivalent per share to all vested stock option holders of $ 531,000 in December 2024. In addition, the Company accrued 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. In August 2024, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid on September 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 $ 534,000 in September 2024. In addition, the Company accrued 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. In May 2024, the Board declared a quarterly dividend of $ 0.04 per share of common stock outstanding which resulted in a total of $ 5.0 million in dividends being paid on June 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 $ 538,000 in June 2024 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 $ 84,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. In February 2024, the Board declared 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 $ 530,000 in March 2024 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 $ 86,000 in dividends on the restricted stock issued to directors, management directors and certain employees that will be payable upon vesting. 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. 114 Outstanding Securities. At December 31, 2025 and 2024, the Company had 125,330,104 and 126,067,436 shares of common stock outstanding, respectively, and zero and 7,934,977 warrants outstanding, respectively, with an exercise price of $ 11.50 per share. All of the Company’s outstanding warrants expired on August 21, 2025. NOTE 16. Subsequent Events Issuance of restricted stock. In January 2026, the Company issued 1,028,000 shares of restricted stock to certain employees of the Company which will vest pro-rata over the next three years. Crude oil derivative financial instruments. Subsequent to December 31, 2025, the Company entered into the following additional crude oil derivative financial instruments: Settlement Month Settlement Year Type of Contract Bbls Per Day Index Swap Price per Bbl Costless Collar Floor Price per Bbl Costless Collar Ceiling Price per Bbl Crude Oil: Jan – Mar 2026 Swap 3,139 WTI Cushing $ 62.16 $ — $ — Jan – Mar 2026 Basis Swap 689 Argus WTI Midland $ 0.92 $ — $ — Apr – Jun 2026 Swap 9,000 WTI Cushing $ 65.09 $ — $ — Apr – Jun 2026 Roll Swap 10,000 NYMEX WTI Roll $ 4.04 $ — $ — Apr – Jun 2026 Basis Swap 5,000 Argus WTI Midland $ 1.01 $ — $ — Jul – Sep 2026 Swap 4,000 WTI Cushing $ 63.50 $ — $ — Jul – Sep 2026 Roll Swap 10,000 NYMEX WTI Roll $ 4.04 $ — $ — Jul – Sep 2026 Basis Swap 5,000 Argus WTI Midland $ 1.01 $ — $ — Oct – Dec 2026 Swap 4,000 WTI Cushing $ 63.50 $ — $ — Oct – Dec 2026 Roll Swap 10,000 NYMEX WTI Roll $ 4.04 $ — $ — Oct – Dec 2026 Basis Swap 5,000 Argus WTI Midland $ 1.01 $ — $ — Jan – Mar 2027 Swap 3,400 WTI Cushing $ 61.81 $ — $ — Jan – Mar 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — — Apr – Jun 2027 Swap 2,950 WTI Cushing $ 61.52 $ — $ — Apr – Jun 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Jul – Sep 2027 Swap 8,950 WTI Cushing $ 61.46 $ — $ — Jul – Sep 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Oct – Dec 2027 Basis Swap 10,000 Argus WTI Midland $ 1.00 $ — $ — Natural gas derivative financial instruments. In January 2026, the Company entered into the following additional natural gas derivative financial instruments: Settlement Month Settlement Year Type of Contract MMBtu Per Day Index Price per MMBtu Natural Gas: Jan – Mar 2026 Swap 1,556 HH $ 7.24 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, 2025 2024 Proved properties $ 4,477,368 $ 3,959,545 Unproved properties 59,285 70,868 Total capitalized costs 4,536,653 4,030,413 Less: accumulated depletion ( 1,606,217 ) ( 1,184,684 ) Net capitalized costs $ 2,930,436 $ 2,845,729 115 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, 2025 2024 2023 Acquisition costs: Proved properties $ — $ 385 $ 3,308 Unproved properties 6,724 14,459 11,777 Total acquisition costs 6,724 14,844 15,085 Exploration costs 145,679 162,223 527,502 Development costs 366,084 442,076 481,528 Crude oil and natural gas expenditures 518,487 619,143 1,024,115 Asset retirement obligations, net 3,823 1,068 6,048 Total costs incurred $ 522,310 $ 620,211 $ 1,030,163 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, 2025 2024 2023 Crude oil, NGL and natural gas sales $ 863,359 $ 1,117,175 $ 1,131,131 Lease operating expenses 139,492 132,244 145,362 Gathering, processing and transportation 68,401 47,761 19,838 Production and ad valorem taxes 37,224 59,677 58,472 Exploration and abandonment expense 16,685 1,476 5,234 Depletion, depreciation and amortization expense 421,776 500,752 424,424 Accretion of discount on asset retirement obligations 1,075 966 522 Income tax expense 37,528 78,603 100,229 Results of operations from crude oil and natural gas production activities $ 141,178 $ 295,696 $ 377,050 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, 2025, 2024 and 2023 were $ 65.34 , $ 75.48 and $ 78.22 per barrel for crude oil and NGL and $ 3.387 , $ 2.130 and $ 2.637 per MMBtu for natural gas, respectively. The estimated realized prices used in computing the Company’s reserves as of December 31, 2025 were as follows: (i) $ 65.32 per barrel of crude oil, (ii) $ 3.20 per barrel of NGL, and (iii) $ 0.795 per Mcf of natural gas. The estimated realized prices used in computing the Company’s reserves as of December 31, 2024 were as follows: (i) $ 75.56 per barrel of crude oil, (ii) $ 20.53 per barrel of NGL, and (iii) $ 0.072 per Mcf of natural gas. 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. 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, 2025, 2024 and 2023 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. 116 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, 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 Extensions and discoveries 34,971 5,387 28,476 45,104 Revisions of previous estimates ( 5,378 ) 10,919 74,854 18,017 Production ( 13,876 ) ( 2,284 ) ( 12,747 ) ( 18,285 ) Proved Reserves on December 31, 2024 135,271 34,118 177,654 198,998 Extensions and discoveries 14,045 2,467 14,052 18,854 Sales of reserves-in-place ( 20 ) ( 1 ) ( 4 ) ( 22 ) Revisions of previous estimates ( 23,086 ) ( 3,245 ) 119 ( 26,311 ) Production ( 12,012 ) ( 2,895 ) ( 16,327 ) ( 17,628 ) Proved Reserves on December 31, 2025 114,198 30,444 175,494 173,891 On December 31, 2025, the Company had approximately 173,891 MBoe of proved reserves. For the year ended December 31, 2025, extensions and discoveries increased proved reserves by 18,854 MBoe as a result of; (i) drilling 17 gross ( 17.0 net) exploratory/extension wells that were on production as of December 31, 2025, (ii) 14 gross ( 14.0 net) exploratory/extension wells that were in the final stages of completion as of December 31, 2025, and (iii) the addition of 24 gross ( 24.0 net) PUDs. Downward revisions of previous estimates of 26,311 MBoe for the year ended December 31, 2025 were the result of negative revisions of approximately 10,767 MBoe primarily due to technical revisions attributable to decreased well performance and adjustments to our estimates, approximately 8,970 MBoe primarily related to decreases in crude oil and NGL realized prices, 6,488 MBoe of reserves that were reclassified to unproved reserves due to changes made to our development plan and approximately 86 MBoe primarily due to increased forecasted operating expenses. In addition to the aforementioned net decrease in proved reserves was 17,628 MBoe in production during the year ended December 31, 2025. The Company also sold small interests in a few old vertical wells outside of its core area during the year ended December 31, 2025 further reducing proved reserves by 22 Mboe. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. On December 31, 2024, the Company had approximately 198,998 MBoe of proved reserves. For the year ended December 31, 2024, extensions and discoveries increased proved reserves by 45,104 MBoe as a result of; (i) drilling 18 gross ( 14.6 net) exploratory/extension wells that were on production as of December 31, 2024, (ii) 5 gross ( 5.0 net) exploratory/extension wells that were in the final stages of completion as of December 31, 2024, and (iii) the addition of 79 gross ( 68.9 net) PUDs. Upward revisions of previous estimates of 18,017 MBoe for the year ended December 31, 2024 were the result of positive revisions of approximately 19,406 MBoe primarily due to technical revisions attributable to increased well performance and adjustments to our estimates, partially offset by approximately 804 MBoe primarily due to increased forecasted operating expenses and approximately 585 MBoe primarily related to decreases in crude oil, NGL and natural gas realized prices. The aforementioned net increase in proved reserves was partially offset by 18,285 MBoe in production during the year ended December 31, 2024. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. 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. 117 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, 2025 2024 2023 Proved Developed Reserves (1) Crude oil (MBbl) 55,092 65,632 58,631 NGL (MBbl) 20,941 22,753 12,183 Natural gas (MMcf) 120,566 118,402 52,671 Total (MBoe) 96,127 108,119 79,593 Proved Undeveloped Reserves Crude oil (MBbl) 59,106 69,639 60,923 NGL (MBbl) 9,503 11,365 7,913 Natural gas (MMcf) 54,928 59,252 34,400 Total (MBoe) 77,764 90,879 74,569 Total Proved Reserves Crude oil (MBbl) 114,198 135,271 119,554 NGL (MBbl) 30,444 34,118 20,096 Natural gas (MMcf) 175,494 177,654 87,071 Total (MBoe) 173,891 198,998 154,162 (1) As of December 31, 2025, 2024 and 2023, proved developed reserves includes proved developed non-producing reserves of 5,554 , 6,239 and 4,598 MBbl of crude oil, 1,101 , 1,044 and 534 MBbl of NGL and 6,349 , 5,668 and 1,889 MMcf of natural gas, respectively. On December 31, 2025, the Company’s estimated PUD reserves were approximately 77,764 MBoe, a 13,115 MBoe decrease over the reserve estimate at December 31, 2024 of 90,879 MBoe. The following table includes the changes in PUD reserves for 2025 (in MBoe): Beginning proved undeveloped reserves on December 31, 2024 90,879 Undeveloped reserves transferred to proved developed reserves ( 12,250 ) Extensions and discoveries 10,666 Revisions ( 11,531 ) Ending proved undeveloped reserves on December 31, 2025 77,764 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, 2025 2024 2023 Future cash inflows $ 7,696,681 $ 10,934,170 $ 9,706,290 Future production costs ( 2,598,811 ) ( 3,240,114 ) ( 2,869,377 ) Future development costs (1) ( 1,459,026 ) ( 1,547,179 ) ( 1,568,033 ) Future income tax expense ( 309,957 ) ( 837,031 ) ( 680,894 ) Future net cash flows 3,328,887 5,309,846 4,587,986 Discount to present value at 10% annual rate ( 1,416,132 ) ( 2,314,849 ) ( 1,980,282 ) Standardized measure of discounted future net cash flows (1) $ 1,912,755 $ 2,994,997 $ 2,607,704 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, 2025 2024 2023 Standardized measure of discounted future net cash flows, beginning of year $ 2,994,997 $ 2,607,704 $ 3,416,508 Sales of crude oil and natural gas, net of production costs ( 618,241 ) ( 877,493 ) ( 907,459 ) Extensions and discoveries, net of future development costs (1) 261,995 772,541 1,202,674 Net changes in prices and production costs ( 1,032,585 ) ( 547,790 ) ( 1,404,147 ) Changes in estimated future development costs (1) 20,497 110,664 ( 37,820 ) Purchases of minerals-in-place — — 4,344 Sales of reserves-in-place ( 354 ) — ( 25,069 ) Revisions of previous quantity estimates ( 416,359 ) 361,064 ( 390,282 ) Accretion of discount 339,873 288,117 395,656 Net changes in income taxes 271,112 ( 130,265 ) 266,579 Net changes in timing of production and other 91,820 410,455 86,720 Standardized measure of discounted future net cash flows, end of year (1) $ 1,912,755 $ 2,994,997 $ 2,607,704 (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. 118 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.