PEDEVCO CORP 10-K

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEX TO FINANCIAL STATEMENTS Audited Financial Statements for Years Ended December 31, 2025 and 2024 PEDEVCO Corp.: Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410 ) 95 Consolidated Balance Sheets as of December 31, 2025 and 2024 97 Consolidated Statements of Operations for the Years Ended December 31, 2025 and 2024 98 Consolidated Statements of Cash Flows for the Years Ended December 31, 2025 and 2024 99 Consolidated Statement of Changes in Shareholders’ Equity For the Years Ended December 31, 2025 and 2024 100 Notes to Consolidated Financial Statements 101 94 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors and Shareholders PEDEVCO Corp. Opinion on the Consolidated Financial Statements We have audited the accompanying consolidated balance sheets of PEDEVCO Corp. (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 two years in the period ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These consolidated financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters 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 critical audit matters does 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Estimation of proved oil and gas reserves impacting the valuation of depletion expense related to proved oil and gas properties As described in Notes 3 and 7 to the consolidated financial statements, the Company uses the successful efforts method of accounting for its oil and gas exploration and production activities and determines depreciation, depletion, and amortization of capitalized oil and gas properties using the unit of production method on a field-by-field basis. Under this method, lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves, and all other capitalized costs are amortized over proved developed reserves. As disclosed by management, proved oil and gas reserves are the estimated quantities crude oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). For the year ended December 31, 2025, the Company recorded depreciation, depletion, and amortization expense related to proved oil and gas properties of $17.0 million. We identified the estimation of proved oil and gas reserves impacting the valuation of depletion expense related to proved oil and gas properties as a critical audit matter. 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 the volumes 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 judgement. 95 Table of Contents 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 reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved oil and gas reserve volumes, and read the reserve report prepared by the Company’s specialists. · We evaluated the methods, data (both Company-produced and data 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: · Compared estimated future production volumes to relevant historical and current period information, as applicable; and · Assessed the reasonableness of the production volume decline curves by comparing to historical decline curve estimates. Merger with North Peak Oil & Gas Holdings, LLC and Century Oil and Gas Sub-Holdings, LLC – Estimation of the fair value of proved oil and gas properties and proved reserves acquired As described in Notes 3 and 6 to the consolidated financial statements, on October 31, 2025, the Company completed the merger with North Peak Oil & Gas Holdings, LLC (“NPOG”) and Century Oil and Gas Sub-Holdings LLC (“COG”), which has been accounted for under the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities of NPOG and COG have been recorded at their respective fair values as of the acquisition date on October 31, 2025. The Company recorded the assets acquired and liabilities assumed at their estimated fair value on October 31, 2025 of $179.9 million, of which $191.7 million related to proved oil and gas properties. As disclosed by management, the fair value of the oil and gas properties was calculated using an income approach based on the net discounted cash flows that utilized inputs requiring significant judgment and assumptions, including future production , future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate. The principal considerations for our determination that the estimation of the fair value of proved oil and gas properties and proved reserves acquired in the business combination are critical audit matters are (i) the significant judgment by management, including the use of specialists, when developing the fair value estimate of the proved oil and gas properties acquired, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital discount rate, and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the fair value of proved oil and gas properties acquired included, among others, the following: · We evaluated the level of knowledge, skill, and ability of management’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineering specialists regarding the process followed and judgments made to evaluate the reasonableness of the future production volumes used in the discounted cash flow models. · We evaluated the level of knowledge, skill, and ability of management’s valuation specialists and their relationship to the Company, made inquiries of those valuation specialists regarding the process followed and judgments made to evaluate the reasonableness of the discounted cash flow models and read the valuation report prepared by the Company’s specialists. · We evaluated the methods, data (both Company-produced and data from external sources) and significant assumptions used in the discounted cash flow models. Specifically, our audit procedures included, among others, the following: · Evaluated the reasonableness of the significant assumptions used by management related to future production volumes, future commodity prices (adjusted for basis differentials), and future operating and development costs by considering past performance, consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit, including the evaluation of any contrary evidence. · Evaluated the reasonableness of the significant assumptions used by management related to the market-based weighted average cost of capital discount rate by considering the consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit, including the evaluation of any contrary evidence. /s/ Weaver and Tidwell, L.L.P. Houston, Texas March 31, 2026 We have served as the Company’s auditor since 2025. 96 Table of Contents PEDEVCO CORP. CONSOLIDATED BALANCE SHEETS (amounts in thousands, except share and per share data) December 31, 2025 2024 Assets Current assets: Cash $ 3,222 $ 4,010 Accounts receivable – oil and gas 25,666 7,995 Note receivable, current - 293 Inventory 61 - Derivative contract assets, current 8,368 - Prepaid expenses and other current assets 434 917 Total current assets 37,751 13,215 Oil and gas properties: Oil and gas properties, subject to amortization, net 303,411 95,070 Oil and gas properties, not subject to amortization, net 18,859 8,442 Total oil and gas properties, net 322,270 103,512 Note receivable - 933 Operating lease – right-of-use asset 213 224 Derivative contract assets 9,640 - Deferred income taxes - 7,255 Other assets 5,995 3,210 Total assets $ 375,869 $ 128,349 Liabilities and Shareholders’ Equity Current liabilities: Accounts payable $ 32,436 $ 2,625 Accrued expenses 8,245 2,255 Revenue payable 21,480 1,266 Operating lease liabilities – current 182 99 Derivative contract liabilities - current 964 - Asset retirement obligations – current 1,170 663 Total current liabilities 64,477 6,908 Long-term liabilities: Revolving credit facility 87,000 - Operating lease liabilities, net of current portion 32 129 Derivative contract liabilities 6,358 - Asset retirement obligations, net of current portion 7,641 5,708 Deferred income taxes 800 - Other long-term liabilities 2,197 - Total liabilities 168,505 12,745 Commitments and contingencies (Note 13) Shareholders’ equity: Series A preferred stock, $ 0.001 par value, 200,000,000 shares authorized; 17,013,637 and - 0 - shares issued and outstanding, respectively 17,014 - Common stock, $ 0.001 par value, 200,000,000 shares authorized; 4,797,239 and 4,474,765 shares issued and outstanding, respectively 5 4 Additional paid-in capital 312,205 227,098 Accumulated deficit ( 121,860 ) ( 111,498 ) Total shareholders’ equity 207,364 115,604 Total liabilities and shareholders’ equity $ 375,869 $ 128,349 See accompanying notes to consolidated financial statements. 97 Table of Contents PEDEVCO CORP. CONSOLIDATED STATEMENTS OF OPERATIONS (amounts in thousands, except share and per share data) December 31, 2025 2024 Revenue: Oil and gas sales $ 45,751 $ 39,553 Operating expenses: Lease operating costs 19,120 12,449 Selling, general and administrative expense 16,788 6,391 Impairment of oil and gas properties 908 - Depreciation, depletion, amortization and accretion 18,009 15,920 Total operating expenses 54,825 34,760 Gain (Loss) on sale of oil and gas properties, net 2,597 ( 76 ) Note receivable – credit loss ( 1,378 ) - Operating income ( 7,855 ) 4,717 Other income (expense): Interest expense ( 1,407 ) - Interest income 274 351 Gain on sale of fixed asset - 12 Net gain on derivative contracts 6,253 - Other income (expense) 428 ( 42 ) Total other income 5,548 321 Income before income taxes ( 2,307 ) 5,038 Income tax (expense) benefit ( 8,055 ) 7,255 Net (loss) income $ ( 10,362 ) $ 12,293 Earnings per common share: Basic $ ( 2.25 ) $ 2.76 Diluted $ ( 2.25 ) $ 2.76 Weighted average number of common shares outstanding: Basic 4,615,058 4,461,732 Diluted 4,615,058 4,461,732 See accompanying notes to consolidated financial statements. 98 Table of Contents PEDEVCO CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (amounts in thousands) December 31, 2025 2024 Cash Flows From Operating Activities: Net (loss) income $ ( 10,362 ) $ 12,293 Adjustments to reconcile net (loss) income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 18,009 15,920 Impairment of oil and gas properties 908 - Note receivable – credit loss 1,378 - Amortization of right-of-use asset 170 110 Amortization of deferred financing costs 267 - Share-based compensation expense 2,763 1,859 Unrealized gain on derivative contracts, net ( 6,253 ) - Cash received for derivative settlements, net 2,136 - Disposition of escrow cash account - 50 Deferred income taxes 8,055 ( 7,255 ) (Gain) loss on sale of oil and gas properties, net ( 2,597 ) 76 Gain on disposal of fixed asset - ( 12 ) Changes in operating assets and liabilities: Accounts receivable – oil and gas ( 4,976 ) ( 2,115 ) Inventory ( 61 ) - Note receivable accrued interest ( 41 ) ( 85 ) Prepaid expenses and other assets ( 899 ) ( 657 ) Accounts payable 2,310 541 Accrued expenses ( 1,067 ) ( 5,854 ) Other long term liabilities ( 46 ) - Revenue payable 1,064 ( 2,105 ) Net cash provided by operating activities 10,758 12,766 Cash Flows From Investing Activities: Cash paid for merger acquisition ( 115,646 ) - Cash paid for drilling and completion costs ( 20,486 ) ( 27,857 ) Cash paid for other property and equipment - ( 169 ) Cash received for sale of oil and gas properties 2,949 1,140 Cash received for sale of vehicle - 12 Net cash used in investing activities ( 133,183 ) ( 26,874 ) Cash Flows From Financing Activities: Proceeds from credit facility 87,000 - Proceeds from the issuance of convertible preferred stock 35,000 - Proceeds from issuance of shares, net of offering costs 139 - Net cash provided by investing activities 122,139 - Net increase (decrease) in cash and restricted cash ( 286 ) ( 14,108 ) Cash and restricted cash at beginning of period 6,607 20,715 Cash and restricted cash at end of period $ 6,321 $ 6,607 Supplemental Disclosure of Cash Flow Information Cash paid for: Interest $ 590 $ - Income taxes $ - $ - Noncash investing and financing activities: Change in accrued oil and gas development costs $ 11,191 $ 5,747 Changes in estimates of asset retirement costs, net $ 1,218 $ 3,501 Issuance of restricted common stock $ 1 $ - Non-cash consideration exchanged in Merger Acquisition: Issuance of convertible preferred stock $ 64,220 $ - See accompanying notes to consolidated financial statements. 99 Table of Contents PEDEVCO CORP. CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY For the Years Ended December 31, 2025 and 2024 (amounts in thousands, except share amounts) Series A Preferred Stock Common Stock Additional Paid-in Accumulated Shares Amount Shares Amount Capital Deficit Totals Balances at December 31, 2023 - $ - 4,362,515 $ 4 $ 225,239 $ ( 123,791 ) $ 101,452 Issuance of restricted common stock - - 115,750 - - - - Rescinded restricted common stock - - ( 3,500 ) - - - - Stock-based compensation - - - - 1,859 - 1,859 Net income - - - - - 12,293 12,293 Balances at December 31, 2024 - - 4,474,765 4 227,098 ( 111,498 ) 115,604 Issuance of series A preferred stock - Mergers 10,650,000 10,650 - - 53,570 - 64,220 Issuance of series A preferred stock - PIPE 6,364,000 6,364 - - 28,636 - 35,000 Issuance of common stock for cash proceeds, net - - 24,497 - 139 - 139 Issuance of restricted common stock - - 297,977 1 ( 1 ) - - Stock-based compensation - - - - 2,763 - 2,763 Net loss - - - - - ( 10,362 ) ( 10,362 ) Balances at December 31, 2025 17,013,637 $ 17,014 4,797,239 $ 5 $ 312,205 $ ( 121,860 ) $ 207,364 See accompanying notes to consolidated financial statements. 100 Table of Contents PEDEVCO CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 – BASIS OF PRESENTATION The accompanying consolidated financial statements of PEDEVCO Corp. (“PEDEVCO” or the “Company”), have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and the rules of the Securities and Exchange Commission (“SEC”). The Company’s consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and subsidiaries in which the Company has a controlling financial interest. All significant inter-company accounts and transactions have been eliminated in consolidation. Reverse Stock Split On March 13, 2026, the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock (the “Reverse Stock Split”). The Reverse Stock Split was approved by the Company’s stockholders on October 29, 2025, with the ratio being approved by the Company’s Board of Directors on February 27, 2026, with the stockholder consent being effective on February 27, 2026. As a result of the Reverse Stock Split: · every 20 shares of issued and outstanding common stock were automatically combined into one share of common stock; · the par value of the Company’s common stock remained unchanged at $ 0.001 per share; and · fractional shares remaining after the Reverse Stock Split were paid in cash. All authorized, issued, and outstanding common stock, stock options, and other equity instruments, as well as the related exercise or conversion prices, were proportionately adjusted to reflect the Reverse Stock Split. Retroactive Adjustment All share amounts, per-share data, earnings (loss) per share, and weighted-average shares outstanding presented in the accompanying consolidated financial statements and related notes have been retroactively adjusted to reflect the Reverse Stock Split for all periods presented, unless otherwise indicated. The Reverse Stock Split did not affect the Company’s total stockholders’ equity or the proportionate voting rights of stockholders, and no fractional shares were issued in connection with the reverse stock split. Stockholders who would otherwise have been entitled to receive fractional shares received cash in lieu thereof, based on the closing price of the Company’s common stock on March 12, 2026, the trading day immediately prior to the effective date of the Reverse Stock Split. NOTE 2 – DESCRIPTION OF BUSINESS PEDEVCO is an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. In particular, the Company focuses on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies. The Company’s current properties are located in the Denver-Julesberg Basin (“ D-J Basin ”) in Colorado and Wyoming, the Powder River Basin (“ PRB ”) in Wyoming, and in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “ Permian Basin ”). The Company’s D-J Basin assets (the “D-J Basin Assets”) are located in Weld and Morgan Counties, Colorado and Laramie County, Wyoming, are held through the Company’s wholly-owned subsidiaries, PRH Holdings LLC (“ PRH ”) and North Peak Oil & Gas, LLC (“ NPOG ”), and are operated by the Company’s wholly-owned operating subsidiaries, Red Hawk Petroleum, LLC (“ Red Hawk ”), North Silo Resources, LLC (“ NSR ”), and Longs Peak Resources, LLC (“ LPR ”). 101 Table of Contents The Company’s Powder River Basin assets (the “Powder River Basin Assets” or “PRB Assets”) are predominantly located in Laramie and Campbell Counties, Wyoming, are held through the Company’s wholly-owned subsidiary Century Oil and Gas, LLC (“ Century ”), and operated by the Company’s wholly-owned operating subsidiaries, Century Oil and Gas Sub-Holdings, LLC (“COG”), Navigation Powder River, LLC (“ NPR ”), and Pine Haven Resources, LLC (“ Pine Haven ”). The Company’s Permian Basin assets (the “Permian Basin Assets”) are located in Chaves and Roosevelt Counties, New Mexico, are held by the Company’s wholly-owned subsidiary, Pacific Energy Development Corp. (“ PEDCO ”), and are operated by the Company’s wholly-owned subsidiary, Ridgeway Arizona Oil Corp. (“ RAZO ”). On October 31, 2025, the Company completed the transactions (the “Mergers”) contemplated by that certain Agreement and Plan of Merger, dated October 31, 2025 (the “Merger Agreement”), by and among the Company; NP Merger Sub, LLC, a wholly owned subsidiary of the Company (“First Merger Sub”); COG Merger Sub, LLC, a wholly owned subsidiary of the Company (“Second Merger Sub,” and together with First Merger Sub, the “Merger Subs”); North Peak Oil & Gas, LLC (NPOG); COG (together with NPOG, the “Acquired Companies”); and, solely for purposes of specified provisions therein, North Peak Oil & Gas Holdings, LLC (“North Peak”). The Acquired Companies own substantial oil-weighted producing assets and significant leasehold interests in the D-J Basin and PRB. The Company believes that horizontal development and exploitation of conventional assets in the Wattenberg and Wattenberg Extension in the D-J Basin, the PRB, and the Permian Basin represent among the most economic oil and natural gas plays in the United States (“U.S.”). Moving forward, the Company plans to optimize its existing assets and opportunistically seek additional acreage proximate to its currently held core acreage, as well as other attractive onshore U.S. oil and gas assets that fit the Company’s acquisition criteria, that Company management believes can be developed using its technical and operating expertise and be accretive to shareholder value. NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation and Principles of Consolidation. The consolidated financial statements herein have been prepared in accordance with US GAAP and include the accounts of the Company and those of its wholly and partially-owned subsidiaries as follows: (i) PEDCO, a Nevada corporation; (ii) Red Hawk, a Nevada limited liability company; (iii) RAZO, an Arizona corporation; (iv) SRPT Acquisition, LLC, a Texas limited liability company, (v) PRH, a Nevada limited liability company, (vi) NPOG, a Delaware limited liability company, (ix) COG, a Delaware limited liability company, and (x) other wholly-owned subsidiaries of NPOG and COG. All significant intercompany accounts and transactions have been eliminated. Use of Estimates in Financial Statement Preparation. The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the consolidated financial statements are appropriate, actual results could differ from these estimates. Significant estimates generally include those with respect to the amount of recoverable proved oil and gas reserves, the fair value of financial instruments, oil and gas depletion, asset retirement obligations, stock-based compensation and the assignment of fair value and allocation of purchase price in connection with business combinations. Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company includes restricted cash within cash and cash equivalents on the consolidated statements of cash flows. 102 Table of Contents Concentrations of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk include cash deposits placed with financial institutions. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal. Sales to two customers comprised 26 % and 22 % of the Company’s total oil and gas revenues, with one third-party operator contributing 30 % of non-operated interest revenues for the year ended December 31, 2025, compared to sales to three customers comprising 38 %, 36 % and 12 %, respectively, of the Company’s total oil and gas revenues for the year ended December 31, 2024. The Company believes that, in the event that its primary customers are unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices. Accounts Receivable. Accounts receivable typically consist of oil and gas receivables. The Company has classified these as short-term assets in the consolidated balance sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable for collectability considering the results of operations of these related entities and, when necessary, records allowances for expected unrecoverable amounts. To date, no allowances have been recorded. Included in accounts receivable - oil and gas are $ 8.5 million related to receivables from joint interest owners. As of January 1, 2024, the company had $ 5.8 million of accounts receivable and no contract assets. Business Combinations. The Company accounts for business combinations using the acquisition method, recording oil and gas assets acquired and liabilities assumed at estimated fair values. Fair values are determined using discounted cash flows, market comparables, and other valuation techniques, with significant judgment applied to estimates of reserves, future commodity prices, and operating and development costs. Purchase price allocations may be adjusted during a one-year measurement period. The Merger Acquisition was completed on October 31, 2025 and has been accounted for under the acquisition method of accounting in accordance with ASC 805, Business Combinations (" ASC 805 "), PEDEVCO was treated as the acquirer for accounting purposes. Under the acquisition method of accounting, the assets and liabilities of Acquired Companies have been recorded at their respective fair values as of the acquisition date on October 31, 2025. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after October 31, 2025. See Note 6 – Merger Acquisition for additional information. Credit Loss Expense. The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. Though the Company’s credit losses have not historically been significant, the Company could experience increased credit loss expense should a financial downturn occur. During the year ended December 31, 2025, the Company recognized a $ 1.4 million note receivable – credit loss related to the sale of our then wholly-owned subsidiary EOR Operating Company in November 2023. There were no credit losses in 2024. Equipment. Equipment is stated at cost less accumulated depreciation and amortization. Maintenance and repairs are charged to expense as incurred. Renewals and betterments which extend the life or improve existing equipment are capitalized. Upon disposition or retirement of equipment, the cost and related accumulated depreciation are removed, and any resulting gain or loss is reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of the assets, which are 3 to 10 years. Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. 103 Table of Contents Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise, the related well costs are expensed as dry holes. Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above. Depreciation, depletion and amortization of capitalized oil and gas properties is calculated on a field-by-field basis using the unit of production method. Lease acquisition costs are amortized over the total estimated proved developed and undeveloped reserves and all other capitalized costs are amortized over proved developed reserves. Costs specific to developmental wells for which drilling is in progress or uncompleted are capitalized as wells in progress and not subject to amortization until completion and production commences, at which time amortization on the basis of production will begin. Impairment of Long-Lived Assets. The Company reviews the carrying value of its long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value. The Company also evaluates oil and gas properties not subject to amortization, including expired leases, for impairment, and when impairment is identified, a loss is recognized in the applicable period. Asset Retirement Obligations. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company will record a liability (an asset retirement obligation or “ARO”) on its consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the capitalized costs are depreciated on a unit-of-production basis over the estimated proved developed reserves. Both the accretion and the depreciation will be included in depreciation, depletion and amortization expense on our consolidated statements of operations. Fair Value of Financial Instruments. The Company’s financial instruments consist of cash, accounts receivable, accounts payable, derivative instruments, and debt. Except for derivative instruments and debt, the carrying amounts of cash, accounts receivable and accounts payable are short-term instruments and approximate fair value due to their highly liquid nature. The carrying amount of debt approximates fair value as the variable rates on the Amended and Restated Credit Agreement, as discussed in Note 9, “Revolving Credit Facility,” are market interest rates. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and natural gas, discount rates, and volatility factors. Revenue Recognition. The Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. NGLs are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery. 104 Table of Contents Contracts with customers have varying terms, including month-to-month contracts, and contracts with a finite term. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues. Income Taxes. The Company utilizes the asset and liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carry-forwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the value of such assets will be realized. Uncertain Tax Positions. The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained. The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results. Stock-Based Compensation. The Company utilizes the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. The Company estimates volatility by considering the historical stock volatility. The Company has opted to use the simplified method for estimating expected term, which is generally equal to the midpoint between the vesting period and the contractual term. The Company accounts for forfeitures as they occur; accordingly, stock-based compensation expense is recognized for all awards granted and adjusted in the period in which awards are forfeited. Derivative Instruments. The Company may periodically enter into derivative contracts to manage its exposure to commodity risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company chose not to elect hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations. 105 Table of Contents Earnings per Common Share. Basic earnings (loss) per share (“EPS”) is calculated by dividing net income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted during the period. Diluted EPS is computed using the treasury stock method for stock options and warrants and the if-converted method for convertible preferred stock. Potentially dilutive securities are excluded from the computation of diluted EPS if their effect would be anti-dilutive. For the year ended December 31, 2025, stock options to purchase 104,200 shares of common stock were excluded from the computation of diluted EPS because their effect was anti-dilutive. In addition, 17,013,637 shares of convertible preferred stock outstanding as of December 31, 2025, each convertible into 0.5 shares of common stock, were excluded from diluted EPS because their effect was anti-dilutive. For the year ended December 31, 2024, potentially dilutive securities related to options 1,834,041 were excluded from the computation of diluted net income per share as the inclusion of such shares would be anti-dilutive. Recently Adopted Accounting Pronouncements . In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. The Company adopted this ASU on December 31, 2025 and has reflected the required disclosures in the accompanying notes to the consolidated financial statements. The ASU had no impact on the Company’s consolidated balance sheets, consolidated statements of operations or consolidated statements of cash flows. Subsequent Events. The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration. NOTE 4 – CASH The following table provides a reconciliation of cash and restricted cash reported within the consolidated balance sheets as of December 31, 2025 and 2024, which sum to the total of such amounts shown in the accompanying consolidated statements of cash flows (in thousands): 2025 2024 Cash $ 3,222 $ 4,010 Restricted cash included in other assets* 3,099 2,597 Total cash and restricted cash $ 6,321 $ 6,607 * Restricted cash is related to collateral for surety bonds, which increased due to additional surety bonds acquired through the Mergers. NOTE 5 – REVENUE FROM CONTRACTS WITH CUSTOMERS Disaggregation of Revenue from Contracts with Customers. The following table disaggregates revenue by significant product type for the years ended December 31, 2025 and 2024 (in thousands): 2025 2024 Oil sales $ 40,230 $ 36,193 Natural gas sales 2,663 1,216 Natural gas liquids sales 2,858 2,144 Total revenue from customers $ 45,751 $ 39,553 There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December 31, 2025 or 2024, respectively. 106 Table of Contents NOTE 6 –MERGER ACQUISITION On October 31, 2025, the Company completed the transactions contemplated by that certain Agreement and Plan of Merger, dated October 31, 2025, by and among the Company; NP Merger Sub, LLC, a wholly owned subsidiary of the Company (First Merger Sub); COG Merger Sub, LLC, a wholly owned subsidiary of the Company (Second Merger Sub); North Peak Oil & Gas, LLC (NPOG); Century Oil and Gas Sub-Holdings, LLC; and, solely for purposes of specified provisions therein, North Peak Oil & Gas Holdings, LLC. Pursuant to the Merger Agreement, (i) First Merger Sub merged with and into NPOG, with NPOG surviving as a wholly owned subsidiary of PEDEVCO, and (ii) Second Merger Sub merged with and into COG, with COG surviving as a wholly owned subsidiary of PEDEVCO. The Acquired Companies own substantial oil-weighted producing assets and significant leasehold interests in the D-J Basin and Powder River Basin located in Wyoming. The aggregate fair value of the consideration paid in the Mergers was approximately $ 179.9 million. Of this amount, $ 115.6 million was paid in cash at closing, including (a) $ 87.0 million drawn under the Company’s Amended and Restated Credit Agreement (net of $ 1.3 million in debt issuance costs) and (b) proceeds from certain investors who subscribed for and purchased an aggregate of 6,363,637 shares of PEDEVCO Series A Preferred Stock at a purchase price of $ 5.50 per share ($ 11.00 per share on a post-reverse stock split basis), resulting in gross proceeds of $ 35.0 million. The cash consideration was further reduced by $ 4.7 million in transaction costs directly related to the Mergers. On February 27, 2026, the Series A Preferred Stock converted into 3,181,818 shares of PEDEVCO common stock (see Note 19 – “Subsequent Events”)(the “Automatic Conversion Date”). The acquisition was accounted for as a business combination under the acquisition method of accounting in accordance with ASC 805, Business Combinations. The fair value of the consideration transferred was allocated to the identifiable assets acquired and liabilities assumed on a relative fair value basis and recorded as of October 31, 2025. The preliminary allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized Acquisition-related costs were expensed as incurred in accordance with ASC 805. Determining the fair value of the acquired assets and assumed liabilities required significant judgment and the use of various assumptions, the most significant of which related to the valuation of NPOG’s and COG’s oil and gas properties. The inputs and assumptions used in valuing these properties were classified as Level 3 within the fair value hierarchy. Consideration: Series A Convertible Preferred Stock 10,650 Fair Value Per Share of Preferred Stock $ 6.030 Common stock consideration, net of estimated liabilities assumed by PEDEVCO $ 64,220 Cash paid to settle North Peak Debt 115,646 Total consideration $ 179,866 Fair value of assets acquired: Cash, cash equivalents and restricted cash $ 24 Accounts receivable 12,806 Commodity derivative, asset - current 5,264 Prepaid expenses and other current assets 591 Evaluated oil and gas properties 191,700 Unevaluated oil and gas properties 11,266 Asset retirement costs 1,584 Other long-term assets 2,177 Total assets acquired $ 225,412 Fair value of liabilities assumed: Accounts payable and accrued liabilities $ 41,719 Asset retirement obligations - current 488 Asset retirement obligations - long-term 1,096 Other long-term liabilities 2,243 Total liabilities assumed $ 45,546 Total identifiable net assets acquired $ 179,866 107 Table of Contents Approximately $ 14.2 million of revenues, $ 7.6 million of direct operating expenses and $ 6.6 million in net income attributed to the Mergers were included in the Company’s Consolidated Statements of Operations for the period from November 1, 2025 through December 31, 2025. The Acquired Companies’ results of operations have been included in the Company’s consolidated financial statements since October 31, 2025, the effective date of the Mergers. The following unaudited supplemental pro forma information for the years ended December 31, 2025 and 2024 presents the combined results of operations as if the Mergers had been completed on January 1, 2024. The unaudited pro forma information reflects adjustments based on available information and assumptions that management believes are reasonable and supportable. The pro forma results do not reflect any anticipated cost savings, operating synergies, or integration costs associated with the acquisition. The unaudited pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that would have been achieved had the transaction occurred as of January 1, 2024, nor is it intended to be indicative of future results. Actual results may differ materially due to a variety of factors, including, but not limited to, production declines, changes in commodity prices, and future acquisitions, divestitures, and development activities. Year Ended December 31, (in thousands, except per share information) 2025 2024 Pro forma revenue $ 132,215 $ 197,879 Pro forma net income $ 21,399 $ 44,429 Pro forma basic earnings per share $ 4.64 $ 9.96 Pro forma diluted earnings per share $ 4.64 $ 9.96 At the closing of the Mergers (the “Closing”), the Company entered into a Shareholder Agreement with Century and North Peak (together, the “Juniper Shareholder”), and, for certain limited provisions, Dr. Simon G. Kukes, the then Executive Chairman of the Company and The SGK 2018 Revocable Trust (a trust which Dr. Simon serves as trustee and beneficiary of). The agreement granted the Juniper Shareholder board nomination rights from the closing of the Mergers until the Automatic Conversion Date, including the ability to designate one board nominee and one non-voting observer. The agreement also provides that, following the Automatic Conversion Date, the Board will consist of six directors, with Juniper’s nominees determined by its ownership percentage of shares of the Company’s common stock on the Automatic Conversion Date. Specifically, the right of the Juniper Shareholder to nominate Juniper Directors pursuant to the Shareholder Agreement will depend on its, together with its affiliates’, ownership of 3,181,818 shares of Company common stock issued to the Juniper Shareholder and its affiliates on February 27, 2026, on the applicable date of determination, as measured relative to a total of 13,300,815 shares of common stock issued and outstanding on February 27, 2026 (“ Juniper Beneficial Ownership ”), as follows: if Juniper Beneficial Ownership is 50 % or more, the Juniper Shareholder may nominate three Juniper Directors, including one which must be an independent director; if Juniper Beneficial Ownership is between 30 % and 49.9 %, the Juniper Shareholder may nominate two Juniper Directors; if Juniper Beneficial Ownership is between 10 % and 29.9 %, the Juniper Shareholder may nominate one Juniper Director; and if Juniper Beneficial Ownership is less than 10%, the Juniper Shareholder loses the right to nominate any Juniper Directors. 108 Table of Contents The Juniper Shareholder also retains the right to remove or replace its directors, subject to Board approval and suitability requirements under SEC and NYSE standards. At least one Juniper Shareholder director will serve on each Board committee (except the audit committee), and will chair the Compensation and Governance Committees, subject to limited exceptions. The Shareholder Agreement also grants the shareholders registration rights, requiring the Company to use commercially reasonable efforts to file a registration statement covering the resale of the shares of common stock issuable upon conversion of the Series A Preferred Stock within 45 days of the Automatic Conversion Date, using Form S-3 or Form S-1 if necessary. Shareholders may request underwritten offerings of at least $ 10 million, subject to customary agreements and underwriter approval, with limits on frequency and “grace periods” for delays. Piggyback registration rights allow participation in offerings by the Company or other holders, subject to underwriter and priority rules. The Company will pay related expenses and indemnify shareholders against certain Securities Act of 1933, as amended liabilities. The Shareholder Agreement became effective at the Closing and will terminate according to its terms. On February 27, 2026 (the Automatic Conversion Date), the Board, with the recommendation of the Nominating and Corporate Governance Committee of the Board, and at the request of the Juniper Shareholder, pursuant to the terms of the Shareholder Agreement (discussed above), increased the number of members of the Board from five (5) to six (6), and appointed Mr. Edward Geiser as a member of the Board and as Chairperson of the Nominating and Corporate Governance Committee of the Board of Directors, to serve until his successor has been duly elected and qualified, or until his earlier death, resignation or removal. Also effective on February 27, 2026, director Josh Schmidt was appointed as Chairman of the Board of the Company. NOTE 7 – OIL AND GAS PROPERTIES The following tables summarize the Company’s oil and gas activities by classification for the years ended December 31, 2025 and 2024, respectively (in thousands): December 31, 2024* Additions Disposals Transfers December 31, 2025 Oil and gas properties, subject to amortization $ 210,039 $ 216,098 $ ( 322 ) $ 8,403 $ 434,218 Oil and gas properties, not subject to amortization 14,738 20,238 ( 2,028 ) ( 8,403 ) 24,545 Asset retirement costs 4,326 2,802 ( 91 ) - 7,037 Accumulated depreciation and depletion ( 81,015 ) ( 17,031 ) - - ( 98,046 ) Accumulated impairment ( 44,576 ) ( 908 ) - - ( 45,484 ) Total oil and gas properties, net $ 103,512 $ 221,199 $ ( 2,441 ) $ - $ 322,270 December 31, 2023* Additions Disposals Transfers December 31, 2024* Oil and gas properties, subject to amortization $ 185,403 $ 19,607 $ ( 1,438 ) $ 6,467 $ 210,039 Oil and gas properties, not subject to amortization 18,703 2,502 - ( 6,467 ) 14,738 Asset retirement costs 853 3,501 ( 28 ) - 4,326 Accumulated depreciation and depletion ( 66,104 ) ( 14,911 ) - - (81,015 ) Accumulated impairment ( 44,576 ) - - - (44,576 ) Total oil and gas properties, net $ 94,279 $ 10,699 $ ( 1,466 ) $ - $ 103,512 109 Table of Contents *Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation, which had no effect on the previously reported total assets, total liabilities, total shareholders’ equity, results of operations or cash flows. For the year ended December 31, 2025, the Company incurred $ 239.2 million of capital additions of which $ 204.6 million are related to the Mergers (noted above) and $ 34.0 million of capital costs primarily related to the Company’s completion operations with respect to four operated wells drilled and completed with a third-party as well as five lift conversions in the Permian Basin. The Company also participated in the drilling and completion of 23 non-operated wells in the D-J Basin for which production had begun in late 2025, ranging from between a 8% to 44% working interest. Additionally, the Company acquired approximately 100 net mineral acres and 1,067 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions at total acquisition and due diligence costs of $ 194,000 and $ 420,000 , respectively. For the year ended December 31, 2025, the Company recorded an impairment of oil and gas properties of $ 908,000 related to undeveloped leases representing 1,034 net acres in the D-J Basin that it allowed to expire or had no plans to drill prior to expiration. In February 2025, the Company entered into a joint development agreement with a private equity-backed operator to jointly develop the Roth and Amber drilling units in Weld County, Colorado. The operator paid $ 1.7 million to the Company, and the Company agreed to expand the units to 1,600 acres each and transfer operatorship to the operator. In February 2025, the Company recognized $ 0.3 million in disposition expense related to the sale of certain capitalized equipment to a third-party in the D-J Basin. In April 2025, the Company sold all of its legacy operated production in Weld County, Colorado to a private buyer for an adjusted price of $ 606,000 . The sale included wellbore and surface equipment only for the Company’s 17 operated wells in its D-J Basin Asset, with the Company retaining ownership in all its existing leasehold. The effective date of the sale is January 1, 2025. As a result, the Company recorded a gain on sale of oil and gas properties of $ 1,021,000 in its consolidated statements of operations. Also, in November 2025, the Company entered into a participation agreement under which a third party acquired 5%–22% working interests in 10 wellbores, for which the purchaser carried the Company’s share of related capital expenditures for the drilling and completion of certain wells. As a result, the Company recognized an additional $ 1,576,000 gain on the sale of oil and gas properties for a combined total of $ 2,597,000 . In September 2023, the Company and Evolution Petroleum Corporation ("Evolution") entered into a Participation Agreement for the joint development of the Chaveroo oilfield in Chaves and Roosevelt Counties, New Mexico. The agreement covers twelve Development Blocks encompassing approximately 16,000 gross leasehold acres, within which the parties may jointly drill up to nine horizontal San Andres wells per block on a 50/50 working interest basis, with the Company serving as operator. Evolution's entry into each successive Development Block is optional, at a cost of approximately $450 per net acre, and either party may independently develop any block the other elects to skip. The agreement continues in effect for so long as the parties proceed with development, and new leases acquired by the Company within certain identified tracts within two years of signing are included as Existing Leases. To date, Evolution has acquired working interests in five Development Blocks: a 50% interest in approximately 813 net acres in the first and second Development Blocks for $ 366,000 in September 2023; a 50% interest in approximately 811 net acres in the third, fourth, and fifth Development Blocks for $ 365,000 in June 2024; and a 50% interest in approximately 640 net acres in the eighth Development Block for $ 288,000 in September 2025. For the year ended December 31, 2024, the Company incurred $ 20.5 million of capital costs primarily related to non-operated drilling and completion costs related to the Company’s participation in 24 new non-operated wells in the D-J Basin in which the Company participated and the Company’s completion operations with respect to three operated wells with a third-party in the Permian Basin, together with costs related to certain workovers for lift conversions, cleanouts and permitting in the Company’s D-J Basin Asset. 110 Table of Contents As of December 31, 2024, the Company also acquired approximately 267 net mineral acres and 4,960 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions at total acquisition and due diligence costs of $ 725,000 and $ 862,000 , respectively. On August 21, 2024, the Company, through its wholly-owned subsidiary, PRH, entered into a five-year Participation Agreement with a large private equity-backed D-J Basin exploration and production company with extensive operational experience (“Joint Development Party”), whereby the Joint Development Party assigned to PRH a 30% interest in approximately 7,607 net acres of existing oil and gas leases and PRH assigned to the Joint Development Party a 70% interest in approximately 3,166 net acres of oil and gas leases, all located within the SW Pony Prospect in the D-J Basin in Weld County, Colorado. Additionally, to facilitate joint development of the SW Pony Prospect, the parties agreed to an approximately 16,900 gross acre Area of Mutual Interest wherein the Joint Development Party will transfer 30% of future interests acquired by the Joint Development Party in leaseholds to PRH, and PRH will transfer 70% of future interests acquired by PRH in leaseholds to the Joint Development Party, in each case at an acquisition cost proportionate to their respective interests. The assigned interests will be subject to an overriding royalty, such that the assigning party shall deliver to the other party leasehold interests with an 80% net revenue interest, and the parties agreed that the Joint Development Party will be the operator of the combined leaseholds. The Participation Agreement specifically addresses the Harlequin Wells, which are existing wells within the SW Pony Prospect, whereby PRH acquired a 30% undivided interest in six Harlequin Wells as part of the leasehold assignment . The Company correspondingly paid $8.6 million in capital costs (included in the $20.5 million number above) related to these wells. Additionally, on September 23, 2024, PRH sold 320 net acres to a third-party in the Company’s D-J Basin Asset for $ 750,000 , and, as a result, the Company recognized a $ 735,000 gain from the sale of oil and gas properties. Also, the Company sold 30 gross 5.1 net non-operated legacy well-bores in our D-J Basin Asset for net cash proceeds of $ 90,000 . As a result of the sale, the Company recognized a loss on sale of oil and gas properties of $ 865,000 for these non-core assets. However, the Company still retained the corresponding acreage related to the sale for any potential future development. In a separate transaction, the Company also sold an additional legacy well-bore assignment for net cash proceeds of $ 25,000 and recognized a gain on sale of oil and gas properties of $ 29,000 . Taken together, the three sales transactions represented a net loss on the sale of oil and gas properties of $ 76,000 on its Consolidated Statement of Operations as of December 31, 2024. The depletion recorded for production on proved properties for the years ended December 31, 2025 and 2024, amounted to $ 17,031,000 and $ 14,911,000 , respectively. NOTE 8 – NOTE RECEIVABLE On November 9, 2023, in accordance with the sale of our then wholly-owned subsidiary EOR Operating Company (“EOR”) to Tilloo Exploration and Production LLC (“Tilloo”), the Company entered into a five-year secured promissory note (the “Note”) with Tilloo, bearing interest at 10 % per annum, with no payments due until January 8, 2025, and fully-amortized payments due monthly over the remaining four years of the term thereafter until maturity. The Note contains customary events of default and is secured by a lien over all the assets and capital shares of EOR created under a Security Agreement, a Security Agreement (Pledge of Corporate Securities), and a Mortgage entered into by and between the Company and Tilloo. Tilloo failed to make its initial installment payment on January 8, 2025, and has not made any subsequent payments as of December 31, 2025. The Company issued a notice of default under the Note to Tilloo in mid-January 2025, and sought to work with Tilloo into April 2025, in an effort to either restructure the Note or arrange for the sale of the assets securing the same to an unaffiliated third-party buyer, with proceeds of such sale to be applied toward repayment of the Note. On September 18, 2025, Tilloo filed a civil lawsuit against the Company in the District Court of Harris County, Texas, alleging breach of contract, fraudulent inducement, and negligent misrepresentation. In November 2025, the Company issued to Tilloo a notice of acceleration and demand for payment under the Note and also filed a counterclaim against Tilloo for breach of contract seeking full recovery under the Note. In February 2026, the Company filed a motion for summary judgement with respect to Tilloo’s claims and the Company’s counterclaims asserted against Tilloo for breach of contract, which motion is currently pending before the Court. Due to Tilloo’s sustained default and a determination by the Company that the prospect of recovery is remote, the Company wrote off the outstanding balance of the Note in the second quarter of 2025. As such, while the Note is still due and payable in full by Tilloo, for reporting purposes, the outstanding balance of the Note as of December 31, 2025 is nil. 111 Table of Contents Accordingly, a $ 1,267,000 note receivable – credit loss has been recognized in the consolidated statements of operations for the year ended December 31, 2025. Additionally, the Company has fully written off post-closing adjustments receivable due from Till related to the sale of EOR in the amount of $ 111,000 . These write-offs reflect the Company's decision that the carrying value of the Note and post-closing adjustments receivable are no longer recoverable. Taken together, the Company recognized a total of $ 1,378,000 in note receivable – credit loss in the consolidated statements of operations for the year ended December 31, 2025. NOTE 9 – REVOLVING CREDIT FACILITY On October 31, 2025, the Company entered into an Amended and Restated Credit Agreement (the “A&R Credit Agreement”), which amended and restated its prior senior secured revolving credit agreement dated September 11, 2024, with Citibank, N.A., as administrative agent, and the lenders party thereto. The A&R Credit Agreement matures on October 31, 2029 and provides for an initial borrowing base and elected commitments of $ 120 million, with a maximum revolving commitment of $ 250 million. The borrowing base is subject to scheduled semiannual redeterminations beginning December 1, 2025, as well as unscheduled redeterminations and other adjustments, and is determined by the lenders in their discretion. Borrowings are subject to customary conditions, including compliance with financial covenants. The obligations are guaranteed by the Company’s subsidiaries and secured by first-priority liens on substantially all assets of the Company and its subsidiaries, including mortgages on oil and gas properties representing at least 90% of proved reserves. Borrowings may be ABR or SOFR loans. SOFR loans bear interest at the applicable term SOFR rate plus a margin of 300–400 basis points, and ABR loans bear interest at the applicable base rate plus a margin of 200–300 basis points, in each case depending on borrowing base utilization. For the year ended December 31, 2025, total interest expense was $ 1.4 million, consisting of $ 1.1 million of contractual interest and $ 0.3 million of amortization of deferred financing costs, resulting in an effective interest rate of 1.6 %. The Company also pays a commitment fee on unused commitments of 37.5 or 50 basis points. Amounts may be prepaid without penalty, and mandatory prepayments apply upon certain events. As of December 31, 2025, the Company paid $ 70,000 in commitment fees. The A&R Credit Agreement includes customary representations, warranties, affirmative and negative covenants, and events of default, including a change in control. Financial covenants require (i) a minimum current ratio of 1.0 to 1.0 and (ii) a maximum leverage ratio of 3.0 to 1.0. Additional covenants restrict, among other things, indebtedness, liens, dividends, investments, asset sales, affiliate transactions, mergers, and hedging activities. The Company is required to hedge at least 75 % of its projected proved developed producing reserves (PDP) oil and gas production at the time of entry into the A&R Credit Agreement, for the first 24 months of the agreement, and 50% of its projected PDP of oil and gas production for months 25-36. Afterward, within 60 days after each fiscal quarter, the Company must show it has hedged at least 50 % of expected oil and gas production for the next 18 months. The Company may hedge crude oil, natural gas, or natural gas liquids (on a barrel of oil equivalent basis) to meet these requirements, but may not hedge more than 75% of anticipated production (on a barrel of oil equivalent basis) for any month. In connection with the closing of the Mergers, the Company drew $ 87 million under the A&R Credit Agreement (see Note 6 – Merger Acquisition above), representing the outstanding balance as of December 31, 2025. The Company subsequently borrowed an additional $ 6.0 million on January 8, 2026 and $ 5.0 million on February 5, 2026. The proceeds from these borrowings are expected to be used to fund the Company’s participation in certain non-operated well operations and to pay other Company obligations. 112 Table of Contents NOTE 10 – DERIVATIVES The Company is exposed to certain risks relating to its ongoing business operations, such as risks related to commodity prices. Therefore, the Company uses derivative instruments primarily to manage commodity price risk. The Company enters into derivative instruments with respect to a portion of its crude oil and natural gas to hedge future prices received. These instruments are used to mitigate revenue volatility resulting from fluctuations in commodity prices. The Company does not hold or issue derivative financial instruments for speculative trading purposes. While there are many different types of derivative instruments available, we use costless collars, producer three-way collars, standalone put options, fixed-price swaps and basis swaps to attempt to manage price risk. Costless collar and three-way producer collar agreements are combinations of put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All collar agreements provide for payments between the counterparties if the settlement price under the agreement exceeds the ceiling or if the settlement price under the agreement is below the floor. Standalone put options are floors that are purchased for a cost and provide that counterparties make payments to us if the settlement price is below the established floor. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement. The basis swaps agreements effectively lock in a price differential between regional prices where the product is sold and the relevant pricing index under which oil or natural gas production is hedged. On November 1, 2025, the Company assumed the derivative liabilities (novated hedges) associated with its Mergers (see Note 6 above) which are subject to master netting agreements. Additional derivative contracts with the same counterparty are also subject to netting. Still, in accordance with ASC 815, the Company will classify the fair value of all its derivative positions on a gross basis in its corresponding consolidated balance sheets. The Company has not designated its derivative instruments as accounting hedges. Accordingly, changes in the fair value of outstanding derivatives and settlements of derivative contracts are recognized in earnings and included in “Other Income (Expense)” under the caption “Net gain (loss) on derivative contracts” in the consolidated statements of operations. “Derivative contract assets” and “Derivative contract liabilities” represent the estimated fair value of open derivative positions, which reflects the difference between current forward commodity prices and the contractual hedge prices for the remaining hedged volumes as of December 31, 2025 (the “mark-to-market” valuation). The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of December 31, 2025 (in thousands). There were no derivative contracts as of December 31, 2024. Derivative Contract Assets Derivative Contract Liabilities Commodity derivative instruments Balance sheet location December 31, 2025 Balance sheet location December 31, 2025 Commodity contracts Current assets - derivative contract assets - current $ 8,368 Current assets - derivative contract liabilities - current $ 964 Commodity contracts Other assets - derivative contract assets 9,640 Other assets - derivative contract liabilities 6,358 Total Commodity derivative instruments $ 18,008 $ 7,322 113 Table of Contents The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations for the year ended December 31, 2025 (in thousands). “ Realized gain on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “ Unrealized gain on derivative contracts” represents the net change in the mark-to-market valuation of the derivative contracts. There were no derivative contracts as of December 31, 2024. Derivative Contract Assets Commodity derivative instruments Location of gain recognized in income on derivative contracts December 31, 2025 Realized gain on derivative contracts Other income and expenses - net gain (loss) on derivative contracts $ 2,136 Unrealized gain on derivative contracts Other income and expenses - net gain (loss) on derivative contracts 4,117 Total gain on derivative contracts* $ 6,253 * The amount represents net gains for the two-month period from November 1, 2025 through December 31, 2025, as the Mergers closed on October 31, 2025 and the related derivative contracts were novated to the Company after closing. 114 Table of Contents As of December 31, 2025, the Company had the following open crude oil and natural gas derivative contracts: Crude Oil - 3 Way Collars Producer Three-Way Collars (Summary of 3 separate contracts) Participating Three-Way Collars (Summary of 3 separate contracts) Date Volume (Boe) Put Sold ($/Boe) Put Bought ($/Boe) Call Sold ($/Boe) Volume (Boe) Put Bought ($/Boe) Call Sold ($/Boe) Call Bought ($/Boe) 1Q 2026 36,400 $ 45.00 $ 55.00 $ 67.65 21,600 $ 62.50 $ 54.00 $ 80.00 2Q 2026 33,900 $ 45.00 $ 55.00 $ 67.65 23,700 $ 62.50 $ 54.00 $ 80.00 3Q 2026 31,800 $ 45.00 $ 55.00 $ 67.65 24,400 $ 62.50 $ 54.00 $ 80.00 4Q 2026 29,700 $ 45.00 $ 55.00 $ 67.65 66,900 $ 62.50 $ 54.00 $ 80.00 FY 2026 131,800 $ 45.00 $ 55.00 $ 67.65 136,600 $ 62.50 $ 54.00 $ 80.00 1Q 2027 27,400 $ 45.00 $ 55.00 $ 71.55 127,700 $ 62.50 $ 54.00 $ 80.00 2Q 2027 26,200 $ 45.00 $ 55.00 $ 71.55 163,700 $ 62.50 $ 54.00 $ 80.00 3Q 2027 25,200 $ 45.00 $ 55.00 $ 71.55 163,300 $ 62.50 $ 54.00 $ 80.00 4Q 2027 24,200 $ 45.00 $ 55.00 $ 71.55 129,800 $ 62.50 $ 54.00 $ 80.00 FY 2027 103,000 $ 45.00 $ 55.00 $ 71.55 584,500 $ 62.50 $ 54.00 $ 80.00 1Q 2028 - - - - 114,100 $ 62.50 $ 54.00 $ 80.00 2Q 2028 - - - - 128,000 $ 62.50 $ 54.00 $ 80.00 3Q 2028 - - - - 123,000 $ 62.50 $ 54.00 $ 80.00 4Q 2028 - - - - 39,100 $ 62.50 $ 54.00 $ 80.00 FY 2028 - - - - 404,200 $ 62.50 $ 54.00 $ 80.00 115 Table of Contents Crude Oil - Swaps and Costless Collars Swaps Costless Collars Date Volume (Boe) Avg. Price ($/Boe) Volume (Boe) Floor Price ($/Boe) Ceiling Price ($/Boe) 1Q 2026 171,000 $ 63.40 79,100 $ 54.57 $ 68.09 2Q 2026 126,000 $ 64.15 103,200 $ 54.89 $ 70.40 3Q 2026 180,000 $ 69.69 34,100 $ 54.87 $ 70.24 4Q 2026 105,000 $ 68.51 53,300 $ 54.63 $ 68.55 FY 2026 582,000 $ 66.43 269,700 $ 54.71 $ 69.12 1Q 2027 30,000 $ 64.90 54,900 $ 54.00 $ 64.00 2Q 2027 30,000 $ 64.90 9,900 $ 54.00 $ 64.00 3Q 2027 30,000 $ 64.90 1,700 $ 54.00 $ 64.00 4Q 2027 30,000 $ 64.90 1,800 $ 54.00 $ 64.00 FY 2027 120,000 $ 64.90 68,300 $ 54.00 $ 64.00 Natural Gas Swaps Costless Collars Date Volume (Mcf) Avg. Price ($/mcf) Volume (Mcf) Floor Price ($/mcf) Ceiling Price ($/mcf) 1Q 2026 - $ 0.00 232,200 $ 3.25 $ 5.85 2Q 2026 259,905 $ 3.95 17,800 $ 3.50 $ 5.21 3Q 2026 247,500 $ 3.95 17,200 $ 3.50 $ 5.21 4Q 2026 234,100 $ 3.95 18,700 $ 3.50 $ 5.21 FY 2026 741,505 $ 3.95 285,900 $ 3.44 $ 5.37 1Q 2027 - $ 0.00 237,000 $ 4.00 $ 5.25 2Q 2027 209,000 $ 3.74 16,900 $ 4.00 $ 5.12 3Q 2027 201,900 $ 3.74 16,900 $ 4.00 $ 5.12 4Q 2027 151,200 $ 3.74 11,500 $ 4.00 $ 5.12 FY 2027 562,100 $ 3.74 282,300 $ 4.00 $ 5.15 1Q 2028 - - 122,700 $ 4.00 $ 4.62 2Q 2028 118,100 $ 3.49 - - - 3Q 2028 115,100 $ 3.49 - - - 4Q 2028 37,900 $ 3.49 - - - FY 2028 271,100 $ 3.49 122,700 $ 4.00 $ 4.62 116 Table of Contents NOTE 11 – 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 (exit price). Authoritative guidance establishes a framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories: · Level 1 – Observable inputs based on quoted market prices for identical assets or liabilities in active markets. · Level 2 – Observable inputs other than Level 1, including quoted prices for similar assets or liabilities in active markets, quoted prices in inactive markets, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the asset or liability. · Level 3 – Unobservable inputs for the asset or liability due to little or no market activity that are significant to the fair value measurement. These inputs reflect assumptions that market participants would use in pricing the asset or liability. Assets and liabilities measured at fair value are classified based on the lowest level input that is significant to the measurement. The determination of the significance of inputs requires judgment and may affect the classification within the fair value hierarchy. There were no transfers between levels of the fair value hierarchy during any period presented. The Company measures its derivative instruments at fair value on a recurring basis using a market approach. Fair value is estimated using observable commodity futures prices for the underlying commodities obtained from a third-party pricing source. These measurements are classified within Level 2 of the fair value hierarchy. The fair values of the Company’s derivatives are not based on quoted prices for identical instruments in active markets. The Company applies fair value guidance on a nonrecurring basis to certain non-financial assets and liabilities, which are not measured at fair value on an ongoing basis but are subject to adjustment if events or changes in circumstances indicate impairment or other adjustments may be necessary. The following table, set forth by level within the fair value hierarchy, shows the Company’s financial assets and liabilities that were accounted for at fair value as of December 31, 2025 (in thousands).The Company did not have any derivative positions in 2024. December 31, 2025 Level 1 Level 2 Level 3 Total Assets Derivative contract assets $ - $ 18,008 $ - $ 18,008 Liabilities Derivative contract liabilities $ - $ 7,322 $ - $ 7,322 Derivative contracts listed above as Level 2 include fixed-price swaps and costless put/call collars that are carried at fair value. The Company records the net change in fair value of these positions in “Net gain (loss) on derivative contracts”. Asset retirement obligations. The fair value of asset retirement obligation is estimated using discounted cash flow projections with primarily Lever 3 inputs, using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation, estimated plugging and abandonment costs, timing of remediation, the credit adjusted risk-free rate and inflation rate. Merger Acquisition. On October 31, 2025, the Company completed the merger with the Acquired Companies, recording assets and liabilities at fair value. Oil and gas properties and asset retirement obligations were valued using discounted cash flows with primarily Level 3 inputs, including estimated future production based upon the estimation of reserves, future operating and development costs, future commodity prices (adjusted for basis differentials), and discount rates. See Note 6—Merger Acquisition. 117 Table of Contents NOTE 12 – ASSET RETIREMENT OBLIGATION Activity related to the Company’s asset retirement obligations is as follows for the year ended December 31, 2025 (in thousands): 2025 Balance at the beginning of the period (1) $ 6,371 Accretion expense 927 Disposition of liabilities ( 784 ) Liabilities settled ( 505 ) Liabilities acquired - Merger Acquisition 1,584 Changes in estimates 1,218 Balance at end of period (2) $ 8,811 (1) Includes $ 663,000 of current asset retirement obligations at December 31, 2024. (2) Includes $ 1,170,000 of current asset retirement obligations at December 31, 2025. In New Mexico, the Company, through its New Mexico operating subsidiary, RAZO, has entered into a Stipulated Final Order (“SFO”) with Director of the Oil and Gas Conservation Division of New Mexico (the “OCD”) pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset at a rate of $ 2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $ 30,000 per month by RAZO. RAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO. The SFO superseded all previous Agreed Compliance Orders, as amended, entered into by and between RAZO and the OCD. During the year ended December 31, 2025, the Company reimbursed the OCD $ 784,000 in plugging and abandoning costs related to the SFO. NOTE 13 – COMMITMENTS AND CONTINGENCIES Lease Agreements Currently, the Company has one operating sublease for office space that requires ASC Topic 842 treatment, discussed below. The Company’s leases typically do not provide an implicit rate. Accordingly, the Company is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at the commencement date. The Company’s incremental borrowing rate would reflect the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. However, at the time of implementation the Company currently maintained no debt, and in order to apply an appropriate discount rate, the Company used a borrowing rate obtained from a financial institution at which it maintains banking accounts. In December 2022, the Company entered into a lease agreement for approximately 5,200 square feet of office space in Houston, Texas, that commenced on September 1, 2023 , which expires on February 28, 2027 . The remaining monthly payments are approximately $ 15,800 through February 2026 and increase to approximately $ 16,000 through the end of the lease. The Company paid a security deposit of $ 14,700 . 118 Table of Contents Supplemental cash flow information related to the Company’s operating lease is included in the table below (in thousands): Year Ended December 31, 2025 Cash paid for amounts included in the measurement of lease liabilities $ 168 Supplemental balance sheet information related to operating leases is included in the table below (in thousands): December 31, 2025 Operating lease – right-of-use asset $ 213 Operating lease liabilities – current $ 182 Operating lease liabilities – long-term 32 Total lease liability $ 214 The weighted-average remaining lease term for the Company’s operating lease is 1.2 years as of December 31, 2025, with a weighted-average discount rate of 7.90 %. Lease liability with enforceable contract terms that have greater than one-year terms are as follows (in thousands): 2026 $ 191 2027 32 Thereafter - Total lease payments 223 Less imputed interest ( 9 ) Total lease liability $ 214 Leasehold Drilling Commitments The Company’s oil and gas leasehold acreage is subject to expiration of leases if the Company does not drill and hold such acreage by production or otherwise exercises options to extend such leases, if available, in exchange for payment of additional cash consideration. In the D-J Basin Asset, 16,138 net acres are set to expire during 2026 (net to our direct ownership interest only), with 2,110 and 678 net acres set to expire for the years ending December 31, 2027 and 2028 respectively, and 8,081 net acres thereafter, if we fail to meet drilling commitments or obtain term assignment extensions (net to our direct ownership interest only). In the PRB, in the Powder River Basin Asset, 4,822 net acres are set to expire during 2026, with 34,999 and 15,828 net acres set to expire for the years ending December 31, 2027 and 2028, respectively. In the Permian Basin Asset only 200 net acres is set to expire for the year ending December 31, 2026, (net to our direct ownership interest only) , all of the remaining acreage is currently held by production. Other Commitments Although the Company may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, the Company is not currently a party to any material legal proceeding. In addition, the Company is not aware of any material legal or governmental proceedings against it or contemplated to be brought against it. As part of its regular operations, the Company may become party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its commercial operations, products, employees and other matters. 119 Table of Contents Although the Company provides no assurance about the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have on the Company, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the Company’s financial condition or results of operations. Milnesand Sale Dispute and Tilloo Note Default and Litigation On November 4, 2024, the Company received correspondence from legal counsel to Tilloo Exploration & Production, LLC seeking to recover damages which Tilloo is alleging were caused by alleged intentional misrepresentations made by principals of the Company to principals of Tilloo in connection with Tilloo’s acquisition of the Milnesand and Sawyer fields in New Mexico from the Company for aggregate consideration of $ 1,122,436 effective August 1, 2023 (the “Milnesand Sale”), which consideration was paid to the Company by Tilloo via a five-year secured promissory note with 10 % annual interest and no payments due until January 8, 2025 (the “Tilloo Note”). The Company does not believe any misrepresentations were made by the Company or its principals in the Milnesand Sale and that the claims will fail as a matter of law. The Company has not received any correspondence from Tilloo regarding the allegations made in November 4, 2024 correspondence subsequent to receipt of the same from Tilloo, and Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025. The Company issued a notice of default under the Tilloo Note to Tilloo in mid-January 2025. On September 18, 2025, Tilloo filed a civil lawsuit against the Company in the District Court of Harris County, Texas, alleging breach of contract, fraudulent inducement, and negligent misrepresentation. The Company is currently in the process of preparing a response and intends to vigorously defend against these allegations, and make appropriate counterclaims against Tilloo, where available. In November 2025, the Company issued to Tilloo a notice of acceleration and demand for payment under the Tilloo Note and also filed a counterclaim against Tilloo for breach of contract seeking full recovery under the Tilloo Note. In February 2026, the Company filed a motion for summary judgement with respect to Tilloo’s claims and the Company’s counterclaims asserted against Tilloo for breach of contract, which motion is currently pending before the Court. The Company does not anticipate that the Company will incur any material losses related thereto. Phoenix Litigation Upon the consummation of the Mergers, effective October 31, 2025, a wholly-owned subsidiary of NPOG, Navigation Powder River, LLC (“NPRLLC”), became an indirect wholly-owned subsidiary of the Company. On July 31, 2025, NPRLLC and Phoenix Energy One, LLC (“Phoenix”) entered into that certain Purchase and Sale Agreement (the “Phoenix PSA”) whereby NPRLLC agreed to sell to Phoenix certain oil and gas properties located in Campbell and Converse Counties, Wyoming. On September 10, 2025, NPRLLC filed a Petition against Phoenix in the Eleventh Business District Business Court of Texas (Navigation Powder River, LLC v. Phoenix Energy One, LLC, Eleventh Business District, Texas Business Court, Houston, TX) alleging a breach of contract by Phoenix Energy for its failure to consummate the transactions contemplated by the Phoenix PSA. The Company intends to vigorously pursue its claims in an effort to secure a favorable ruling from the court. If the matter is ultimately not resolved in the Company’s favor, the Company estimates that its potential loss will be the approximately $ 7.7 million purchase price consideration due from Phoenix under the Phoenix PSA, provided that NPRLLC would retain the oil and gas properties in full. 120 Table of Contents NOTE 14 – SHAREHOLDERS’ EQUITY All share and per-share amounts presented below have been retroactively adjusted to reflect the 1-for-20 reverse stock split effected on March 13, 2026. Series A Convertible Preferred Stock As part of the Mergers, the Company issued newly designated Series A Convertible Preferred Stock of the Company in two separate transactions. First, in connection with the Mergers, 10,650,000 shares of Series A Convertible Preferred Stock were issued to Century Oil and Gas Holdings, LLC and North Peak in exchange for their interests in the Acquired Companies (the “Merger Shares”). These Merger Shares are fully paid and nonassessable and are designed to automatically convert into common stock at a 0.5-to-1 ratio yielding 5,325,000 shares upon full conversion (see Note 6 – Merger Acquisition above for the purchase price consideration allocated to the aforementioned Series A Convertible Preferred Stock issuance). In addition, concurrently with the Mergers, certain investors (the “PIPE Investors”) purchased 6,363,637 shares of the same Series A Convertible Preferred Stock at $ 5.50 per share ($ 11.00 per share on a post-reverse stock split basis) under subscription agreements (“PIPE Preferred Shares”). Like the Merger Shares, these PIPE Preferred Shares are convertible into common stock at a 0.5-to-1 ratio, yielding 3,181,818 shares upon full conversion. The PIPE Investors included (a) The SGK 2018 Revocable Trust, a family trust of which Dr. Simon Kukes, the then Executive Chairman of PEDEVCO is trustee and beneficiary ($15,409,977); (b) American Resources, Inc., an entity partially owned and controlled by J. Douglas Schick, the Chief Executive Officer, President and member of the Board ($250,003); (c) Clark R. Moore, the Executive Vice President, General Counsel and Secretary of the Company ($25,003); (d) John J. Scelfo Revocable Trust Dated October 8, 2003, a trust of which John J. Scelfo, a member of the Board, is trustee and beneficiary ($550,000); (e) Jody D. Crook, the Chief Commercial Officer of the Company ($25,003); (f) J PED, LLC, an entity affiliated with Juniper Capital Advisors, L.P. (“Juniper”) ($18,550,004); (g) Reagan T. Dukes, the then Chief Executive Officer of the Acquired Companies, who was appointed Chief Operating Officer of PEDEVCO at the closing of the Mergers ($52,503) and (h) Robert J. Long, the then Chief Financial Officer of the Acquired Companies, who was appointed Chief Financial Officer, Treasurer and Principal Accounting/Financial Officer of the Company at the closing of the Mergers ($52,503) . The PIPE Preferred Share investment (the “PIPE Financing”) closed concurrently with the Mergers and the $ 35.0 million of net proceeds raised by the Company pursuant to the PIPE Financing was used to pay off certain liabilities of the Acquired Companies in connection with the Mergers and certain expenses of the PIPE Financing and Mergers. As of December 31, 2025, the Company had 17,013,637 total shares of Series A Convertible Preferred Stock outstanding. During the year ended December 31, 2024, there was no Company preferred stock issued or outstanding. In both preferred stock issuances noted above, the preferred stock functioned as a temporary equity instrument that subsequently and automatically converted into 8,506,818 shares of common stock on February 27, 2026 (see Note 19 – Subsequent Events below). Common Stock During the year ended December 31, 2025, the Company granted an aggregate of 297,978 restricted stock awards to various employees and board members of the Company (see Note 15 below), after giving effect to the 1-for-20 reverse stock split. During June 2025, the Company sold an aggregate of 24,498 shares of common stock in five separate transactions under its ongoing “at-the-market” offering program (the “ATM Offering”), at sales prices ranging from $ 14.32 to $ 16.02 per share. These sales generated net proceeds of approximately $ 354,000 , after deducting $ 11,000 in commission fees. The Company also incurred approximately $ 214,000 in initial and subsequent legal and audit-related fees and expenses in connection with the registration and placement of the ATM Offering. The ATM Offering was made pursuant to the terms of that certain December 20, 2024 Sales Agreement (the “Sales Agreement”) entered into with Roth Capital Partners, LLC (the “Lead Agent”) and A.G.P./Alliance Global Partners (“AGP,” and collectively with the Lead Agent, the “Agents”), pursuant to which the Company may sell securities from time to time in an “at-the-market” offering. The Company will pay the Lead Agent a commission of 3.0% of the gross sales price of any shares sold under the Sales Agreement. The Company also agreed to reimburse the Agents for their reasonable and documented out-of-pocket expenses in an amount not to exceed $75,000 in connection with entering into the Sales Agreement and for their reasonable and documented out-of-pocket expenses related to quarterly maintenance of the Sales Agreement in an amount not to exceed $5,000 per quarter . 121 Table of Contents As previously disclosed, 17,013,637 shares of Series A preferred stock automatically converted into 8,506,818 shares of the Company’s common stock on February 27, 2026 (see Note 19—Subsequent Events). During the year ended December 31, 2024, the Company granted an aggregate of 297,978 restricted stock awards to various employees and board members of the Company (see Note 15 below). NOTE 15 – SHARE-BASED COMPENSATION All share and per-share amounts presented below have been retroactively adjusted to reflect the 1-for-20 reverse stock split effected on March 13, 2026. 2021 Incentive Plan On September 1, 2021, the shareholders of the Company approved the 2021 Equity Incentive Plan (the “2021 Plan”), which was previously approved by the Board of Directors on July 11, 2021 and authorizes the issuance of various forms of stock-based awards, including incentive or non-qualified options, restricted stock awards, performance shares and other securities as described in greater detail in the 2021 Incentive Plan, to the Company’s employees, officers, directors and consultants. The 2021 Incentive Plan was amended on August 29, 2024 to increase the number of shares reserved for issuance under the 2021 Incentive Plan by 250,000 to 650,000 shares of common stock. Additionally, on October 29, 2025, the Board adopted, subject to shareholder approval, and on October 31, 2025, pursuant to a written consent to action without a meeting, the Company’s majority shareholders approved, an amendment to the 2021 Plan to increase by 250,000 shares, from 650,000 shares to 900,000 shares , the number of shares available under the 2021 Plan, which amendment became effective on February 27, 2026. As of March 27, 2026, 551,982 shares have been issued as restricted stock, and 88,200 shares are subject to issuance upon exercise of issued and outstanding options, with 259,818 shares remaining available for issuance under the 2021 Incentive Plan as of March 27, 2026. Restricted Stock Awards Effective upon the closing of the merger on October 31, 2025, the Company granted an aggregate of 150,000 shares of restricted common stock to certain executive officers and employees. The grants consisted of: (i) 100,000 shares to J. Douglas Schick, President and Chief Executive Officer and a member of the Board; (ii) 25,000 shares to Clark R. Moore, Executive Vice President, General Counsel and Secretary; (iii) 15,000 shares to Jody Crook, Chief Commercial Officer; and (iv) an aggregate of 10,000 shares to two other employees. These shares have a total fair value of $ 1,276,000 based on the market price on the grant date. 50,000 of the 100,000 shares granted to Mr. Schick, and all shares granted to Mr. Moore, Mr. Crook, and the two other employees , vest in three equal annual installments on the first, second, and third anniversaries of the grant date, subject to continued service with the Company on each applicable vesting date and the terms and conditions of the applicable restricted stock grant agreements. The additional 50,000 shares granted to Mr. Schick are performance-based and are described below under the Performance-Based Restricted Stock Award section. On January 23, 2025, restricted stock awards were granted to officers and employees for an aggregate of 92,206 shares under the Company’s 2021 Plan. These shares vest as follows: 33.3% on the 10-month anniversary of the vesting commencement date, 33.3% on the 22-month anniversary of the vesting commencement date, and 33.4% on the 34-month anniversary of the vesting commencement date, contingent upon continued service . These shares have a total fair value of $ 1,568,000 based on the market price on the grant date. On July 7, 2025, the Company appointed John K. Howie to the Board of Directors and granted him 7,500 shares of restricted common stock under the Company’s 2021 Equity Incentive Plan, as amended. These shares vest on July 7, 2026, contingent upon continued service. These shares have a total fair value of $ 92,000 based on the market price on the grant date. 122 Table of Contents On August 28, 2025, the Company granted an aggregate of 27,000 shares of restricted common stock to three members of its board of directors under the Company’s 2021 Equity Incentive Plan, as amended. The shares vested in full upon the directors’ resignation from the board on October 31, 2025. The shares had a total grant-date fair value of $ 313,000 , based on the Company’s market price on the date of grant. On November 13, 2025, the Company appointed Josh Schmidt to the Board of Directors and granted him 9,818 shares of restricted common stock under the Company’s 2021 Equity Incentive Plan, as amended. The grants vest in four quarterly installments at the end of each fiscal quarter. Mr. Schmidt disclaims any interest in the restricted stock awards, as pursuant to applicable policies of Juniper, the shares subject to such awards are payable to Juniper following vesting. These shares have a total fair value of $ 120,000 based on the market price on the grant date. Additionally, on November 13, 2025, newly appointed board members, Martyn Willsher and Kristel Franklin, were each issued 5,727 shares of restricted common stock in consideration for services rendered as members of the Board. The shares vest 25% on each of the three-, six-, nine-, and twelve-month anniversaries of October 31, 2025, subject to continued service and the terms of the applicable Restricted Shares Grant Agreements. On January 26, 2024, restricted stock awards were granted to officers and employees for an aggregate of 105,250 shares under the Company’s 2021 Plan. These shares vest 33.3% each subsequent year from the date of grant, contingent upon continued service . These shares have a total fair value of $ 1,426,000 based on the market price on the grant date. On August 29, 2024, an aggregate of 10,500 shares were granted to two board members under the Company’s 2021 Plan. The grants consisted of 6,250 shares vesting on July 12, 2025 and 4,250 shares vesting on September 27, 2025, contingent upon continued service . These shares have a total fair value of $ 184,000 based on the market price on the grant date. On May 24, 2024, 3,500 shares of restricted common stock were forfeited due to an employee termination. As a result, these shares were canceled and again became eligible for future awards under the Company’s 2021 Plan. Performance-Based Restricted Stock Award Performance-based restricted stock awards with stock price-based conditions are valued using a Monte Carlo simulation model that estimates the probability and timing of achieving the specified stock price hurdle over the contractual performance period. Stock-based compensation expense is recognized on a straight-line basis over the respective derived service periods of the award tranches, provided the award holder remains an employee of the Company. Previously recognized compensation expense is reversed only if the requisite service period is not rendered by the holder, resulting in forfeiture of the award. As noted above, the Company granted an additional 50,000 restricted shares of its common stock to Mr. Schick, which are subject to performance-based vesting conditions tied to the market price of the Company’s common stock. The 50,000 restricted shares vest upon achievement of a market condition whereby the 30-day average closing price of the Company’s common stock equals or exceeds $18.00 per share within four years following the closing of the Mergers (the “Closing” and the “Price Trigger”). The earliest possible vesting date is 30 days following the first anniversary of the Closing, provided the Price Trigger has been satisfied. These shares have a total fair value of $ 491,000 based on the criteria noted above. 123 Table of Contents Vesting upon achievement of the Price Trigger is subject to the following schedule: (a) If the Price Trigger is achieved between one year and 30 days and the second anniversary of the Closing, one-third of the shares shall vest immediately upon satisfaction of the Price Trigger, with the remaining two-thirds vesting in equal installments on the second and third anniversaries of the grant date. (b) If the Price Trigger is achieved between the second and third anniversaries of the Closing, two-thirds of the shares shall vest immediately upon satisfaction of the Price Trigger, and the remaining one-third shall vest on the third anniversary of the Closing. (c) If the Price Trigger is achieved after the third anniversary of the Closing and prior to the fourth anniversary of the Closing, all shares subject to the Price Trigger shall vest immediately upon achievement. If the Price Trigger is not achieved on or before the fourth anniversary of the Closing, all 50,000 restricted shares subject to the Price Trigger shall be forfeited. All of the awarded shares above are subject to trading restrictions, and forfeiture, subject to the vesting terms described above. When such securities are vested in accordance with their terms, the trading restrictions are lifted. The Company grants restricted stock awards to employees. The following table summarizes activity for nonvested restricted stock awards for the year ended December 31, 2025: Nonvested Awards Number of Awards Weighted-Average Grant-Date Fair Value ($) Nonvested at January 1, 2025 173,916 16.78 Granted 297,978 13.56 Vested ( 179,651 ) 16.60 Forfeited ( 16,464 ) 15.80 Nonvested at December 31, 2025 292,243 13.61 Stock-based compensation expense recorded related to restricted stock, including performance based, during the years ended December 31, 2025 and 2024 was $ 2,542,000 and $ 1,581,000 , respectively. The remaining amount of unamortized stock-based compensation expense related to restricted stock at December 31, 2025 and 2024 was $ 2,412,000 and $ 807,000 , respectively. Options On January 23, 2025, the Company granted options to purchase an aggregate of 23,200 shares of common stock to various employees at an exercise price of $ 17.00 per share under the Company’s 2021 Plan. The options have a term of five years and fully vest in November 2027, with 33.3% vesting on the 10-month anniversary of the vesting commencement date, 33.3% vesting on the 22-month anniversary of the vesting commencement date, and 33.4% vesting on the 34-month anniversary of the vesting commencement date, contingent upon the recipient’s continued service with the Company . The aggregate fair value of the options on the date of grant, as determined using the Black-Scholes option-pricing model, was $ 195,000 . Variables used in the Black-Scholes model included: (1) a discount rate of 4.45 % based on the applicable U.S. Treasury rate, (2) an expected term of 3.5 years, (3) expected volatility of 64.5 % based on the Company’s trading history, and (4) zero expected dividends. On January 26, 2024, the Company granted options to purchase an aggregate of 23,000 shares of common stock to various employees at an exercise price of $ 13.55 per share under the Company’s 2021 Plan. The options have a term of five years and fully vest in January 2027, with 33.3% vesting each year from the date of grant, contingent upon continued service . The aggregate fair value of the options on the date of grant, as determined using the Black-Scholes model, was $ 216,000 . Variables used in the model included: (1) a discount rate of 4.04 % based on the applicable U.S. Treasury rate, (2) an expected term of 3.5 years, (3) expected volatility of 104 % based on the Company’s trading history, and (4) zero expected dividends. During the year ended December 31, 2025, 10,783 options expired unexercised. 124 Table of Contents During the year ended December 31, 2024, 12,833 options were forfeited due to an employee termination. As a result, these options again became eligible for future awards under the Company’s Amended and Restated 2012 and 2021 Plans. During the year ended December 31, 2025 and 2024, the Company recognized stock option-based compensation expense related to options of $ 221,000 and $ 278,000 , respectively. The remaining amount of unamortized stock options expense at December 31, 2025 and 2024 was $ 100,000 and $ 194,000 , respectively. There was no intrinsic value of outstanding and exercisable options at December 31, 2025 and 2024, respectively. Option activity during the years ended December 31, 2025 and 2024 was: 2025 2024 Number of Stock Options Weighted Average Grant Price Weighted Average Remaining Contract Term (Years) Number of Stock Options Weighted Average Grant Price Weighted Average Remaining Contract Term (Years) Outstanding at Beginning of Period 91,783 $ 26.94 2.4 81,617 $ 25.53 2.8 Granted 23,200 17.00 23,000 13.55 Expired/Canceled ( 10,783 ) 33.60 ( 12,834 ) 26.02 Outstanding at End of Period 104,200 $ 20.09 2.3 91,783 $ 22.46 2.4 Exercisable at End of Period 65,567 $ 22.15 1.7 46,783 $ 26.94 1.4 NOTE 16 – EARNINGS PER COMMON SHARE Earnings (loss) per common share-basic is calculated by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Net (loss) income per common share-diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock, as defined above, outstanding plus potentially dilutive securities. Net income (loss) per common share-diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares, as defined above, would have an anti-dilutive effect. All share and per-share amounts have been retroactively adjusted to reflect the reverse stock split described in Note 1 above. The calculation of (loss) earnings per share for the years ended December 31, 2025 and December 31, 2024 were as follows (amounts in thousands, except share and per share data): 2025 2024 Numerator: Net (loss) income $ ( 10,362 ) $ 12,293 Denominator: Weighted average common shares – basic 4,615,058 4,461,732 Dilutive effect of common stock equivalents: Options - - Denominator: Weighted average common shares – diluted 4,615,058 4,461,732 (Loss) Earnings per share – basic $ ( 2.25 ) $ 2.76 (Loss) Earnings per share – diluted $ ( 2.25 ) $ 2.76 125 Table of Contents For the years ended December 31, 2025 and 2024, potentially dilutive securities consisting of options to purchase 104,200 and 91,783 shares of common stock, respectively, and convertible preferred stock equivalent to 8,506,818 and zero shares of common stock, respectively, were excluded from the computation of diluted net (loss) income per share because their inclusion would have been anti-dilutive. NOTE 17 – INCOME TAXES The components of the income tax expense (benefit) for each of the periods presented below are as follows: December 31, 2025 December 31, 2024 Current: Federal - - State - - Total Current Expense / (Benefit) - - Deferred: Federal 8,011 ( 7,335 ) State 44 80 Total Deferred Tax Expense / (Benefit) 8,055 ( 7,255 ) Income Tax Expense (Benefit) 8,055 ( 7,255 ) A reconciliation of the U.S. federal statutory tax rate to the Company’s effective income tax rate is as follows, in accordance with the updated requirements of ASU 2023-09 for the years ended December 31, 2025 and December 31, 2024: 2025 2024 U.S. Federal Statutory Rate ( 485 ) 21.0 % 1,058 21.0 % State Taxes, net 44 ( 1.9 )% 3,233 64.2 % Changes in Valuation Allowance 8,459 ( 366.6 )% ( 26,381 ) ( 523.7 )% Nondeductible Items: Officer Life Insurance 42 ( 1.8 )% 46 0.9 % Stock Compensation ( 9 ) 0.4 % 38 0.8 % Other 2 ( 0.1 )% 2 0.0 % Other Adjustments: Deferred Tax Adjustments 2 ( 0.1 )% 14,750 292.8 % Tax Expense / (Benefit) 8,055 ( 349.1 )% ( 7,255 ) ( 144.0 )% 126 Table of Contents In 2025, the Company recorded a $ 8.1 million tax expense primarily due to the valuation allowance recorded against deferred taxes in 2025. Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences and net operating loss (“NOL”) carryforwards that comprise our deferred income taxes are as follows: December 31, 2025 December 31, 2024 Deferred Tax Assets: Net Operating Losses 15,545 13,974 Asset Retirement Obligation 2,162 1,566 Stock Compensation 675 556 Right of Use Liability 53 56 Other 1 1 Deferred Tax Assets 18,436 16,153 Valuation Allowance ( 8,459 ) - Deferred Tax Assets after Valuation Allowance 9,977 16,153 Deferred Tax Liabilities: Oil & Gas Properties ( 8,103 ) ( 8,843 ) Derivatives ( 2,622 ) - Right of Use Asset ( 52 ) ( 55 ) Deferred Tax Liabilities ( 10,777 ) ( 8,898 ) Net DTA / (DTL) ( 800 ) 7,255 As of December 31, 2025 and 2024, we had net deferred tax liabilities of $ 0.8 million and net deferred tax assets of $ 7.3 million, respectively, upon which we had a valuation allowance of $ 8.5 million and $ 0 million, respectively. The net change in the valuation allowance of $ 8.5 million is due to the recording of the valuation allowance on deferred tax assets that are not more-likely-than-not to be realized. The change in the conclusion regarding the valuation allowance at December 31, 2025, compared to December 31, 2024, primarily relates to the operational impact of the companies acquired in the fourth quarter of 2025. The Company concluded that, due to the lack of operating history, projections of future taxable income are not available to support the valuation allowance assessment as of December 31, 2025, whereas such projections were available as of December 31, 2024. As of December 31, 2025, the Company has federal net operating loss carryforwards of approximately $ 69.2 million, which if not utilized, approximately $ 16.0 million will begin expiring in 2025 and ending 2037 , respectively. The remaining net operating losses can be carried forward indefinitely and are subject to an 80% taxable income limitation. In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all deferred assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Utilization of NOL and tax credit carryforwards may be subject to a substantial annual limitation due to ownership change limitations that may have occurred or that could occur in the future, as required by the Internal Revenue Code (the “Code”), as amended, as well as similar state provisions. In general, an “ownership change” as defined by the Code results from a transaction or series of transactions over a three-year period resulting in an ownership change of more than 50 percent of the outstanding stock of a company by certain shareholders or public groups. Based on the available objective evidence, management believes it is more likely than not that the net deferred tax assets will not be fully realizable based on the Company's ability to generate income in future periods. Accordingly, management has recorded a valuation allowance of $8.5 million against its net deferred tax assets on December 31, 2025. 127 Table of Contents The Company’s policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2025, and 2024, the Company did not have any significant uncertain tax positions or unrecognized tax benefits. The Company did not have associated accrued interest or penalties, nor was any interest expense or penalties recognized for the years ended December 31, 2025, and 2024. With the adoption of ASU 2023-09, Income Taxes, a disclosure of income taxes paid, net of refunds received, to an individual taxing jurisdiction is now required if the net payments exceed a certain threshold. The Company did not have any income tax payments or refunds for both periods ending December 31, 2025 and December 31, 2024. The Company currently has tax returns open for examination by the Internal Revenue Service for all years, since 2019. NOTE 18 — SEGMENT INFORMATION Operating segments are defined as components of an enterprise for which separate financial information is available and regularly evaluated by the Chief Operating Decision Maker (“CODM”) for the purpose of making key operating decisions, allocating resources, and assessing operating performance. The Company operates in one reportable operating segment, oil and natural gas development, exploration and production. The Company’s oil and gas properties are managed as a whole rather than through discrete operating segments. Financial and operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company’s entire portfolio without regard to geographic area, and considers among other things, return on investment, current market conditions, including commodity prices and market supply, availability of services and human resources, and contractual commitments. The Company’s Chief Executive Officer is its CODM. The Company’s profitability measure is consolidated net income which is used to assess budgeted versus actual results and drives the Company’s operating cash flow. The CODM reviews significant consolidated forecasts and results of operations, including return on capital, operating expenses, and cash flow when making decisions such as the allocation of capital. The financial position, results of operations and cash flows of the Company’s reportable operating segment are consistent with the Company’s consolidated financial statements included herein. NOTE 19 – SUBSEQUENT EVENTS On January 27, 2026, after recommendation by the Compensation Committee of the Company’s Board of Directors, the Board of Directors of the Company, in connection with the Company’s annual compensation review, approved calendar year 2025 cash bonuses (paid in February 2026) for (i) Mr. Paul Pinkston, the Company’s Chief Accounting Officer, in the amount of $ 43,000 , (ii) Mr. J. Douglas Schick, the President, CEO and Director of the Company, in the amount of $ 170,000 , (iii) Mr. Clark R. Moore, the Executive Vice President, General Counsel and Secretary of the Company, in the amount of $ 131,000 and (iv) Mr. Jody Crook, the Chief Commercial Officer of the Company, in the amount of $ 125,000 , (v) Reagan Tuck (R.T.), Chief Operating Officer of the Company, in the amount of $ 135,000 , and (vi) Robert “Bobby” Long, Chief Financial Officer of the Company, in the amount of $ 126,000 . On January 6, 2026 and February 5, 2026, the Company borrowed an additional $ 6.0 million and $ 5.0 million, respectively, under its Credit Facility. The proceeds are expected to be used to fund the Company’s participation in certain non-operated well operations and to satisfy other Company obligations. On February 27, 2026, in connection with his appointment to the Board, Edward Geiser was granted 9,874 shares of restricted common stock under the 2021 Plan. The shares vest in four equal 25% installments on the three-, six-, nine-, and twelve-month anniversaries of the grant date, subject to his continued service and the terms of a restricted shares grant agreement. These shares have a total fair value of $ 123,200 based on the market price on the grant date. On February 27, 2026, 17,013,637 shares of Series A preferred stock automatically converted into 8,506,818 shares of the Company’s common stock on February 27, 2026. On March 13, 2026, the Company effected a 1-for-20 reverse stock split of its issued and outstanding shares of common stock (the “Reverse Stock Split”). The Reverse Stock Split was approved by the Company’s Board of Directors and stockholders on February 27, 2026. As a result of the Reverse Stock Split: · every 20 shares of issued and outstanding common stock were automatically combined into one share of common stock; · the par value of the Company’s common stock remained unchanged at $ 0.001 per share; and · fractional shares were paid in cash. All authorized, issued, and outstanding common stock, stock options, and other equity instruments, as well as the related exercise or conversion prices, were proportionately adjusted to reflect the Reverse Stock Split. All share amounts, per-share data, earnings (loss) per share, and weighted-average shares outstanding presented in the accompanying consolidated financial statements and related notes have been retroactively adjusted to reflect the Reverse Stock Split for all periods presented, unless otherwise indicated. The Reverse Stock Split did not affect the Company’s total stockholders’ equity or the proportionate voting rights of stockholders, except for adjustments resulting from the treatment of fractional shares. 128 Table of Contents SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following disclosures for the Company are made in accordance with authoritative guidance regarding disclosures about oil and natural gas producing activities. Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed,” and “proved undeveloped” crude oil, natural gas liquids and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. Proved undeveloped reserves or proved undeveloped reserves (“PUDs”) . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. PROVED RESERVE SUMMARY All of the Company’s reserves are located in the United States. The following tables sets forth the changes in the Company’s net proved reserves (including developed and undeveloped reserves) for the years ended December 31, 2025, 2024 and 2023. Reserves estimates as of December 31, 2025 were estimated by the independent petroleum consulting firm Cawley, Gillespie & Associates, Inc. The reserve report is incorporated herein by reference to Exhibit 99.1 of the Annual Report on Form 10-K which these financial statements are filed with. Oil (MBbls) Gas (MMcf) NGL (MBbls) Combined (MBoe) Proved developed and undeveloped reserves: December 31, 2023 11,358 19,885 2,374 17,046 Revisions of previous estimates (2,784 ) (2,476 ) 169 (3,028 ) Purchases in place 471 1,728 253 1,012 Extensions, discoveries and other additions 2,241 4,939 732 3,796 Sales in place (54 ) (154 ) (19 ) (99 ) Production (439 ) (506 ) (62 ) (585 ) December 31, 2024 10,793 23,416 3,447 18,142 Revisions of previous estimates (782 ) (4,865 ) (826 ) (2,419 ) Purchases in place 8,953 7,864 1,237 11,501 Extensions, discoveries and other additions 4,747 3,277 608 5,901 Sales in place (54 ) (90 ) (11 ) (80 ) Production (671 ) (818 ) (114 ) (921 ) December 31, 2025 22,986 28,784 4,341 32,124 129 Table of Contents For the year ended December 31, 2024: Revisions of previous estimates : Includes (i) revisions of 2,841 Mboe related to an increase in leasehold and minerals and expected performance increase of 586 MBoe in the D-J Basin Asset based on offset well results, and a decrease of 3,427 MBoe related to removal of PUD locations in D-J Basin (1,970 Mboe) and Chaveroo Field of our Permian Basin Asset (1,457 MBoe) that were moved outside of the five-year development plan, (ii) downward revision of 148 MBoe due to reduced well performance compared to previous estimates, and (iii) downward revision of 39 MBoe due to change in price from December 31, 2023 to December 31, 2024 (YE2024). Purchases in place : Includes 1,012 MBoe of purchases of working interest and mineral interest across several units in DJ-Basin. Extensions, discoveries and other additions : Includes extensions of 3,796 MBoe related to the development of operated and non-operated sections in the D-J Basin (3,256 MBoe) and operated sections in Permian Basin (540 MBoe). Sales in Place : Includes 99 MBoe of sale of interests in certain non-operated wellbores in DJ-Basin. Production : Includes 585 MBoe of production from our NM and DJ-Basin assets. For the year ended December 31, 2025: Revisions of previous estimates : Includes (i) revisions related to expected performance increase of 102 MBoe in the D-J Basin Asset, and an expected performance decrease of 191 MBoe in Chaveroo asset, and (ii) decrease of 1,984 MBoe related to decrease in leasehold and minerals and removal of PUD locations in D-J Basin, (iii) downward revision of 143 MBoe due to change in price from December 31, 2024 to December 31, 2025, a nd (iv) downward revision of 202 Mboe due to reduced well performance compared to previous estimates. Purchases in place : Includes 11,501 MBoe of purchases related to the acquisition of Juniper’s assets in DJ and Powder River Basin. Extensions, discoveries and other additions : Includes additions of 5,791 MBoe related to the development of acquired properties in the D-J Basin as well as 110 MBoe related to the additional wells developed in the D-J Basin production from acquired properties. Sales in Place: Includes 80 MBoe of sale of interests in certain operated wellbores in DJ-Basin. Production: Includes 921 MBoe of production from our NM and DJ-Basin assets as well as production from acquired properties. RESERVES During the year ended December 31, 2025, the Company’s reserves increased by 14.0 MMBoe of proved reserves. Included in the increase, the Company had a 1.4 MMBoe increase in proved undeveloped reserves (noted below) resulting primarily from the addition of volumes in the D-J Basin following the acquisition of properties in the D-J Basin. The Company also had an increase of 12.1 MMBoe in proved developed producing reserves related to acquisition of properties in the D-J and Powder River Basin. 130 Table of Contents The following table sets forth the Company’s proved developed and undeveloped reserves at December 31, 2025, 2024 and 2023, respectively: Proved Developed Producing Reserves 2025 2024 2023 Crude Oil (MBbls) 11,872 2,443 1,869 Natural Gas (Mmcf) 12,675 4,292 2,998 NGL (MBbls) 1,895 630 255 Oil Equivalents (MBoe) 15,880 3,788 2,624 Proved Developed Non-Producing Reserves Crude Oil (MBbls) 372 13 702 Natural Gas (Mmcf) 395 44 1,229 NGL (MBbls) 65 7 144 Oil Equivalents (MBoe) 503 27 1,051 Proved Undeveloped Reserves Crude Oil (MBbls) 10,742 8,337 8,787 Natural Gas (Mmcf) 15,713 19,079 15,659 NGL (MBbls) 2,381 2,809 1,975 Oil Equivalents (MBoe) 15,742 14,327 13,372 Proved Reserves Crude Oil (MBbls) 22,986 10,793 11,358 Natural Gas (Mmcf) 28,783 23,415 19,886 NGL (MBbls) 4,341 3,446 2,374 Oil Equivalents (MBoe) 32,124 18,142 17,046 Proved Undeveloped Reserves The following table is a reconciliation of the change in our PUD reserves for the periods indicated below (quantities in net MBoe): Proved undeveloped reserves, December 31, 2023 13,372 Transfers to proved developed - Additions 3,796 Revisions of prior estimates (2,841 ) Proved undeveloped reserves, December 31, 2024 14,327 Transfers to proved developed (2,303 ) Additions 5,791 Revisions of prior estimates (2,073 ) Proved undeveloped reserves, December 31, 2025 15,742 131 Table of Contents For the year ended December 31, 2024, total proved undeveloped reserves (PUDs) increased by 955 MBoe to 14,327 MBoe, primarily related to the following: · Additions of 3,796 MBoe related to the development of operated and non-operated sections in the D-J Basin (3,256 MBoe) and operated sections in Permian Basin (540 MBoe). · Revisions of 2,841 Mboe related to increase in leasehold and minerals and expected performance increase of 586 MBoe in the D-J Basin Asset based on offset well results, and decrease of 3,427 MBoe related to removal of PUD locations in D-J Basin (1970 Mboe) and Chaveroo of our Permian Basin Asset (1457 MBoe) outside of the five-year development plan. · There was no transfer of proved undeveloped to proved developed reserves in 2024 since projects scheduled to be completed in 2024 were delayed to future periods and replaced with participation in wells through acquired leasehold properties in the D-J Basin. For the year ended December 31, 2025, total proved undeveloped reserves (PUDs) increased by 1,415 MBoe to 15,742 MBoe, primarily related to the following: · Additions of 5,791 MBoe related to the development of acquired properties in the D-J Basin. · Revisions of 2,073 MBoe related to expected performance increase of 102 MBoe in the D-J Basin, decrease of 1,984 MBoe related to a decrease in leasehold and minerals and removal of PUD locations in the D-J Basin, and expected performance decrease of 191 MBoe in Chaveroo of our Permian Basin Asset. · Transfer of 2,303 MBoe to proved developed reserves, with conversion of 1,846 MBoe from D-J Basin asset and 457 MBoe from Chaveroo of our Permian Basin Asset. We expect to spend an aggregate of $190–$225 million developing proved undeveloped reserves through December 31, 2030. All proved undeveloped reserves are scheduled to be developed within five years of initial booking. We expect to fund these development costs with cash from operations and cash on hand, supplemented as needed by proceeds from asset sales, private and public offerings, credit availability and equity infusions. Capitalized Costs Relating to Oil and Natural Gas Producing Activities . The following table sets forth the capitalized costs relating to the Company’s crude oil and natural gas producing activities at December 31, 2025 and 2024 (in thousands): 2025 2024 Proved oil and gas properties $ 452,950 $ 229,103 Unproved oil and gas properties 12,850 - Total oil & gas properties 465,800 229,103 Accumulated depreciation and depletion and impairment (143,530 ) (125,591 ) Net Capitalized Costs $ 322,270 $ 103,512 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities . The following table sets forth the costs incurred in the Company’s oil and natural gas property acquisition, exploration and development activities for the years ended December 31, 2025 and 2024 (in thousands): 2025 2024 Acquisition of properties Proved $ 192,364 $ 1,587 Unproved 11,266 - Exploration costs - - Development costs 33,924 20,522 Total $ 237,554 $ 22,109 Results of Operations for Oil and Natural Gas Producing Activities . The following table sets forth the results of operations for oil and natural gas producing activities for the years ended December 31, 2025 and 2024 (in thousands): 2025 2024 Crude oil and natural gas revenues $ 45,751 $ 39,553 Production costs (19,120 ) (12,449 ) Depreciation and depletion and impairment (17,939 ) (14,911 ) Results of operations for producing activities, excluding corporate overhead and interest costs $ 8,692 $ 12,193 132 Table of Contents Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves. The following information has been developed utilizing procedures prescribed by ASC Topic 932 and based on crude oil and natural gas reserves and production volumes estimated by the independent petroleum consultants of the Company. The estimates were based on a 12-month average of first-of-the-month commodity prices for the years ended December 31, 2025 and 2024. The following information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company. The future cash flows presented below are based on cost rates and statutory income tax rates in existence as of the date of the projections and average prices over the preceding twelve months. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves as of December 31, 2025, 2024 and 2023 (in thousands): 2025 2024 2023 Future cash inflows $ 1,645,677 $ 916,105 $ 972,432 Future production costs (705,972 ) (288,879 ) (250,681 ) Future development costs (264,866 ) (209,139 ) (202,842 ) Future income taxes (210,804 ) (100,484 ) (121,204 ) Future net cash flows 464,035 317,603 397,705 Discount to present value at 10% annual rate (213,995 ) (173,440 ) (207,344 ) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 250,040 $ 144,163 $ 190,361 Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows for each of the years ended December 31, 2025, 2024 and 2023 (in thousands): 2025 2024 2023 Standardized measure, beginning of year $ 144,163 $ 190,361 $ 274,916 Crude oil and natural gas sales, net of production costs (31,930 ) (24,653 ) (22,779 ) Net changes in prices and production costs (10,293 ) (32,032 ) (76,156 ) Extensions, discoveries, additions and improved recovery 45,068 - - Changes in estimated future development costs 498 (740 ) (7,068 ) Development costs incurred - - - Revisions of previous quantity estimates (18,114 ) (40,363 ) (15,021 ) Accretion of discount 29,304 (1,173 ) (11,697 ) Net change in income taxes (72,972 ) 6,629 58,301 Purchases of reserves in place 164,441 47,162 - Sales of reserves in place (125 ) (1,028 ) (10,151 ) Change in timing of estimated future production - - 16 Standardized measure, end of year $ 250,040 $ 144,163 $ 190,361 133 Table of Contents ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None.