PEDEVCO CORP

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.

NOTE 2 – DESCRIPTION OF BUSINESS

PEDEVCO is an oil and gas company focused on the development, acquisition and production 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 San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “Permian Basin”) and in the Denver-Julesberg Basin (“D-J Basin”) in Colorado and Wyoming. The Company holds its Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through its wholly-owned operating subsidiary, Pacific Energy Development Corp. (“PEDCO”), which asset the Company refers to as its “Permian Basin Asset,” and it holds its D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through its wholly-owned subsidiary, PRH Holdings LLC, and which asset the Company refers to as its “D-J Basin Asset.” In 2023, the Company assigned all of its oil and gas assets held in its wholly-owned subsidiary Red Hawk Petroleum LLC to PRH Holdings LLC.

The Company believes that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J 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 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 Petroleum LLC, a Nevada limited liability company; (iii) Ridgeway Arizona Oil Corp., an Arizona corporation (“RAZO”); (iv) SRPT Acquisition, LLC, a Texas limited liability company, and (v) PRH Holdings LLC, a Nevada limited liability company. 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 financial statements are appropriate, actual results could differ from these estimates. Significant estimates generally include those with respect to the amount of recoverable oil and gas reserves, the fair value of financial instruments, oil and gas depletion, asset retirement obligations, and stock-based compensation.

**Cash and Cash Equivalents.**The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. As of December 31, 2024 and 2023, cash equivalents consisted of money market funds and cash on deposit of $-0- and $5,188,000, respectively. The Company includes restricted cash within cash and cash equivalents on the consolidated statements of cash flows.

**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 three customers comprised 38%,36% and 12%, respectively, of the Company’s total oil and gas revenues for the year ended December 31, 2024, compared to sales to three customers comprising 42%,35% and 18%, respectively, of the Company’s total oils and gas revenues for the year ended December 31, 2023. 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 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 $3.8 million related to receivables from joint interest owners.

Bad Debt Expense. The Company’s ability to collect outstanding receivables is critical to its operating performance and cash flows. Accounts receivable are stated at an amount management expects to collect from outstanding balances. The Company extends credit in the normal course of business. The Company regularly reviews outstanding receivables and when the Company determines that a party may not be able to make required payments, a charge to bad debt expense in the period of determination is made. Though the Company’s bad debts have not historically been significant, the Company could experience increased bad debt expense should a financial downturn occur.

**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.

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.

**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.

**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.

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.

Earnings per Common Share. Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) available to common shareholders (numerator) by the weighted average number of shares outstanding (denominator) during the period. Diluted EPS give effect to all dilutive potential common shares outstanding during the period using the treasury stock method and convertible preferred stock using the if-converted method. In computing diluted EPS, the average stock price for the period is used to determine the number of shares assumed to be purchased from the exercise of stock options and/or warrants. Diluted EPS excluded all dilutive potential shares if their effect is 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 November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280). The amendments in this update expand segment disclosure requirements, including new segment disclosure requirements for entities with a single reportable segment among other disclosure requirements. This update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Adoption of this standard is on a modified retrospective basis and had no impact on the Company’s financial position, results of operations, cash flows or net income per share.

Recently Issued 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. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU

Subsequent Events. The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration.

NOTE 4 – RESTATEMENT OF PREVIOUSLY ISSUED CONSOLIDATED FINANCIAL STATEMENTS

In connection with the preparation of the Company's Consolidated Financial Statements as of and for the fiscal year ended December 31, 2024, the Company discovered that in prior years it had not appropriately accounted for the depletion expense related to its oil and gas properties. The error resulted in an overstatement of depreciation, depletion, amortization and accretion expense and accumulated DD&A of approximately $1,435,000 and $1,251,000 for the fiscal years ended December 31, 2023 and 2022, respectively. The error did not impact total revenue, cash flow and cash balances for the fiscal years ended December 31, 2023 and 2022, respectively. In conjunction with the restatement of DD&A, we also restated certain balances in the net deferred tax asset / deferred tax liability schedule to correct an additional error.

The misstatements were material to the previously issued financial statements of the Company and as a result, the Company has restated its Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Cash Flows, Consolidated Statements of Changes in Shareholder's Equity and for Note 7 – Oil and Gas Properties, Note 13 – Earnings Per Common Share and Note 14 – Income Taxes, and as of and for the fiscal years ended December 31, 2023 and 2022, respectively, presented herein. The restatement includes adjustments to oil and gas properties, subject to amortization, net; depreciation, depletion, amortization and accretion; accumulated deficit; net income; and earnings per share.

The impact of the correction of the misstatements is summarized below:

NOTE 5 – CASH

The following table provides a reconciliation of cash and restricted cash reported within the balance sheets on December 31, 2024 and 2023, which sum to the total of such amounts shown in the accompanying consolidated statements of cash flows (in thousands):

• Increase in restricted cash is primarily related to additional collateral for surety bonds for the Company’s New Mexico operations, due to an updated assessment from the New Mexico Bureau of Land Management.

NOTE 6 – 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, 2024 and 2023 (in thousands):

There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December 31, 2024 or 2023, respectively.

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, 2024 and 2023, respectively (in thousands):

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.

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 Holdings, LLC (“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.

For the year ended December 31, 2023, the Company incurred $21,573,000 of capital costs primarily related to non-operated drilling and completion costs related to the Company’s participation in 13 new non-operated wells in the D-J Basin Asset in which the Company participated and the Company’s drilling of three operated wells with Evolution Petroleum Corporation (“Evolution”), noted below, together with costs related to certain workovers for lift conversions and cleanouts in the Company’s Permian Basin Asset.

The Company also acquired approximately 282 net mineral acres, and 6,465 net lease acres, in and around its existing footprint in the D-J Basin through multiple transactions with total acquisition and due diligence costs of $493,000 for the net mineral acres and $5,211,000 for the net lease acres.

On September 12, 2023, the Company and Evolution entered into a Participation Agreement for the joint development of approximately 16,000 gross leasehold acres divided into twelve “Development Blocks” within the Company’s Permian Basin Asset, in which the parties may jointly develop by drilling and completion of up to nine horizontal San Andres wells in each Development Block. The Company received net proceeds of $366,000 and serves as the operator. Evolution acquired a 50% working interest share in existing leases, covering the initial two Development Blocks (which equals Evolution’s share of the acreage portion for nine drilling locations therein), and upon completion of the wells in each Development Block, Evolution will have the right, but not the obligation, to acquire a 50% working interest share in the next Development Block in exchange for the payment of $450 per net acre of existing leases held by the Company in such block, and participate on a 50% working interest share basis in the drilling and completion of up to nine horizontal San Andres wells in such Development Block. Pursuant to the Participation Agreement, in June 2024, Evolution acquired a 50% working interest share in Existing Leases covering approximately 811 net acres located in the third, fourth and fifth Development Blocks in exchange for the payment of $365,000 in total proceeds to the Company.

On November 9, 2023, the Company entered into a Purchase and Sale Agreement and a Stock Purchase Agreement with Tilloo, pursuant to which we sold our wholly-owned subsidiary EOR Operating Company (“EOR”) and approximately 8,035 gross leasehold acres, current operated production, and all of PEDCO’s and EOR’s leases and related rights, oil and gas and other wells, equipment, easements, contract rights, and production located in the Milnesand and Sawyer Fields of the San Andres play in the Permian Basin situated in eastern New Mexico, which assets included approximately 80 legacy vertical oil and gas wells (53 producers and 27 injectors). Aggregate consideration received by the Company for the sale, which was effective August 1, 2023, was $1,122,436, subject to customary adjustments, which is to be paid by Tilloo through entry into a five-year secured promissory note (see Note 7 below). As a result of the transaction, the Company sold all of its operated oil and gas interests in the non-core Milnesand and Sawyer Fields, including 52 inactive legacy wells that the Company would otherwise be required to plug and abandon, thereby successfully reducing its asset retirement obligations with respect to these assets and reducing itsestimated aggregate plugging and abandoning liabilities by over $3.2 million. The Company recognized a receivable of $56,000 due from Tilloo in post-closing adjustments, and as a result of the transaction, the Company recognized a $4.3 million loss on sale of oil and gas properties as reflected in the Statement of Operations for the year ended December 31, 2023.

The depletion recorded for production on proved properties for the year ended December 31, 2024 and 2023, amounted to $14,911,000 and $8,830,000, respectively.

NOTE 8 – NOTE RECEIVABLE

On November 9, 2023, in accordance with the sale of our wholly-owned subsidiary EOR to Tilloo (see Note 6 above), 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. As of December 31, 2024, the Company recognized $293,000 of the Note in Current Assets, with the remaining balance of $933,000 (including $104,000 of accrued interest) in Other Assets on the Company’s balance sheet.

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 Note to Tilloo in mid-January 2025, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters. Tilloo may not timely pay the Note when due, if at all. However, as the Tilloo Note is fully-secured, the Company believes that should it pursue foreclosure under the security agreement and mortgages, that it would ultimately be made whole, so no reserve allowance is required as of December 31, 2024.

NOTE 9 – ASSET RETIREMENT OBLIGATION

Activity related to the Company’s asset retirement obligations is as follows for the year ended December 31, 2024 (in thousands):

In New Mexico, the Company, through its New Mexico operating subsidiary RAZO, has entered into a Stipulated Final Order (“SFO”) with 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 fiscal year 2024, the Company reimbursed the OCD $248,000 in plugging and abandoning costs related to the SFO.

NOTE 10 – COMMITMENTS AND CONTINGENCIES

Lease Agreements

Currently, the Company has one operating sublease for office space that requires Accounting Standards Codification (“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, the Company currently maintains 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.

The Company had a lease for its corporate offices in Houston, Texas on approximately 5,200 square feet of office space that expired on August 31, 2023 and had a base monthly rent of approximately $10,000. In December 2022, the Company entered into a new lease agreement for its existing office space that commenced on September 1, 2023, which expires on February 28, 2027. The base monthly rent is approximately $9,200 for the first 18 months and increases to approximately $9,500 thereafter. The Company paid both a security deposit and prepaid rent for $14,700, respectively.

Supplemental cash flow information related to the Company’s operating lease is included in the table below (in thousands):

Supplemental balance sheet information related to operating leases is included in the table below (in thousands):

The weighted-average remaining lease term for the Company’s operating lease is 2.2 years as of December 31, 2024, 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):

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, 808.91 net acres are set to expire during 2025 (net to our direct ownership interest only), with 3,662 and 1,657 net acres set to expire for the years ending December 31, 2026 and 2027 respectively, and 508.53 net acres thereafter, if we fail to meet drilling commitments or obtain term assignment extensions (net to our direct ownership interest only). 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. The Company plans to hold significantly all of this acreage through a program of drilling and completing producing wells. If the Company is not able to drill and complete a well before term assignment expiration, the Company may seek to extend terms of contractual assignments.

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.

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

On November 4, 2024 the Company received correspondence from legal counsel to Tilloo Exploration & Production, LLC (“Tilloo”) 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 are baseless, without merit, and fail as a matter of law. The Company has not received any correspondence from Tilloo subsequent to receipt of the November 4, 2024 correspondence 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, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters.

NOTE 11 – SHAREHOLDERS’ EQUITY

Common Stock

During the year ended December 31, 2024, the Company granted an aggregate of 2,315,000 restricted stock awards to various employees and board members of the Company (see Note 12 below).

During the year ended December 31, 2023, the Company granted an aggregate of 1,460,000 restricted stock awards to various employees and board members of the Company (see Note 12 below).

NOTE 12 – SHARE-BASED COMPENSATION

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 5,000,000 to 13,000,000 shares of common stock. As of December 31, 2024,5,145,000 shares have been issued as restricted stock, and 1,310,000 shares are subject to issuance upon exercise of issued and outstanding options.

2012 Incentive Plan

On July 27, 2012, the shareholders of the Company approved the 2012 Equity Incentive Plan (the “2012 Incentive Plan”), which was previously approved by the Board of Directors on June 27, 2012 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 2012 Incentive Plan, to the Company’s employees, officers, directors and consultants. The 2012 Incentive Plan was amended on June 27, 2014, October 7, 2015 and December 28, 2016, December 28, 2017, September 27, 2018 and August 28, 2019 to increase by 500,000,300,000,500,000,1,500,000,3,000,000 and 2,000,000 (to 8,000,000 currently), respectively, the number of shares of common stock reserved for issuance under the 2012 Incentive Plan. As of December 31, 2024,6,449,503 shares have been issued as restricted stock, and 525,667 shares are subject to issuance upon exercise of issued and outstanding options. The Company is not eligible to grant any additional awards under the 2012 Incentive Plan.

Common Stock

On January 26, 2024, restricted stock awards were granted to officers and employees of the Company for an aggregate of 2,105,000 shares of the Company’s restricted common stock, under the Company’s 2021 Plan. The grant for the 2,105,000 shares of restricted common stock vest as follows: 33.3% vest each subsequent year from the date of grant contingent upon the recipient’s continued service with the Company. 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 210,000 restricted stock awards were granted to two board members under the Company’s 2021 Plan. The grant of the 210,000 shares of restricted common stock vest as follows: 100% of 125,000 shares and 100% of 85,000 shares vesting on July 12, 2025 and September 27, 2025, respectively, contingent upon each recipient’s continued service with the Company. These shares have a total fair value of $184,000, based on the market price on the grant date.

On May 24, 2024, 70,000 shares of restricted common stock were forfeited due to an employee termination. As a result, these shares were canceled, and the shares once again became eligible for future awards under the Company’s 2021 Plan.

On January 23, 2023, an aggregate of 1,250,000 shares of restricted common stock were granted to officers of the Company under the Company’s 2021 Plan. The grant of the 1,250,000 shares of restricted common stock vest as follows: 33.3% vest each subsequent year from the date of grant, contingent upon the recipient’s continued service with the Company. These shares had a total fair value of $1,363,000 based on the market price on the issuance date.

On August 31, 2023, an aggregate of 210,000 restricted stock awards were granted to two board members under the Company’s 2021 Plan. The grant of the 210,000 shares of restricted common stock vest as follows: 100% of 125,000 shares and 100% of 85,000 shares vesting on July 12, 2024 and September 27, 2024, respectively, contingent upon each recipient’s continued service with the Company. These shares have a total fair value of $200,000 based on the market price on the grant date.

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.

Stock-based compensation expense recorded related to restricted stock during the years ended December 31, 2024 and 2023 was $1,581,000 and $1,621,000, respectively. The remaining amount of unamortized stock-based compensation expense related to restricted stock at December 31, 2024 and 2023 was $807,000 and $819,000, respectively.

Options

On January 26, 2024, the Company granted options to purchase an aggregate of 460,000 shares of common stock to various Company employees at an exercise price of $0.6775 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 subsequent year from the date of grant, contingent upon the recipient’s continued service with the Company. The aggregate fair value of the options on the date of grant, using the Black-Scholes model, was $216,000. Variables used in the Black-Scholes option-pricing model for the options issued include: (1) a discount rate of 4.04% based on the applicable US Treasury bill rate, (2) expected term of 3.5 years, (3) expected volatility of 104% based on the trading history of the Company, and (4) zero expected dividends.

During the period ended December 31, 2024,256,667 options were rescinded due to an employee termination. As a result, these options once again became eligible for future awards under the Company’s Amended and Restated 2012 and 2021 Plans.

On January 23, 2023, the Company granted options to purchase an aggregate of 540,000 shares of common stock to various Company employees at an exercise price of $1.09 per share under the Company’s 2021 Plan. The options have a term of five years and fully vest in January 2026, with 33.3% vesting each subsequent year from the date of grant, contingent upon the recipient’s continued service with the Company. The aggregate fair value of the options on the date of grant, using the Black-Scholes model, was $429,000. Variables used in the Black-Scholes option-pricing model for the options issued include: (1) a discount rate of 3.61% based on the applicable US Treasury bill rate, (2) expected term of 3.5 years, (3) expected volatility of 113% based on the trading history of the Company, and (4) zero expected dividends.

During the period ended December 31, 2023,315,333 options expired unexercised.

During the year ended December 31, 2024 and 2023, the Company recognized stock option-based compensation expense related to options of $278,000 and $422,000, respectively.

The remaining amount of unamortized stock options expense at December 31, 2024 and 2023 was $194,000 and $210,000, respectively.

There was no intrinsic value of outstanding and exercisable options at December 31, 2024 and 2023, respectively.

Option activity during the years ended December 31, 2024 and 2023 was:

NOTE 13 – EARNINGS PER COMMON SHARE

Earnings per common share-basic is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. Net 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 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.

The calculation of earnings per share for the years ended December 31, 2024 and December 31, 2023 were as follows (amounts in thousands, except share and per share data):

For the years ended December 31, 2024 and 2023, share equivalents related to options to purchase 1,375,667 and 1,632,334 shares of common stock, respectively, were excluded from the computation of diluted net income per share as the inclusion of such shares would be anti-dilutive.

NOTE 14 – INCOME TAXES

In conjunction with the restatement for DD&A, we also restated certain balances in the net deferred tax asset / deferred tax liability schedule to correct an additional error. The components of the income tax expense (benefit) for the years ended December 31, 2024, and 2023, respectively, are as follows:

The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate. The following table reconciles the U.S. federal statutory income tax rate in effect for the years ended December 31, 2024, and December 31, 2023 (in thousands):

In 2024, the Company recorded a $12.8 million tax benefit primarily due to the release of the full valuation allowance recorded against deferred taxes in 2023.

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 as of December 31, 2024, and 2023 taxes are as follows (in thousands):

As of December 31, 2024, and 2023, the Company had deferred tax assets of $12.8 million and $26.4 million, respectively, upon which the Company had a valuation allowance of $0 and $26.4 million, respectively. The net change in the valuation allowance of $26.4 million is due to the release of the valuation allowance.

As of December 31, 2024, the Company has federal net operating loss carryforwards of approximately $88.4 million, which if not utilized, approximately $10.6 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, the Company 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, the Company believes it is more likely than not that the net deferred tax assets will be fully realizable based on the Company's ability to generate income in future periods. Accordingly, the Company has recorded no valuation allowance against its net deferred tax assets on December 31, 2024.

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, 2024, and 2023, 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, 2023, and 2022.

The Company currently has tax returns open for examination by the Internal Revenue Service for all years, since 2019.

NOTE 15 — 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 16 – SUBSEQUENT EVENTS

On January 23, 2025, the Company granted options to purchase an aggregate of 464,000 shares of common stock to various Company employees at an exercise price of $0.85 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 date of the vesting commencement and 33.4% vesting on the 34-month anniversary date of the vesting, contingent upon the recipient’s continued service with the Company. The aggregate fair value of the options on the date of grant, using the Black-Scholes model, was $195,000. Variables used in the Black-Scholes option-pricing model for the options issued include: (1) a discount rate of 4.45% based on the applicable US Treasury bill rate, (2) expected term of 3.5 years, (3) expected volatility of 64.5% based on the trading history of the Company, and (4) zero expected dividends.

Additionally, on January 23, 2025, restricted stock awards were granted to officers and employees of the Company for an aggregate of 1,844,118 shares of the Company’s restricted common stock, under the Company’s 2021 Plan. The grant for the 1,844,118 shares of restricted common stock vest as follows:33.3% vesting on the 10-month anniversary of the vesting commencement date, 33.3% vesting on the 22-month anniversary date of the vesting commencement and 33.4% vesting on the 34-month anniversary date of the vesting, contingent upon the recipient’s continued service with the Company. These shares have a total fair value of $1,568,000 based on the market price on the grant date.

In addition, on January 23, 2025, 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 cash bonuses for(i) Mr. Paul Pinkston, the Company’s Chief Accounting Officer, in the amount of $50,000, (ii) Mr. J. Douglas Schick, the President and newly appointed Chief Executive Officer of the Company, in the amount of $130,000, (iii) Mr. Jody Crook, the newly appointed Chief Commercial Officer of the Company, in the amount of $100,000, and (iv) Mr. Clark R. Moore, the Executive Vice President, General Counsel and Secretary of the Company, in the amount of $120,000.

In February 2025, the Company entered into a joint development agreement (“Agreement”) with a large, Denver, Colorado-based private equity-backed D-J Basin E&P Company with extensive operational experience (“Operator”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber DSUs located in Weld County, Colorado, with the Operator paying to the Company $1.7 million, the Company agreeing to amend the Company’s existing Roth and Amber DSUs to increase each to 1,600 acres and transferring operatorship of the DSUs to the Operator, and the parties agreeing to jointly participate in the development of the Roth and Amber DSUs.

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 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, 2024 and 2023. Reserves estimates as of December 31, 2024 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.

RESERVES

During the year ended December 31, 2024, the Company’s reserves increased by 1.1 MMBoe of proved reserves. Included in the increase, the Company had a 0.95 MMBoe increase in proved undeveloped reserves (noted below) resulting primarily from the addition of volumes in the D-J Basin due to increased activity. The Company also had an increase of 1.2 MMBoe in proved developed producing reserves related to acquisition of properties in the D-J Basin and reclassification of wells from proved developed non-producing at the end of 2023 to proved developed producing for 2024, which offset the natural decline in existing production base in the D-J Basin Asset and Permian Basin.

The following table sets forth the Company’s proved developed and undeveloped reserves at December 31, 2024 and 2023, respectively:

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):

For the year ended December 31, 2023, total proved undeveloped reserves (PUDs) increased by 430 MBoe to 13,372 MBoe, primarily related to the following:

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:

We expect to spend an aggregate of $170–$200 million developing proved undeveloped reserves through December 31, 2028. 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 or loans (which may be convertible) made available from Dr. Simon G. Kukes, the Company’s former Chief Executive Officer and newly appointed Executive Chairman of the Company's Board of Directors, or entities which he controls, which funding Dr. Kukes is under no obligation to provide.

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, 2024 and 2023 (in thousands):

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, 2024 and 2023 (in thousands):

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, 2024 and 2023 (in thousands):

*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, 2024 and 2023. 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, 2024 and 2023 (in thousands):

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, 2024 and 2023 (in thousands):