RING ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

Index to the Notes to the Condensed Financial Statements

NOTE 1 — BASIS OF PRESENTATION AND SIGNIFICANT ACCOUNTING POLICIES

Condensed Financial Statements – The accompanying condensed financial statements prepared by Ring Energy, Inc., a Nevada corporation (the “Company,” "Ring Energy," “Ring,” "we," "us," or "our"), have not been audited by an independent registered public accounting firm. In the opinion of the Company’s management, the accompanying unaudited condensed financial statements contain all adjustments necessary for fair presentation of the results of operations for the periods presented, which adjustments were of a normal recurring nature, except as disclosed herein. The condensed results of operations for the three months ended March 31, 2025 are not necessarily indicative of the results to be expected for the full year ending December 31, 2025, for various reasons, including the impact of fluctuations in prices received for oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors.

These unaudited condensed financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) applicable to interim financial information, and, accordingly, do not include all of the information and notes required by GAAP for complete financial statements. Therefore, these condensed financial statements should be read in conjunction with the financial statements and notes included in the Company’s annual report on Form 10-K for the year ended December 31, 2024.

Organization and Nature of Operations –Ring Energy is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin in Texas. Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform in the Permian Basin in Texas.

Liquidity and Capital Considerations – The Company strives to maintain an adequate liquidity level to address volatility and risk. Sources of liquidity include the Company’s net cash provided by operating activities, cash on hand, available borrowing capacity under its revolving credit facility, and proceeds from sales of non-strategic assets.

While changes in oil and natural gas prices affect the Company’s liquidity, the Company has put in place hedges in seeking to protect a substantial portion of its cash flows from price declines; however, if oil or natural gas prices rapidly deteriorate due to unanticipated economic conditions, this could still have a material adverse effect on the Company’s cash flows.

The Company expects ongoing oil price volatility over an indeterminate term. Extended depressed oil prices have historically had and could have a material adverse impact on the Company’s oil revenue, which is mitigated to some extent by the Company’s hedge contracts.

The Company believes that it has the ability to continue to fund its operations and service its debt by using cash flows from operations.

Use of Estimates – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reporting period. The Company’s unaudited condensed financial statements are based on a number of significant estimates, including estimates of oil and natural gas reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Actual results could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the Company’s future results of operations.

Fair Value Measurements – Fair value is 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). The Financial Accounting Standards Board (“FASB”) has established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

Fair Values of Financial Instruments – The carrying amounts reported for our revolving line of credit approximate their fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of accounts receivable and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.

Fair Value of Non-financial Assets and Liabilities – The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property and equipment, and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs, and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy.

Concentration of Credit Risk and Receivables – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and receivables.

Cash and cash equivalents – The Company had cash in excess of federally insured limits of $850,851 and $1,616,395 as of March 31, 2025 and December 31, 2024, respectively. The Company places its cash with a high credit quality financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.

Accounts receivable – Substantially all of the Company’s accounts receivable is from purchasers of oil and natural gas. Oil and natural gas sales are generally unsecured. Accounts receivable from purchasers outstanding longer than the contractual payment terms are considered past due. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. During the three months ended March 31, 2025, sales to three purchasers represented 67%,13% and 10%, respectively, of total oil, natural gas, and natural gas liquids sales. As of March 31, 2025, receivables outstanding from these three purchasers represented 80%,10% and 7%, respectively, of accounts receivable. The following table reflects the Company's beginning and ending balances of our account receivables from purchasers of our oil and gas.

Production imbalances – The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company recorded no imbalances as of March 31, 2025 or December 31, 2024.

Joint interest billing receivables, net – The Company also has joint interest billing receivables. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself. Receivables from joint interest owners outstanding longer than the contractual payment terms are considered past due. The following table indicates the Company's provisions for credit loss expense associated with its joint interest billing receivables during the three months ended March 31, 2025 and March 31, 2024.

The following table reflects the Company's joint interest billing receivables and allowance for credit losses as of March 31, 2025 and December 31, 2024.

The increase of $17,917 in the allowance for credit losses during the three months ended March 31, 2025 was for owner settlements considered uncollectible with no offsetting revenues held in suspense.

Cash and Cash Equivalents – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. At March 31, 2025 and December 31, 2024, the Company had no such investments.

Inventory – The full balance of the Company's inventory consists of materials and supplies for its operations, with no work in process or finished goods inventory balances. Inventory is added to the books upon the purchase of supplies (inclusive of freight and sales tax costs) to use on well sites, and inventory is reduced by material transfers for inventory usage based on the initial invoiced value. The Company reports the balance of its inventory at the lower of cost or net realizable value. Inventory balances are excluded from the Company's calculation of depletion.

Oil and Natural Gas Properties – The Company uses the full cost method of accounting for oil and natural gas properties. Under this method, all costs (direct and indirect) associated with acquisition, exploration, and development of oil and natural gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization. All of the Company’s capitalized costs, excluding inventory, are subject to amortization.

The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The Company’s ARO relates to future plugging and abandonment expenses of its oil and natural gas properties and related facilities disposal. Dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs.

All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and natural gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent petroleum engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is offset to the capitalized costs to be amortized. The following table shows total depletion and the depletion per barrel-of-oil-equivalent rate, for the three months ended March 31, 2025 and 2024.

In addition, capitalized costs less accumulated depletion and related deferred income taxes are not allowed to exceed an amount (the full cost ceiling) equal to the sum of:

1)the present value of estimated future net revenues discounted at ten percent computed in compliance with SEC guidelines;

2)plus the cost of properties not being amortized;

3)plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;

4)less income tax effects related to differences between the book and tax basis of the properties.

No impairments on oil and natural gas properties as a result of the ceiling test were recorded for the three months ended March 31, 2025 and 2024.

Land, Buildings, Equipment, Software, Leasehold Improvements, Automobiles, Buildings and Structures – Land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures are carried at historical cost, adjusted for impairment loss and accumulated depreciation (except for land). Historical costs include all direct costs associated with the acquisition of land, buildings, equipment, software, leasehold improvements, automobiles, buildings and structures and placing them in service. Upon sale or abandonment, the cost of the fixed asset(s) and related accumulated depreciation are removed from the accounts and any gain or loss is recognized.

Depreciation of buildings, equipment, software, leasehold improvements, automobiles, buildings and structures is calculated using the straight-line method based upon the following estimated useful lives:

The following table provides information on the Company's depreciation expense for the three months ended March 31, 2025 and 2024.

Notes Payable – At the end of May 2024, the Company renewed its control of well, general liability, pollution, umbrella, property, workers' compensation, auto, and D&O insurance policies, funding the premiums with a promissory note with a face value after down payments of $1,501,507. In November 2024, the Company renewed its cybersecurity insurance policy, and funded the premium with a promissory note with a face value after down payments of $58,773. The APR for both notes was 7.98%. As of March 31, 2025 and December 31, 2024, the notes payable balances included in current liabilities on the Condensed Balance Sheets were $0 and $496,397, respectively.

The following table reflects the weighted average notes payable balances and the weighted average interest rate on the weighted average notes payable outstanding during the period as of and for the three months ended March 31, 2025 and 2024.

The following table shows interest paid related to notes payable for the three months ended March 31, 2025 and 2024. This interest is included within "Interest (expense)" in the Condensed Statements of Operations.

Revenue Recognition – In January 2018, the Company adopted Accounting Standards Update (“ASU”) 2014-09 Revenues from Contracts with Customers (Topic 606)(“ASU 2014-09”). The timing of recognizing revenue from the sale of produced crude oil and natural gas was not changed as a result of adopting ASU 2014-09. The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The transaction price includes variable consideration as product pricing is based on published market prices and reduced for contract specified differentials (quality, transportation and other variables from benchmark prices). The guidance regarding ASU 2014-09 does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and Ring engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. See "NOTE 2 — REVENUE RECOGNITION" for additional information.

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred income taxes are provided on differences between the tax basis of assets and liabilities and their carrying amounts in the condensed financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the condensed financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

In assessing the Company’s deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and the Company’s ability to utilize operation loss carryforwards during the periods in which the temporary differences become deductible. We also consider the reversal of deferred tax liabilities and available tax planning strategies. As of March 31, 2025 and December 31, 2024, the Company didnot carry a valuation allowance against its federal and state deferred tax assets.

The Company recorded the following federal and state income tax benefits (provisions) for the three months ended March 31, 2025 and 2024.

(1) The Company’s overall effective tax rate is calculated as Benefit from (Provision for) Income Taxes divided by Income Before Benefit from (Provision for) Income Taxes. The effective tax rates for the three months ended March 31, 2025 and 2024 were higher than the federal statutory corporate tax rate, primarily impacted by the state income taxes.

Accounting for Uncertainty in Income Taxes – In accordance with GAAP, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years. The Company has identified its federal income tax return and its franchise tax return in Texas in which it operates as a “major” tax jurisdiction. The Company’s federal income tax returns for the years ended December 31, 2020 and after remain subject to examination. The Company’s federal income tax returns for the years ended December 31, 2008 and after remain subject to examination to the extent of the net operating loss (NOL) carryforwards. The Company’s franchise tax returns in Texas remain subject to examination for 2019 and after. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by GAAP. No interest or penalties have been levied against the Company and none are anticipated; therefore, no interest or penalty has been included in our provision for income taxes in the Condensed Statements of Operations.

Leases– The Company accounts for its leases in accordance with ASU 2016-02, Leases (Topic 842), effective January 1, 2019. The Company made accounting policy elections to not capitalize leases with a lease term of twelve months or less (i.e. short term leases) and to not separate lease and non-lease components for all asset classes. The Company also elected to adopt the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases, or (iii) initial direct costs for any existing leases, and the practical expedient regarding land easements that exist prior to the adoption of ASU 2016-02. The Company did not elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date.

Earnings (Loss) Per Share– Basic earnings (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the applicable period. Diluted earnings (loss) per share are calculated to give effect to potentially issuable dilutive common shares.

Share-Based Employee Compensation –The Company has outstanding stock option grants, restricted stock unit awards, and performance stock unit awards to directors, officers and employees, which are described more fully below in "NOTE 11 — EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK UNITS". The Company recognizes the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award and recognizes the related compensation expense over the period during which an employee is required to provide service in exchange for the award, which is generally the vesting period.

Share-Based Compensation to Non-Employees –The Company accounts for share-based compensation issued to non-employees as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of (i) the date at which a commitment for performance by the recipient to earn the equity instruments is reached or (ii) the date at which the recipient’s performance is complete.

Share-Based Compensation –The following table summarizes the Company's share-based compensation, included with General and administrative expense within our Condensed Statements of Operations, incurred for the three months ended March 31, 2025 and 2024.

Derivative Instruments and Hedging Activities – The Company periodically enters into derivative contracts to manage its exposure to commodity price 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.

As the Company has not designated its derivative instruments as hedges for accounting purposes, any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of other income (expense) in the Condensed Statements of Operations.

When applicable, the Company records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. See "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS" for additional information.

The Company uses the indirect method of reporting operating cash flows within the Condensed Statements of Cash Flows. Accordingly, the non-cash, unrealized gains and losses from derivative contracts are reflected as an adjustment to arrive at Net cash provided by operating activities. The total Gain (loss) on derivative contracts less the Cash received (paid) for derivative settlements, net represents the unrealized (mark to market) gain or loss on derivative contracts.

Recently Adopted Accounting Pronouncements –In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provided optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that referenced LIBOR ("London Inter-Bank Offered Rate") or another rate. ASU 2020-04 was in effect through December 31, 2022. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. In December 2022, the FASB issued ASU 2022-06, "Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848"("ASU 2022-06"), which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. The Company adopted ASU 2020-04 with an effective date of January 1, 2024. Beginning August 31, 2022, under the Company's Credit Agreement, the Company's interest rates were transitioned from the LIBOR to the SOFR ("Secured Overnight Financing Rate") reference rate. At this time, the Company does not plan to enter into additional contracts using LIBOR as a reference rate. As such, the adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.

In July 2023, the FASB issued ASU 2023-03, Presentation of Financial Statements (Topic 205), Income Statement - Reporting Comprehensive Income (Topic 220), Distinguishing Liabilities from Equity (Topic 480), Equity (Topic 505), and Compensation - Stock Compensation (Topic 718): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 120, SEC Staff Announcement at the March 24, 2022 EITF Meeting, and Staff Accounting Bulletin Topic 6.B, Accounting Series Release 280 - General Revision of Regulation S-X: Income or Loss Applicable to Common Stock. The ASU provided updated views from the SEC Staff on employee and non-employee share-based payment accounting, including guidance related to spring-loaded awards. As the ASU did not provide any new ASC guidance, and there was no transition or effective date provided, the Company adopted this standard upon issuance, and the adoption did not have a material impact on the Company's condensed financial statements.

In November 2023, the FASB issued ASU 2023-07 "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures." This update requires that a public entity with multiple reportable segments disclose significant segment expenses that are regularly provided to the chief operating decision maker ("CODM"), as well as other segment items that are included in the calculation of segment profit or loss. A public entity will also be required to disclose all annual disclosures about a reportable segment's profit or loss currently required by Topic 280 in interim periods. Although a public entity is permitted to disclose multiple measures of a segment's profit or loss, at least one of the reported segment profit or loss measures should be consistent with the measurement principles used in measuring the corresponding amounts of the public entity's consolidated financial statements. Further, a public entity must disclose the title and position of the CODM as well as how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. Finally, the update requires that a public entity that has a single reportable segment provide all the disclosures required by the amendments in this update and all existing segment disclosures in Topic 280. The amendments in this update became effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 effective January 1, 2024.

In December 2023, the FASB issued ASU 2023-09 "Income Taxes (Topic 740): Improvements to Income Tax Disclosures." The amendments from this update provide for more transparency about income tax information through improvements to income tax disclosures primarily related to the rate reconciliation and income taxes paid information. Specifically, public business entities are required to disclose a tabular reconciliation, using both percentages and reporting currency amounts, showing detail from eight specific categories: (a) state and local income tax net of federal (national) income tax effect, (b) foreign tax effects, (c) effect of changes in tax laws or rates enacted in the current period, (d) effect of cross-border tax laws, (e) tax credits, (f) changes in valuation allowances, (g) nontaxable or nondeductible items, and (h) changes in unrecognized tax benefits. In addition, public business entities are required to separately disclose any reconciling item, disaggregated by nature and/or jurisdiction, in which the effect of the reconciling item is equal to or greater than five percent of the amount computed by multiplying the income (or loss) from continuing operations before income taxes by the applicable statutory income tax rate. Also, for the state and local category, a public business entity is required to provide a qualitative description of the states and local jurisdictions that make up the majority (greater than 50 percent) of the category. Further, the amount of income taxes paid (net of refunds received) are required to be disaggregated by (i) federal (national), state, and foreign taxes, and (ii) by individual jurisdictions in which income taxes paid (net of refunds received) is equal to or greater than five percent of total income taxes paid (net of refunds received). Finally, the amendments from this update require that all entities disclose (i) income (or loss) from continuing operations before income tax expense (or benefit) disaggregated between domestic and foreign and (ii) income tax expense (or benefit) from continuing operations disaggregated by federal, state, and foreign. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2024. As such, the Company adopted ASU 2023-09 effective January 1, 2025. The Company will include the applicable enhanced disclosures in its annual financial statements for the year ended December 31, 2025.

In March 2024, the FASB issued ASU 2024-02 "Codification Improvements –Amendments to Remove References to the Concepts Statements" ("ASU 2024-02"), which contains amendments to the Codification to remove references to various FASB Concepts Statements. In most instances, the references are extraneous and not required to understand or apply the guidance. Generally, ASU 2024-02 is not intended to result in significant accounting changes for most entities. ASU 2024-02 is effective for the Company for fiscal years beginning after December 15, 2024. As such, the Company adopted ASU 2024-02 effective January 1, 2025. The adoption did not have a material impact on the Company's condensed financial statements.

Recent Accounting Pronouncements –In October 2023, the FASB issued ASU 2023-06, "Disclosure Improvements: Codification Amendments in Response to the SEC's Disclosure Update and Simplification Initiative." This update modifies the disclosure or presentation requirements of a variety of Topics in the Codification, which should be applied prospectively. For instance, within ASC 230-10 Statement of Cash Flows –Overall, the amendment requires an accounting policy disclosure in annual periods of where cash flows associated with their derivative instruments and their related gains and losses are presented in the statement of cash flows. Additionally, within ASC 260-10 Earnings Per Share –Overall, the amendment requires disclosure of the methods used in the diluted earnings-per-share computation for each dilutive security and clarifies that certain disclosures should be made during interim periods. The Company is currently assessing the impact of this update on its financial statements and related notes. If by June 30, 2027, the SEC has not removed the applicable requirement from Regulation S-X or Regulation S-K, the pending content of the related amendment will be removed from the Codification and will not become effective for any entity.

In November 2024, the FASB issued ASU 2024-03, "Income Statement –Reporting Comprehensive Income –Expenses Disaggregation Disclosures (Subtopic 220-40) –Disaggregation of Income Statement Expenses" ("ASU 2024-03"). The purpose of this update is to improve the disclosures about a public business entity's expenses and address requests from investors for more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation, amortization, and depletion) in commonly presented expense captions (such as cost of sales, SG&A, and research and development). The amendments in this update are effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods with annual reporting periods beginning after December

15, 2027, with early adoption permitted, and either prospective or retrospective application permitted. The Company is currently assessing the impact of adopting this new guidance on its financial disclosures.

NOTE 2 — REVENUE RECOGNITION

The Company predominantly derives its revenue from the sale of produced crude oil, natural gas, and NGLs. The contractual performance obligation is satisfied when the product is delivered to the purchaser. Revenue is recorded in the month the product is delivered to the purchaser. The Company receives payment from one to three months after delivery. The Company has utilized the practical expedient in ASC 606-10-50-14A, which states an entity is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s sales contracts, each unit of production delivered to a purchaser represents a separate performance obligation, therefore, future volumes to be delivered are wholly unsatisfied and disclosure of transaction price allocated to remaining performance obligation is not required. The transaction price includes variable consideration, as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content, and transportation. The guidance does not require that the transaction price be fixed or stated in the contract. Estimating the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. Once consideration is received from the purchaser, the Company records any variances between the estimates and actual amounts, which has historically not been significant.

Oil sales

Under the Company’s oil sales contracts, the Company sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue at the net price received when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive.

Natural gas and NGL sales

Under the Company’s natural gas sales processing contracts for its Central Basin Platform properties and a portion of its Northwest Shelf assets, the Company delivers unprocessed natural gas to a midstream processing entity at the wellhead. The midstream processing entity obtains control of the natural gas and NGLs at the wellhead. The midstream processing entity gathers and processes the natural gas and NGLs and remits proceeds to the Company for the resulting sale of natural gas and NGLs. Under these processing agreements, the Company recognizes revenue when control transfers to the purchaser at the point of delivery and it is probable the Company will collect the consideration it is entitled to receive. As such, the Company accounts for any fees and deductions as a reduction of the transaction price.

Until April 30, 2022, under the Company's natural gas sales processing contracts for the bulk of our Northwest Shelf assets, the Company delivered unprocessed natural gas to a midstream processing entity at the wellhead. However, the Company maintained ownership of the gas through processing and received proceeds from the marketing of the resulting products. Under this processing agreement, the Company recognized the fees associated with the processing as an expense rather than netting these costs against Oil, Natural Gas, and Natural Gas Liquids Revenues in the Condensed Statements of Operations. Beginning May 1, 2022, these contracts were combined into one contract, and it was modified so that the Company no longer maintained ownership of the gas through processing. Accordingly, the Company from that point on accounts for any such fees and deductions as a reduction of the transaction price. There remains only one contract with a natural gas processing entity in place where point of control of gas dictates requiring the fees be recorded as an expense.

Disaggregation of Revenue. The following table presents revenues disaggregated by product:

(1) In the three months ended March 31, 2025 and 2024, the Company experienced a net negative total gas revenue, due to a lower gross realized sales prices per Mcf compared with the plant fees per Mcf.

NOTE 3 — LEASES

The Company has operating leases for its offices in Midland, Texas and The Woodlands, Texas. The Midland office was originally under afive-year lease which began January 1, 2021. The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027. Beginning January 15, 2021, the Company entered into a five-and-a-half-year sub-lease for office space in The Woodlands, Texas; however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated. On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas. The future payments for these office spaces are reflected in the future lease payments schedule below.

The Company has month to month leases for office equipment and compressors used in its operations on which the Company has elected to apply ASU 2016-02 (i.e. to not capitalize). The office equipment and compressors are not subject to ASU 2016-02 based on the agreement and nature of use. These leases are for terms that are less than 12 months and the Company does not intend to continue to lease this equipment for more than 12 months. The lease costs associated with these leases is reflected in the short-term lease costs within Lease operating expenses, shown below.

The Company has financing leases for vehicles. These leases have an initial term of 36 months at the end of which the Company owns the vehicles. These vehicles are generally sold at the end of their term and the proceeds are settled in cash or applied to a new vehicle.

Future lease payments associated with these operating and financing leases as of March 31, 2025 are as follows:

(1)The weighted average annual discount rate as of March 31, 2025 for operating leases was 4.50%. Based on this rate, the future lease payments above include imputed interest of $148,280. The weighted average remaining term of operating leases was 3.25 years.

(2)The weighted average annual discount rate as of March 31, 2025 for financing leases was 7.45%. Based on this rate, the future lease payments above include imputed interest of $121,951. The weighted average remaining term of financing leases was 1.87 years.

The following table represents a reconciliation between the undiscounted future cash flows in the table above and the operating and financing lease liabilities disclosed in the Condensed Balance Sheets:

The following table provides supplemental information regarding lease costs in the Condensed Statements of Operations:

(1)Amount included in Lease operating expenses

(2)Amount included in Depreciation, depletion and amortization

(3)Amount included in Interest (expense)

NOTE 4 — EARNINGS PER SHARE INFORMATION

The following table presents the calculation of the Company's basic and diluted earnings (loss) per share for the three months ended March 31, 2025 and 2024. For all dilutive securities, the treasury stock method of calculating the incremental shares is applied.

The following table presents the securities which were excluded from the Company's computation of diluted earnings (loss) per share for the three months ended March 31, 2025 and 2024, as their effect would have been anti-dilutive.

NOTE 5 — ACQUISITIONS AND DIVESTITURES

CBP Vertical Well Sale

On September 30, 2024, the Company completed the sale of certain oil and gas properties, including vertical wells and associated facilities, within Andrews County, Texas and Gaines County, Texas to an unaffiliated party for $5.5 million, with cash consideration being the same. As part of the sale, the buyer assumed an asset retirement obligation balance of approximately $2.7 million.

Lime Rock Acquisition

On February 25, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”) and Lime Rock Resources IV-C, L.P. ("LRRC" and with LRRA, "Lime Rock"), as seller, entered into a purchase and sale agreement (the “Purchase Agreement”). Pursuant to the closing of the Purchase Agreement, on March 31, 2025 the Company acquired (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of the Texas Permian Basin in Andrews County, Texas, for a purchase price (the “Purchase Price”) of (i) a cash deposit of $5.0 million paid on February 26, 2025 into a third-party escrow account as a deposit pursuant to the Purchase Agreement, (ii) approximately $63.6 million in cash paid on the closing date, net of approximately $12.7 million of preliminary and customary purchase price adjustments and subject to final post-closing settlement between the Company and Lime Rock with an effective date of October 1, 2024, (iii) an aggregate of 6,452,879 shares of common stock and (iv) a deferred cash payment of $10.0 million to be paid by December 31, 2025.

The Lime Rock Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The fair value of the consideration paid by Ring and allocation to the underlying assets acquired, on a relative fair value basis, was recorded as of the date of the closing of the Lime Rock Acquisition. Additionally, costs directly related to the Lime Rock Acquisition were capitalized as a component of the purchase price. Determining the fair value of the assets and liabilities acquired required judgment and certain assumptions to be made, the most significant of these being related to the valuation of Lime Rock's oil and gas properties. The inputs and assumptions related to the oil and gas properties were categorized as level 3 in the fair value hierarchy.

The following table represents the preliminary allocation of the total cost of the Lime Rock Acquisition to the assets acquired and liabilities assumed as of the Lime Rock Acquisition date:

NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. It utilizes derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.

From time to time, the Company enters into derivative contracts to protect the Company’s cash flow from price fluctuation and maintain its capital programs. The Company has historically used costless collars, deferred premium puts, or swaps for this purpose. Oil derivative contracts are based on WTI ("West Texas Intermediate") crude oil prices and natural gas contacts are based on the Henry Hub. A “costless collar” is the combination of two options, a put option (floor) and call option (ceiling) with the options structured so that the premium paid for the put option will be offset by the premium received from selling the call option. Similar to costless collars, there is no cost to enter into the swap contracts. A deferred premium put contract has the premium established upon entering the contract, and due upon settlement of the contract.

The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. All of our derivative contracts are with lenders under our Credit Facility. Non-performance risk is incorporated in the discount rate by adding the quoted bank (counterparty) credit default swap (CDS) rates to the risk free rate. Although the counterparties hold the right to offset (i.e. netting) the settlement amounts with the Company, in accordance with ASC 815-10-50-4B, the Company classifies the fair value of all its derivative positions on a gross basis in the Company's Condensed Balance Sheets.

The Company’s derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying Condensed Balance Sheets. The Company has not designated its derivative instruments as hedges for accounting purposes, and, as a result, any gains or losses resulting from changes in fair value of outstanding derivative

financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included as a component of "Other Income (Expense)" under the heading "Gain (loss) on derivative contracts" in the accompanying Condensed Statements of Operations.

The following presents the impact of the Company’s contracts on its Condensed Balance Sheets for the periods indicated.

The components of “Gain (loss) on derivative contracts” from the Condensed Statements of Operations are as follows for the respective periods:

The components of “Cash received (paid) for derivative settlements, net” within the Condensed Statements of Cash Flows are as follows for the respective periods:

The following tables reflect the details of current derivative contracts as of March 31, 2025 (Quantities are in barrels (Bbl) for the oil derivative contracts and in million British thermal units (MMBtu) for the natural gas derivative contracts):

(1) The oil basis swap hedges are calculated as the fixed price (weighted average spread price above) less the difference between WTI Midland and WTI Cushing, in the issue of Argus Americas Crude.

(2) The gas basis swap hedges are calculated as the Henry Hub natural gas price less the fixed amount specified as the weighted average spread price above.

NOTE 7 — FAIR VALUE MEASUREMENTS

Fair value is 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). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy. We continue to evaluate our inputs to ensure the fair value level classification is appropriate. When transfers between levels occur, it is our policy to assume that the transfer occurred at the date of the event or change in circumstances that caused the transfer.

The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.

The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments if events or changes in certain circumstances indicate that adjustments may be necessary.

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis (further detail in "NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS").

The carrying amounts reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates. The carrying amounts of receivables and accounts payable and other current assets and liabilities approximate fair value because of the short-term maturities and/or liquid nature of these assets and liabilities.

NOTE 8 — REVOLVING LINE OF CREDIT

On August 31, 2022, the Company entered into that certain Second Amended and Restated Credit Agreement (the "Credit Agreement"), with a maximum borrowing base of $1 billion secured by substantially all of the assets of the Company and a maturity date of August 2026. On February 12, 2024, the Company, Truist Bank as the Administrative Agent (the "Administrative Agent") and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Credit Agreement. Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow.

The Credit Agreement has a borrowing base of $600 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions.

The reference rate in the Credit Agreement is the Secured Overnight Financing Rate ("SOFR"). Also, the Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Credit Agreement) is not greater than 80%.

The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage). The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv)0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).

The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Agreement) of 1.0 to 1.0. The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas. However, if the borrowing base utilization is less than 25% at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.

As of March 31, 2025, $460 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Credit Agreement.

Under the Credit Agreement, the applicable percentage for the unused commitment fee is 0.5% per annum for all levels of borrowing base utilization. As of March 31, 2025, the Company's unused line of credit was approximately $140.0 million, which was calculated by subtracting the outstanding Credit Facility balance of $460 million and standby letters of credit of $35,000 ($10,000 with a federal agency and $25,000 with an insurance company for New Mexico state surety bonds) from the $600 million borrowing base.

NOTE 9 — ASSET RETIREMENT OBLIGATION

The Company records the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the costs or timing estimates. The asset retirement obligation is incurred using an annual credit-adjusted risk-free discount rate at the applicable dates. A reconciliation for the asset retirement obligation during the three months ended March 31, 2025 is as follows:

The following table presents the Company's current and non-current asset retirement obligation balances as of the periods specified.

NOTE 10 — STOCKHOLDERS' EQUITY

As of December 31, 2024, the Company had 78,200 exercisable common warrants outstanding, with a contractual exercise price of $0.80 per warrant, expiring five years from initial issuance in October 2020. During the three months ended March 31, 2025 and 2024, no common warrants were exercised. The following table reflects the common warrants exercised, including the proceeds received for such exercises. As of March 31, 2025, there remained 78,200 exercisable common warrants.

NOTE 11 — EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK UNITS

Share-based compensation expense charged against income for share-based awards during the three months ended March 31, 2025 and 2024 was as follows. These amounts are included in General and administrative expense in the Condensed Statements of Operations.

In 2011, the Board of Directors (the "Board") of the Company approved and adopted a long-term incentive plan (the “2011 Plan”), which was subsequently approved and amended by the stockholders. There wereno shares eligible for grant, either as stock options or as restricted stock, as of March 31, 2025.

In 2021, the Board and Company stockholders approved and adopted the Ring Energy, Inc. 2021 Omnibus Incentive Plan (the “2021 Plan”). The 2021 Plan provides that the Company may grant options, stock appreciation rights, restricted shares, restricted stock units, performance-based awards, other share-based awards, other cash-based awards, or any combination of the foregoing. At the 2023 Annual Meeting of Stockholders, the stockholders approved an amendment to the 2021 Plan to increase the number of shares available under the 2021 Plan by 6.0 million. There were 1,625,756 shares available for grant as of March 31, 2025 under the 2021 Plan.

Employee Stock Options

A summary of the status of the stock options as of March 31, 2025 and 2024 and changes during the respective three month periods then ended are as follows:

The intrinsic values were calculated using the closing price on March 31, 2025 of $1.15 and the closing price on March 31, 2024 of $1.96. As of March 31, 2025, the Company had $0 of unrecognized compensation cost related to stock options.

Restricted Stock Units

A summary of the restricted stock unit ("RSU") activity as of March 31, 2025 and 2024, respectively, and changes during the respective three month periods then ended are as follows:

As of March 31, 2025, the Company had $5,835,740 of unrecognized compensation cost related to RSU grants that will be recognized over a weighted average period of 2.35 years. Grant activity for the three months ended March 31, 2025 was primarily RSU for the annual long-term incentive plan awards for employees.

Performance Stock Units

A summary of the status of the performance stock unit ("PSU") grants as of March 31, 2025 and 2024, respectively, along with changes during the respective three month periods then ended are as follows:

As of March 31, 2025, the Company had $2,644,746 of unrecognized compensation cost related to the PSU awards that will be recognized over a weighted average period of 1.38 years.

NOTE 12 — COMMITMENTS AND CONTINGENCIES

Standby Letters of Credit– A commercial bank previously issued standby letters of credit on behalf of the Company for $250,000 to the State of Texas, $10,000 to a federal agency, and $500,438 to an insurance company to secure the surety bonds described below. On February 23, 2024, the bank reduced the $500,438 standby letter of credit to $25,000 after approval of the insurance company, reduced the $250,000 standby letter of credit to the State of Texas to $0, and retained the standby letter of credit to the federal agency at $10,000. As of March 31, 2025, the Company had total standby letters of credit outstanding of $35,000. The standby letters of credit are valid until cancelled or matured and are collateralized by the Credit Facility with the bank. The terms of the letter of credit to the federal agency is extended for a term ofone year at a time. The Company intends to renew the standby letter of credit to the federal agency for as long as required. Although the Company no longer operates any wells in the State of New Mexico, that standby letter of credit will need to be renewed until released. No amounts have been drawn under the standby letters of credit.

Surety Bonds – An insurance company issued surety bonds on behalf of the Company totaling $500,438 to various State of New Mexico agencies in order for the Company to do business in the State of New Mexico. The surety bonds are valid until canceled or matured. The terms of the surety bonds are extended for a term ofone year at a time. As of March 31, 2025, the Company still had a surety bond in place of $25,000 for the State of New Mexico; however, these bonds are expected to be eliminated once change of ownership is approved by the New Mexico Oil Conservation Division. On January 10, 2024, two insurance companies issued surety bonds on behalf of the Company, one for $250,000, a Texas Railroad Commission ("RRC") required blanket performance bond to operate 100 wells or more in the State of Texas, and one for $2,000,000, an RRC required blanket plugging extension bond, each with zero collateral requirements. The term for thesetwo surety bonds ends on July 1, 2025 and they can be renewed at that time. As of March 31, 2025, the Company had $2,275,000 in total surety bonds.

NOTE 13 — SEGMENT REPORTING

In accordance with ASU 2023-07 "Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures," the Company has performed an assessment of its reporting to comply with the new requirements for the fiscal year beginning January 1, 2024 and for interim periods beginning January 1, 2025. The Company's operations consist of the exploration, production, and sale of oil, natural gas, and NGLs, primarily within the Permian Basin of Texas, and is regulated by the RRC. The Company operates different areas within the Permian Basin, including the Northwest Shelf and Central Basin Platform.

The Company's operations and financials are managed by one cohesive group of individuals, identified as the chief operating decision maker ("CODM"), consisting of the Chairman of the Board and Chief Executive Officer; Executive Vice President and Chief Operations Officer; Executive Vice President and Chief Financial Officer; Executive Vice President and Chief Exploration Officer; and Senior Vice President of Operations. The CODM group reviews the Company's operating results, including condensed financial statements on a monthly basis for evaluating performance and determining resource allocation. The significant expense categories provided to the CODM include lease operating expenses; gathering, transportation and processing costs; ad valorem taxes; and oil and natural gas production taxes. Each of these costs are deducted from oil, natural gas, and natural gas liquids revenues by operating segment to arrive at operating segment profit, used to assess performance.

The Company assessed whether its operating segments exhibited similar economic characteristics and whether its operating segments had a similar nature of products, services, production processes, purchaser types/classes, product distribution, and regulatory environment. Each operating segment has similar products (oil, natural gas, and NGLs), similar production processes, similar types of purchasers (midstream companies, or companies with midstream components), similar methods of product delivery, and is governed by the same regulations. After a thorough analysis of each of these factors with regards to the Company's operating segments, it has been determined that it is appropriate to aggregate its operating segments into a single reportable segment, Exploration and Production, which includes all of its revenues, lease operating expenses, gathering, transportation and processing costs, ad valorem taxes, and oil and natural gas production taxes. Refer to the table below.

(1) All of the Company's revenues are within the Permian Basin within the United States.

(2) The CODM also reviews the following cost categories within lease operating expenses. Refer to the following table.

The following tables include a reconciliation of the total reportable segments' measures of profit or loss to the Company's consolidated income before income taxes. Additionally included is a reconciliation between the reportable segments' assets to the Company's consolidated assets.

(3) All of the Company's assets are located within the United States. As the CODM does not view depreciation, depletion and amortization as a significant Exploration and Production segment expense, the Company has included this expense within the Corporate column of the reconciliation table.

The following table discloses the purchasers from which 10% or more of revenues were derived in the years noted.

(4) All the Company's purchasers are within the Exploration and Production operating segment.

• Represents less than 10%

NOTE 14 — SUBSEQUENT EVENTS

In accordance with ASC Topic 855, Subsequent Events, the Company has evaluated all events subsequent to the balance sheet date of March 31, 2025, through the date these condensed financial statements were issued, May 7, 2025. The Company did not have any material subsequent events to report.