Note 2 - Significant Accounting Policies	12 Months Ended
Jul. 31, 2025
Notes to Financial Statements
Significant Accounting Policies [Text Block]	NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES Basis of presentation These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and the rules and regulations of the Securities and Exchange Commission (“SEC”). Use of estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. Cash and Cash Equivalents The Company considers all cash accounts, which are not subject to withdrawal restrictions or penalties, and all highly liquid debt instruments purchased with a maturity of three months or less as cash and cash equivalents. The carrying amount of financial instruments included in cash and cash equivalents approximates fair value because of the short maturities for the instruments held. The Company had no cash equivalents as of July 31, 2025 and 2024. Principles of Consolidation The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Kathis Energy LLC, Kathis Energy Fund 1, LLP and Enmex Operations LLC. All financial information has been prepared in conformity with accounting principles generally accepted in the United States of America. All significant intercompany transactions and balances have been eliminated. Mineral Property Acquisition and Exploration Costs Mineral property acquisition and exploration costs are expensed as incurred until such time as economic reserves are quantified. Cost of lease, exploration, carrying and retaining unproven mineral lease properties are expensed as incurred. We have chosen to expense all mineral exploration costs as incurred given that it is still in the exploration stage. Once our company has identified proven and probable reserves in its investigation of its properties and upon development of a plan for operating a mine, it would enter the development stage and capitalize future costs until production is established. When a property reaches the production stage, the related capitalized costs will be amortized over the estimated life of the probable-proven reserves. When our company has capitalized mineral properties, these properties will be periodically assessed for impairment of value and any diminution in value. Oil and Gas Properties The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether those wells are successful or unsuccessful. Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts. Depletion and amortization of oil and gas properties are computed on a well-by-well basis using the units-of-production method. Unproved property costs are not subject to amortization and consist primarily of leasehold costs related to unproved areas. Unproved property costs are transferred to proved properties if the properties are subsequently determined to be productive and are assigned proved reserves. Proceeds from sales of partial interest in unproved leases are accounted for as a recovery of cost without recognizing any gain until all cost is recovered. Unproved properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage. Asset Retirement Obligation Accounting Standards Codification (“ASC”) Topic 410, Asset Retirement and Environmental Obligations (“ASC 410”) requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The net estimated costs are discounted to present values using credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements. Fair Value of Financial Instruments The fair value is an exit price representing the amount that would be received to sell an asset or required to transfer a liability in an orderly transaction between market participants. As such, fair value of a financial instrument is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value: ● Level 1: Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. ● Level 2: Observable inputs that reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the assets or liabilities; or inputs that are derived principally from or corroborated by observable market data by correlation or other means. ● Level 3: Unobservable inputs reflecting our own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participants assumptions that are reasonably available. On July 31, 2025, there are no instruments requiring fair value hierarchy disclosure. The carrying amount of the Company’s financial assets and liabilities, such as cash, accounts receivable, accounts payable, accrued expenses and loans payable approximate their fair value because of the short maturity of those instruments. Basic and Diluted Earnings Per Share Net income (loss) per common share is computed pursuant to ASC 260-10-45, Earnings per Share—Overall—Other Presentation Matters. Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock and potentially outstanding shares of common stock during the period. For the years ended July 31, 2025 and 2024, the Company had no potentially dilutive shares of common stock. Revenue Recognition The Company recognizes revenue under ASC 606, “Revenue from Contracts with Customers” and in accordance with ASC 326 “Financial Instruments-Credit Losses”. The core principle of the new revenue standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The following five steps are applied to achieve that core principle: Step 1: Identify the contract with the customer. Step 2: Identify the performance obligations in the contract. Step 3: Determine the transaction price. Step 4: Allocate the transaction price to the performance obligations in the contract. Step 5: Recognize revenue when the Company satisfies a performance obligation. The Company receives revenues from the sale of oil and natural gas from its investment in Lost Creek Acquisitions LLC (Note 4). The Company owns a working interest in 14 oil and gas wells located in northeastern Oklahoma. These wells produce both oil and natural gas. As a working interest holder, revenue from the sale of oil and natural gas must first pay the production taxes to the state of Oklahoma, then the royalties to the mineral holders and then the expenses incurred to cause the oil and gas to produce. Operating expenses are typically administrative, pumper, electricity, water disposal, chemical and repairs. After taxes, royalties and expenses are paid, the remining amount is the net profit from the gross sales received from the 14 wells. The Company then receives its share of the revenues as per the percentage ownership as outlined per well in the purchase agreement. Accounts Receivable Accounts receivable consists of expected amounts due for its percentage of the sale of oil and natural gas from its investment in Lost Creek Acquisitions LLC. As of July 31, 2025, the Company has recorded $6,750 of accounts receivable. Allowance for Credit Losses The Company estimates its allowance for credit losses using the Current Expected Credit Loss (CECL) model under ASC 326. The CECL model requires recognition of expected credit losses over the contractual life of financial assets held at the reporting date, considering the nature of debt, industry expectations, current conditions, and reasonable and supportable forecasts. Financial assets subject to CECL include trade receivables. The Company groups financial assets based on shared risk characteristics and evaluates them collectively. The allowance is measured using a combination of historical activity, industry expectations, adjusted for current economic trends and forward-looking factors such as industry outlook and macroeconomic indicators (e.g., unemployment rate, GDP). Under CECL, the carrying amount of a financial asset (net of the allowance for credit losses) represents the amount the Company expects to collect. This means that when the CECL estimate is appropriately recorded, the net reported balance of financial assets reflects management’s best estimate of collectible cash flows, based on available and supportable information. Management reviews the adequacy of the allowance at each reporting period and updates estimates as appropriate. Changes in estimates are recorded in the income statement as a component of credit loss expense. As of July 31, 2025, there was no indication that the Company required an allowance for credit losses. Operating Segments Operating segments are defined as components of an entity for which discrete financial information is available that is regularly reviewed by the Chief Operating Decision Maker (“CODM”), or decision maker group, in deciding how to allocate resources to an individual segment and in assessing performance. Our chief operating decision–making group is composed of the Chief Executive Officer. The Company has one operating segment as of July 31, 2025 and 2024. Recently issued accounting pronouncements In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which requires disclosure of incremental segment information on an annual and interim basis, primarily disclosure of significant segment expense categories and amounts for each reportable segment. The new standard is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 in the annual financial statements for the year ended December 31, 2024, and for interim periods beginning in 2025. The Company adopted this ASU, effective for the year ended December 31, 2024. The adoption had no impact on the Company’s financial statements. The Company periodically reviews new accounting standards that are issued. Although some of these accounting standards may apply to the Company, the Company has not identified any new standards that it believes merit further discussion or change to adopted policies, and the Company expects that none will have a significant impact on its financial statements.

Note 2 - Significant Accounting Policies

12 Months Ended

Jul. 31, 2025

Significant Accounting Policies [Text Block]

NOTE 2 — SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and the rules and regulations of the Securities and Exchange Commission (“SEC”).

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.

Cash and Cash Equivalents

The Company considers all cash accounts, which are not subject to withdrawal restrictions or penalties, and all highly liquid debt instruments purchased with a maturity of three months or less as cash and cash equivalents. The carrying amount of financial instruments included in cash and cash equivalents approximates fair value because of the short maturities for the instruments held. The Company had no cash equivalents as of July 31, 2025 and 2024.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Kathis Energy LLC, Kathis Energy Fund 1, LLP and Enmex Operations LLC. All financial information has been prepared in conformity with accounting principles generally accepted in the United States of America. All significant intercompany transactions and balances have been eliminated.

Mineral Property Acquisition and Exploration Costs

Mineral property acquisition and exploration costs are expensed as incurred until such time as economic reserves are quantified. Cost of lease, exploration, carrying and retaining unproven mineral lease properties are expensed as incurred. We have chosen to expense all mineral exploration costs as incurred given that it is still in the exploration stage. Once our company has identified proven and probable reserves in its investigation of its properties and upon development of a plan for operating a mine, it would enter the development stage and capitalize future costs until production is established. When a property reaches the production stage, the related capitalized costs will be amortized over the estimated life of the probable-proven reserves. When our company has capitalized mineral properties, these properties will be periodically assessed for impairment of value and any diminution in value.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether those wells are successful or unsuccessful. Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts. Depletion and amortization of oil and gas properties are computed on a well-by-well basis using the units-of-production method.

Unproved property costs are not subject to amortization and consist primarily of leasehold costs related to unproved areas. Unproved property costs are transferred to proved properties if the properties are subsequently determined to be productive and are assigned proved reserves. Proceeds from sales of partial interest in unproved leases are accounted for as a recovery of cost without recognizing any gain until all cost is recovered. Unproved properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage.

Asset Retirement Obligation

Accounting Standards Codification (“ASC”) Topic 410, Asset Retirement and Environmental Obligations (“ASC 410”) requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The net estimated costs are discounted to present values using credit-adjusted, risk-free rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense and (4) revisions to estimated future cash flow requirements.

Fair Value of Financial Instruments

The fair value is an exit price representing the amount that would be received to sell an asset or required to transfer a liability in an orderly transaction between market participants. As such, fair value of a financial instrument is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or a liability.

A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:

● Level 1: Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

● Level 2: Observable inputs that reflect quoted prices for identical assets or liabilities in markets that are not active; quoted prices for similar assets or liabilities in active markets; inputs other than quoted prices that are observable for the assets or liabilities; or inputs that are derived principally from or corroborated by observable market data by correlation or other means.

● Level 3: Unobservable inputs reflecting our own assumptions incorporated in valuation techniques used to determine fair value. These assumptions are required to be consistent with market participants assumptions that are reasonably available.

On July 31, 2025, there are no instruments requiring fair value hierarchy disclosure. The carrying amount of the Company’s financial assets and liabilities, such as cash, accounts receivable, accounts payable, accrued expenses and loans payable approximate their fair value because of the short maturity of those instruments.

Basic and Diluted Earnings Per Share

Net income (loss) per common share is computed pursuant to ASC 260-10-45, Earnings per Share—Overall—Other Presentation Matters. Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock and potentially outstanding shares of common stock during the period.

For the years ended July 31, 2025 and 2024, the Company had no potentially dilutive shares of common stock.

Revenue Recognition

The Company recognizes revenue under ASC 606, “Revenue from Contracts with Customers” and in accordance with ASC 326 “Financial Instruments-Credit Losses”. The core principle of the new revenue standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The following five steps are applied to achieve that core principle:

Step 1: Identify the contract with the customer.

Step 2: Identify the performance obligations in the contract.

Step 3: Determine the transaction price.

Step 4: Allocate the transaction price to the performance obligations in the contract.

Step 5: Recognize revenue when the Company satisfies a performance obligation.

The Company receives revenues from the sale of oil and natural gas from its investment in Lost Creek Acquisitions LLC (Note 4). The Company owns a working interest in 14 oil and gas wells located in northeastern Oklahoma. These wells produce both oil and natural gas. As a working interest holder, revenue from the sale of oil and natural gas must first pay the production taxes to the state of Oklahoma, then the royalties to the mineral holders and then the expenses incurred to cause the oil and gas to produce. Operating expenses are typically administrative, pumper, electricity, water disposal, chemical and repairs. After taxes, royalties and expenses are paid, the remining amount is the net profit from the gross sales received from the 14 wells. The Company then receives its share of the revenues as per the percentage ownership as outlined per well in the purchase agreement.

Accounts Receivable

Accounts receivable consists of expected amounts due for its percentage of the sale of oil and natural gas from its investment in Lost Creek Acquisitions LLC. As of July 31, 2025, the Company has recorded $6,750 of accounts receivable.

Allowance for Credit Losses

The Company estimates its allowance for credit losses using the Current Expected Credit Loss (CECL) model under ASC 326. The CECL model requires recognition of expected credit losses over the contractual life of financial assets held at the reporting date, considering the nature of debt, industry expectations, current conditions, and reasonable and supportable forecasts.

Financial assets subject to CECL include trade receivables. The Company groups financial assets based on shared risk characteristics and evaluates them collectively. The allowance is measured using a combination of historical activity, industry expectations, adjusted for current economic trends and forward-looking factors such as industry outlook and macroeconomic indicators (e.g., unemployment rate, GDP).

Under CECL, the carrying amount of a financial asset (net of the allowance for credit losses) represents the amount the Company expects to collect. This means that when the CECL estimate is appropriately recorded, the net reported balance of financial assets reflects management’s best estimate of collectible cash flows, based on available and supportable information.

Management reviews the adequacy of the allowance at each reporting period and updates estimates as appropriate. Changes in estimates are recorded in the income statement as a component of credit loss expense. As of July 31, 2025, there was no indication that the Company required an allowance for credit losses.

Operating Segments

Operating segments are defined as components of an entity for which discrete financial information is available that is regularly reviewed by the Chief Operating Decision Maker (“CODM”), or decision maker group, in deciding how to allocate resources to an individual segment and in assessing performance. Our chief operating decision–making group is composed of the Chief Executive Officer. The Company has one operating segment as of July 31, 2025 and 2024.

Recently issued accounting pronouncements

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280) - Improvements to Reportable Segment Disclosures, which requires disclosure of incremental segment information on an annual and interim basis, primarily disclosure of significant segment expense categories and amounts for each reportable segment. The new standard is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 in the annual financial statements for the year ended December 31, 2024, and for interim periods beginning in 2025. The Company adopted this ASU, effective for the year ended December 31, 2024. The adoption had no impact on the Company’s financial statements.

The Company periodically reviews new accounting standards that are issued. Although some of these accounting standards may apply to the Company, the Company has not identified any new standards that it believes merit further discussion or change to adopted policies, and the Company expects that none will have a significant impact on its financial statements.